Drilling Operation Practices Manual (ONGC) (2007)

DRILLING OPERATION PRACTICES MANUALOIL AND NATURAL GAS CORPORATION LIMITED INSTITUTE OF DRILLING TECHNOLOGY DEHRADUN, INDIA FOR INTERNAL CIRCULATION ONLY First Edition January 2007 Published by V.K.Jain Head-IDT Institute of Drilling Technology Oil and Natural Gas Corporation Ltd. Kaulagarh Road, Dehradun-248195, INDIA Preparation Team A.B.Sharma Rajeev Dhupar R.P.Patel D.Das Gupta A.K.Joshi Ram Shanker Designed & Printed by Shiva Offset Press, Dehradun 14, Old Connaught Place Dehradun Ph.: 0135-2715748; Fax : 0135-2715107, E-mail : [email protected] rsy ,oa izkÑfrd xSl vk;ksx fyfeVsM OIL AND NATURAL GAS CORPORATION LIMITED TEL BHAVAN DEHRADUN-248003 0135-2754203 / 275 7753 R.S.SHARMA CHAIRMAN AND MANAGING DIRECTOR MESSAGE Drilling of oil and gas wells is a very complex operation requiring application of latest technology, accurate procedures of different activities of drilling operation and total attention is required for successful completion of the well. A healthy well is a requirement for optimum production of hydrocarbons. It is a matter of great happiness that Institute of Drilling Technology has prepared a Drilling Operation Practices Manual to provide assistance to the field engineers engaged in drilling a well including application of Drilling Fluid Engineering and Cementation Technology. I am sure that this manual will help to update the technological knowledge of drilling engineers, cementing engineers, mud engineers and other technical staff in field applications. In addition, it would also be of help to other disciplines associated with drilling and completion of wells. R.S.SHARMA rsy ,oa izkÑfrd xSl vk;ksx fyfeVsM OIL AND NATURAL GAS CORPORATION LIMITED TEL BHAVAN DEHRADUN-248003 Phone 0135-2753372 Fax: 0135-2753524 Telex: 0585-206/207 U.N.BOSE Director (Technology & Field Services) FOREWORD I am happy that earnest efforts have been made by Institute of Drilling Technology to bring out a Drilling Operation Practices Manual for ready reference by the field personnel. I am sure that the manual will be of immense use in providing necessary procedures & guidelines for carrying out operations correctly and efficiently on drilling rigs. Drilling Operation Practices Manual assumes a great importance particularly in view of the fact that drilling activity has been growing rapidly in volume and has also become more complex during the last few years. These complexities need immediate solution for which the Drilling Operation Practices manual would serve as a ready reference in field applications. This will also go a long way in streamlining the procedures being followed for various operations while drilling wells both onshore and offshore. I wish every field person should go through the manual thoroughly to implement the guidelines and procedures contained therein for performing drilling operations in the most efficient and cost effective manner. My best wishes U.N.BOSE PREFACE In the fast changing scenario worldwide in the field of drilling technology, publication of a DRILLING OPERATION PRACTICES MANUAL was felt necessary so that our executives on the rig can follow uniform Practices & Procedures and thereby increase the efficiency & productivity of drilling operations. This manual has also been attempted with an aim to collect all scattered mateials required for drilling engineers at one place. Thus, in a single reference book their need may be satisfied to the great extent. The book provides adequate theoretical, practical background explanation before setting operations procedures/guidelines in order to enable the users understand the procedures behind practices. The manual has also been specially designed with the objective of providing an insight to various operations and procedures carried out right from release of a drilling location to completion of drilling and testing of a well. Therefore, it will be an extremely useful reference handbook to the drilling engineers, mud engineers and cementing engineers especially to the new entrants in this field, for performing their assignment. The topics are devised in a way that should give a good basic understanding of the subject at all levels. Also, the topics discussed in this manual will play significant role in proper well planning, execution, monitoring and solving down hole complications. Proper and healthy use of this manual is bound to develop good understanding and better co-ordination among the interdisciplinary groups thereby creating an environment of synergy. A Team of highly qualified and experienced young executives has prepared this manual and it has been edited by very senior knowledgeable executives. Apart from our in-house publications, useful materials from the publications of various companies/authors/publishers have been used in this manual for maintaining its quality. Suggestions received from various quarters, at different stages of finalization of this manual, were examined critically and incorporated in the manual wherever possible. I am confident that humble effort of brining out this manual will benefit all the concerned users in playing a healthy role in the organization in addition to develop technical capabilities of individual. V.K.JAIN Head - IDT . who remained the key person during editing and printing of the manual. GGM(D) OVL.Dobhal.Joshi.(D). D.N. editing and printing the manual. Chakraborty. Ajeeth Xavier Parapullil. R. Sibsagar and other senior executives of Drilling Services for giving valuable suggestions to improve the quality of the manual.Methew.K.M. Ram Shanker. Vinod Kumar.K. Bandhopadhyay. Dr. ED-CDS. DGM (Chem).K.Dutta.Javed. A. S. A. Bhattacharya. A work of this nature could not have taken shape without their constant interest. Rajeev Dhupar. Head-DTS. Head-WCS. P. Manimmanan. Ram Shanker. DGM (Chem).E. Anurag Ahuja.K. Dasgupta. HDS. CE(D). D. R. I/C-R&D. Sanjay Kulkarni. Bhattacharjee. who remained the key person during compilation.K. V. A.Vig. A. Head-CCM.K. Chief Engineer (D).P. C. D.Mishra. Supdtg. DGM(D). support and encouragement. Librarian now in IPSHEM Goa. I would like to thank the authors of all 20 chapters i.K. Vishwajeet Das. . Pramanik. Saxena.Dubey. Bhattacharjee. Dr. CE(D). DGM(D). Again. Joshi. I/C-Training. HDS-Frontier Basin.K.I. EX-CDS for his constant association and valuable suggestions in giving shape to this manual.Kali. companies and publishers who have permitted us to use their publication materials in our manual as well as whose materials have been referred to during preparation of this manual. I would like to thank Shri A. A. Venkesteshwaran. Vinod Sharma. S/Sh S.B. A. C. they could spare their time and resources in bringing out this manual. Special thanks are reserved for Late Sh. Head-TSG as well as all the officers and staff of IDT who extended their co-operation in preparation of this manual. G. I would like to thank S/Sh K.S.I/C DFE. DGM (D) Mumbai. A.(D). whose sincere efforts made the publication of this manual possible. A.T.P. P. V.D. GGM(D). R. CE(D). A. A. Dobhal. The following persons deserve mention of their active association in preparation of this manual in different capacities: S/Sh A.E.Sharma.Patel. Head Monitoring Group.ACKNOWLEDGEMENT I would specially thank the C&MD and all the Directors of the Corporation for giving us the opportunity for preparing the Drilling Operation Practices manual. I would like to thank Sh. Head-R&D. S. Agarwal. My sincere thanks to the authors. Sehmi. Dutta. Dwivedi as well as all the officers and staff of IDT who spared their time in writing the subject procedures and bringing out this manual in addition to their other assignments. Inspite of pressing operational requirements.Singh.e. TRK Sherwani. I would like to thank S/Sh M. Security Dresser Industries Inc.K. Society of Petroleum Engineers (USA).. V. M/S Sperry-sun Drilling Services. M/S Hycalog. Pannwell Publishing Company. I acknowledge the services rendered by M/S Shiva Offset Press in bringing out the manual in this form. Gulf Publishing Company (World Oil). M/S Schlumberger Asia Services Ltd. Dowell Schlumberger Inc. Petroleum Extention Services Division. M/S. Finally.. M/S Hughes Christensen Company.The following companies/authors/publishers are being acknowledged thanks for permitting reproduction of their material for this manual..Jain . API Smith International. ............ . ................. .. . PAGE 1 22 36 47 51 54 59 65 71 85 96 116 141 177 189 196 205 219 245 276 355 .. .. ............ . .. .... . ............... .... .............. ....................... ....NO 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 SUBJECT LAND RIG CLASSIFICATION AND RIG BUILDING OFFSHORE RIG DRILLING OPERATIONS HYDRAULICS DRILLING BIT WELL LOGGING BHA SELECTION DRILL STRING WIRE ROPE WELL HEAD FITTING BOP STACK WELL CONTROL DOWN HOLE COMPLICATIONS CASING OPERATIONS DRILL STEM TESTING CORING OPERATION DIRECTIONAL DRILLING CEMENTING OPERATIONS DRILLING FLUID EMERGING TECHNOLOGIES REFERENCES .......CONTENTS S.... .... .... .......... .. ......... ..................... . C.II 16000 1400/1500 4000 Deeper Type . These rigs are for shallower depth wells. High Floor Mast & Sub structure rigs in ONGC are • • BHEL Electrical Rig Romanian Electrical Rig Shallow Type . Drilling rig equipment can be divided in 2 systems: 1. –D.I Capacity (ft. A cellar pit is made along with rig specific foundation. local roads and appropriate areas around the rig are surfaced to facilitate transportation of rig equipments. This carrier can be driven to the well site with all necessary hoisting equipment. b) D. the drill site for the future well must be prepared for proper placement of equipment.-D. engines and special telescopic mast as complete on truck unit.III 20000 2000 4000 Super Deep Super Deep 20000-30000 3000 6000 Type of Rigs Electrical Drive System 1 . (b) High Floor Mast & Sub Structure These are higher capacity rigs.C. For all other auxiliary equipment placement leveled foundation strips are made. In which rig is mounted on wheeled carrier.C. Mast and sub-structure 2. graded & leveled. If necessary.C.) Draw works(HP) Rig HP(Power Pack) Mechanical Drive System 12000 ≤1000 3000 IR-750 IR-900 IPS-700 BHEL-450 E-760 F-3050 MBHEL-760 E-1400 F-4900 BI-1500 E-2000 F-6100 ARMCO-1320UEBI-2000 E-3000 Medium Type .Land Rig Classification and Rig Building CHAPTER – 1 LAND RIG CLASSIFICATION AND RIG BUILDING Based on the type of rig. (obsolete now) Most land rigs come under two categories (a) Carrier-mounted Rigs These are also called mobile rigs. Power system a) A. In this rig components are transported to new location with the help of trucks and heavy-duty trailers. The land around the well site is cleared. 1 Rig Components of BHEL Electrical Rig Sub-Bases (Bottom Boxes): The sub-base assembly is designed to transmit the various loads to infirm soil conditions. Draw-works and surrounding floor are raised to drilling position by use of draw-works power and mast raising line. 1.2 RIG MOVE/ BUILDING PROCEDURE Rig building operations involves the following activities A.1. Raising of rear floor with draw-works. Mast: . In normal operating condition it supports the sub structure and transmits the loads from mast to the sub base. Drill site preparation 2 . no other rigging or wire line required. A-frame erection & Raising of Mast with set back parallelogram in place 2. Box type substructure consists of a pair of separated yet parallel rectangular boxes connected by pinned beam having provisions for mounting of / substructure and supporting drilling equipment. It also resists forces during raising and lowering of front and rear floors and also loads during mast raising and lowering.Acts as gin pole and provide high leverage to the bull line for mast raising operation. Various elevating systems are provided for raising the derrick floors through line and sheave arrangement. 1. coupled to a low structure.The mast is freestanding cantilever with rectangular shaped cross-section providing ample clearance for traveling block and also to facilitate easy handling of drill pipes. beams and girders connected to columns. Sub-Structure: It takes over mast. through parallel spaced links. Racking Platform: To accommodate drill pipes during tripping. Designed with wide flange beams. this is subjected to heavy torsional loads. rather than base. draw works and other loads generated during drilling operation and transmit them to sub base.Drilling Operation Practices Manual 1.1 BHEL Electrical Rigs are of two types (i) Sky Top / Brewster design – High floor modular Rig: This design is an improved modular rig having elevatable drill floor. Spreading of A-frame and Mast erection (ii) Branham Industries Universal Cantilever Swing lift (Type1) mast: This design is an improved version having self-elevating sub-structure. Rear floor raising along with draw-works 2. It consists of a structured framing system of trusses. The base of mast is pivotally supported from the derrick floor. It is also designed to resist the loads coming in addition to above due to storage of drill pipes. Steps involved in raising of sky top type rig: 1. It is assembled by joining five parts in sky top design or by joining six parts in branham design. rotary table. Front Floor raising 3. drill collars and casings. This takes entire mast load from slings through the pulleys provided and transmits it to the ground through sub-base. Steps involved in raising of Branham type rig: 1. Mast-A Frame: . Mast raising lines need only be moved from A-frame sheaves to the sheaves on draw-works elevator to complete rigging for erection. B. Route Survey: (Before rig release) Route survey shall be conducted prior to rig shifting and following points should be taken into consideration with respect to the type of rig to be transported: a. Height of the electrical transmission lines. E. f. BOP etc. Radius of curvature on turnings. Rig foundation should be as per the rig specifications and designed based on bearing capacity of soil. Mud pumps. c. If concrete slabs are used as foundation for auxiliary equipment. During stacking of site. b. e. Anchors for top man escape device. it should be seen that no overhead electrical line passes through drill site area (at least 30 mts. Effluent pit. should be grouted properly. all flow lines of the previous wells should be buried underground and X-mass tree of old well should be caged. 3 . All statutory and regulatory clearances should be obtained wherever it is necessary b. Diesel tank should be enclosed to arrest HSD spillage. Concrete slabs for mud tanks should be strong enough to support the load of completely filled tanks. Proper drainage for entire rig site to be provided. In cluster drilling site. Surrounding area of all equipment foundation should be hardened to bear the load of heavy transport vehicles. Strength of bridges and culverts. d. Drill Site Preparation: (Before rig release) a.Land Rig Classification and Rig Building B. c. Waste pit and Oil pit should be as per the requirement of OISD standard. Approach road should preferably be in line with the centerline of the well for giving enough space for vehicle movement. Cutting pit. C. p. then all the slabs should be at the same level and ground should be strong enough to support the load. e. j. Entire drill site area should be fenced with barbed wire and there should be only one entry point. Route survey Rig release / Rigging Down Transportation of rig equipments Rigging Up Above mentioned first two activities are performed before actual rig release from old location. away from well mouth). k. D. d. out line. g. h. Width and strength of the road. Security personnel be posted at new location before transportation. l. Site area should be inspected and ensured that its layout is suitable for the type of rig to be deployed there. Foundation level should be maintained for sub base structure and for the auxiliary equipments like PCRs. m. n. Power pack. i. A. o. Railway crossing and traction lines. a. u. All long hanging lines. Obstruction due to trees / branches. Application of brakes at any stage should not create any jerk. t. Mast raising and lowering lines (bull lines) should be inspected for any damage. Fold diving board of monkey board. brakes. o. A designated experienced person who knows the procedures should lower the mast. h. m. l. i. operations should be stopped for taking corrective action. e. g.Drilling Operation Practices Manual f. and sand lines should be tied up to the mast. k. railings. Fill water in bottom boxes wherever applicable. weight indicator and quick release valve should be checked. In case. During lowering check the rotation of the pulleys. Flow line of the existing well or cluster well. Ensure that all un-wanted persons are away during mast lowering from rig floor. Proper functioning of the clutches. Route survey team should consist of: Rig In-charge Electrical Engineer Civil Engineer Logistics personnel Land acquisition man C. 4 . In case of non-availability of mast snubbing system. d. n. if any should be protected from any inadvertent damage. Tackle system should be checked for free rotation of pulleys. Ensure that bottom boxes (rear and front extensions) wherever applicable are properly fitted and bolted. Rig release/Rigging down After releasing the rig from existing location the following procedure should be ensured. Derrick floor should be free of all unwanted materials prior to lowering of mast. Crossing points availability / requirement. p. Traffic in the cities en-route at peak hours. s. if any problem related to above aspects is noticed. stabbing board. v. then it should be rectified before start of rig shifting. It should be ensured that safety clips of every pin are in place. It should be ensured that the racking board. Rotary hoses should be secured and dismantle H-manifold and other pipes. Properly reeve bull lines for lowering of mast. Ensure that mast-snubbing system is functioning properly if available. is folded wherever applicable. fingers of monkey board etc. b. j. g. q. Raising and lowering of mast should be done in daylight. Mast should be lowered at slowest possible speed. Ensure the correct positioning of horse so that monkey board should not touch ground. and if any abnormality is observed. h. c. It should be ensured that there is no loose item on mast members. Mast raising and lowering sheaves and their guards should be inspected. ensure that the snub line is of sufficient length and without any joint. f. The front area of mast should be cleared for movement of chain tractor / Mole trailer. r. cat lines. e. Align sub-base structure to the center of the well. spool the casing line on drum and tighten the dead end properly. h. j. incidental damage etc. h. Lifter beams for lifting the equipment like PCR house. Check functioning of clutch. belly board. Proper transport fleet should be chosen based on equipment dimensions and weight and route selected. j. As far as possible. D. k. c. b. Minimum clearance from overhead lines to the transporting equipment shall be maintained. i. BOP trolley beams etc. Rest the mast on horse and remove monkey board. brake and ECB.g. engine room. etc. f. Fitness certificates of transport fleet should be checked before commencing shifting. Check mast members for cracks and bends etc while fitting. b. Damaged or kinked or twisted slings should not be used for lifting of loads. Check and service mast-lifting sheaves and equalizer pulley. should be used. d. Ensure all equipment reaches at new location in good working condition. c. i. ensure proper break-in. The equipment with liquid inside the tanks e. Unwanted person should not be allowed in the vicinity of the lifted load. fix fast end. No loose material should be stored inside the PCR. Load Handling and Transportation Rig equipment dimensional details. E. x. weight with regard to transportation should be well documented. diesel tanks etc. 5 . Grease all the pins before fitting and fit all the safety clips in all pin. should not be lifted / transported. Hooks for lifting should be engaged only on lifting lugs/eyes provided on the equipment being lifted. then power lines shall be de-energized. especially in hilly area. (Annexure-1) a. Fix the casing line guide roller on the mast wherever it is applicable. Check mast bull lines for broken wires. Rigging Up a. Reeve the traveling block. Planks / concrete slabs should be provided below the crane jacks based on the weight of the equipment to be lifted and soil condition. brake shoes shall not be replaced prior to lowering and raising of mast. Assemble the sub-structure and assemble the mast. compressor shed. Tug lines should be used for handling loads while lifting / placing. (Refer Annex-2) e. d. mud. Check reeving of bull lines. crane before handling any load. On trailers load should be properly secured with proper chains/ropes during transportation. g. power packs. corrosion. If it becomes necessary to replace the shoes. l. Loads should be assigned to transport fleet sequentially. m. g. Ensure proper rating of truck.Land Rig Classification and Rig Building w. diesel etc. Crane jacks should not be placed on auxiliary equipment foundation. In case minimum clearance required is not met. f. 36.(Fig. Connection of rear and front support floor to the base by means of parallel spaced leg 18. (Fig. l. 1. fix the proper size pins and then release the snub line. should be tied to the side of the mast to avoid entangling during lifting of mast. q. Raise the rear floor along with draw works. Observe casing line of tackle system for any obstruction with monkey board while lifting of mast. So the fall back of the mast should be controlled with the help of hydraulic snubbing system or snubbing line. Fixing of draw-works with the rear floor. Leakage of air/oil. Connect spreader beams & braces. s. Connect spreader beams & braces. b. 4) and erection of mast. n. Unwanted lines like tong hanging lines. and load on weight indicator.1-sky top mast) Assemble sub-base on ground adjacent to well site 26. Observe the lifting mechanism sheaves for any hindrance in rotation. Check the condition of bumper blocks (wooden blocks) and its clamps at crown block. p. Erection of strong back on sub-base 34. Raise the mast with slowest possible speed. m. cat lines etc. Ensure bottom boxes and sub base extensions are fitted properly. o. Any other abnormality If any abnormality observed take corrective actions. During the final stage of mast raising bull lines lose its tension due to fall of the mast towards A-frame. At least two power packs should be available during rig building. t. Fill water in bottom boxes (wherever applicable). (2) Procedures for Assembling: a) Sub-base a. Connect and align rear sub-base boxes to the middle sub-base.Drilling Operation Practices Manual k. 6 .24. Place and align middle sub-base sections of DS (Driller side) and ODS (Off Driller side).3 RIG UP PROCEDURES (A) Sky Top Mast (1) Steps Involved The assembly of rig comprises following steps: . Couple the mast lower end to the front floors. r.30. with respect to center of well. Lift the mast from the horse saddle about 6 inches and hold it there for 5 minutes and observe for: Any cracks on foundation. 2) Raising of front Floor (Fig. Align the mast with A-frame pinholes.28. 40-D/works support floor under structure. & e are mast section). 1 : 12-Mast (a. NOTE: Front sub-base extensions may be removed for ease of operation. c. 2 : 80-sheave. 110-direction of block movement. 28-Rear halve of sub base. 116-Rear floor raising line dead end 7 . Connect front sub-base extensions to middle boxes while raising and lowering of mast only. b. 42Front floor support under structure 38 106 22 116 88 18 112 108 80 26 110 104 12 104 26 32 Fig. 104-casing line. b) Sub-structure a.Strong back Assembly. 32. Install strong back columns and braces on sub-base in DS and ODS respectively and connect strong back spreader beam. 22-draw works Floor . 36-Digonal support to strong back assembly. 24-D/works support floor. 16-Mast pivot. 108-T/block hook. 34-vertical column of strong back assembly. 88-Sheave. 14-trailer. 38-Sheave. 18-Front support. 32 38 20 12 14 22 34 36 16 24 40 40 28 31 26 42 10 30 42 18 12a 12b 12c 12d 12e Fig. 31-sub-bases joining point . 30-Front halve of subbase. d. 112Rear floor raising bull line.Land Rig Classification and Rig Building c. 26-sub-base. 8 . but do not connect crown safety platform. 3: Rear Floor Reeving Diagram 38 106 22 104 120 88 18 114 118 26 12 24 32 108 110 Fig. Install columns of rear floor (DS & ODS) in horizontal position and connect rear floor boxes to it and connect draw-works spreaders. crown block. Install front floor columns (DS & ODS) in horizontal position and connect their boxes to it and then connect spreaders.Drilling Operation Practices Manual STRONGBACK COLUMN SHEAVES TO CROWN BLOCK FRONT FLOOR SHEAVES STRONG BACK BEAM SHEAVES BREAK OVER SHEAVES EQUALIZER SHEAVES SB 26A MALE SOCKET FEMALE SOCKET SB 26B BREAK OVER SHEAVES FRONT FLOOR SHEAVES STRONG BACK COLUMN SHEAVES Fig. Keep the travelling block on Dolly board and reeve the casing line. d. racking platform and Belly board till front floor is raised. Connect mast bottom section with front floor boxes and assemble other sections of mast. f.4: 120-Front floor raising bull line dead end b c. g. e. Connect ladders. Place rotary table on rotary beams. Position the draw-works on draw-works spreaders. electric fittings and ton-mile transmitter to the mast. Place the mast on the horse. 5 and fix dead end connections on both side. Fix Belly Board. j. The mast is rested on trailer as per drawing for front floor raising (fig. i. Racking platform (monkey board) and Crown block safety platform with handrails and other accessories. Raise the rear floor along with draw-works with the self-power of draw-works. k. Use the rear floor raising line only. when front floor is up. 3 and fix dead end connections on both sides. n. Front floor erection or lowering. Connect rear support box to strong back columns and fit the braces of rear floor boxes (DS & ODS). Raise the front floor with the self-power of draw-works. Pin column braces of front floor (DS & ODS). Also connect rotary spreader to strong back beam. b. 9 . STRONG BACK SHEAVES DEAD END CONN TO CROWN BLOCK FRONT FLOOR SHEAVES STRONG BACK BEAM SHEAVES STRONG BACK SHEAVES DEAD END CONN BREAK OVER SHEAVES SB 26C MALE SOCKET FEMALE SOCKET SB 26D FRONT FLOOR SHEAVES BREAK OVER SHEAVES Fig. l.1). Front floor raising Reeve front floor raising lines as per Fig. Ensure all pins are well fitted and all member connections are perfect. when front floor is down. c. The trailer must be allowed to follow the motion of mast. Use the front floor raising line only.Land Rig Classification and Rig Building h. in all conditions. Reeving for raising the floor Rear floor erection or lowering. 5 : Front Floor reeving diagram Mast Erection a. fit it to the pedestal in rear floor boxes. After front floor being elevated connect front floor support boxes to strong back. Rear floor raising Reeve rear floor raising lines and fast line (d/works) as per Fig. Connect all other joints with strong back beam. o. Use front floor raising line only. m. Assemble (or expand if already fitted on mast) A-frame and swing its rear legs. Now bull line can be removed. B. 12 6. 6 j. g. Here bull 48 32 line will be slackened. exterior flooring. Note: Remove front sub-base extension before start of drilling operations. As the mast 34 56 26 pinholes align with A-frame holes. Slowly raise the mast till it 52 42 44 36 is near to vertical. Center the mast before drilling. If required provide adequate shims for centering. After alignments. Racking finger and diving board should be secured to 16 hand railings of monkey 24 18 54 board. so 40 control the mast fall back 42 with snub line. (i) Jacking and lowering shall be done on one leg at a time. Install all sub-structure accessories. 58 40 h. k. Reeve bull lines as per Fig. pass bull line through equalizer 20 pulley and connect their ends. Then tighten casing 64 line for keeping Traveling Block in elevated position. Attach front sub-base extension before lowering the mast.Drilling Operation Practices Manual d. loosen nuts only. tighten the nuts. Use crane to lift traveling block to 60 the required height. handrails etc.P. 22 62 f. pin up mast to Aframe. e. 7) a. 10 .(Fig. After raising floors pull Travelling Block and Dolly to within 40’-0" approximately 66 from the center of well.O. by an 8" drill collar hung from T/ block as a plumb. such as adjustable flight stairway. (ii) No bolts shall be removed from shoes. trolley beams Ramp and stair combination. Fig. (3) Procedure For Rigging Down Mast Lowering : . Attach necessary snub-line (in crown block) to protect the fallback of mast. i. Reeve Bull line and attach snub line for initial motion of mast. 600 LBs 00 86 s LB C. e. Remove all sub-structure accessories and items added after erection of mast. e. which might interfere with lowering of mast. 137600 Lbs 73’-3” VIEW A-A Floors Lowering (either the front or rear floor can be lowered first). Whichever floor is lowered. d. Reeve floor raising line as per the requirement of floor (Prefer front floor. first remove its column braces. b. c. Place mast on horse. Lower floor cautiously and trailer must be allowed to follow the mast forward movement. The A-Frames are normally transported folded into the Bottom Boxes. box pins and spreader pins. Spreaders. a. f. Erect A-frame on sub-base or bottom box. (B) Branham Mast Sequence one (Fig. 7 Belly Board then place mast on small stand.0” TO 200’ b. (ii) Do not remove any braces or pins of the floor that is not ready for lowering. and Fig. APPROX 170’ .G. 11 . f. Pin and Bolt Front Extensions & Rear Extensions to Bottom Boxes. c. g. Braces and ‘A’ Frames a. Place DS and ODS Bottom Boxes on Center Line using Front and Rear Spreaders and Braces to ensure that the Bottom Boxes are correctly positioned. Remove crown block safety platform. Guide floating sheave (in Aframe) to align with fast line during lowering. Remove interior and exterior flooring and doghouse. Do not allow any slack on Bull line or fast line before and while lowering the mast. monkey board. Rest mast top section on trailer. c. Swing A-frame on mast). Disengage bull lines and place T/block on dolly board. 8) (i) Bottom Boxes. CAUTIONS (i) No floor raising line slack shall be allowed before or during lowering. d.Land Rig Classification and Rig Building b. with Hook approximately 60 ft. The Draw-works Support Braces are normally transported pinned to Bottom Boxes. Ladders & Tong Counterweights a. Crown. d. Place Mast assembly stands (small stand) under lower sections near the top and pack up as necessary. Check free rotation of roller. Attach lines to Tong Buckets and take lines through to the Brackets on the middle section. Assemble Mast middle sections of DS and ODS and middle section spreader. Pin Mast stub section Spreader to stub sections after mounting Fast-line Roller on the two pillow blocks supplied. Pin Front B. Pin Mast Bottom sections to Bottom Boxes and Pin to Setback Spreader of DS and ODS. c. j. Ensure that the Top and Bottom Pin connections are well greased. pin to lower section.P. Lift section. Position Setback Spreader on Bottom Box Extension Stools. Hook and equalizer. Assemble Mast lower sections of DS and ODS to lower section Spreader. Place Traveling Block. and pin to Front Setback Legs. Trolley Beam to Setback Spreader of DS and ODS.O. 8) (ii) Setback. 12 . move stands to the front of middle section Braces. reeve snatch Block and tie line off at a convenient point on Stub Section.Drilling Operation Practices Manual C A B D Sequence one “A” Frame Erection Fig. Position Front Setback Legs on Support Arms on Bottom Box Extensions and Pin to Bottom Boxes of DS and ODS. lift slightly to release Mast assembly stands. g. h. from centerline of Well. f. Sequence Two (Fig. i. b. lift section and pin to stub section and pin in lower section Braces. Mast. e. Ensure that the top and bottom Setback Leg Pin connections are well greased. 8 d. Racking Board. Assemble flooring extension. from the centerline of well before assembling the Mast Lower Section to the Mast Stub Section. Using shortest bull line connect open socket to bull line Anchor on Lower Section. Reeve casing line into tackle system with the help of wire rope. Mast Raising and Snubbing (Place Traveling Block. a. d. 13 . pass under vertical Sheave round horizontal Sheave on Stub section replacing both line guards then take bull line through equalizer (To fit bull line to equalizer it will be necessary to remove Sheave and shaft from the yoke). Pin draw works extension to draw works Support. kink should not come in lines. Position draw works Support on Bottom Box and rear Extensions and pin to front and rear support columns. Normally the Mast top section is transported with the Crown block attached. p. lift slightly to release mast assembly stand and move stand to front of upper section. Pin Front draw works Support Column to Bottom Boxes of DS and ODS and bolt together with Spreader. Fit Core line Sheave. Grease pin connections. Connect air and Brake water systems. Lift Crown block with top section and pin to upper section. Using the longest bull line connect open socket to bull line Anchor on Mast section and pass line over A-Frame Sheave. lift section and pin to middle section. Assemble Mast upper section of DS and ODS. lubricate all Sheaves and ensure they rotate freely. Fit ladders to DS from Stub Section to Crown. Fit Standpipe. Set draw works and bolt down as recommended by equipment Supplier. then reeve as above connecting Open and Closed Socket together. fill water tanks in bottom boxes of DS and ODS. Place equalizer on Hook. o. b. (iii) Drawworks etc. Braces and handrails to Crown Frame. c. f. d. b. Lift Mast at Crown with the Crown Pad eyes and place it on (16’0" high stand) horse under top Section near the Crown Frame. Clamps attached with ‘U’ Bolts to the lower and Stub Section of the Mast of ODS. Fit draw works flooring & Wing Flooring. Check that the Standpipe does not interfere with Setback Spreader when raising the Mast. to Crown Frame. Grease pin connections. If interference occurs remove Standpipe before Raising the Mast. Grease pin connections. Place bull line between Side plates and then slide Sheave back into position replacing Shaft and securing bolt. etc. Pin rear draw works Support Columns to Bottom Boxes of DS and ODS and bolt together with Spreader.) a. m. e. Special care must be taken when uncoiling bull line. g. n. l. Hook and Equalizer at approximately 60 ft.. c. (iv) Mast Reeving. replace rear line guard roller. Hook up weight indicator.Land Rig Classification and Rig Building k. Before reeving. and fasten fast end to draw works drum. Pin Rotary Support Beam Unit and Rotary Floor Support Units. Check that all pins have been fitted with Safety clips. swing and tie back Diving Board to handrails and open gates at Drill Collar fingers to the maximum. Using the Control Unit retract Rams and Continue to Spool in slowly with draw works. 9 e. Test Cylinders to ensure that both Rams move simultaneously in the same direction. have been removed from Mast and Crown. Before Raising the Mast: Check that the Bottom Section and Setback Legs pin connections are well greased. Check that all the Line and bull line has been reeved correctly. h. During this operation the Mast will ‘Break over’ its center of gravity. Continue retracting 14 . Check that all loose tools etc. Any other abnormality If any abnormality observed take corrective actions. Connect Hydraulic Supply to ‘Quick connect’ Lines on A-Frames of DS and ODS. Leakage of air/oil. f. Hook up BOP chain hoists of DS & ODS. lift the monkey board and pin it to Mast Middle sections at selected height for operating position.IWRC) ∅ “A” Frame To Draw works Reeving Diagram For 142’ MAST Fig. Check that all bolts have been tightened. Assemble monkey board and skid under Mast. Raise Mast slowly using draw works power until Mast touches Snubbing Noses of DS and ODS. g.IWRC) Single Line or nch le A g Sin “A” Frame 238 x 164’ SLING LINE (EIPS . Fully extend Rams ready for Mast Snubbing. Pin support Brace to Mast middle section.Drilling Operation Practices Manual 238∅ x 144’ SLING LINE (EIPS . j. i. Lift the mast from the horse saddle about 6 inches and hold it there for 5 minutes and observe for: Any cracks on foundation. Check that all line guards have been fitted correctly. 11) (v) Drawworks Raising a. Pin the mast with AFrame on both sides. 15 . 10) k. Sequence Three (Fig. 10 Rams. using soft line from Catheads pull Loop in bull line behind A-Frame while continuing to lower Travelling Block.Land Rig Classification and Rig Building Fig. Attach Ramp to Setback Support. pass bull line over draw works Sheave of DS and ODS. partly Lower Traveling Block. (Fig. Change bull line DS and ODS from round to over top of A-Frame Sheave. while taking up slack with Hook until pin connections line up. Remove rear Line Guard on A-Frame Sheaves. Replace Line Guards and Take up Slack with Hook. Slowly raise draw works with its power. Check that Draw works Column Pins have been well greased All Bolts have been tightened. (vi) Doghouse Support and Misc. b. Raise Travel Block and hang equalizer pulley and bull line in the Mast. d. Swing up draw works Lock Brace of DS and ODS pin and fit Safety clips. remove from Hook. Remove bottom box rear extensions and also remove bottom box front extension (DS) for entry of BOP stack. drill floor panels and other miscellaneous items. Items a. Lower Traveling Block and remove bull line from draw works Sheaves of DS and ODS. Or Lower to Drill Floor. c. All draw works and stub section line guards have been fitted.REEVING OF DRAW WORKS To Sin gle Lin eA nch or Fig. The A-Frame Line guards should not be fitted at this stage. e. remove and store Equalizer pulley and bull line. Check that the bull line is reeved correctly. All pins have been fitted with Safety Clips.Drilling Operation Practices Manual To Block SQUENCE THREE . 11 b. 16 . Hookups dog house support. Pin all Rotary and Floor Beams to Setback and draw works. ensure that the Rotary Beam connections line up and pin Rotary Beams to Setback Spreader. P. Center the mast before drilling. Especially areas adjacent to end connections should be examined closely for any corrosion. Trolley Beams. (i) Jacking and lowering shall be done on one leg at a time. (2) Corrosion: It is related to time and atmospheric conditions. Points to be kept in mind for inspection & replacement of sling lines: a. To lower Mast remove pins and extend Rams of snubbing unit while lowering the Hook. IMPORTANT Remove rear B. continue to lower mast onto Mast horse. Tighten block and recheck bull lines. c. (ii) No bolts shall be removed from shoes. b. g. i. Because some times line are replaced early due to incidental damage and some times lines are used beyond the time when they should be replaced. which might interfere with the Lowering procedure. so it should be replaced. SLING (BULL) LINE INSPECTION AND REPLACEMENT There are three factors. d. k. Cautiously lower the draw works. (vii) Lowering Sequence a. and round draw works Support Sheaves of DS and ODS and sockets are correctly pinned to Lower section Mast of DS and ODS. Continue section D to A in reverse order for further de-rigging. Remove any additional items added after Erection. (1) Wear due to operation: it is a function of the number of times the mast is raised.O. maintaining very little slack as Mast ‘breaks over’ its Center of Gravity. Unpin and lower draw works Lock Brace. Re-hook Equalizer pulley with bull line. (3) Incidental damage: It may occur at first location or any other location. Connect Hydraulic’ Power to snubbing unit of DS and ODS. Tighten block and check Lines. Make sure the bull lines are round A-Frame Sheaves of DS and ODS. l. Hoists and Trolleys. Reverse Section F. After alignment. making sure that the bull lines pass over the A-Frames Sheaves of DS and ODS. e. j. f. h. loosen nuts only. b. Unpin Rotary Beam Unit at draw works only. tighten the nuts. by an 8" drill collar hung from T/ block as a plumb. 17 . The Lowering Sequence is the reverse of the Raising Sequence. IMPORTANT Change Bull line of DS and ODS as shown on section D. If required provide adequate shims for centering. Unpin Rotary Floor Beams at Setback only.Land Rig Classification and Rig Building c. There is no way of judging the remaining strength of a rusty rope. Data used for replacement does not give any clue. The main sequence is as below. Replace Line Guards at Stub and draw works Sheaves. which may limit the life of sling line. Reeve bull lines as Section E. In coastal areas sling lines left hanging in the mast may become corroded and found unfit for further use. Replace Line Guards. m. But again this will not preclude the necessity of careful inspection. It is possible to establish sling line life expectancy in terms of number of locations on which it was used. Replacement of lines based on normal life expectancy will provide some degree of safety. A line with any material reduction of metal from abrasion should be replaced.Drilling Operation Practices Manual c. Sling line should be maintained in a well-lubricated condition. as long as a set number of months were not exceeded. d. crushing. 18 . e. or any other damage resulting in distortion of rope structure should be replaced. The object of rope lubrication is to reduce internal friction and prevent corrosion. The field lubricant should be compatible with the original lubricant. but due to which there should not be any laxity in sling line inspection. A line showing with broken wires should be replaced. A line showing kinking. Continue assembly of mud system TPT:Cat walk – 1 Dog House – 1 HP Line – 1 Mast & substructure left over items – 1 Mech./ Elect. .1 Dismantling of mast & substructureTPT: Mast section – 5 Set back – 1 Draw works – 1 Draw works platform – 1 Bottom Boxes – 2 Tubular – 2 Other loads like desander. Shale shaker . two power packs.Land Rig Classification and Rig Building Annexure-1 RIG BUILDING PLAN BHEL Electrical Rig / Sky Top/ Brahnam : Day wise activities and requirement of fleet: Job to be done D1 Cleaning front side of mast. substructure.1 Assembling of substructure and mast. silt. and one diesel tank/water tank/hopper. Bunk Houses –2 Store Rooms . Pump – 1 Mast & structure – 4 Monkey Board – 1 Belly board .3 Crane Type 1 (OS) Type 2 (OS) Type 2 (NS) Days 1 2 1 Trailer Load 14 D2 Type 1 (OS) Type 2 (OS) Type 2 (NS) 1 2 2 17 D3 Type 1 (OS) Type 2 (OS) Type 2 (NS) 1 2 2 14 D4 Type 2 (OS) Type 1 (NS) Type 2 (NS) 2 1 2 9 19 . dismantling of mud system/mud pumps.Loads: Power pack – 2 Diesel tank – 1 Water tank – 3 Water tank Skid –1 Hoppers skid – 1 Reserve tank – 4 BOP Control – 1 Trip Tank -1 Lowering of Mast.1 T/Block etc. desilter. dismantling of mastTPT: Mud pumps – 2 Power Pack – 2 Diesel tank – 1 Utility (Compressor) house – 1 Mud tank –3 Super charger with skid – 1 Degas/D. removal of bull lines. Choke & Kill assembly and other left over Tubular -2 Lift mast on horse & fix Monkey Board. TPT: DIC Bunk house – 1 Staff Bunk House – 1 PCR – 2 BOP. 4. NS – New Site. fixing of d/floors. Mud system to be completed TPT: Complete transportation from old site Checking of power and raise the mast. For sky top mast one more day is required due to its design. Preparation of spudding Type 1 (OS) Type 2 (OS) Type 2 (NS) 1 1 3 6 D6 Type 2 (OS) Type 1 (NS) Type 2 (NS) Type 2 (OS) Type 1 (NS) Type 2 (NS) Type 2(NS) 1 1 2 1 1 2 1 6 D7 D8 Abbreviations:. 20 . 3. Rig movement is within the radius of 20 Km. Fitting of cat walk/ inclined ramp. Rig equipment should be transported on above priority so that it is unloaded at appropriate place at new site. pipe rack dog house. belly board. Type 2 crane capacity – 30-40 Ton 5. Note: 1. 2.Drilling Operation Practices Manual Job to be done Crane Days Trailer Load D5 Assembling of mast completed & casing line reeving and assembly of mud system. Type 1 crane capacity – 75 Ton . Also 1 Truck is needed for miscellaneous items as per the requirement of rig In-charge. during good weather condition. HP lines.OS – Old site. Type of rig E-760 Type of Line Bull Line Description 2 3/8" Φ. E-2000 Bull Line Floor Lifting Line (i) (ii) (iii) (iv) (v) Snub Line For Front Floor Use – (iii) + (v) For Rear Floor Use – (iii) + (iv) Both open end Both open end Both open end One open end & One closed end One open end & One closed end Both open end Both open end BRANHAM MAST SN 1. 6 × 37 classification. E-1400 Bull Line 3. 6 × 49 classification. IWRC. 6 × construction. RHRL 142’ 1 1/8" Φ. IPS. 194’ (ii) 2 3/8" Φ. IWRC. IWRC. RHRL 90’ ½” Φ. IWRC. 6x49 construction. 6x49 IWRC. 6 × 37 classification. RHRL. EIPS. 144’ Remarks One Open socket & One closed socket. 6x49 IWRC. IWRC. 6x49 construction. IWRC. 6x49 construction. (ii) 2 3/8" Φ. Type of Rig E -760 Type of Line Bull Line Description (i) 1 ¾” Φ. RHRL 127’-6" 1 ¾” Φ. IWRC. EIPS. RHRL. IPS. 6 × 37 classification. EIPS. EIPS. IWRC. 6 × 37 classification. 6 × 37 classification. 6 × 37 classification. EIPS. IWRC. IPS. 6x49 construction. 6 × 37 classification. IWRC. 6 × 37 classification. 6x49 construction. IPS. IPS. RHRL. RHRL 150’ 1 1/8" Φ. 6 × 37 classification. EIPS. RHRL 126’ 2" Φ. IWRC. Remarks Both Open end Floor Lifting Line (ii) One open end & One closed end One open end & One closed end (iii) (iv) (v) 2. 6x49 construction. 6 × 37 classification. RHRL. IWRC. 6x49 construction. 135’ (i) 2 3/8" Φ. 6x49 construction. 6 × 37 classification.Land Rig Classification and Rig Building Annexure-2 SIZES OF DIFFERENT LIFTING LINES SKY TOP MAST SN 1. 6 × 37 classification. RHRL 147’-6" 1 1/8" Φ. 6 × construction. 6x49 construction. RHRL. IWRC. 6 × 37 classification. RHRL 90’ 2" Φ. IWRC. 6x49 construction. RHRL. (i) (i) 37 classification. 6 × 37 classification. RHRL 163’ 1 1/8" Φ. 145’ (ii) 2 3/8" Φ. IPS. Both Open end socket One Open socket & One closed socket Both Open end socket One Open socket & One closed socket Both Open end socket 2. 6x49 construction. EIPS. RHRL 142’ 1 1/8" Φ. EIPS. 6x49 construction. RHRL 163’ 1 1/8" Φ. 6x49 construction. E-2000 Bull Line 2 3/8" Φ. 6x49 construction. EIPS.164’ 37 classification. 6 × 37 classification. IWRC. 175’ 21 . EIPS. EIPS. or under tow. & type of persons to jack down and move drilling units are: NUMBER 1 1 1 1 1 1 1 1 2 6 POSITION/LEVEL Move Supervisor Tool pusher Driller Rig Engineer Electrician Mechanic Welder Derrick man Motorman Roughnecks or Roustabouts Three men assigned to each yoke house TASK DESCRIPTION In charge of operation Assigns individual responsibilities. All personnel operating the unit’s equipment should read the “Information and Operating Instruction Book” published by the manufacturer. Check the emergency power plant and all emergency systems at least once a week. and Motorman responsibilities and stands by to assist Stands by below deck to take action to correct any electrical malfunction Stands by below deck to take action to correct any mechanical malfunction Assures that welding equipment is in good condition and that welding supplies are on board 2.Drilling Operation Practices Manual CHAPTER. Mechanic. or 3 before the red “FIXED PIN OUT” light on any of those columns comes 22 . when afloat. 2. 2. If rod end pressure reaches 2500 psi on columns 1.2 JACKING DOWN OPERATION 1. monitoring rod end pressure gauges and “FIXED PIN OUT” light on all columns. Emergency repair supplies should be on board. is jacking console operator Maintains proper clearances and communication with console operator Assigns Electrician. This book gives specific instruction on the operation and maintenance of the unit’s machinery. Lower yokes (raise platform) slightly with master jacking lever.2 OFFSHORE RIG Independent-leg units and mat-type units are designed to withstand certain operating limits for (1) load capacities (2) afloat conditions and (3) elevated conditions. and be inspected periodically for quantity and condition. Jacking and moving procedures must take into account the capabilities and limitations of the unit when sitting on bottom. 2. Newly classed ABS jack up rigs have emergency power sources.1 PERSON ON BOARD: Recommended Nos. Switch fixed pins to “OUT” on all columns. Any attempt to exceed these limits will jeopardize the safety of the crew and the unit. jacking should be stopped until the cause of the problem can be determined (such as a stuck fixed pin. 5. 6. 4. switch all the fixed pins to the “IN” position on the console and continue jacking in the same direction. etc. Before the platform enters the water. If difficulty is encountered and the mat will not pull loose with two feet excess draft. six-foot stroke. This information should be obtained by telephone from personnel in each jack house. switch yoke pins to “OUT” position on the console. When all fixed pins are confirmed to be “OUT. a maladjusted limit switch. raise the mat the desired clearance (bottom to bottom) for the move. 3. This is accomplished by holding the override button down in the lower left corner of the console before the end of the last 4’6" stroke is reached. NOTE : The automatic leveling device incorporated within the jacking system should keep the three yokes in line to: 1 inch relative to column 1 during the power stroke. the derrick skid unit may also be moved to expedite the adjusting of the LCG. override the automatic shutdown at columns 2 and 3. The piping for this system terminates in column 1. With this amount of excess buoyancy. about six inches before the end of the return stroke. If it is desired to raise the mat up to the uppermost position (2’6" clearance between the molded platform bottom and mat deck). The method for adjusting the platform LCG to coincide with the floating longitudinal center of buoyancy (LCB) will normally be by shifting drilling water only. indicating that all fixed pins are in. stop jacking until the fixed pin (or pins) which may be stuck is disengaged.). and continue jacking until all yoke pins are “IN” as before and confirmed. provisions have been made for water to be jetted from the underside of the mat. should come on before rod end pressure starts to decrease. Confirmation of the pin situation from each column should be obtained with every pin change before proceeding with the jack-ing. 23 .Offshore Rig on. 3. Repeat steps 2. as can be observed by a decrease in platform draft and head end pressure on all three columns. watch both the “FIXED PIN IN” lights and the rod-end pressure gauges for all three columns. The green “FIXED PIN IN” lights. and use the master jacking lever to raise the yokes (transfer the platform load to the fixed pins). During the power stroke and when about 10 inches from the end of the stroke. As the end of the stroke nears. Switch yoke pins back to the “IN” position. a platform weight summary and platform longitudinal center of gravity (LCG) calculations are to be made. and 4 as required to bring the platform down to the water. These pins will not move all the way in immediately as they are not centered over the respective pin holes. Continue jacking down until platform draft exceeds the calculated floating draft by two feet. the mat should free itself from the sea bottom. Confirm yoke pin disengagement and then push the master jacking lever to the “YOKES DOWN” position for the return stroke (six feet). Using the same action it took to lower the platform. If there is an indication of pressure decrease before a green light activates on any one column. allowing the yoke pins to disengage themselves from the columns. but the “FIXED PIN OUT” lights will go off and the pins will be loaded up against the columns ready to go into the column pin holes as soon as they become aligned. the aluminum wedges can be removed.” use the master jacking lever to raise the yokes (lower the platform) in unison one full. This is required for determining the amount of drilling water to be shifted in the platform in order to obtain even keel conditions when the mat is free and the unit floating. When all fixed pins are “IN” and confirmed. again. During the stroke. If feasible for the particular drilling unit and location. All mud handling equipment should be serviced including. all plugs. gauges. 24 . settings are specified in the manufacturers recommendations (pressure test to be recorded on a chart). 3. Service all standpipes.1 Procedure Conduct the shallow gas survey 1. 3. 2.Drilling Operation Practices Manual 7. Check the calibration and function of all drilling instrumentation e. The shale shakers should be fitted with the correct size of screen for the top-hole section as per requirement. GENERAL NOTES FOR SERVICE AFLOAT 1. 2. caps. and only when. desander. when in actual use. 6. conductor pipe or BOP tensioners. 6. and only. When sufficient clearance between the bottom of the mat and sea bottom exists. Rig movement and deck-loading conditions may determine the scope of work that can be carried out during rig move and positioning operations. vents. both afloat and elevated. If after a period of time the pressure decreases in the rod end of the cylinders. they are necessary for system operation. BOPs. chick sans. they can be repressured to 1500 psi.g.g.3 RIG MOVE AND PRELOADING Preparation for drilling the next well should be carried out while the rig is moving between wells or locations. the manhole cover must again be bolted closed. and companionways must be secured watertight while the unit is afloat except when in actual use.. choke and kill manifold valves. Manhole covers into the inner bottom tanks must be bolted closed at all times unless access to a tank is necessary. etc. 5. hoses. shale shakers.g. Immediately upon completion of each job requiring access to any tank. Service / inspect all tensioning and BOP handling equipment e. chart records. Reset relief valves (pop offs) of the mud pumps depending on the liner burst rating as required for the liner in use. Perform fluid end inspections on the mud pumps and change liners as specified in the well programme. except during the actual discharge (dumping) of the preload. all manifold valves and all bilge control valves in the tank piping systems must be closed unless. This will prevent relative movement between mat and platform due to wave action.3. valves. mud cleaner. 4. All watertight doors and thru-bulkhead vents are to be closed. 7. All sounding tubes must be capped except. pressure up the rod ends of all cylinders (lower the yokes) with both the fixed pins and the yoke pins engaged and the yoke down to about 1500 psi. 2. 4. All watertight hatches. desilter and mud mixing equipment. safety valves etc. Perform inspections of all BOP equipment e. If possible pressure test these items with water. at filling points must be closed. 2. and conduct pressure test of these if required. 5. Also. While the unit is afloat. The preload dump valves must be closed at all times. Install any drill floor access stairs. Ensure that all the relevant fishing equipments are available. Secure the cantilever and drilling package to prevent any movement during the well. Making up and racking stands during drilling operations is not permitted. 3. 2. the bushings not be removed until the shoe joint is ready to be run through the rotary table. 2. BOP and diverter operations be in place and followed. Drilling consumables for the first hole sections should be on location including but not limited to wellheads. as per the operations manual. Once skidding of cantilever and drilling package is complete check that rotary table is positioned directly over the proposed well centre. All drilling tools supplied by the Client should be checked for compatibility with the Contractors equipment (e. .2 Skid Cantilever and Rig Up Once the rig has been pre-loaded and jacked up to the final air gap. certified and in good working order. 10. drill bits and nozzles of various sizes stabilizers. 12. pick up. Prepare the BHA.Offshore Rig 2. 9.3. walkways and v-door ramp if removed for skidding. 8. with the correct properties as specified in the drilling programme. associated with the removal and replacement of rotary table components. and permissions obtained from the OIM. 1. It also verifies that all equipment and materials required for the surface hole section are on board. This should include both drilling and fishing tools. 25 . Specified quantities of mud chemicals. When rigging up to run 30" and 20" casing. drift and rack enough drill pipe to complete the surface hole sections. hole openers and reamers. 7. Minutes of these meetings be DOCUMENTED. running surface casing. Sufficient spud mud. casing and its handling tools. Specified quantities of cement and additives should be on location. A pre-spud meeting be held with all personnel involved in the operation. are suspended for any period of time. 11. Consult with the Client and service personnel to verify the wellhead systems and stack up dimensions.4. Install any safety equipment (handrails) and adjust / install mud return flow line. 5. 3. During skidding operations position watchmen to ensure that the skid beams / package does not contact any of the installations/ fixed equipment. A Rig Specific Procedure for handling the Master Bushings during drilling.4 SURFACE HOLE PREPARATION This phase of the process ensures that the rig is fully operational prior to the actual spudding of the well. The first of which is to skid the cantilever and drilling package out to the desired operating position. 4. Service hoses. drilling operations may commence. 2. including barite and bentonite. 2. A hole cover be in place when ongoing activities. should be on location. electrical loops and cable trays will also be monitored to prevent damage to them. correct tool joint connections). should be mixed ready for use.g.1 Procedure 1. 6. 2. Should the desired shoe depth not be obtained before a pre-determined maximum blow count per foot of penetration or refusal.1 Procedures 1. 2. Do not allow the hammer support slings to take load while driving. 5. block. drive pipe or structural pipe are all terms used to describe the first string of casing to be set. 9. 8. 10. 6.2 Drive / drill procedure. tag the seabed and commence driving at slack tide. This may require the use of 30" elevators. and crown prior to and after the hammering operations for any loose objects. To ensure the 30" is vertical. 26 . All lifting gear on the hammer assembly will be checked for rating and certification. 15. top drive. 14. It allows the diverter system to be hooked up. While drilling limit the ROP to prevent overloading of the annulus and do not drill further than the shoe. 7. Once maximum bottom penetration is achieved from the weight of the 30" alone. If casing is to be run using lifting eyes then check the slings shackles are available and are certified to the appropriate load rating. Check all conductor handling equipment for certification and compatibility with the size of casing to be run. 2. however specific requirements will be issued in the well programmed. Initially it will allow a circulation system to be set up taking returns back to rig. 2.5. Check that there is sufficient oxygen and acetylene equipment ready to cut the lifting eyes. The casing size referred to in this section is 30" as it is the most common. Record the rotary to seabed measurement and weight of 30" from rotary to seabed in the IADC drilling report. Paint the shoe joint white to assist with ROV observation. Sizes of casing vary depending on the Clients requirements and well plan. All shackles will be secured with split pins and checked periodically during the operation. 4. Rig down and layout the hammer then run in with a 26" bit and BHA. then it may be necessary to implement a drive / drill procedure. Ensure that hammer operator is also monitoring the support slings. It also prevents surface sediments from sloughing and protects against rig foundation failure (washout). Check the derrick. allow the hammer and chaser joint to rest in the top of the 30".Drilling Operation Practices Manual 13. Support the weight of the 30" while drilling using the conductor tensioning/support system.5 CONDUCTOR PILING (DRIVING) Conductor. 16. Do not set slips on the 30" once driving has commenced. If available the ROV will observe seabed for obstructions prior to the 30" penetration. The 30" may be driven (hammered) from the seabed to a desired depth / refusal or to a pre-determined blow per foot count. is situated next to the controls and is able to stop the hammer blows should the need arise. 1.5. Measure the conductor pipe (measurements to be checked by clients representative) to determine the correct footage of hole to be drilled. continue to watch them and slack off on the blocks simultaneously. 3. 2. 3. Run the 30" casing to one joint above the seabed then rig up the hammer and chaser joint. pad eyes or a load ring on the 30". This reduces meta. development drilling on subsea templates and subsea completion of single wells. its response to hydrodynamic forces is excellent. keeping only the columns in contact with wave/ swell action. This way. risers. However. They are suitable for water depths from 30m . However.Offshore Rig 4. They are designed to minimise the impact of hydrodynamic forces on the vessel thus greatly reducing the heave as well as roll and pitch. This results in a drastically reduced deck load capacity as compared to a drillship. On the other hand. if equipped with dynamic positioning system are independent of water depth and seabed conditions. Otherwise. The variable loads like casings. The 30" will not be driven if shallow gas is a potential problem unless the formations have been drilled and proven to be gas free. 2. The most popular is rectangular design in which there are two bottom hulls each supporting 3 to 4 columns on which working deck is placed.) is a major handicap as we venture in deep waters. anchor moored type ships are not suitable for harsh environments as their response to hydrodynamic forces is not as good as compared to Semis. They are suited in logistically difficult areas as normally they have high load carrying capacities. they can be deployed on a location where jack-up operations is not possible due to soft/loose seabed having a gradient more than the that required for Mat type jack-up. This keeps the CG at much lower level and imparts more stability to drillships. But they are more prone to capsizing as the centre of gravity keeps on moving up with the addition of load on top deck during drilling operations which is inevitable. i) Drillship Drill ships are suitable for water depths 20m-3000m plus.6 FLOATERS Floaters are the drilling vessels that keep floating during the entire course of drilling and other operations. floaters. Drillships are normally cheaper than semi-submersibles for moderate environment areas. drill ships are more stable in terms of survival and station-keeping in adverse weather conditions as their CG is lower. are stored on a drill ship at much lower level as compared to a Semi. In off-shore. Around half the length of columns is also submerged in water.2500m. Also in the water depth range of jack-ups floaters also provide a solution to some problems like punch through locations. Semis can be triangular. The pontoons are much below the surface of water and drilling deck is raised high up. They can carry out exploratory drilling. the initial investment and the operating cost of floaters are much higher than that of a jack-up rig. tubulars. They are more suitable in areas with rough sea conditions and harsh environ-ments including icy seas. Semis are costly in operations but are a better choice for areas where harsh weather prevails for a longer period during the year. ii) Semi-submersibles or Column Stabilised Rig These rigs are floater type rigs in which the drilling deck is mounted on columns which are supported by submerged pontoons or hulls. Therefore in harsh weathers. downtime tends to be much more on a drill ship than a Semi. Also. rectangular or pentagonal type. drilling is much economical with jack-up rigs but their limited water depth capability (generally 400 ft. Drill ships are suitable for drilling in deeper waters beyond the limit of Jack-ups. mud chemicals etc.centric height and thus the righting lever & tendency to capsize increases. 27 . They are very costly to operate as fuel consumption is very high for DP system. BOP stack (generally 18 ¾” bore) is lowered and installed at the seabed after 20" casing and once installed all the subsequent operations right up to abandoning of the well are carried through the stack . or places with subsea pipelines. B. 2. 26" hole is drilled with seawater/mud and returns to rig. or lower water depths with harsher environments or locations which may require quick movement like frequent storms. A string of risers about 20" bore is used which needs a special tensioning system to maintain constant tension for heave compensation. annulars and Kill/chocke line valves. Turret moored rig are capable of reorienting themselves as per weather conditions using its turret and thrusters. Dimensionally this stack is much smaller in size and has less no.8 DIFFERENCE BETWEEN FLOATER AND JACK UP RIGS FLOATER Vessel keeps floating during the entire course of operations and is subjected to various movements like Roll. A single riser pipe is used. 30" casing is piled in to the seabed. Not required 28 .Drilling Operation Practices Manual 2.It has more functions and requires special handling system. 26" hole is also drilled (generally) with seawater with no returns to the rig. of rams. Self Propelled. ANCHOR MOORED : 8. Every casing string lowered in the well is brought up to the surface (except liner casing).7 STATION KEEPING A. New ships are being designed which will be capable of anchor mooring in approx. Suitable for water depth upto 1500m. . BOP control system is much more complex for remote operation and redundancy. communication lines etc. 30" casing is lowered in a drilled 36" hole with seawater with no returns to the rig. Every casing string lowered in the well is terminated at the seabed (except liner casing). The BOP stack (generally 13 5/8") has to be removed for the installation of each section of well head. 2400m of water depths. DYNAMICALLY POSITIONED : Station keeping is done by DP system though anchors are also normally provided. Pitch. They are self propelled and are suitable for areas with water depths greater than 1500m. which impede operations. BOP control system is same as that is used on land rigs. 9 or 10-point mooring. Heave etc. Drill String Motion Compensator is used to maintain WOB JACK-UP Once the vessel is jacked-up it stands firmly on the ocean floor like a fixed platform. Risers with a pin connector (without BOP stack) might be run with the diverter on top if shallow gas sands are likely to be encountered. • Final adjustment of heading and position is now made with the help of instrumentation. • The running of anchors begin with the help of anchor handling vessel. the site is surveyed and a marker buoy is dropped by the survey boat on the location for easy identification (In shallow water depth). The anchors are laid as per a predetermined pattern. The diverter is required because the well can not be shut in on the 30" casing. • The process of pulling of anchors begins for an anchor-moored vessel while a D.P. the same is switched on to move into the position. vessel moves to the next location instantly. • The vessel moves to the new location. During these operations there are no returns of circulating fluid to the rig. • The subsequent operations for drilling 13 3/8". This casing is strictly for the structural support and will not sustain any pressures. • The vessel is now ready to spud the well. pre-tensioned and then slacked-off to the operating tension values.9. below the well head Either explosives or mechanical cutters may be used.9 5/8".. 2. • The vessel moves into position and the heading is adjusted depending on the prevailing sea condition. • The 36" hole is drilled 80 to 200 ft. The casing is cemented in place • The 18 ¾” BOP stack is now run and latched on to the 18 ¾” well head. 7" phases and the well testing are carried through the BOP stack • After testing. penetration test and exploration test to confirm shallow gas presence is carried out 50-200m down stream of released location as detailed below: 29 . • A temporary guide base is lowered to the seabed during the low tide with the help of guidelines. In this case a pilot hole is drilled and then enlarged to 26" • 20" casing is run with 18 ¾” well head on top with a running tool and drill pipes. the well is often plugged and abandoned by squeezing cement into the perforations used for testing and spotting the cement at given intervals in the casing as the drill string is pulled out from the well. below the mud line and 30" casing is run and cemented in place.1 Pre-spud Activities Once anchors are laid and pre tensioned to require load in case of moored rigs or positioning of DP rigs at desired location. A permanent guide frame is secured with 30" casing head while running casing to guide the BOP stack on the well head. • The well head equipment including the TGB and the PGB is retrieved by cutting the casing about 10 ft. or • If the vessel is equipped with dynamic positioning system.9 SEQUENCE OF DRILLING A WELL FROM A FLOATER: • Once a location is released for the deployment of a floater. below the mud line. • 26" hole is drilled for a 20" casing that is set about 1000 ft.Offshore Rig 2. • The riser and the BOP stack are retrieved. Gently tag seabed-using ROV and calculate KB to seabed depth with tide correction. Lower drill string until the bit is lost from view. • Cementing unit should be kept in readiness. This depth is known as murk line. Prediction of shallow gas by means of geo technical tools is not very reliable therefore. • As usual a Kelly cock should also be used to arrest gas flow in the pipe. • A minimum of twice the pilot hole capacity of kill mud (10 ppg) should be kept ready. 3 stands of 8" drill collars. Open drill string motion compensator to full stroke and set pressure to compensate at 5000 Kgs.Drilling Operation Practices Manual i) Penetration Test It is carried out to check the seabed formation to ascertain the depth of conductor casing so that it can safely withstand the weight of wellhead. cross over. 5 to 7 stands of HWDP and 5" D/P. time & ROP. The requirement and procedure for drilling pilot hole for exploration test is as under: ii) Requirement • A float valve should be installed in bit sub. Plot a graph Depth vs. Initial WOB and flow rate should be low and be gradually raised one at a time when there is no progress. 6. Exploration Test Exploration test to confirm shallow gas presence when the drill string is positioned for jetting test off location is also conducted there. • 50 bbls barite plug to be kept ready. Continue to lower the drill string until the bit takes 5000 Kgs of weight and does not settle any more. Keeping parameters same gives a fairly god idea as to when formation begins to change. requirement. Based on depth up to the point of refusal conductor casing tally is made. bit sub. 30 . Normally shallow gas pockets are observed from 600 to 900m below seabed. It is carried out 50 –200m down stream and down wind side so that if gas is encountered ship can be pulled upstream by anchors or using propulsion to move away from gas zone. 8. The point of refusal is the point where the formation can withstand 10 T of slack off. This depth is known as competent mud line. subsequent casing and BOP. 3. 2. it is a standard practice to drill small size preferably 8 ½” pilot hole. It is carried out using a jetting assembly which consist of 12 ¼” bit. 7. Initial jetting starts with 20 SPM. Seabed should be tagged at 5-10 spm and 4-6 KIPS of WOB. Bit and bit sub should be painted white for observation by ROV. 5. Hence Pilot hole should be drilled upto expected shallow gas/water zone or upto a suitable depth where formation strength is sufficient to withstand increased mud wt. Rate of penetration will be dependent on pump strokes mainly. 4. Space out should be adjusted so as maintain jetting assembly and bit in the hole while making first connection. The sequence of operations in carrying out penetration test is as under: 1. Based on this and wind direction location of this exploration test is decided. The exploration test must be carried out upto the sectional target depth of 26" phase. Gas plume in shallow gas occurrences has been observed to form a low angle of 10° at the wellhead. Penetration test should be continued without rotation up to the point of refusal. This procedure to becontinued till such time that the gas streams is minimal. The ship will be moved upstream but not downward in order to move away from Shallow gas. • Hold PGB with guidelines in place.D. • Once safe conditions have been established continue drilling to T. • If the gas stream continues at a constant rate or diminishes during the flow check then a further 3m can be drilled.5m above the seabed at the end of jetting. iii) Spudding Based on seabed conditions either 30" casing alongwith permanent guide base (PGB) can be directly jetted down or 40/42" conductor alongwith float boxes and temporary guide base (TGB) is lowered when seabed is very soft for increasing the resistance to sinking. • Displace hole volume with 10 ppg kill mud. • If the well is dead or subdued then proceed as with a minor gas flow. • If failed to subdue the gas flow with barite plug then prepare to pull rig off location. • If the gas stream does not diminish then pump 50 bbl barite plug at bottom. • Always observe the well carefully for gas flow prior to making connection. reaching to bottom (TD) in 3m interval (prior to that ensure adequate kill mud is made available) or once the well is under control then pump a cement plug above the barite pill and pull back to sea bed to review options. circulate bottom up and observe the well. In such condition immediate action is to be taken to move the ship off the location by atleast 500 m to be out of danger. Moving Rig off Location The gas plume in shallow gas occurrences has been observed to form a low angle (10-degree) to the vertical. In 900m of water depth the gas plume will be approximately 158m wide.Offshore Rig • • Captain and marine crew be kept ready for moving rig off location if situation arises. • Inform captain/chief engineer/DP operator. In case enough room is not available we may have to go for emergency winching off with anchors. Procedure • Normal drilling over this section will be relatively fast hence drilling should be done at a moderate rate so that minor gas flows if any can be identified with ROV. • If however the gas flow increases and develops into major flow then the following procedures need to be followed. Jetting of 30" conductor • Based on penetration test results tally is made such that top of PGB remain 1. • Once a major flow has been noted by the ROV maintain circulation through out the gas flow kill operation. • If minor gas shows are seen the bit is to be pulled off bottom and observe the well. 31 . Marine crew (captain/chief engineer etc) will be aware at all the times while drilling the pilot hole which way the rig will be pulled off location if required to do so. ROV should be stationed near the seabed. • Space out jetting assembly so that it will remain ½’ inside conductor casing.5 m above seabed. of 9-1/2" d/c + 1 std. Release casing running tool under surveillance by ROV.Drilling Operation Practices Manual • • • • • • • • • • • • • • • • • • • Conductor pipes are run in the conventional manner through PGB with box down and pin up preferably with squnch joints for faster operation. • Center the string among guidelines using chain pieces and nylon rope. • Put paint mark on guidelines at moon pool level. Lower jetting assembly BHA (26" bit + 2 nos. Drilling 36" hole • Make up 26" bit & 36" hole opener and BHA. Jet in conductor following the parameters used for penetration test. Break circulation with seawater and ensure conductor is vertical using bull’s eye of PGB. • Gently touch bottom and jet down to the point of refusal. Establish guidelines. It should be within 1°. • Hoist the TGB with D/Works and remove spider beam and RI to sea bed. In between flush the hole using high viscous gel. Once required depth is reached remove all cuttings using high viscous pill. • Check the inclinometer reading. 32 . • Bring TGB to moon pool & latch on to 40/42" conductor. Inclination of the conductor should not exceed one degree at any position. Lower the same and J on to the TGB. Jetting assembly length should be so adjusted that bit remains about 1 to 2 ft inside the casing shoe. Check for any movement of PGB or change in inclination of slope indicator by ROV. Mark guidelines at moon pool for reference. Lowering of 40/42" conductor with float boxes and TGB • Weld 40/42" squench connectors with conductor pipe as required with pin up. • Eye pad may be welded to rest on rotary. Make up 30" running tool to the housing. Continue RIH with drill pipes till conductor is nearing seabed-using ROV. Record the distance between rotary table and the top of PGB at corrected tide for further reference. • Check list & trim of rig and adjust slope indicator reading. • Regulate guideline tensioners to 3000 lbs. • Secure float boxes to the TGB with bolts & slings. • Un J the running tool and POOH without using rotary. • Make up TGB running tool to the jetting assembly. of 8" d/c + 5 to 7 std. Jet down and position PGB about 1. Ensure inclination is within 1°. Lower all the conductor pipes. • Bring float boxes to moon pool & rest conductor string on float boxes. of HWDP + 5" d/p through the 30" casing using C-plate. Adjust space out to avoid first connection above seabed. • Weld 40/42" connector box on the bottom of TGB. of 9–1/2" d/c + 26" NRRSS + 1 no. Allow the conductor to settle/soak for about one hour. • Run ROV and confirm the position of TGB. • Lower 30" casing through PGB and center with nylon rope and chain on guidelines. Perform wiper trip after drilling to sectional T. • Run casing slowly using D/P as per tally • Run the casing into the TGB using ROV. RIH to bottom and drill down to T. Use compensator to avoid damage to PGB. it can lead to serious problems. • Make up R/T and open bull plugs of R/T. Drill down to 20" casing depth with seawater. Tension guidelines to 6000 lbs. iv) • • • • • • • • DRILLING 26" HOLE Make up BHA using a float valve in the string just above the bit. • Install slope indicator on PGB and drill pipe. • Carry out circulation and cementation. • Let air escape and fill casing with s/water. Also drilling rate should not be very high as due to excessive cuttings in the annulus it caninduce fracture. • Lower the string until the PGB is one or two meters under water. • POOH completely without rotary and recover slope indicator. RIH to casing shoe. Make wiper trip. • Lower and attach the housing to the PGB. There are cases where even BOP gets lost in the seabed because of this. When the casing is full replace bull plugs. 33 . • Release Running tool and POOH without using rotary. • Check returns after WOC. • Install 30" housing with its running tool. • Break out Running Tool and run drill pipe as stingers using ‘c’ plate. • Calculate the PGB depth and compare with the depth of TGB. Further ROV should be deployed at seabed for monitoring any gas coming from the well and around 30" casing. • Use ROV to verify that TGB is properly leveled and PGB is correctly mounted.Offshore Rig • • • • Alternatively use guidance equipment. Run TOTCO every 100-150 m. Fill the well completely with high viscous gel/mud prior to POOH for casing.D. POOH 30" Casing and Cementation • Set the PGB on two beams on the spider deck. Also use ROV for monitoring. • Circulate thoroughly near housing before POOH. In such cases cement should be pumped in large quantity in the annulus to avoid complications. • Monitor returns during cementation. in case ball is used. • Run the guidelines into guideposts and close the guidepost tops.D. RIH to the PGB opening. • Land the PGB on the TGB with the drill string compensator in the mid stroke. R/I BHA using either nylon rope and chain or guidance equipment for entering the housing. In between remove cuttings using high viscous gel. • Fill casing. Lower string and enter 40/42" conductor slowly. • In case cementation is poor or 30" casing & TGB is not properly secured at sea bed. Install guide lines in guide posts. Surface & BOP mounted accumulator bottles are to be pre-charged with Nitrogen to the calculated pressure. hanging from the hook to the BOP. Connect the riser. kill. Set guideline tension to 6000 lbs. v) BOP LOWERING After completion of 20" casing. Stand by bottles to be at max press. Increase guideline tension to 8000 lbs. After displacement with seawater. of casing joints. Make up 18 ¾” well head and set in the rotary Make up and lower required length of stringer using 5" drill pipes using Sub Sea cementing manifold. Check all functions are in block position. If shoe is OK. If NRV is used then plug can be bumped to ensure displacement. 34 Lowering • • • • • • • • • • • . Adjust the heave compensator to the weight of the landing string. Circulate thoroughly and carry out cementation. Check that tensioner’s bottle press is at calculated value. Fill the casing at regular intervals. Since formation at shallow depth is quite weak cement slurry should not be very heavy as it may induce fracture and due consideration should be given for low seabed temperature while designing cement slurry.Drilling Operation Practices Manual Lowering 20" casing and cementation • • • • • • • • • • • • • • • • • • Casing is run in conventional manner. The BOP stack must be in perfect working order when lowered. Make up running tool with wellhead. Disconnect junction boxes on hose reels. R/I required nos. Perform pick up test using compensator. The first joint being guided by four nylon pieces & chain for entering in the 30" housing. Pressure test choke. Carryout function test on both yellow pod & blue pod. unscrew R/TOOL and POOH completely after washing well head. Check for back flow. Make up cementing head to last 5" drill pipe and connect cementing hose. BOP is lowered as described below Preparation • • • Pressure test of BOP is performed up to their rated working pressure. Mount the riser angle beacon above the flex joint. Carefully monitor the entry of shoe in the PGB using ROV. booster & hydraulic lines to recommended test pressures. Switch hydraulic power unit to block position. check water tightness at shoe. Monitor the approach of 18 ¾’ well head towards 30" housing using ROV. Continue R/I 20" casing by using 5" d/p. Land the 18 ¾” well head on the housing. Activate lock down dogs (Rotating dogs) of support ring. Testing of BOP stack • • • • • • RIH BOP test tool using 5" OD drill pipe & land on wellhead. Carry out diverter operational check. Check hook load and lower stack carefully on wellhead while monitoring with ROV. Slowly lower the assembly. Open the D. Further drilling operations are carried out in conventional manner.S. Check all riser tensioners pressure. As each riser joint is added pressure test choke. Stop descent about 2-3 metres from guide posts according to heave conditions. Add one dummy riser joint and slowly lower the assembly to support ring. Open inner barrel & rest on spider and disconnect dummy riser. Position the stack firmly and activate BOP well head connector to “lock”. compensator at 20T. booster and hydraulic lines. Hook up kill. Perform pick up test by over pulling up to 20-25 T by means of compensator. pull out BOP test tool and install wear busing. 35 . Continue BOP lowering monitoring the approach towards guide posts by ROV.Offshore Rig • • • • • • • • • • • • • • • • • • • • • • • • • Hoist BOP stack assembly with the traveling block. Move slightly up and down to check that dogs are well in place. kill and booster lines. Unlatch blocking dogs. Make up diverter on inner barrel and install in rotary. Pressure test choke & kill lines to 7000 psi against failsafe valves. Lower telescopic joint and land it on spider below seal assembly. Decrease guide line tension to 4000 lbs. choke. Fill up choke & kill lines with NaCl and Glycol mix for gas hydrate suspension. Close the lower pipe ram & perform pressure test to 7000 psi. Carry out BOP test against all rams and annular. Connect all hydraulic lines and break out diverter running tool. Open spider beams & lower the BOP stack & continue lowering by adding riser joints. Check riser tensioner pressure to carry all weight of string minus 20T. Keep fitting pod hose clamps to the pod hoses and pod lines during BOP lowering. Connect telescopic joint (collapsed) to the last joint of riser. After completion of all BOP tests. 9.Drilling Operation Practices Manual CHAPTER – 3 DRILLING OPERATIONS 3. Bits required for rat hole drilling and first phase drilling with all required substitutes. Ezy torque. 2. 18. 10. Geo Technical Order of the well. Functional check of hydraulic cylinder (make up & break out) in case of mobile rigs.1 CHECK LIST FOR SPUDDING 1. Kelly. rig & hoisting equipment. drill collar safety clamps according to first phase of drilling. kelly top sub. Safety kit and first aid kit as per the Mines regulations. Adequate quantity of HSD.g. Functional check of power generating system. Well head. float valve etc. Geolograph. • Drilling • Mud services • Geology • Logging Services • Health Safety & Environment • Engineering Services • Logistics • Fire Services • Cementing services 36 . kelly saver sub. 23. 8. Required quantity of proper size of drill string for drilling. kelly drive bushings.upper and lower kelly cocks. 20. 15. Ensure the quality of make up and break up tong lines 17. inside BOP. if required. Fire fighting equipment duly inspected. 22. Bit breaker for various size of bits to be used. power tongs. Functional check of the instruments like weight indicator. mud circulating system 16. BOP stack. Functional check of Twin stop device 3. 4. Availability of crane for handling casing etc. rotary RPM meter. oil and lubricants. 11. rotary torque gauge. drill pipe & drill collar slips. 19. FOSV. 5. Handling tools like elevators. 7. 3. Hole opener. Device for making rat hole e. 21.2 PRE-SPUD CONFERENCE: Spud conference be conducted with representatives of following departments. 6. Supply of water for drilling operations and drinking purpose. 14. Pressure testing of high pressure lines and air tank 13. 12. choke and kill manifold as per well requirement & tested to its rated capacity. etc. Availability of conductor and surface casing as per GTO. tong torque gauge. Cementing units and adequate quantity of cement for all exploratory wells in remote areas. Chemicals required for preparation of mud and for controlling its parameters. turbine etc. Start the rotary table at 20-25 RPM and slowly lower the kelly up to the point marked on the kelly where the formation was touched. Guide the turbine/motor/kelly by manila rope which is tied with the mast in the right direction for controlling the back torque of the turbine. Initially drilling is to be carried out with low RPM. 5. Later on both pumps can be used. 2.5 DRILLING FOR SURFACE CASING Follow the bit break-in procedures in case of new bit. 7. 8. WOB.4 PROCEDURE FOR SPUDDING 1. 6. 7. Record the cellar pit bottom. Connect the turbine /motor with used bit of 12-1/4 inch dia. 4. Check the water line and mud pump connections. Start drilling a hole through the slot provided for rat hole on the rig floor with water outside the cellar pit. Connect Kelly saver sub to the lower Kelly cock. Procedure 1. 1. 10. type. Case the drilled hole immediately by lowering the rat hole casing pipe of 9-5/8 inch (length should be equal to length of Kelly plus one meter). Keep the height of rat hole casing equal to one metre above the derrick floor for proper resting of the swivel. Open the rotary lock. serial number and size of nozzles . 9. 4. Continue drilling with low WOB till bit breaks.3 RAT HOLE DRILLING Rat hole is used to place the Kelly. remove bit breaker. 37 . and now assembly is ready to tag bottom. Apply thread dope on the bit. 8. Make up the bit. Continue drilling upto the surface casing shoe depth with optimum ROP. 11. 3. 2. 3. WOB and discharge to avoid the erosion of cellar pit area. Lower assembly and tag the bottom marking kelly.Drilling Operations • • Security Medical Services 3. 9. in the bit breaker after checking the condition of the cones. 3. Connect lower Kelly cock of rated capacity to the lower end of Kelly after cleaning threads and applying proper thread dope. Lock the rotary table’s forward motion by mechanical lock. Take the required quantity of water in mud tank. Place the bit breaker on the rotary table and the bit required for spudding. Record the bit details such as make. 3. 5. 6. 12. Start the mud pump at slow SPM initially & establish required circulation. Continue drilling till the depth equal to the length of Kelly + length of lower Kelly cock + length of Kelly saver sub to be placed plus one meter is reached. Always cover this rat hole slot to avoid accident. bit substitute & Kelly to the required torque. 6. 3. and measure the volume of fluid recovered and compare this with the volume pumped. plot the increase in surface pressure against volume pumped. Test well head & BOP as per recommended procedure and pressure. Test the casing at 80% of the burst rating of the casing. 2. Hold the required test pressure for 15 min. Lower the casing and cement upto surface. Test duration is 15 minutes. (For plotting the graph see leak off test). Pipe connection should be done as fast as possible to avoid sticking of pipe. This is the sum of surface pressure and the hydrostatic pressure of the fluid being used during the test.. Flush the BOP stack. Make necessary arrangements for lowering of the casing while circulation. 3.7. kill and choke lines with water. BOP Stack. It should be equal to the hydrostatic pressure at the shoe of the heaviest mud that will be used in the well before running the next string of casing. . 8. Calculate the shoe test pressure. cement and float shoe carefully. Drill float collar. Hook up cementing unit with Kill line. 6. Close pipe ram BOP and Kelly cock. Install the well head. 7. 2. Run in drill string and bit. If the shoe is hermetical.6 CASING TEST PROCEDURE 1. Continue drilling till 0. Ream down the hole if required. Pull the drill bit in side the casing. 4. 4. It is considered positive if drop in pressure is not more than 5 %. 3. Release the pressure through choke line. 3. 3. 5.7.5 m below the casing shoe. 3. Circulate and condition the mud. 3. Pump steadily at a rate of one litre per second till the time test pressure at shoe is reached. formation should not be opened.1 Drilling of Cement. 10. Close gate valve on choke line.2 Shoe Test This test is done to determine the competency of cement job around the shoe. choke and kill manifold. 5. up to the top of the cement. Circulate & condition the mud prior to lowering surface casing. The shoe is considered OK if the pressure does not fall more than 10% of the test pressure during this time. Circulate the cuttings out of the well. Break circulation and clear cement upto top of float collar. Procedure 1. 2. the plot will be linear. 1. 4.Drilling Operation Practices Manual 2. 38 7.7 DRILLING BELOW THE SURFACE CASING 3. Both the volumes should be almost equal. 9. Drill cement at 2-3 tones of weight on the bit and rotary rpm as 40-50 only. 4. Float Collar and Shoe Procedure Make up used bit to drill cement with slick assembly. 8. 12. squeeze cement and repeat all the above procedure for testing shoe. Record pressure readings after pumping each incremental volume of 50 litres. Let it be ‘Ps’ kg/cm2. 3. The volume of return mud for conducting the test should be almost equal to the volume of mud pumped. 14. 13. Hydrostatic pressure due to mud column is calculated at the depth where leak-off is being performed as under: Wm X D Hs = —————— kg/cm2 10 Where. The pumping unit should have a graduated suction tank in litres or fitted with a pump stroke counter so that the volume of the mud pumped in can be accurately measured. Connect the cementing unit through kill line. Depth in meters. 4. Hs Wm D Ps Then PLOT = = = = Pressure due to hydrostatic head (kg/cm2). release the pressure and measure the volume of return mud. Surface pressure at which leak takes place (kg/cm2) 8. 9. The first reading of pressure which does not change proportionally after pumping incremental volume of 50 litres is noted. Start pumping mud in the well at a controlled rate of one litre/sec. In case the shoe does not hold the required pressure.3 Leak-off Test This test is carried out to determine the competency of the formation. It will be observed that pressure will proportionally increase after pumping each incremental volume of 50 litres of mud. Drill down 1-2 meter fresh formation below the casing shoe. Procedure 1. 6.Drilling Operations 11. 2. Close the pipe ram BOP. 7. Plot these values of pressures against volume of mud pumped on the graph. Connect kelly and close lower Kelly cock. 11. Close kill line and open both the outlet valves of casing head housing. = Ps + Hs 10 x PLOT LOT = ——————— gm/cc D After the test is completed.7. 10. Pull the drill bit inside the casing shoe. 3. Circulate to clean the hole. Open kelly cock. Specific gravity of mud. 39 . 12. 5. 2. Standard logs should be taken before lowering the casing and. 4. as and when required. Totco reading or inclinometer survey should be recorded during each trip and also whenever required. test pressure should not exceed the formation fracture pressure at the shoe. rise of cement may be changed as per the well condition.7. 1. Maintain angle deviation with in 5° for straight hole. 3.5 Intermediate Casing Test After testing of BOP.4 Drilling after Leakoff 1. choke & kill manifold etc. Install & test well head. Calculation of Maximum Specific Gravity of Mud: The maximum specific gravity of mud is limited by the LOT pressure at the casing shoe. This may lead to over pumping and formation breakdown. 3. 1. Mud weight should not be allowed to increase beyond LOT value. Depending upon well condition wiper trip should be made as and when required. Drill down to shoe depth of intermediate casing . 10. testing of intermediate casing is to be carried out as follows. b) Maximum allowable casing head pressure. the testing is stopped. 12. After conducting leak-off test. 3.7. 6. Drill/ clear up to top of float collar. test pressure should not exceed minimum of the following. the point ‘A’ at which this change is noticed is marked. 11. it is the lower part of the casing which is subjected to maximum burst loading. 5. c) The surface pressure should not exceed 80% of the burst pressure of casing. Test the casing. W max 10 x LOT Pressure at shoe (in kg/cm2) = ——————————————————— Depth of casing shoe (in metres) 3. Circulate and condition the mud. b) The first straight line portion of the graph ‘OA’ indicates elastic deformation of the formation. 2. When the curve starts getting visibly flat (at point A in the fig. Centralizers should be placed as per the plan. up to the top of the cement. Test duration is 15 minutes. 7. observe the WOC as per the plan or and casing on casing hanger (Sea Bed) immediately after cementation. Circulate for hole cleaning. a) 80% of the internal yield pressure of the weakest section of the casing lowered. resume drilling with the drilling parameters as mentioned in GTO. After casing has been lowered and cemented. If required. Run in drill string and bit.Drilling Operation Practices Manual Points to remember a) Do not keep the pressure and volume data for plotting later on. 40 . Note : If casing shoe is drilled out. Dog leg severity should not be allowed to go beyond 3° per 30 meter 8. 9.24) at the upper end of the plot. d) When such tests are conducted with heavy mud inside and lighter mud outside the casing. Pressurize casing unto required test pressure by pumping water at slow & steady rate. Dog leg severity should not be allowed to go beyond 3° per 30 meter 8. Standard logs should be taken before lowering the casing and.9 HERMETICAL TESTING 1.10. 3. Test Pressure Test pressure should not exceed minimum of the following: 1. 4. Engage the rotational lock in the desired direction (hook tongue facing towards the swivel bail) of the hook. In case the differential pressure between mud & water at bottom is unusually high. 5. The swivel hangs in the hook with the help of a bail.1 Procedures for Connecting Kelly.Drilling Operations 3. 3. 41 .10 OPERATING PRACTICES OF EQUIPMENT 3. 3. 4. 3. 5. as and when required. 4. Install & test well head. After casing has been lowered and cemented. 7. 1. Totco reading or inclinometer survey should be recorded as when required. Coring to be done as per requirement. 9. Mud weight should not be allowed to increase beyond LOT value. Continue drilling the hole (same as above) till it reaches the depth where next intermediate casing is to be lowered. Maximum allowable casing head pressure 3. Hold this pressure for 30 minutes. 5. Conduct leak-off test and resume drilling 2. Close the BOP & annulus well head valves. 2. Centralizers should be placed as per the plan. observe the WOC as per the plan or land casing on casing hanger (Sea Bed) immediately after cementation. Test duration is 30 minutes.8 DRILLING BELOW INTERMEDIATE CASING 1. 11. 6. 80% of the internal yield pressure of the weakest section of the casing. Displace the mud in the well with water and wash the well till clear water starts coming out of the well. rise of cement may be changed as per the well condition 10. displacement should be carried out in steps. 12. Connect cementing unit to string & test surface equipment & lines. 6. 2.Swivel and Hook The Kelly is connected to the swivel through a left hand substitute. Maximum allowable annulus surface pressure (MASP) while circulating out the kick below shoe. If required. Disconnect the circulation line from string. Pump water at steady rate of one liter per second. Maintain angle deviation with in 5° for straight hole. The pore pressure less the pressure exerted by the column of the gas as production requirement. either the slips.10. the total transverse load would be equally distributed over the maximum slip area and crushing will not occur. it is the rotary slips which were at fault. For accurate results. The hook is freed from the swivel by opening the tongue of the hook and bringing out the hook from the bail. 5. the same tests should be repeated with a new or like new set of rotary slips. On the other hand. if on using the new or like new rotary slips. To determine which is at fault. lift it up slowly and put the lock of the tongue in position. resting on the rotary table. 4. wrap the pipe gripping area with a white paper and set the slips against the paper. If this corrects the problem and the pattern is uniform.3 Checking of Master Bushings and Rotary Slips To determine effective gripping action of the rotary slips and master bushings follow the simple field test procedure as 1. 2. If the gripping pattern is such that it does not conform to the entire slip.2 Procedure for Disconnecting Kelly and Hook 1. When the hook’s tongue enters the bail of the swivel.10. If the rotary master bushings and slips are in good condition. Hold the Kelly by a winch line to prevent its sudden coming out from the rat hole housing. 3. 3. This test should be performed every three months and each time a new master bushings or set of slips with set of new dies is put into service. 5. remove slips and carefully examine gripping area to determine length. Pick up Kelly. SLIP TEST 1. 3. and it is evident that the master bushing is out of specification. Lower it into rat hole slowly. or the master bushing or both are out of specification. use a hook-load of at least 100. A slip test is an invaluable aid for determining the degree of rotary equipment wears. After the positioning of the lock at correct place. lift the block and hook in slow speed. a uniform gripping can readily be observed. 4. Pick up. Keep the hook at a desired height so that the hook’s tongue can enter the swivel bail on pushing the block and hook system towards the swivel. 2. After disconnecting from drill string lift the Kelly sufficiently and put thread protector on Kelly saver sub. While pulling out the Kelly from the rat hole. The lock which restricts the rotation of the hook is then disengaged and thus the block and hook become ready for handling the drill string or for doing any auxiliary job. matching the length of the slip being employed. Then free the block and hook. Pull it with a winch line towards the rat hole housing. 2. circumferential amount.Drilling Operation Practices Manual 2. Under such conditions. The tongue lock of the hook is then closed. and uniformity of holding by gripping elements. It is necessary that the slips and/or the master bushing be properly repaired or replaced immediately.000 pounds: 42 . 3. the uniform pattern is not observed. 3. 4. Care must be taken to prevent the hitting of the Kelly into the pipe. the casing line should not be rubbing the members of the mast. Avoid using old & new dies in combination. If the results of the second test indicate top contact only. While R/I in the hole. discard the old slips because they are worn. Never catch the tool joint box in the slips when the driller slacks off. 6. 2. If there is no full contact. Doing so causes improper contact with the pipe. 3. From time to time. If a full insert contact is indicated. 5. Never use one tong as it greatly increases the possibility of bending or “hooking” the pipe at the rotary. All damages to rotary slips should be immediately attended to. 4. Torque measuring equipment should always be used to prevent under or over torquing. Observe the second layer of the paper because the outside layer will have misleading slip impressionms. 3. Clean an area of pipe where there is no insert marks and clean slip inserts with a wire brush. resulting in both pipe and slip damage. Also line pull should not exceed recommended makeup torque with tongs at 90 Degrees to the jerk line. hold them firmly around the pipe as it is raised. Hold the slips in place while the pipe is being lowered at normal speed. . 8. Never resharpen inserts. 16. 12. 9. ensure that the slips do not accidentally catch the drill pipe. 15. Wrap two layers of test paper or mud sack around the cleaned section of pipe. 11. If problem persists discard the old slip. Torquing tool joints properly is the most important single factor in prevention of tool joint troubles. If slip is not holding the pipe due to worn out dies. This often happens when coming out of the hole and the driller does not pick up high enough for the slips to fall around the pipe properly. Change the dies of the old slip and again carry out the test to check the condition of slip. Stop the downward motion of the drill pipe with the brake not by the slips. Do not let the slips ride the pipe.10. the test should be conducted with new slips. this occurs though it is difficult to believe. 7. After the slips are set. 7. The slips should be carefully removed to prevent damage to the paper. crushed or otherwise distorted. 6. Place the slip around the pipe against the paper. 13. 17. the same must be replaced immediately.Drilling Operations 3. Do not use slips designed for one specific size of pipe on any other size of pipe. 4. Slippage of pipe through the slips due to worn out inserts can result in dropping the pipe. If the second test results in full contact. 10. Then carefully remove the paper. 43 .4 Proper Slip Handling Techniques 1. This not only damages the slips. the master bushing and slips are in good condition and no further analysis is necessary. also reduces the configuration of the gripping elements. Use adhesive tape at the top and bottom of the paper to hold it in place. the master bushing and/or bowls are worn and should be inspected for replacement. 5. 14. Maximum recommended make-up torque.11. 2. A square drive section normally will tolerate a greater clearance with acceptable life as compared with hexagonal section. Initially tighten d/p & tubing using spinner. d. This is required when maximum torque is applied. Check corners of drive section for narrow wear surface particularly on hexagonal kelly. 5. 2. 2. Angle of separation between tongs.5 Proper Use Of Drill Pipe Tongs 1. 44 . When making up or breaking out drill pipe stands without back-up tongs. the drill-o-meter needle will show that the pipe is in tension. use the same method except Kelly will need to be placed in 120 degree V-blocks so that face of drive section is vertical and deflection measurements taken on three successive sides (turning Kelly through 60 degrees each time). essentially flat in shape on the driving edge of the Kelly. Examine junctions between upset and drive section for cracks. because the pipe is dropping while it is slipping. Keep the tool joint as close to the rotary table as possible during makeup and breakout. 4.e.11 TRIPPING PRACTICES 3. When this happens the block should be released slightly so that the weight indicator shows weight equal to that of an empty block and the drill collar. the pipe may slip enough to make bad scars. Measure & record their length. New roller bushing assemblies working on new Kelly will develop wear patterns i.10.10. 3. There is a maximum height that a tool joint may be positioned above the rotary slips and the pipe resist bending. Such scars are usually spiral. Length of the tong handles. 3. Minimum yield strength of the pipe. Kelly straightness can be checked either of two ways: • By watching for excessive swing of the swivel and traveling block while drilling. the Kelly drive bushings should be adjusted if possible and/or examined for wear. apply thread dope. 4. Use the safety clamp for plain D/C. Keep in mind the factors governing the height limitation: a. or • On hexagon Kelly’s.Drilling Operation Practices Manual 3. The tongs should be placed either at an angle of 90 degree or 180 degrees apart. Inspection Inspection procedure for used Kelly: 1. 3. 3.1 Procedure for Making Up Joints 1. The life of the drive section is directly related to the Kelly fit with the Kelly drive. Clean and inspect the threads of the pin and box joints of the drill pipe.6 Kelly Drive Bushing Fit 1. Drill collar joints to be tightened initially with the help of chain tong. ID and OD in BHA book. c. As the upper joint is tightened to the lower joint. 2. if found all right. If wear surface does not extend at least 1/3 across flat. b. 3. drill collar. 3. • If high mud weights are being used. if well condition permits.3 Good Practices to Break Circulation after Round Trip 1. 3. The drill string is then hoisted sufficiently to permit the removal of slips. Break the joint completely with the help of spinner and do not use rotary for the same. consider the margin for ECD. 3. Ensure mud fill up/return with the help of trip tank only and as per trip sheet. stiff bristle brush.11. 7. 2. the yield point is normally kept optimum to reduce swabbing and surges. 2.Drilling Operations 6. Note: 1. distributing the compound over the threads and the mating surfaces preferably with a round. • Tripping should be done at slow rate in open hole in view of swabbing and surge specially in 8½ inch and lower hole sizes. Pipe should never be made up by reversing the rotary table. Finally the D/C joints should be made up to the specified torque using both the tongs/ easy torque. Dilution of thread doped will reduce the amount of available metal filler and make the compound ineffective.2 Procedure for Breaking Up Joints Apply lubricant on the back of the slips to avoid sticking in rotary table. • Consider the influence of Yield Point on Trip Margin Yield point MWtrip = MWbal + —————— 11. Tongs shall never be fitted on the body of the drill pipe. Tag bottom carefully to prevent bit damage (or plugging of nozzles) when using a PDC bit. 1. Start pump slowly. 3. 45 . 4. Do not dilute the thread compound for the ease of application. Crack the D/C joint with the help of jerk line (or Ezy torque if available).7(Dh-Dp) Where MWtrip MWbal Dh Dp • • • = = = = Estimated mud weight (ppg) to trip that will over come swab effect Mud weight (ppg) to balance formation pressure (no trip margin) Hole dia in inch D/P dia in inch To prevent wet pull out slug should be pumped in.11. Prepare trip schedule prior to running in or pulling out. Keep pipe moving (rotating/reciprocation). Pressure-up new joint before lowering below rotary table. Clean & dry the joint which is being added to the string. • Mud system should always be in good condition. POINTS TO REMEMBER • Evaluate bit condition after P/O to decide the new bit. • Before tripping out. 4. 3. 2. The box threads and shoulders should be doped. and record any U-tube pressures required to initiate flow or to kick float open. • Mud conditioning should be done in coordination with the tripping plan. 3 Balancing Strap This is used to keep the centre-latch elevators balanced in any desired position for the ease of operations. 3. 3. 3. 1. Adjust the height of the U-bolt assembly so that the elevator remains in horizontal position when in open or closed position. 2.12 DRILL STRING AIDS 3.11. Prior to making a fresh connection the hole should be reamed for the length of the kelly.12. It is very useful while lowering casing and tubing.12. Tie one end of the tong pull back to the end of the lever of the tong. Hook one end of the loop of ‘tong pull back’ over tong line pin at the end of lever-arm or with the help of a manila rope. Tie the other end of the tong pull back to derrick leg or any other fixed place with the help of a wire line or a manila rope. tongs are required to be fixed again and again on the tool joints of the pipes. 46 . while opening or tightening the joints. Tighten the U-bolt assembly. 4. For wells being drilled in hazardous and complex conditions. Put one end of the strap on the bolt assembly.1 Drill Pipe Wiper These are installed by splitting & pulling apart the ends and pushing on to the drill pipe till the wiper’s groove for the pipe is reached to facilitate the cleaning of mud from the surface of drill pipes during pulling out. Procedure The frequency of reaming is established depending upon the ROP and method of drilling. 5. The tong pull back saves time by automatically repositioning the tong for another take-up.4 Reaming It is the process of re-drilling of left over formation and is essential in the process of deepening of the hole. 2. 1.Drilling Operation Practices Manual 3. Fix the U-bolt assembly on the elevator link at a suitable height. the frequency and technology of working over drilled intervals may be adopted as per the conditions of that well . 3.12. Attach the other end of the strap to the elevator handle. It should be installed after pulling the first ten stands from the bottom in order to observe the swabbing in the well during the initial pull out.2 Tong Pull Back During round trip operations. However in order to optimize the hydraulics. Proper hydraulic programme consist of selection of most appropriate nozzle sizes and circulation rate for an existing set of conditions found at the rig 4.(1) . rate of penetration and the volume of drilled solids. If drilling with water. Annular velocity/Circulation rate Discharge Q = A*V where A is the annular cross-sectional area and V is the annular velocity. hence to avoid large pressure losses through them.. .Hydraulics CHAPTER ....(3) 47 .. the circulation rate should be held as low as possible. which contributes in improvement of penetration rate of bit..5 Annular velocity (M/min) = ————————————————————— Hole sizes H (in) X Mud weight W ( gm/cc) . consistent with effective cutting removal and proper utilization of the pump power... of mud pumps X discharge per stroke There are certain values of annular velocity used for different hole sizes. Drilled cuttings are heavy and travel upward initially but tend to fall thereafter. The losses through drill string and annulus are directly proportional to the square of the circulation rate (approximately). It depends on hole size.1 MINIMUM ANNULAR VELOCITY It is important to avoid large pressure losses through drill string and annulus so that the maximum of the available pump’s hydraulic horse power (HHP) may be utilized at the bit. drill string size and annular velocity.. Total circulation rate Nos of strokes per min = ———————————————————— No. This downward velocity of cutting is called slip velocity. 50 M/min is adequate. HOLE SIZE 26” 17-1/2” 12-1/4” 8-1/2” 6” 4 3/4” ANNULAR VELOCITY 5-9 M/min 18-30 M/min 21-33 M/min. Pump stroke can be determined by. 42-60 M/min is adequate.4 HYDRAULICS Proper hydraulics is one of the main factors... 42-66 M/min is adequate. Circulation rate = 2-3 lit/Sec/Inch of hole size431. Maintain annular velocity about twice the slip velocity.(2) Circulation rate that can transport cuttings to the surface is determined by carrying capacity of drilling fluid. Avoid turbulence. 36-54 M/min. higher velocities can also be used.. in Inches . then it is advisable not to carry out further drilling. M/sec per inch of diameter 8 7 6 Important Hydraulic Formulae.86 x 0. 4. Bit size in inches 6-3/4 – 9 9-5/8 – 10-5/8 11 and larger Minimum nozzle velocity. Dh = Hole dia.86 d = ID of Pipe in Inches.86 P2 = ——————— Kg/cm2 d4. Surface Equipment Pressure losses P1 = CW(Q)1. Annular Velocity V 1. Jet Nozzle pressure losses (WQ)2 x 1. Dp = Pipe OD in Inches 2.15 3.019 Kg/cm2 C = Friction Factor.(Dp)2 Q = Circulation Rate lt/min.Drilling Operation Practices Manual Note : If the desired annular velocity is not achievable due to break down of one of the pumps. The minimum nozzle velocity required for jet drilling is about 54 M/sec to 69 M/sec. W = Mud Weight In SG Equipment type 1 2 3 4 C 1.0 0. Drill String Bore Pressure losses 0.36 0.02 WLQ1. (Dh)2. The following rule of thumb may be used.22 0.356 X 10 P3 = —————————— Kg/cm2 (An)2 An = Area of nozzles in sqare inches -2 48 . 1.97 Q = ——————– M/min. 9640 X 10-6 ———— Kg/cm2 Dh-Dp 6.55 x circulation rate (lit/sec) 3./s) 5. Hydraulic Horse power PxQ HHP = –––––––– 450 8.97 x (hole diameter in inch)2 1. higher value for soft formation) 100 to 168 M/sec. Jet velocity (m/sec) = ——————————————— Area of nozzles (inch2) In case of soft formation annular velocity is important. % BHHP = ———————————————————— x 100 Stand pipe pressure Actual pressure loss through bit nozzle (kg/cm2) 2.5505 Q —————– m/sec An 7. BHHP (lit/sec) = —————————————————————— x Circulation rate (Lit. while in case of hard formation jet impact is important. For an optimum hydraulics programme the above parameters should have a value within the following range. iii) Jet velocity 49 .14 Optimization of hydraulic programme Calculate the following parameters: Actual pressure loss through bit nozzle 1. i) ii) % BHHP BHHP/sq. Annular pressure losses WLV2 P4 = 2. inch of hole size = = = 50 to 65% 2 to 5 (lower value for hard formation. Viscosity Correction Factor VCF = ⎜ ⎛ PV ⎞ ⎟ ⎝W⎠ 0.Hydraulics 5. Jet Velocity Vn = 1. 5. 2. 7. Calculate system pressure losses using tables (except for pressure loss through nozzle) Correct the same for actual mud weight and viscosity. If the values are out side thestated limits. 50 . 6. correct the value for mud weight. 3. record pressure losses through nozzles from the tables available in the data book. change the variables namely annular velocity and circulation rate so that hydraulic programme is optimized within available constrains. If the values are within limits. After nozzle size has been chosen. Calculate SPM required based on the discharge of the rig pump. 4. Select proper liner size. Select circulation rate for the annular velocity depending upon the hole size and BHA used. Calculate the three parameters stated above for optimization of hydraulic programme. The pressure available for nozzle selection is the difference between operating pressure limit (depending on surface equipment and liner chosen) and actual system pressure losses.Drilling Operation Practices Manual Procedure to achieve best hydraulic 1. then our nozzle selection is optimum. Select an annular velocity appropriate for a particular hole size from tables . Use proper type and size of substitute with bit. 12. 9. formation characteristics and bit design to improve the next bit selection. Use 2/3rd rules to find wear of tricone roller bit with a ring gauge. Relate dull bit grading to operating practices. WOB can be increased up to the recommended value or until the desired ROP is achieved. 23. Break the bit at bottom with low WOB & slow RPM for 1-2 m to establish bottom hole pattern. 25.Drilling Bits CHAPTER . Tighten the bit at recommended torque. Gradual breaking of sealed bearing bits will enhance the life of the bit. 26. Select a bit with long widely spaced teeth where balling tendency of the formation is expected. 3. cones & around nozzles area to grade the bit judiciously. quartz and basalt etc. While approaching well bottom. Lower the bit slowly into ledge. 11. 6. In case of sealed bearing.1 TRI CONE ROLLER (TCR) BIT The performance of the TCR bit is dependent on many factors such as selection of proper bit. 15. type. Reaming with TCR bit should be done with low WOB and low RPM. chert. Select the bit on the basis of lithology/formation to be drilled. Use proper bit breaker for tightening & breaking the bit. do not try to make rollers free. 24. diameter before lowering into the well.. After pulling out bit. 5. pyrite. Select a tungsten carbide insert bit with minimum or no offset when drilling hard and abrasive lime stone. wash the teeth. operating parameters and hydraulics. 22. 14. Check the bit for any physical damage. 18. 4. Select the tooth bit with tungsten carbide inserts on gauge if sand streaks are expected in the formation. hard dolomite. Use lifter for handling TCR bit to avoid damage of threads. Record the bit serial No. Do not use rotary table for initial tightening of the bit. 2. dogleg and at liner hanger top. Do not consider a new TCR bit as oversized on checking with the ring gauge as TCR bits can have positive tolerances. 21.5 DRILLING BITS 5. 17. 51 . 19. 8. 13. Consider the following points while using TCR bits. rotate the bit and circulate mud to clear out any fill and to avoid plugging of the nozzles. Conduct drill off test to ascertain optimum drilling parameters. Ensure free rotation of rollers in case of standard bearing bit. 16. 7. 10. Use of junk sub above the insert bit will help in avoiding the damage to the bit due to presence of broken inserts and previously left metallic junk in the well. Use of junk sub above last mill tooth bit run prior to drilling with an insert bit is recommended. 1. 20. Clean reservoir cap equalization ports of sealed bearing bits before running in a hole. Check the condition of the pulled out bit for a) Physical damage b) Cutters condition and c) Gauge.2. operating parameters and hydraulics PDC bit running procedures are quite different from roller cone bits or even natural diamond bits. While tagging bottom with PDC bit. Care must be taken while running in PDC bit through surface equipment as PDC bit being one piece and is not flexible as roller cone bit. It is advisable to use TCR bit with junk basket in case of metallic junk or severely under gauged hole is observed prior to running of PDC bit. Do not load the bit abruptly. Clean bit pin and apply recommended thread dope compound. 6.3 Tripping In 1. 3. Prior to running in with a new PDC bit run junk sub with last bit to clear bottom hole for any metallic junk.2. 29. 5. 2. 28. then lower PDC bit to drill further. 3. 4. inserts and nozzles. Use the bit breaker of the same company to which PDC bit belongs. Avoid high torque while reaming.1 Hole Preparation 1. 2. Drill cement and casing shoe with used TCR bit.2. serial No. Keep rotary speed at about 60 RPM and proceed slowly through a tight spot with maximum WOB 1. Never put excessive WOB and high RPM while reaming.5 -2 T.Drilling Operation Practices Manual 27. 5. Consider the following while using PDC bits. Place the bit with breaker in the rotary table and make up the drill collars string to the specified torque as per API. Record the bit make. 5. Take out PDC bit from its box and place it on a piece of plank carefully and do not roll or place the bit directly on steel surface to avoid damage to cutters /inserts. 4. If inserts are found severely damaged and bit is under gauge then clear & condition the hole with roller cone bit and junk sub/junk basket. Pass through tight spots very slowly as striking ledges can damage gauge cutters. Do not try to push the bit through tight spots. Ensure that all nozzles of bit are of required size & properly tightened.. Avoid PDC bit for reaming long interval in case previous bit was observed significantly under gauged. pick up Kelly and run pump at slow rate as compared to drilling. 5. keep on circulating at required pump SPM & RPM to avoid plugging of the bit. In case of tight spots. 3. 5. 5. Do not touch well bottom with a sudden jerk/impact. 5.2 POLYCRYSTALLINE DIAMOND COMPACT (PDC) BIT The performance of the PDC bit is dependent on many factors: Selection of proper bit. 2. 52 . 7.2 Making Up PDC Bit 1. 6. bit type and diameter before running into the well. 30. Check PDC bit for any damage of cutters. 5. 6. Maintain normal circulation rate when Kelly is raised. Avoid sudden release of the drill string as this may result in damage to the PDC cutters. Following steps are to taken while drilling. New PDC bit should be slowly set on well bottom at a slow rotary speed (50-60 RPM) & WOB not more than 2 T to establish bottom hole pattern. Pick up the bit 6’’ to 12’’ off bottom. If bit does not perform well after few minutes then increase the W. 5. Steady torque is observed while drilling through shale & heterogeneous formations. In order to avoid the bit slip phenomena in plastic/soft formations reduce the WOB and increase rotary RPM preferably. 2.5 Drilling Procedure Rotary torque is effective parameter to know the activity at the bit face at bottom.4 Breaking. Reduce the WOB if torque increases considerably while drilling through sands/fractured formation. Optimum WOB necessary for PDC bit is 2/3rd of that required for a roller cone bit.Drilling Bits 6. Varying surface torque is observed in layered formations. Bit should be washed back to bottom slowly at normal circulation rate. in steps till it performs well. If sudden increase in torque is observed at well bottom due to aggressive cutting structure of PDC bits. In soft formations. When there is reduction in ROP. more WOB should be applied in increments of one ton to take care of wearing of PDC cutters.In 1. Keep constant watch on rotary torque & weight indicator while tagging bottom. 2. 4. 2.2. there may be indications of rotary torque even if the bit is off bottom. 1. 53 . In softer formations increase in rotary speed results in better ROP but reverse may occur in harder formations as PDC cutters are unable to ‘dig.in’ beyond a certain threshold RPM limit. WOB should be increased before increasing the rotary speed in order to attain maximum depth of cut by PDC cutter. O. Increase the WOB to the recommended value to achieve the desired ROP. 5. B. This will help in preventing bit from becoming unstable. 3. 4. Making Connections 1. Carry out drill off test to achieve optimum ROP. thereby stopping backward whirling motion. 3.2. 3. Circulate out the cuttings before resuming drilling. such as porosity. oil and gas accumulate in these voids. It is accomplished by moving a down hole logging probe and recording its sensor output at the surface through an electrical cable. though with different objectives. The formation fluids e. The borehole logging probe or the well logging tool relates to a particular physical property of the rock and mud system. It is measured in percentage. which help in describing the texture and producibility of reservoir and are essentially determined for estimation of oil and gas reserves. Generally these tools are named according to what parameter they measure or to the physical process involved during their operation e.Electrical resistivity.2 RESERVOIR PROPERTIES Porosity: When sediments are deposited and compacted they do not form a solid mass.g. It is defined as a measure of fluid conductivity of the rock.Porosity.1 PURPOSE Logging is conducted to locate reservoir rock and to evaluate its viability as hydrocarbon producer. The effectiveness of a rock as a commercial hydrocarbon producer depends upon its following properties: a) Reservoir properties.. permeability and fluid saturation. The most common reservoir rocks are sandstones (elastic rocks) and limestone and dolomite (carbonate rocks). 6. The well logging system consists of (a) Down hole-logging tool. 54 . help in describing nature of rock and its saturating fluids.6 WELL LOGGING Well logging is a technique to record geophysical properties of rock as a function of depth. Permeability: It is an important directional property that permits fluid flow through interconnecting pores of the rock.Drilling Operation Practices Manual CHAPTER . The well logging techniques are employed to measure these physical properties of rocks directly in the borehole. self-potential (SP).g. It is measured in milidarcy/darcy. permeability and other geological parameters in a more realistic manner. 6. radioactivity. The amount of space or voids as a percentage of total volume of formation is called the porosity. The logs are recorded both in the open hole as well as in the cased hole. the tool which measures resistivity of the formation is generally referred to as Resistivity Tool. fluid saturation. Majority of logs are recorded while pulling the tool upward in the borehole. elastic wave propagation etc. The larger the porosity more is the amount of fluid a formation will contain. b) Physical properties. water. (b) Surface computer system and (c) Wire line cable for transmitting down hole signal to surface system. There exists some space between the grains called inter granular pores. • There is a large variety of logging tools meant for different types of measurements. The well log data interpretation is the methodology to translate in-situ measured physical properties into reservoir parameters. Well Logging Water Saturation: Water wet rocks are more common in oil fields as water is found present practically throughout reservoir rocks whether they contain oil or gas. This provides information on porosity and lithology. Radioactive Properties The rocks exhibit natural gamma ray (GR) activity by virtue of dissemination of radioactive elements K. Therefore fluid distribution in a reservoir is traditionally expressed in terms of percentage of water saturation denoted as Sw. rock matrix and cementing material exhibit high electrical resistivity when dry. Other fluid saturations are inferred from water saturation. c) Sub surface temperature of the rock. is one of the major parameters for porosity determination. Analysis of artificial radioactivity enables to get information on various petrophysical properties of the rocks. artificial radioactivity can be induced in the rocks by exciting rock atoms by bombarding either fast neutrons or gamma rays on to rock medium. which constitute their solid framework. which conduct electricity when wet. The pore space geometry that is represented by rock porosity constitutes three-dimensional complex networks interconnecting the pores in twisting and tortuous manner. porosity and the water saturation. The formation density thus measured.e. Uranium and thorium are adsorbed at the clay lattice surface. It is therefore observed that clay due to their high adsorption property exhibit highest radioactivity among all sedimentary rocks. Therefore electric conductivity or electric resistivty of rocks depends upon following factors related to water properties: a) Salinity and ionic composition of the water associated with the rock. Electric current flows in porous rock through saline water contained in the pore space. The conduction of electricity in clean porous sedimentary rocks is due to the presence of electrolytic fluid saturating the rock such as water. The variation of natural GR in different rocks act as an effective tool to differentiate the lithology. Uranium and Thorium is thus caused by sedimentation and different geochemical activities. Apart from natural radioactivity.3 PHYSICAL PROPERTIES Electrical Resistivity All sedimentary rocks are characterized by mineral composition. 55 . Distribution of K. Potassium the major contributor to natural GR activity. This increases the length of current path through rock resulting in increase of rock resistivity.Higher the water saturation.Increase in the rock temperature increases the ionic mobility thereby decreasing the resistivity of formation water. • The presence of clay minerals. Uranium. Neutron excitation method involves slowing down (thermalisation) of neutrons after interaction with the rock and emission of captured gamma rays. also influence the resistivity of the rock. The gamma ray interaction method involves attenuation of gamma rays by photoelectric absorption and Compton scattering. They are highly resistive to the flow of electricity when free from conducting minerals because the solid material such as mineral grains. b) Water content of the rock i. lower the resistivity.The resistivity decreases with increase in the salinity. 6. which provide information on rock density and lithology. is present as an integral part of clay. thorium and their associated radioactive elements found in sedimentary rocks. Shales have higher GR values compared to sandstones or limestone. as these depart from true values of physical properties of rocks due to effect of borehole environment. 56 . The GR is indicative of the rock type present. The caliper log thus is useful in correcting some of the logs which are very sensitive to hole size variations 6. This infiltration creates invaded zones near the well bore and creates mud cake against permeable zones. 6. • The most important properties of mud having direct bearing on logging data are mud density.3 Gamma Ray (GR) Log The gamma ray log is indicative of the intensity of natural radioactivity of rocks. The basic principles of frequently recorded open hole well logs and their measured parameters are as follows.4 OPEN HOLE LOGGING The logs recorded in open hole. shale and sand sequences.g. 6. The SP log is recorded by measuring the potential difference between an electrode in the borehole and a grounded electrode at the surface.4. hole deviation and mud infiltration into porous and permeable beds. Against permeable zones it deviates from shale base line either to left (negative SP) or to right (positive SP) depending upon formation water salinity being greater or less than mud filtrate salinity respectively.2 Spontaneous Potential (SP) Log The SP log records the change in naturally occurring potentials as a function of depth in the borehole. The quality of logs taken depends on borehole environment which are described below: Borehole Environment • The drilling fluid or the mud maintains hydrostatic pressure over and above the formation pressure against permeable zone to prevent blowout and also to protect well bore wall collapse.Drilling Operation Practices Manual Elastic Wave Propagation The characteristic feature of sound waves is that they change speed with the change in media (density) through which they travel. mud circulation.4. formation water salinity and degree of shale ness. 6. Bit action. mud cake formation and mud filtrate salinity. It is measured in mili-volts. GR log is used in identifying bed boundaries e. All SP changes are measured from shale base line as absolute value of shale potential is of no interest and the curve is monotonous. reaction of mud with formation and several other technical reasons create rigidity in borehole walls. The SP will not develop in wells where no salinity contrast exists between mud filtrate and formation fluid. • Log values measured under such conditions are called apparent values. SP log is used to determine sand-shale bed boundaries.4. Porosity being the most common parameter is determined using elastic wave propagation method. provide a direct measurement of a number of physical properties of rocks based on different tool principles. In well logging the acoustic properties of the rock and the fluid present in its pores can be used to evaluate various characteristics.1 Caliper Log The caliper log records the borehole size variations with depth. viscosity. 4.4. In Latero tool the current is focused to flow horizontally in lateral direction perpendicular to tool axis. 6. The gamma rays loose their energy depending upon the electron density of the formation (proportional to the formation density). The slowed down gamma ray is measured by the GR detector in the tool. The density logging tool works on the principle of ‘ interaction of gamma rays with matter’. Induction tool) into the formation. The speed of sound wave is reduced by presence of fluids in the formation pores. Thus measured induced voltage is proportional to the conductivity of formation. 6. Therefore this speed or travel time is used as a measure of porosity of the formation. 6. The strength of induced current is proportional to the formation conductivity. which are bombarded on the formation. 6. The hydrogen atom having the same mass and size that of neutrons.g. The tool is calibrated with standard density materials and the detected GR count thus is directly presented in terms of bulk density of the formation. Gamma rays are emitted from an artificial GR source (Cs137). The induced current in turn generates secondary induced electromotive force (voltage) in the measuring coil. depending upon the type of detector used. It depends on lithology of the rock matrix and density of the fluid occupying the pores. is most effective in slowing down the neutrons. Induction tool is ideal for logging in fresh mud or in gas filled holes. The detector of the tool detects either the slowed down neutrons (called thermal neutrons) or the captured gamma rays. This tool is used in conductive mud. Latero tool) or high frequency electromagnetic waves (e.4.4 Resistivity Log A resistivity log measures the formation resistivity.g. The porosity estimation in density log is referred as ‘Density porosity’. It is also used in depth correlation with cased hole logs. GR log is most widely used for well to well correlation as geological signatures on gamma ray are present over a wide area.4.6 Density Porosity Log The density logging tool measures electron density of the formation. In acoustic logging tool the accoustic waves of ultrasonic frequency are sent into the formation by the transmitter and accoustic travel time of compressional wave arrival at the receiver is recorded.5 Sonic (Accoustic) Log The sonic log is based on propagation of accoustic wave through formation. The travel time is influenced by framework of the rock and fluid filled pore space. The resistivity of undisturbed formation is required to quantitatively evaluate the fluid saturation of the formation of interest. The tool responds basically to hydrogen nuclei in the formation. which can be related to total porosity of the formation. The GR log finds an important application in estimation of shale volume in shale formations. GR log is presented as gamma ray in API units.Well Logging GR log is commonly used for depth correlation as it shows similar sharp features in two different logging runs.7 Neutron Porosity Log The neutron log works on the principle of neutron interaction with the nuclides of the atoms present in the formation. The formation resistivity is measured either by sending low frequency current (e. depending upon their volume. In Induction tool the current in the transmitter coil of tool generates an induced current loop in conductive formation. which is defined as resistance to electric current flow by unit cube of formation. The log is usually presented with density log in compatible scale. 57 . The neutron logging tool contains a neutron source (Am-Be) which emits neutrons which are bombarded on the formation. Porosity Bulk density of the formation (rock metrix + fluid occupying the pores) Porosity/gas zones As the number of detected thermal neutrons or gamma rays is controlled by the hydrogen concentration in the formation. Pipe line with cathodic protection should be switched off. Caliper log Spontaneous Gamma ray log Resistivity log Sonic (acoustic) log Density Porosity log Neutron porosity log Bore hole size variations Sand-shale boundaries/degree of shaleness Sand-shale boundaries/well to well correlations/depth correlation Measures resistivity/Support tool along with other tools. therefore it is a measure of porosity in terms of presence of hydrogen atoms present in the pore fluid (water or hydrocarbon). Intimation of logging jobs involving explosives should be given 24 hours in advance to make proper arrangements. 2. 58 . cable or explosive device should be removed before perforation job. cat walk and unit parking place should be cleared for safe handling of explosive devices. BOP must not be operated during logging. 3. However hydrogen index of gas is small compared to that of water. The density log gives apparently higher porosity in gas zones. Safety Precautions for Rig Crew During Logging 1. Any rig electrical rig wiring which can make contact with the unit. 9. radio room must be locked. A copy of electrical layout plan and communication network plan should be briefed to logging engineer. 4. 8. 5. Ensure that BOP is pressure tested above the expected surface pressure. 5. 15. No movement of tubular should be done during logging. 13. No welding job should be carried out during perforation job. 6. Even mobile phones are to be switched off. 2. the neutron log does not differentiate much between oil and water. There should not be any fire /flame producing devices near cat walk. The neutron-density log overlays in gas zone clearly show this difference in porosities. 10. Since hydrogen index of oil is very near to one. The neutron log responds to gas indicating very low apparent porosities. No unauthorized person should be allowed in the vicinity of thirty meters of working area. Special care should be taken to avoid accidental firing of tool at the surface when a failed Tubing Conveyed Perforation tool is pulled out to the surface. tractor should be allowed to operate in the drill site area while logging. 11. Derrick floor. Wireless set should be switched off.N. No heavy equipment like crane. Logging unit parking place should be at a distance of thirty meter plus from the well head. Any high tension line (over/under ground) in the vicinity of the catwalk should be disconnected and ends should be insulated. 14. 12. 7. Name of the log Measured parameter 1. 4.Drilling Operation Practices Manual S. 6. 7. 3. This feature is used to identify gas zones. Possible solutions to control deviations are. In vertical hole drilling. 4. 7. offsets. Addition of one more contact point will not follow a curved path and will maintain a straight path.1 PACKED HOLE THEORY In vertical drilling. 1. 2.2 Packed Hole Assembly Design Following are considered pertinent parameters for designing a packed hole BHA. If diameter of drill collar is doubled stiffness increases 16 times. never use near bit stabilizer alone for drilling as it invariably causes angle build up. • Packed hole theory • Pendulum theory 7. Stiffness is proportional to moment of inertia. Crooked hole drilling tendencies (a) Mild crooked (b) Medium crooked (c) Severe crooked 2. short blade length stabilizer and in soft formation. but it is not a cure all. smooth bore and free of doglegs and key seats. Pendulum assembly is used only as corrective measure to reduce angle when maximum permissible deviation has been reached.1 Packed Hole Design Factor 1.Bha Selection CHAPTER . In hard formation. Mr. Stiffness of drill collars is another factor which play an important role in straight hole drilling. packed hole assembly is used to overcome hole crookedness and to enhance ROP. Even a typical 5° limit does not assure the well is free of troublesome doglegs.7 BHA SELECTION The main consideration in BHA selection is to ensure that a specific pay zone is penetrated or drilled as per the plan. Three or more stabilizing points are needed to form a packed hole assembly. Two points contact can follow a curved line. Maximum permissible drill collar diameter in a given hole should preferably be used. 3. The restriction of total hole angle may solve some problems. Formation firmness (a) Hard to medium hard formations (b) Medium hard to soft formations 59 . long blade length stabilizer is preferable.1. spirals and ledges. Lubinski pointed out that the rate of change in hole angle should be the main concern and not necessarily the maximum hole angle while selecting a particular BHA. 7.1. The main objective should be to drill a useful hole with a full gauge. Non rotating rubber sleeve stabilizers (NRRS) Use: It is most effective in very hard formations such as lime and dolomite.1. ii. Integral blade type (SR) Welded blade construction (SR) iii. 1. It has got few limitations like: Limitation: • Bottom hole temperature < 250° F • It has got no reaming ability • Sleeve life is short in rough walls 3. The rubber sleeve is stationary and it acts like a drill bushing. Roller cutter reamers Use: These are used for reaming and added stabilization in hard formation.Drilling Operation Practices Manual 7. Shrunk-on sleeve construction (SR) iv. Replaceable metal sleeve type (RR) v. Rotating Blade Stabilizer Use: It is most effective in soft to medium hard formations Long(soft formation) Straight blade Short (medium to hard formation) Rotating blade stabilizer Long (soft formation) Spiral blade Short (medium to hard formation) Types of rotating blade stabilizers: i. non-rotating rubber sleeve and the rolling cutter reamer. roller cutter reamer should be used near the bit to overcome under gauging of the hole. 3-point reamer Rolling cutter reamer 6-point reamer (hard to extreme hard formations) ( medium to hard formations) 60 .3 STABILIZING TOOLS The three basic types of stabilizing tools include the rotating blade. Replaceable wear pad type (RWP) (RR) • SR = Shop repairable • RR = Rig repairable 2. If any under gauge problems are encountered. It does not dig and damage the wall of the hole. 3 Vibration dampener ZONE .2 ft Zone .2 Vibration dampener ZONE .1 ZONE .2 BOTTOM HOLE ASSEMBLIES 1.2: Blade stabilizer 30 feet above zone-1 Vibration dampener/Shock sub to be used at zone-2 above stabilizer in rough drilling conditions.3 : Three point string reamer or a non-rotating rubber sleeve stabilizer (NRRS) 30 ft above zone-2 Note : Any stabilizers run above zone-3 would be used only to prevent the drill collars from buckling or becoming wall stuck and in most cases would have little effect on directing the bit. Blade stabilizer 30 feet above zone-2 (in a medium size hole. Short drill collar length in ft = hole size in inches + / .Bha Selection 7. MILD CROOKED HOLE TENDENCIES (for hard formations) Zone-1: Three point reamer directly above the bit Zone-2: Three point string reamer 30 feet above zoneVibration dampener/shock sub to be used at zone-2 above stabilizer in rough drilling conditions.1 ZONE . Zone. 61 .1 MILD MEDIUM SEVERE The short drill collar size located between zone-1 and zone-2 is determined by hole size.2 ZONE .3 ZONE . like 8-1/2”) Zone.3: Blade stabilizer 60 feet above zone-2 (in a larger size hole.3 ZONE . MILD CROOKED HOLE TENDENCIES (for medium hard to soft formations) ZONE . 12-1/4” or larger) 2.2 Vibration dampener ZONE .1: Some type of long blade stabilizer directly above the bit Zone . b) For smaller holes less than 7” in diameter would require shorter drill collar not more than 6-8 ft long. The reason for this is to enhance stiffness. large diameter drill collar are required to be used between zone-1 and zone-2.2 Combination of a reamer and a blade stabilizer (for medium hard formation) Vibration dampener/shock sub to be used at zone-2 above stabilizer in rough drilling conditions. a 30 ft long.4 : The tools used in zone-4 can be the same type as tools used in zone-3 4.Drilling Operation Practices Manual 3. The reason for this is to enhance stiffness. Two long blade stabilizers (for soft formation) Zone. SEVERE CROOKED HOLE TENDENCIES(for medium hard to soft formations) Three blade stabilizers directly above the bit (for soft formation) Zone-1 Combination of a reamer and blade stabilizer (for medium hard formation) a) For medium size and larger holes a 10-15 foot long. MEDIUM CROOKED HOLE TENDENCIES (for hard formations) Zone-1 : A 6-point reamer just above the bit Zone-2 : One string reamer Vibration dampener/shock sub to be used at zone-2 above string reamer in rough drilling conditions. large diameter drill collar would be used between zone-2 and zone-3. large diameter drill collar are required to be used between zone-2 and zone-3 One Long blade stabilizer (for soft formation) Zone. Zone-3 : One string reamer or one NRRS stabilizer 5. b) for smaller holes less than 7” in diameter would require shorter drill collar not more than 6-8 ft long.3 String reamer or NRRS or blade stabilizer (for medium hard formation) A large diameter 30 ft long drill collar is required to be run between zone-3 and zone-4 Zone. Two long blade stabilizers (for soft formation) Zone. large diameter drill collar are required to be used between zone-1 and zone-2. MEDIUM CROOKED HOLE TENDENCIES (for soft to medium hard formations) One or two long blade stabilizers directly above the bit (for soft formation) Zone-1 Combination of a reamer and a blade stabilizer (for medium hard formation) a) For medium size and larger holes a 10-15 foot long. a) For medium size (8-1/2”) and larger holes. b) For smaller hole size 10-15 ft long.2 Combination of a reamer and a blade stabilizer (for medium hard formation) 62 . HW drill pipes (15 to 30 nos) 11.Bha Selection Vibration dampener/shock sub to be used at zone-2 above stabilizer in rough drilling conditions.4 : The tools used in zone-4 can be the same type as tools used in zone-3 7. One Long blade stabilizer (for soft formation) Zone. Drill pipes 63 . large diameter drill collar would be used between zone-2 and zone-3.low torque) 3.3 BHA FOR DEVIATED HOLE 1. Bit 2. MOTOR KICK-OFF AND BUILD UP ASSEMBLY 1. One drill collar non-magnetic 4. Non-magnetic drill collar (monel) 7. Near bit stabilizer (spiral blades not too long) 3. Orientation sub 6. D/C as required 5. 1 HW drill pipe stand 9. Motor (preferably high speed . The build up assembly consists of: 1. Bent sub 5. Float valve (shallow kick-off point only)\ 4. a) For medium size (8-1/2”) and larger holes. HW drill pipes 8. Drilling jar (over 500 m) 10. The purpose of this standard build up assembly: i) To complete the build up before the straight hole section ii) To ream the hole prior to run stiff “hold” assembly. a 10-15 ft long.3 String reamer or NRRS or blade stabilizer (for medium hard formation) A large diameter 30 ft long drill collar is required to be run between zone-3 and zone-4 Zone. 6. The reason for this is to enhance stiffness. One drilling jar 7. One or two HW drill pipe stands. b) For smaller holes less than 7” in diameter would require shorter drill collar not more than 6-8ft long. Limited drill collar (1-2 stands) 8. Drill pipes 2. ROTARY BUILD UP This assembly is run generally to finish build up initiated with motor and bent sub. Bit 2. Drilling Operation Practices Manual 3. HW drill pipe stands 9. Stabilizer near bit (full gauge) 3. 9 m Monel 4. Required drill collars 6. Bit 2. Drill pipes 64 . 1-2 HW drill pipe stands 7. Stabilizer (full gauge) 5. Drilling jar 8. HOLDING BHA 1. Care should be taken to prevent chafing of tool joint shoulders on adjacent joints. Weight on bit 6.1 TRANSPORTATION Onshore 1. 4. prior to commencement of loading operations. retighten load binding chains loosened as a result of load settling. Offshore 1.8 DRILL STRING The drillstring consists of Kelly. drill pipe. steel or concrete floors. Thread protectors must be installed on both ends of pipe. 65 . Tubular should be secured to the deck or hull of the vessel by the use of load binding cables or chains attached at structurally adequate points. 8. Use at least three spacing strips. Proper spacing practices should be observed to prevent chafing of drill pipe by hard banding on tool joints. The boat captain according to expected sea conditions usually determines the number and size of such cable or chains. Load with either all the pin ends or all of the box ends of the tool joints to the same end of the truck. The first tier of pipe should be about 12 inches above the ground to keep moisture and dirt away from pipe. After load has been hauled a short distance. 2. Well Depth 3. 3. reamer. 3. Do not pile pipe directly on ground. which are spaced at approximately 10-foot intervals and shimmed to the same horizontal plane. Hole Size 2. strips should be lined up on a vertical plane with the deck stringers. stabilizers. BHA consists of bit. BHA etc.2 STORAGE 1. Wooden strips are placed so as to separate each layer of pipe. 3. rails. Margin of Over pull 5. Provide wooden strips as separators between successive layers of pipe so that no weight rests on the tool joint. D/C and HW drill pipes etc. Properly sized steamboat ratchets or turnbuckles are used to maintain proper chain or cable tension. Drillstring Design depends on 1. 2. Mud Weight 4. jar. Pipe is to be placed on wooden stringers. 2. Each layer of pipe should be blocked. Pipe should rest on supports properly spaced to prevent bending of the pipe or damage to the threads.Drill String CHAPTER . Well Trajectory 8. do not use the drill pipe. All drill pipes should be marked and recorded. Threads and shoulders of the box and pin of a dry connection should be carefully checked. 18.Drilling Operation Practices Manual 4. 21. Mount thread protectors while laying down drill pipe on catwalk. spinning chain marks. Thread protectors must be screwed on to both. 8. 15.) on pipe body. Do not spin pipe too fast. Always use both tongs while making up or breaking out drill pipes. Do not use specially made API modified compound for casing and tubing on drill pipe tool joints. If new drill pipes are to be used for first time. The tool joint should be kept as close to the rotary slip as possible during make up or break out. 20. If joint wobbles and bends. 23. 13.e. 9. 10. Place spacing strips at right angles to pipe and directly above the lower strips and supports to prevent bending of the pipe. Drill pipes should be stacked in such a way at rig site that the box ends are facing the rig floor. Set back area should be cleaned before stacking the drill pipe stands in fingers. 24. 17. 22. 14. Apply protective coating on pipe surface to prevent corrosion. Corrosion may form circumferential groove on pipe body if rubber protectors are left on. 11. 5. Down ward motion of the drill pipe must be stopped with the brakes and not the slips. Remove rubber protectors (bettis) while storing drill pipes. Pin and box threads and shoulders of tool joints should be thoroughly cleaned before the joint is made up. While stacking drill pipes at the ground. Do not use the drill pipe if such parallel longitudinal cracks are present. The pin and box threads should be lubricated with drill pipe thread compound before mounting the protectors. Tool joint shoulder should be free from any cut mark or wash out. Check for any notch (i. Always use recommended thread compound (compound containing 40-60% finely powdered zinc by weight as recommended by API). thread compound for ease of application. high speed can burn threads. 3. 6. 4.3 HANDLING Drill Pipes 1. Threads must be free from foreign materials and must not be damaged . tong marks and cuts etc. 12. slip mark. 7. the height of the stack should not be more than 10 feet. If any circumferential or transverse notch is found on pipe body. threads should be cleaned with suitable solvent and soft bristle brush. Do not thin. Do not allow the pin end to strike the box shoulder while tagging.working joint. box and pin ends of drill pipe while handling. 66 . 19. 8. 16. 2. Check for any longitudinal cracks on tool joint body because of heat cracking. 5. Always make up tool joints with appropriate recommended torque. In every third trip working joints of drill pipe stands must be changed to facilitate the checking of non. Do not use wrench or other sharp edged tool to jack drill pipe stand in position on set back platform. 8. 9. Kelly 1. this may damage the slips and may create other complications. Check for any burrs or damage and lubricate properly. 14. its pin threads should be cleaned. Thread protectors should be used and screwed fully on both pin and box ends when handling drill collars. 3. Drive assemblies should be replaced periodically to ensure minimum clearance from wear. A torque gauge should be used on tong line to measure the make up torque. Drill Collars 1. 13. Do not use rotary for making up and breaking out drill pipes. Do not use slips designed for one specific size of pipe on any other size of pipe. Do not weld on the drive corners of Kelly for rebuilding the worn Kelly.) 5. Thread compound should contain 60% finely powdered metallic lead. 28. 6. Always use a good thread compound. 27. 7. Do not use bend or crooked Kelly as it results in rapid wear of Kelly and drive rollers. Do not let the slips ride the pipe. Insufficient torque or too much torque both may cause problems. 9. if possible. Do not over torque or under torque a drill collar connection during make up. Always use chain tong for initial tightening of drill collars. Avoid rotary for making up or breaking out of drill collar connection. 5. Do not jerk the line while making up D/C. Visual inspection at regular intervals should be made to check the wear of drive bushings and Kelly corners. Lubricate the drive surfaces so that Kelly slides freely through the drive bushings. 7. Do not use tongs on pipe body. 2. 6. Before make up. 26. 4. A safety clamp should be invariably used while making up or breaking drill collars which do not have slip and elevator recess (i. 29. 12. If lift subs are used. It protects the lower pin thread of Kelly from excessive wear.e. Always use Kelly saver sub. A new joint should be carefully lubricated. It provides the support to limber Kelly.Drill String 25. 11. change the working joints of drill collars. The rollers of drive bushing assemblies must be adjusted for minimum clearance. non magnetic drill collar etc. relubricated and made up again on initial make up. checked and lubricated on each trip. Use cast steel protectors on pin and box end of drill collars while picking up from catwalk to derrick floor. 8. 67 . 4. made up. clean the threads thoroughly. Check that slips and elevator for handling the drill collars are of proper size. 15. 3. Always use new drive bushing roller assemblies with new Kelly. 10. 2. broke out. On every third trip. Do not move or transport Kelly without scabbard. Make close visual inspection of every non-working joint while pulling out. Drilling Operation Practices Manual 8. 1. Drill collar inspection should be more than just looking for cracks. 4. Boxes should be checked for swelling and shoulders should be inspected for leaks or conditions that may cause leaks. When galling is observed. torque. check for proper thread compound. Shoulders can be polished with refacing tools if the damage is not too severe. Thread profile should be checked with a profile gauge to detect stretched pins and worn threads. Watch for washouts in drill pipe in the connection area of the joint. If eccentric tool joint wear is noticed. Crooked drill pipe 4. Look for dry or muddy threads. These areas are potential points for failures to originate which are thoroughly investigated and checked out before running in the hole. 7. Too much change in cross-sectional area 3.7 FATIGUE FAILURE Following points needs to be taken care to avoid fatigue failure of drill string. Drilling through dog-leg 8.1 Care and Handling 1. 8. The typical Brinell hardness of aluminum drill pipe is 135 while grade E-75 steel is approximately 200 BHN. 5. Check for wear on tool joints and drill pipe. Watch tool joints while tripping for evidence of pin stretch and box swelling due to overtorquing. 68 .6 H2S EXPOSURE H2S forms weak acids with water that attacks the drill string material. 2. 3. burrs and small galls can be removed with a small grinder or file. 3.8. in the slip area and in the transition between the upset and the pipe nominal wall. 8. Maintain higher pH above 10. check for wash out. and adequate shoulder areas.5 FIELD INSPECTION OF DRILL COLLARS 1. 2. slip cuts and other similar damage. Watch for undercutting of the tool joint in the area of the 18-degree elevator shoulder. 4.5 in the mud system. Aluminum is more easily marked because it is softer. 2. galling and worn threads.4 VISUAL EXAMINATION WHILE TRIPPING 1. 8. Undercutting may be more prevalent on tool joints without hard metal bands. Careless handling can mark both tubes. Over-torquing frequently occurs down hole while drilling. Minor repairs can be performed in the field to keep the collars running. Watch for dents.8 ALUMINIMUM DRILL PIPE 8. 6. Running drill pipe in compression 2. Drill String with aluminum drill pipe should be transported on a float bed truck with minimum three supporting spacers on each layer. Fins. check pipe for straightness. 7. 69 . The stretch of aluminum is greater in air or in mud lighter than 12 pounds per gallon (ppg). Care should be taken that tensile yield is not exceeded by measuring mid-length pipe diameters frequently. While using mixed strings of aluminum and steel. 13. extended reach wells or horizontal completions.6 x 106 compared with 29 x 106 for steel. 4. 20. 6. BOP: In case of external upset aluminum drill pipe. Loading and unloading drill string should be controlled and quiet. aluminum string should not be less than 5% of the total string and this minimum amount should be added at one time. 16. Slip dies for aluminum pipe are modified for minimum penetration and maximum power. Slips should never be used to stop the downward motion of drill string. Also calculate carefully to determine the additional turns necessary to achieve the equivalent torque in these and other operations. 15. If rams for steel pipe are used on aluminum. 8. or in all those cases where pipe is subjected to severe bending during rotation. the aluminum pipe is likely to be damaged severely. It is recommended that drill string with aluminum drill pipe be plastic coated internally. The flexibility of aluminum drill pipe gives it excellent fatigue resistance. Plastic coating improves hydraulics and reduces the erosive or corrosive effects of drilling fluids. checking pipe tallies and determining if pipe has been stretched. aluminum drill pipe can be most useful when operating in crooked hole areas. Drill String Operating Limits: The modulus of elasticity of aluminum is 10. 9. Aluminum has much greater flexibility and requires about twice as many turns to reach the same torque level. the stretch of aluminum is less than steel. whether the pipe is aluminum or steel. 14. 19. 17. Always use elevators with cylindrical “bores which will clear these DTE DPE diameters. Slips should be set close to rotary table for making up and breaking out. Always use two tongs to make and break connections. This will minimize pipe bending during these operations. use proper size of Ram Block. the OD of the pipe is slightly larger than steel pipe of the same nominal size. Avoid hooks in handling the drill string. placing back off shots or other instruments. Slightly bowed pipe tends to straighten under the stretching effect of the drill collar load in a normal drilling operation. The consistent lengths of aluminum drill pipe offer greater accuracy when using free point indicators. setting a liner or when steel pipe is below aluminum. When the mud weigh is more than 12 ppg. The nicks and gouges that appear in aluminum pipe rarely lead to fatigue problems unless the marks are very deep. To avoid this. 5. Calculate the stretch of aluminum carefully when pulling stuck drill string. Thus.Drill String 3. Straighten Aluminum Drill Pipe if it is bent. 10. 12. Aluminum drill pipe is likely to show more wear and/or erosion when drilling formations that are hard and abrasive. Choker slings with not less than 10' separation on a strong back or spacer bar are recommended. Use aluminum pipe in the upper section of the string but care should be taken to keep loading within recommended limits. 18. This should be replaced as necessary during the string life. 11. 8. safety precautions should be exercised to prevent injury to personnel. • The spring back energy of aluminum pipe is greater than steel. Also longer taper at each end means that overshot assemblies must be long enough to fit over the fish.2 Fishing of Stuck Aluminium Drill Pipe The general procedure in fishing of stuck aluminum drill pipe is similar to those for steel with these exceptions: • Electro-mechanical free point indicators are necessary because of aluminum’s non-magnetic quality.Drilling Operation Practices Manual 8. • If circulation is lost. or fish is without circulation when temperature is above 300 °F. 70 . high torsional and/or tensile load should be avoided until pipe temperature is reduced. On a heavy pull. Standard overshots with a 3 or 4-foot extension or a joint long enough to reach over the next tool joint are normally satisfactory. • The OD of external upset aluminum drill pipe is larger than the equivalent size steel pipe. 71 . In case of flattened strand. which suits the condition.e. Example Where 1“ 5000’ 6 19 S PRY RRL IMPS IWRC 1” X 5000’.Wire Rope CHAPTER. Wire rope is the combination of wires. Choose and follow a cutoff program.1 NOMENCLATURE The wire rope is made of number of strands laid helically around a core. The multi wire strands that are helically laid around the core are of two types i. 9. of wires in each layer of strand is described. Compute and record the service performed in Ton Miles by the line. reeved on the crown block and traveling block and is used for drilling operation. Proper care should be taken to increase the service obtained from the line. flattened strand & round strand. and core. Filler. Warrington.3 CLASSIFICATION Regular Lay The wires are laid in one direction and the strands in other so that the visible wires appear running parallel to the rope axis. 6 X19 S PRY RRL IMPS IWRC - Diameter of line in inches Length of line in feet Number of strands per line Number of wires per strand Seale pattern Pre formed strands Right Regular Lay Improved plow steel Independent Wire Rope Core RIGHT LAY REGULAR LAY LEFT LAY REGULAR LAY RIGHT LAY LANG LAY LEFT LAY LANG LAY 9. In round strand the make up is named as Seale. strands.2 SELECTION CRITERIA Wire line selection depends on work to be carried out which in turn decides the size and type of line to be used. The wire rope is spooled on the drum of the draw works. the no. Wire rope consists of strands laid around a main fibre or steel core.9 WIRE ROPE 9. RRL.IWRC 5. 1–1/8 6X26. IWRC 6X37 class.IPS. 6 X 7 Bright or Galv..RRL. IWRC 6X36 WS. RRL. Bright or Galv. 3-3/4 to 4-3/4 in. FC 3. RRL. IPS or EIP. 7/8 7/8 to 1-1/8 inch. 7 / 8. 1.1 / 8 1-1 / 4 to 2 inch. 8. 7. IPS or EIP. 1. RRL.PF. 72 . RRL. 6 X 21 FW. PS or IPS. IPS or EIP. IPS or EIP. IPS or EIP. 7 / 8 7 / 8. IPS or EIP. 1 3 / 4.WS.IPS or EIP.. 1 1. IWRC 6 X 19 S or 6 X 21 S or 6X25 FW. IWRC 6. IWRC 6X61 class. RRL or IPS. Bright or Galv. IWRC 6X19 S or 6X26 WS. 1–1/8 6 x 25 FW or 6 x 26 WS or 6 X 31 WS RRL or LRL. IWRC 6X19 class.4 DIFFERENT TYPE & SIZES OF WIRE ROPE SN 1. RRL. 9. IPS or EIP. FC 4. Bright or Galv. INCHES ROPE DESCRIPTION 1/2 to 3/4 inch 3/4. 7/8 to 1-1/8 inch.FC or IWRC 6X25FW. 1/4 to 1/2 inch 1 /2* to 9/16 9/16 to 5/8 5 / 8.RRL. IWRC 6X26WS or 6X31WS. IWRC 2. 7/8 to 2-3/4 inch. Direction of Lay The direction of lay or rotation of the strands is normally right hand but the wire ropes also are of left hand lay.Rotary Rigs Coring & Slim HoleShallow Intermediate Drilling lines-large rotary rigs Shallow Deep Winch Line-Heavy Duty Offshore Anchorage Line SIZE. RRL. SERVICE & WELL DEPTH Rod & Tubing Pull Lines Shallow Intermediate Deep Sand Line Shallow Intermediate Deep Drilling lines–Cable Tool Shallow Intermediate Deep Casing Lines-Cable Tool Shallow Intermediate Deep Drilling Lines. 6X25FW.Drilling Operation Practices Manual Lang’s Lay In Lang’s lay the wires and strands are laid in the same direction so that the visible wires run at an angle of about 30 degree to the rope axis.RRL. 1 1. . 7 / 8 7 / 8.. RRL or LRL. IPS or EIP. 3/ 4 3 / 4. 5/8 to 7/8 inch.IPS or EIP. 1-3/8 to 4-3/4 in. If a rope becomes covered with dirt or grit clean it with a brush.5. The new rope should not be welded to the old rope to pull it through the system. 6X36 WS or 6 X 41 WS or 6X41 SFW or 6X49 SWS. 9. sufficient tension should be kept on the rope to assure tight and even spooling. 73 . RRL. 4. IWRC 1-1/2 and larger 6X37 class. IWRC11. Do not allow the wire rope to come in contact with mud. always protect the rope from the flame and sparks.1 Handling the Reel 1.harmful to steel to protect it against damage. It is good practice to suspend the traveling block from the crown block on a single line while changing lines as it tends to limit the amount of rubbing on guards or spacers.Wire Rope 9. RRL . IPS or EIP. sharp object. 2 6X25 FW. 7. Bars for moving the reel should be used against the reel flange. 6. 6. Never use wire rope in an arc welding circuit as it damages the line. This practice is also very effective in pull through and cut–off procedure. IPS or EIP. as it reduces the strength of wire rope. Always use wooden blocks between the wire rope and the sling to prevent damage to the wire or distortion of the strands of the rope while lifting. IWRC 3/4 1-1/2 . IWRC 10. Never strike the wire rope with hammer or crow bar. Never drop the reel from a truck or platform while unloading. Blocks should be strung to give a minimum of wear against the sides of sheave grooves.5. 3. and not against the rope. While winding the wire rope on the drum. 4. Use a wooden block between the hammer and rope while hammering for crowding the wraps and operation should be carried out with great care. Set the reel on a substantial horizontal axis so that it is free to rotate as the rope is pulled of and in such a position ensure that it is not rubbing against derrick members or other obstructions while being pulled over the crown. While using a torch near the wire rope. Store wire rope in properly lubricated condition to minimize the effects of corrosion on wire rope. The reel should be jacked off the floor and hold by using suitable fixture so that it can turn on its axis freely. IPS or EIP. 3. as well as chances for kinks. it may cause kinks or bruises. RRL . Do not allow the wire rope to kink when spooling or un-spooling.2 Handling During Installation 1. 7. IPS or EIP. the use of a swivel type-stringing grip for attaching the new rope to the old rope is recommended.5 CARE & MAINTENANCE 9. 2. 5. 2. dirt. When a worn rope is to be replaced with a new one. Mast Raising Lines or Bull line 1–3 /8 and smaller 6X19 class. or any other medium. 5. Never roll over or drop reel on any hard. Guideline Tensioner Line Riser Tensioner Lines 9. RRL . because slackness can cause loops and/or kinks to form. 9. do not apply the brake on the rope itself. Take the old line off the drum and transfer it to a storage reel. 10. 12. To start stringing the rope. If a new coring or swabbing line is excessively wavy when first installed.6 REEVING PROCEDURE 1. raise the traveling block and take off the supporting line. When the traveling block is at the lower pick-up point. 6. The reel should be firmly supported on its horizontal axis with the line unwinding from beneath the reel drum (not from the top of the drum). 9. The best position is where the elevators are in pick-up position near the rotary table. Break the reel flanges so that the rope does not become loose on the reel while being unwound. 74 . 14. Hold down sheaves is the best way to anchor the line when cut-off practices are to be employed. Remove the old rope from the dead line anchor and fasten it to the new rope with a swivel grip. 16. 2. Keep as much back tension in the rope as possible. After properly securing the wire rope in the drum socket. When leading the line from the reel to the first crown sheave.9 wraps should be on the drum (if grooved). Care should be taken to see that the grip is properly applied. flatten or crush the rope. 13. and so an even tension is applied on the rope between the blocks. 15. a new wire line should be run under controlled loads and speeds for a short period after installation as it will help to adjust the rope to working condition. the number of excess or dead wraps or turns specified by the equipment manufacturer should be maintained. Plain-faced drums must have a full layer of line plus 4-6 wraps on the second layer as needed. Wind all the old rope on the draw works drum and pull enough of the new rope through to permit attaching to the drum. 5. hook and elevators may then be lowered through the V-door far enough to unreel the line on the drum. 8. 9. Fasten the new line so that it will not run back through the blocks. The block. 10. two to four sinker bars may be added on the first few trips to straighten the line 11. Attach the new line to the draw works drum and provide enough wraps so that the proper number will be on the drum at the pick-up point.Drilling Operation Practices Manual 8. 6. Ensure that clamps used for fastening the rope to dead end do not kink. Provide a permanent location for the reel of drilling line near the deadline anchor. Always anchor the dead end of the line properly without damaging the wire as it can cause kink in line. use snatch blocks with large diameter sheaves to guide the line and keep it from rubbing on derrick members and other obstructions. 3. Attach the traveling block to the hang line or otherwise support in a vertical position. After anchoring the deadline end. Whenever possible. The rope should be spooled under a sufficient load to ensure tight spooling. Remove the swivel grip. 7. Reeve the line. 11. The line should go around the hold-down sheaves in the same direction as it comes over the deadline sheave and from the storage reel. so that it can be re-reeled tightly. 4. Stabilizers should be used to avoid whipping of the fast line. therefore. Each operator should establish the most economical point at which sheaves should be re-grooved by considering the loss in rope life. 5.Wire Rope 9. Wire line must be periodically examined. 10. . A record of work done in ton – mileage should be maintained Use only drop forged clamps of U-bolt type. a wire line stabilizer must be installed on fast line. All sheaves should be in proper alignment. 9. Failure due to vibration is most serious at the deadline (crown block) sheave. which results from worn sheaves as compared to the cost involved in re grooving. Therefore longer rope life can generally be expected when relatively high design factors are maintained. Consider minimum design factor for successful field operations as follows. The fast sheave should line up with the center of the hoisting drum.off practice should be followed after evaluating the work done by a rope. moderately increasing the load and diminishing the speed can achieve best results. 3. The sheave grooves should have a diameter of not less than that of the gauge otherwise a reduction in rope life can be expected. 9.8 CARE OF WIRE ROPE 1. For most drums a maximum rope speed of 40 ft/min rope travel for hoisting or lowering is recommended.7 DESIGN FACTOR Design Factor = B/W Where : B = Nominal catalog strength of the wire rope. A jerk line may be rigged and clamped to the drilling line when it is necessary to do considerable jarring in one place.5 Note: Wire rope life varies with the design factor. Vibration causes drilling line fatigue and shortens life. Line whip and natural vibrations also cause fast line fatigue. A proper slip and cut. Sudden. 8. pounds W = Fast line Tension / load. • Cable-tool line 3 • Sand line 3 • Rotary drilling line 3 • Hoisting service other than rotary drilling 3 • Rotary drilling line when setting casing 2 • Pulling on stuck pipe or infrequent operations 2 • Mast raising and lowering 2. 7. As wear increases with speed. pounds Take care when a wire rope is operated close to its Minimum Design Factor ( MDF). 4. 75 2. 6. Sheave grooves should be checked periodically with the gauge for worn sheaves and dimensions. Excessive speeds of the block may injure wire rope. severe stresses are injurious to wire rope and such applications should be reduced to the minimum. 5 degrees. the maximum angle c.Drilling Operation Practices Manual 11. Poor fleet angles cannot only cause excessive abrasive wear. usually the center. • • 76 .9 FLEET ANGLE When a wire rope is led from the drum onto the fast sheave. This angle is called the fleet angle. It can be reduced by controlled spooling. Turn-back rollers or kick plates prevent piling up of wraps at the flange. In controlled pyramid spooling wear and cutting-in is parallel and there is no tendency for the line to slip over. which is provided by grooved drums. This is a grooving system where the crossover points are controlled thereby reducing wear and vibration. 14. The minimum angle should be at least 9. an angle is created which starts wear on the side of the rope. Do not subject the wire rope to severe stresses due to impact and shock loading. For smooth faced drums. the maximum angle b. Dead anchor should be equipped with a drum and strong clamping device to withstand the wire rope loading. 12.5 degrees. Wear due to crossover points cannot be completely avoided. In any type of spooling there must necessarily be two crossover points with each wrap. 2. All sheaves should be properly lubricated to ensure minimum turning efforts. 13. should be held to a minimum. but also build-up excessive torque in a rope.0 degrees. most of the grooves are parallel to the drum flanges. pitch changes rapidly where the line is crossed from one groove to the next. Repair the drums if corrugated impressions are made by wire line. That is to say the first layer acts as a sort of a “grooving” for following layers. One way to assist proper drum winding is by means of a riser strip or wedge on the dead end side. 15. An improvement in spooling methods is the controlled crossover system. If rope is operated with heavy loads or if the metal is too soft. Diameter of anchor drum or sheave should be minimum 12 times the normal rope diameter. In controlled spooling the change in pitch is less severe. Wire rope should be securely seized on each side of the cut before cutting the rope. it is parallel to the sheave groove only when at one point on the drum.Instead of being a helical shape like a coiled spring. 0. Two ropes are crossed over in each drum revolution. As a lower layer proceeds in one direction across the spool. Experience indicates that it should be held to less than 1-1/2 degrees for smooth faced drums and to less than 2 degrees for grooved drums.10 SPOOLING • It is most important to get the first drum layer full and tight without over crowding so that it will support the succeeding layers. As the rope departs from this point either way. a. scouring or corrugation of drums and sheaves will occur. = = = 1. the next layer must proceed in the other direction. The fleet angle although necessary. 9. Normally at the crossover points. For grooved drums. It will prevent the rope from untwisting. NEVER PLACE “U-BOLT” OVER THE LIVE LINE ALL THREE BOLTS ARE ON THE LIVE LINE U-BOLTS ARE STAGGARED. 4. If Seale construction or similar large outer wire type construction in the 6 x 19 class is to be used for sizes 1 inch and larger. 3.e. the U-bolt must be applied in such a way that the “U” section is in contact with the dead end of the rope (Figure 1-3) as per the following steps. 3. 1. IPS or EIP. 1. 77 . it may be necessary to add additional clips to the number shown. Inspect periodically and retighten to the recommended torque. Rope will stretch and be reduced in diameter when loads are applied. UNBOLT ARE ON LIVE LINE Fig. The number of clips shown is based upon using right regular lay. Turn back the specified amount of rope from the thimble. 6. Add one additional clip if a pulley is used in place of a thimble for turning back the rope. i. will cause a reduction in efficiency rating. For other classes of wire rope not in this list. 7. take up rope slack. Correct Method to Attach Clips to Wire Rope Fig. Crosby Wire Rope Clips INCORRECT SPLICING OF TWO WIRE ROPES. Apply the initial load and retighten nuts to the recommended torque. and tighten all nuts evenly on all clips to the recommended torque.11 ATTACHMENT OF CLAMPS ON WIRE ROPE Procedure When using U-bolt clips. Turn on nuts. Apply the next clip as near the loop as possible. Turn on nuts firmly but do not tighten. or failure to periodically check and retighten to the recommended torque. Apply the first clip one base width from the dead end of the wire rope (U-bolt over the dead end. 6 x 19 class or 6 x 36 class. the live end rests in the clip saddle). then add one additional clip. care must be exercised to make sure that they are attached correctly. fiber core or IWRC. Failure to make a termination in accordance with aforementioned instructions. then the amount of rope turn back should be increased proportionately.Wire Rope 9. 2 Incorrect Method to Attach Clips to Wire Rope The correct way to attach U-bolts is shown at the top. Tighten nuts evenly to the recommended torque. the “U” section is in contact with the rope’s dead end and is clear of the thimble. If a greater number of clips are used than shown in the table. or right Lang lay wire rope. ONE CLIP IS ON THE LIVE LINE Fig. 2. Space additional clips if required equally between the first two. 5. Drill stem tests.5 15 30 45 65 65 95 95 130 225 225 225 360 360 360 430 590 750 750 750 750 1200 TORQUE N.5 7.Drilling Operation Practices Manual NUMBER OF CLIPS FOR DIFFERENT WIRE ROPE SIZES WIRE ROPE DIAMETER.1 10 20 41 61 88 88 129 129 176 305 305 305 488 488 488 583 800 1020 1020 1020 1020 1630 9. draw works drum Type of string-up . fleet angle 78 . 4. 1.” twist offs” and “fishing” jobs 6.12 EVALUATION OF ROTARY DRILLING LINE The factors affect the life of wire rope. wire line stabilizer and turn-back rollers 3. Dead line anchor or clamp. crown blocks sheaves. Setting casing.6. stuck pipe. OF CLIPS LENGTH OF ROPE TURNED BACK INCH 3 –1/ 4 3-3/4 4-3/4 5-1/4 6-1/2 7 11-1/2 12 12 18 19 26 34 44 44 54 58 61 71 73 84 100 106 MM 83 95 121 133 165 178 292 305 305 457 483 660 864 1117 1120 1372 1473 1549 1800 1850 2130 2540 2690 Frt.3 / 8 1–1/2 1–5/8 1–3/4 2 2–1/4 2–1/2 2–3/4 3 2 2 2 2 2 2 3 3 3 4 4 5 6 7 7 8 8 8 8 8 9 10 10 NO. 8.M 6. Mast/derrick height.1 / 4 1. coring. depth of well & drilling conditions 4. traveling block sheaves. INCHES 1/8 3 / 16 1/4 5 / 16 3/8 7 / 16 1/2 9 / 16 5/8 3/4 7/8 1 1–1/8 1. Size and number of drill pipe & drill collars 5. Experience of crew. 10 or 12 lines 2. However. and on the drum where each wrap of rope crosses over the rope on the layer below. even though the remainder of the rope is in good condition. • Do not cut too much wire rope frequently. meter ft Number of stands of drill pipe. The objective is to obtain maximum rope service without jeopardizing the safety of the rig operation. 79 .” One ton-mile equals 10.280 feet. It must be remembered that in all cases. and a systematic procedure for making cuts of the appropriate length at the appropriate time. ⎛ C⎞ D(Ls + D) Wm + 4D ⎜ M + 2 ⎟ ⎝ ⎠ T = 5280 x 2000 where. On a drilling rig the loads and distances are so great that we use “ton-miles. The purpose of this simplified cut-off practice is to give the drilling crew a method for keeping track of the amount of work done by the drilling line. daily visual inspection of the drilling line should be made for broken wires and any other rope damage.000 foot-pounds. • In conjunction with the record keeping required for the cut-off procedure. FORMULA FOR WORK DONE: Total work done by line during trip is equal to. and where the rope makes contact with the crown block sheaves when the slips are pulled going in or coming out of the hole. • The only complicated part of a cut-off procedure is the determination of how much work has been done by the wire rope. Methods such as counting the number of wells drilled or keeping track of days between cuts are not accurate because the load changes with depth and with different drilling conditions. D Ls N Wm = = = = Depth of the hole in meter ft. work is measured in foot-pounds. it is important that the drilling line be cut at the proper rate. and is equivalent to lifting 2. Broken wires at these points of critical wear would result in the retirement of the entire string up. visual inspection of the wire rope by the drilling crew must take precedence over any pre-determined calculations. damage to equipment and expensive downtime. In engineering terms. • For an accurate record of the amount of work done by a drilling line.Wire Rope TON.560.) subject the rope to different amounts of wear. it will be necessary to make a “long cut” to eliminate some broken wires. there will be an obvious waste of usable drilling line. fishing. etc. injury to personnel. if the rope is moved through the reeving system too slowly. setting casing. At the very least. Effective weight of drill pipe lb/ft.000 pounds a distance of 5. it is necessary to calculate the weight being lifted and the distance it is raised and lowered.MILE CALCULATION • Heavy wear would occur in a few localized sections where the rope makes contactwith the traveling block sheaves. sooner or later some section of the drilling line will become worn and damaged to such an extent that there will be a danger of failure. • For these reasons. coring. which will result in higher than necessary rig operating costs. Length of drill pipe stand. • Use the Ton-mile indicator. The various operations performed (drilling. By staying as close as possible to the Ton-mile goal you will avoid long cuts and maintain the safest and most economical use of drilling line. 5. 6.0. Failure to record Ton-miles during drilling is probably the most common mistake made in cut-off practice. and the wear on the drilling line will be uniformly spread along its length. It is best not to run up to the maximum permitted ton-miles each time between making a cut. This practice does not waste wire rope because you are always cutting off lengths in proportion to the work accumulated. Work done can be calculated by the following method. the goal can be raised one ton-mile per foot cut. 9. 3. 80 . 10. a cut may be made whenever it is convenient. A better approach is to bounce around on your program. 4. This procedure should be followed until the optimum goal is found. Avoid accumulating more ton-miles between cuts than the maximum shown on the program for your rig even on the first cut of a new line. Calculate ton-miles during drilling after each round trip. It is only necessary to total the ton-miles accumulated since the last cut and divide by 19.Drilling Operation Practices Manual M C T = Total weight of traveling block assembly lb = Effective weight of drill collar minus the effective weight of same length of drill pipe lb = Ton miles Note : For round trip work done will be twice of the calculated above. 2. of slips between cut offs can vary considerably depending upon drilling conditions and on the length and frequency of cut offs. 8. If no long cuts are required. A steel tape should be used when making this measurement. When stringing back from 12 to 10 lines. Keep your wire rope history sheets accurate and complete. cutting with a new ton-mile accumulation sometimes and alternating with a medium or higher ton-mile accumulations. make a cut of the appropriate length based upon the ton-mile accumulation at that time. 11. The best cut-off program is the one with the most consistent ton-mile per foot cut values.0 to determine what length to cut. No. Daily visual inspection of the drilling line should be made for broken wires and any other rope damage. This way the ton-miles per foot cut will always be exactly 19.13 CUT-OFF PROGRAM So long as the maximum ton-mile accumulation shown on the program is not exceeded. This procedure will shift the critical wear points on the rope during heavy operations such as casing lowering. Slip & cut programs should be continually evaluated to maximize efficiency and minimize waste. 9. or from 10 to 8 lines. During slip and cut operations the travelling equipment (block and hook) will be properly secured with hanging off pendants so that inadvertent movement is not possible. Whatever program is used. it should be followed throughout the life of one entire drilling line. as some problem on your rig could prevent a cut being made at the proper time and lead to a ton-mile over run. 7. and it is believed that more service can be obtained from a line. Accurate measurement of the length to cut is very important. 1. 14 CUT-OFF PRACTICE FOR DRILLING LINE Cumulative work before first Cut. 638 T-miles 81 . safety factor: 3 Say you are operating at a safety factor of 4 then total work done found in the table must be multiplied by 0.= 5.8.Every body is aware of that this safety factor often falls consistently below 5 CALCULATION OF WORK DONE Height of mast: 138 ft. wire rope diameter: 1 ¼”.e. For S. Ans: For S. drum diameter: 28 inches.Wire Rope 9.58 .off Work done by a wire line in Ton -miles with respect to height of mast & diameter of wire line for the first cut can be obtained as: Derrick or Mast Formation Hardness Height (ft) Very hard Hard Medium Soft Very hard Hard Medium Soft Very hard Hard Medium Soft 133-138 Very hard Hard Medium Soft Very hard Hard Medium Soft Very hard Hard Medium Soft Total work of drilling line before the first cut off 1” Ton miles 500 500 500 600 500 500 500 600 600 700 800 900 600 700 800 900 600 700 800 900 1000 1100 1200 1300 1000 1100 1200 1300 1000 1100 1200 1300 1600 1800 2000 2100 1600 1800 2000 2100 2000 2200 2400 2600 1 1/8” Ton miles 1 1/4” Ton miles 1 3/8” Ton miles 1 1/2” Ton miles 80-87 94-100 126-131 142-147 187-189 Note: All the ton-miles in the table have been calculated using a safety factor of 5.F = 3 curve (fig. 4a.b below) gives the corrective fig: = 0.F.i. the total work done is 1100 T-miles.58 Then the total work done is = 1100 x . 0 8½ 34.7 9½ 25.2 17½ 11.3 9½ 33.9 12½ 23.2 19½ 18.5 14½ 19. 4a: Fig.9 12½ 18.3 17½ 20.4 10½ 23. where wear and crushing are most sever.9 11½ 19.5 4 7 6 5 3 2 Based on cutoff program indicated in Fig. of wraps laps (1) Cut off length in meters and number of drum per cut-off 34. Note: Cut off length in metre is mentioned in bold letters in top line whereas no of wraps to cut off is given below the cut off length.9 12½ 18.7 24.1 14½ 18.0 TON MILE SERVICE FACTOR 0.5 10½ 19.Drilling Operation Practices Manual 1.7 15½ 22.0 12½ 22.5 11½ 23.7 14½ 18. 4b: 2.7 11½ 25. 82 .9 13½ 24.7 11½ 23. RECOMMENDED CUT OFF LENGTHS FOR ROTARY DRILLING LINES Drim diameter (inch) MAST HEIGHT (ft) 187 11 12 14 16 18 20 22 24 26 28 30 32 34 36 No.0 12½ 12.9 12½ 23.1 10½ 34. the laps to be cut are given in multiples of one-half lap.2 9½ 25.5 10 9 8 1.8 10½ 24.4 11½ 25.7 14½ 27.5 11½ 25.5 13½ 26. 2000 3000 4000 5000 6000 7000 0 1 2 3 4 5 6 7 RELATIONSHIP BETWEEN ROTATRY LINE INITIAL LENGTH AND SERVICE LIFE DESIGN FACTOR Fig.5 14½ 21.3 9½ 9 ½ (1) In order to change the point of cross over on the drum.6 17½ 19.9 11½ 23.0 11½ 19.3 15½ 18 12½ 16.9 12½ 33 11½ 142-143 -147 133-136 -138 126-129 -131 94-96 -100 87 66 22.6 15½ (1) 25. Avoid fatigue failure of wire rope subjected to heavy loads over small sheaves. 5. Avoid ‘strand nicking’ which is caused by adjacent strand rubbing against on another and is usually caused by core failure due to continued operation of rope under high tension. 5. and too big 83 . Avoid fatigue break in a cable tool drill line caused by a tight kink developed in the during operation. Nominal dia of rope. Wire line tolerances are given below in table. 5) Detail “A” reflects gauge fit in a sheave.Wire Rope 9. 4. 2. Sheave grooves must neither be too small nor too large to avoid damage to the line. inch 0 0 0 Oversize.15 PRECAUTIONS WHILE USING WIRE ROPE 1. Avoid developing of kink caused by pulling down a loop in a slack line during improper handling. Avoid bird caging caused by sudden release of tension and resultant rebound of rope from over loaded condition. Small grooves cause pinching and over heating. inch 1/32 3/64 1/16 Place sheave gauges in grooves as shown (Fig. Detail “B” reflects gauge “fit” in a worn (tight groove) sheave. large grooves allow flattening of the line. Grooves too small. 3. 6. Sheave grooves in the crown and traveling blocks should be checked at the time of installation a new line. Detail B Groove Too Small Detail A Detail C Correct Size Groove Groove Too Wide Fig. Early rope failure will undoubtedly occur at this point. 7. just right. Detail “C” reflects gauge “fit” in a sheave where the groove is too large. Inspect localized wear over an equalizing sheave carefully because it is not visible during operations of wire rope. inch 0 to 3/4 1-3/16 to 1-1/8 1-3/16 to 1-1/2 Undersize. In this individual wire rope breaks in the valleys of the strands. inches Recommended (6 X19) 7/8 1 1-1/8 1-1/4 1-3/8 1-1/2 39 45 50 56 62 67 Mini (6 X 19) 26 30 34 38 41 45 84 . When wire rope is used over sheaves that are too small its service life is reduced. Wires in drilling line will break by continuously bending it backward and forward.Drilling Operation Practices Manual 9. To minimize the fatigue of the drilling line due to bending sheave diameters should be with in the following limits. Such re-adjustment. Bending causes readjustment of the positions of the wires and strands as well as bending of the wires themselves. For the bending itself puts a load on the line. Rope diameter.16 ATTACHING LINE AND SHEAVE DIAMETERS Bending of the drilling line over sheaves reduces the amount of load it can carry. causes fatigue. which must occur continuously in the multiple –line reeving system. inch Sheave diameter. Table No…. Hence diameter of the sheave should be big enough for drilling line. Care should also be exercised so that welding of the surface casing to the casing head housing can be done easily. The following procedure is adopted. Both the female as well as male threaded housing are available. 1. In terms of strength the API casing head material is equivalent to J-55 casing. Casing head housing serves as a connector from the surface casing to the BOP stack during drilling and then to other subsequent well head components. The height obtained is the height at which the surface casing should be cut from the cellar pit bottom.1 TYPES OF CASING HEAD HOUSING Casing head housing are available in two different types: 1. The height is calculated as under: Deduct the total height of all the well head components except the tubing spool from the depth of the cellar pit. The weld –on housing of the casing head is slipped on the cut casing and is kept perfectly horizontal and welded from both inside and outside using the proper type of welding electrodes. housing with male threaded bottom are used. 10. casing head housing which is the first well head component to be installed is fitted on the surface casing. 2. 4.Well Head Fitting CHAPTER -10 WELL HEAD FITTING After WOC. Cut the surface casing at a suitable height from the bottom of the cellar pit. 85 . 2. Welded Bottom 1. 1. This means that in the event that a male threaded housing is screwed on N-80 or P-110 grade casing. The bore through such type of casing housing must match the casing ID which will vary not only for different casing sizes but also for the different pipe weights within a given range. It has a bowl to accept a casing hanger to suspend the intermediate casing. The use of such housing is discouraged due to the following reasons: 1. Cut casing and chamfer properly on the inside. a) Female Threaded Bottom This housing is screwed directly on casing and is considered standard since one housing can be used for all weights and grades of a particular size casing. Threaded Bottom. THREADED BOTTOM The threaded bottom housing is furnished with API casing threads so that they may be screwed on to the casing pipe. b) Male Threaded Bottom In order to screw the casing head housing directly on to the coupling of the casing. the male thread on the casing head would be the weakest connection because it would be equivalent to J-55. 2. Remove false conductor / Riser. 2. 3. The welded casing head housing is allowed to air cool. The marks are put all around the surface of the casing at a number of points and then a circular marking is done. drive the packing down until it is flush with the body flange. One housing can be used over all the weights and grades of a particular size casing. flanged outlets or a combination thereof are available. Place the upper packing support with the lip receiving face down over the casing and drop it into place. Install the rubber packing as per procedure explained for installation of primary lip seal packing. 3. 4. Drop the lower secondary seal packing support with its lip face up over the casing. Installation of Primary Seals (National Well Head ) 1. Install the upper secondary packing support. 2. Housing/Bowl flange should be aligned with respect to the cellar pit. Care must be taken to avoid damage to the lips of the rubber packing. Install the next casing spool or tubing spool on to the well head assembly keeping the flanges matching the flange on the casing head on the bottom and bolt up properly. Installation of Secondary Seals 1. Remove burrs from the cut end of the casing. Test port is provided to test the quality of welding. 4. After the outer lips have fully entered the bevel in Bowl. 2. B. Threaded outlets. 86 . testing is carried out to determine the effectiveness of the field installed seals and connections. 10. Either one or two outlets can be provided. SLIP ON WELD TYPE HOUSING This type of housing is equipped with a socket weld preparation which slips over the casing and has provision for welding top of the casing to the ID of the housing and also for welding the bottom of the housing to the OD of the casing.3 TESTING OF CASING HEAD CONNECTIONS 1. Thoroughly clean and lubricate with oil the casing as well as inner and outer surfaces of seals and put one side of the seal lip over the casing. drop the lower packing support with the lip face up over the casing and into the body counter bore. 2. Thus secondary packing is installed. 10. • Collapse pressure of the pipe after taking into consideration safety factor. Installation of Next Casing or Tubing Spool 1.2 INSTALLATION OF WELLHEAD SEALS A. After installing the different parts of a well head. Tap progressively all around the rubber packing with a hammer until the casing has completely entered the inner lips. Outlets on the casing head housing Outlets are provided on the casing head housings for access to the annulus. 3.Drilling Operation Practices Manual 2. 2. • Load restriction on primary seal. Place the ring gasket in its groove. The pressure should not exceed the lowest pressure determined from the following: • Working pressure of connection. A D B E C F G Installation of Primary and Secondary Seals (National) 87 . Internal yield pressure of pipe after taking into consideration safety factor.Well Head Fitting • • • • Load restriction on secondary seal. Working pressure rating of the spool. Working pressure of end or outlet connection. Pick up the 13-3/8" Male threaded Casing of the required length. 2.3000 psi 5000 psi Wellhead :13-5/8" . taking into consideration wing valve directions and slip it over the casing. Pick up the casing head and orientate it. Slip on welded bottom connection 1. taking into consideration wing valve directions and make up with the Male threaded Casing. Installation of 13-5/8"nominal casing head threaded bottom connection 1.1. Ensure that the casing has entered the socket weld preparation and the Casing Head is seated correctly. 3. Nipple up BOP and riser with the flange connections.5000 psi 10000 psi Wellhead:13-5/8" . 3.1 Installation Procedures 10. 2.4. Pick up the casing head and orientate it.1 13-3/8" Casing and Wellhead Equipment a.Drilling Operation Practices Manual 10. Smooth and level the casing. Cut the casing at the desired height above the cellar pit level. b.4 RUNNING PROCEDURE FOR 3 CASING POLICY WELLHEAD (BHEL) SYSTEM DESCRIPTION The Typical production system consists of the following casing sizes: Typical Flange Sizes & Ratings for 3CP WELLHEAD: (1) (2) (3) 3000 psi Wellhead: 13-5/8" .3000 x 11" -5000 x 7-1/16" . 88 .3000 x 11" .3000 x 7-1/16” .4.5000 x 11" -10000 x 7-1/16" -10000 psi ASSEMBLY / CONTRACT DRAWINGS 10. Note: It is recommended to use BHEL 13-5/8" Nom. 10.Test plug assembly to the drill string. Upon reaching the bowl in the casing body. The dimensions selected for these slips compensate for the tubular mill tolerances. bore protector while drilling to protect the casing head inner surface from damage. Type BB primary packing should be used with this hanger. 3. Increasing the load of the suspended casing completely closes the gaps. place ½” LP Plug.2 9-5/8" Casing and Wellhead Equipment 10. The annulus is automatically and effectively sealed upon slack off. The design is such that when light to medium casing loads are supported. 6. Test Plug Assembly by pressurizing through the drill string and bypass in the 13-5/8" Test Plug assembly.4. Drill hole for 9-5/8" casing to prescribed depth. After successful test. Make up the 13-5/8" Nom. 10.2 Running The 13-5/8" Test Plug 1. seal test the welds via test port to a maximum Working Pressure. B) Type Bcmbfns Casing Slip & Seal Hangers The BCMBFNS hanger is an automatic suspend-and-seal unit. but do not exceed 80% of the casing collapse pressure. It can be wrapped around the casing and lowered through preventers. 89 . After the welds have cooled. The fully loaded slip assembly resembles and reacts as a continuous. Nipple up BOP and riser with the flange connections. there are radial gaps between the segments.1 Installation Of 13-5/8 "Nomx 9-5/8" Casing Hanger Installation of Casing Hanger (BCMBNS / BCMBFNS) is as follows: BHEL Make BCMBNS and BCMBFNS slips incorporate a new controlled make up principle that permits casing string loads equivalent to the pipe body strength to be handled with a controlled pipe Inner Diameter. Remove the ½” LP plug from the Casing Head. A) Type Bcmbns Casing Slips Type BCMBNS casing slips are three piece hinged assemblies with a simple latch permitting them to be closed around the casing and lowered through BOP.2. It utilizes a metal hinge and a simple integral latch pin.Well Head Fitting 4. so that maximum casing loads can be supported without reducing the casing Inner Diameter below the API drift diameter. 4.4. 2. The 45° shoulder on the casing head / spool body furnishes a solid supporting surface for the fully loaded slip unit. avoiding any possibility of deformed casing when maximum string lengths are suspended. solid ring with a fixed Inner Diameter. No manual adjustments are necessary before installation or after slack off.4.1. 5. it grips and suspends the casing string. Test the BOP and connections above the 13-5/8" Nom. Weld the Casing to the Casing Head taking into consideration the material of the Casing Head (Low Alloy Steel) and Casing material combination and stress relieve. Run the 13-5/8" Nom. Excessive packing pressure is relieved. Remove the test Plug after testing. Test Plug assembly on the drill string and land it in the casing head bowl. 5. place it on the boards and reinstall the hinge pin. Hold the casing to desired tension. 1 2 3 4 5 Part Name Slip Segment Drive Pin Hinge Plate Hinge Pin Eye Bolt No. 6. 90 . Slack off the casing tension slowly to actuate the slips. 2. 9. Remove the support boards. Do not slack off. Remove the hinged pin (Item No. 7.1 5 2 1 4 3 Fig:1 : Type Bcmbns Slip Type Casing Hangers 1. Casing shall be spaced so that there shall be no collar located between the points of assembly above the BOP stack and the casing head / spool which would prevent the hangers from sliding down the BOP into position. 3. Position two boards across the top of the BOP stack / casing head.Off 3 5 3 1 2 Material Steel Carburized Hardened Steel Steel Steel Steel Guidelines for Installing Casing Hangers (Slip Assembly): Fig. 8. Part the BOP stack.4) to open out the slip assembly 5. Lower the slip assembly through the BOP stack / casing head / spool and land it in the casing head / spool.Drilling Operation Practices Manual Item No. 4. Wrap the slip assembly around the casing. No movement of the casing assures that the slips have gripped. Mark and cut off casing approximately 4" (102 mm) above the upper surface of Casing Head Flange. 2: Type Bcmbfns Slip & Seal Casing Hangers 1.Off 2 4 1 1 1 4 4 2 Material 60K Steel Steel Carburised Steel Steel Buna-N Steel Steel Steel Guidelines For Installing Bcmbfns Casing Hangers (Slip Seal Assembly) : Fig. place it on the boards and re-install the hinge latch pin. Lower the slip seal assembly through the BOP stack / casing head / spool and land it in the casing head / spool.(Ensure that Item 6 (Shouldered Screws) is free to move and not binding on the body) 6. 2. No movement of the casing assures that the slips have gripped. Note : If the slip assembly has not gripped.4) to open out the slip assembly. Remove the support boards. 4. 3. Remove the hinge latch pin (Item No.2 2 3 8 4 1 6 5 Fig. 1 2 3 4 5 6 7 8 Part Name Spider Slip Hinge Pin-Fixed Hinge Latch Pin Seal Shouldered Screw Pin-Slip (Not shown) Eye Bolt No.Well Head Fitting Item No. slip teeth are to be checked for sharpness. 7. Hold the casing to desired tension. Do not slack off. 91 . Wrap the slip assembly around the casing. 5. Casing shall be spaced so that there shall be no collar located between the points of assembly above the BOP stack and the casing head / spool which would prevent the hangers from sliding down the BOP into position. Slack off the casing tension slowly to actuate the slips. Position two boards across the top of the BOP stack / casing head. 10. 2. 10. 4. 4. Place the upper packing support. 3.Drilling Operation Practices Manual 8.4. Note : It is recommended to use BHEL 11" Bore Protector while drilling to protect the Casing Spool inner surface from damage.2. 3. remove test pump and install check valve. drive the Packing down until it is flush with the body flange. with the lip receiving face down over the casing. TEST PLUG BUSHING 1. drop and drive it until it is flush with the Body Flange. 2. Make up 11" Test plug assembly to the drill string.2. Make up the bottom flanged connection with stud bolts and nuts.2. 6.Test Plug Assembly by pressurising through the drill string and bypass in the 11" Nominal Test Plug assembly. Mark and cut off casing approximately 4" (102 mm) above the upper surface of Casing Head Flange.4. Place Ring Gasket in place on the Casing Head flange. Note : 5. Pick and drop 13-5/8"Nom x 9-5/8" Primary packing lower support with the lip receiving face up over the casing and seat it into the Casing Head body counter bore. Caution : Do not cut or gouge the lips of the Packing during installation. Hook up test pump to test port on lower flange of Casing spool. 7. Test the BOP and connections above the 11"Nom. Lower the casing spool over the Casing Head flange and carefully orientate it. 9. 2. 10.2.4 Installation Of Casing Spool 1. Nipple up BOP and riser. 10. Run the 11" Test Plug assembly on the drill string and land it in the casing spool bowl.2 Installation Of Primary Packing 13-5/8" Nom X 9-5/8" 1. Tap progressively around the packing with a hammer until the casing has completely entered the inner lips.2. Clean and grease the casing as well as the inner and outer surfaces of the Primary packing and slide one side of the packing lip over the casing. Test to maximum Working Pressure or 80% of collapse pressure of casing whichever is minimum. Part the BOP stack.4. Bleed off test pressure.4. 3 After the outer lips have fully entered the bevel in the bowl. 4. taking into consideration wing valve directions. Remove Check Valve from test port before testing. Reinstall Seal plug. entrapped air will not hinder seating of packing.2.3 Installation of Secondary Packing 13-5/8"Nom X 9-5/8" Install the Secondary Packing group by dropping the lower support with its lip receiving face up and then install the packing and upper support as described in Step 10. Drill hole for 7"/ 5½” casing to prescribed depth.4.5 Running The 11"Nom. 92 . Remove the test Plug after testing. Note: If the wing valve outlet is open. 2.3. Open the hanger assembly by removing the latch pin wraps it around the 7" / 5½” Casing. 2. Lower the hanger through BOP Stack and make sure that the Hanger has seated in the Casing Spool. Do not slack Off. 3. Upon reaching the bowl in the casing spool body. 1. Center and Hold the 7" / 5½” casing to desired tension. place it on the Board and make up the latch pin. drive the Packing down until it is flush with the Body Flange. 8. 4.2 Installation of Primary Packing 11"Nom x 7" / 5½” 1.1 for construction and installation of the Casing Hanger (BCMBNS/ BCMBFNS) . Mark and cut off casing approximately 4" (102 mm) above the upper surface of Casing Spool Flange. 6.1 Installation of 11 "Nom x 7" / 5½” Casing Hanger See Sl. It utilizes a metal hinge pin and a simple integral latch pin. Remove Support boards. Slack off the tension slowly to actuate the slips. 3.Well Head Fitting 10. 93 . 5. Pick and drop 11"Nom x 7"/ 5½” Primary packing lower support with the lip receiving face up over the casing and seat it into the Casing Spool body counter bore.3.4.3 Installation of Secondary Packing 11"Nom. Tap progressively around the packing with a hammer until the casing has completely entered the inner lips. No manual adjustments are necessary.2. . Space out the casing so that there is no collar located between the point of assembly above the BOP stack and the Casing Head/spool which would prevent the hanger from sliding down the BOP into position. Part the BOP stack. 7. relieve the entrapped air through the inner / outer side of the primary packing using a screw driver.casing securely. Run the 7"/ 5½” casing.4. Remove burrs from the cut edges of the casing and ensure that the edge is smooth and level. Note : Type BCMBFNS . Position two boards across the top of the BOP Stack. Clean and grease the casing as well as the inner and outer surfaces of the Primary packing and slide one side of the packing lip over the casing. Place the upper packing support.4. The annulus is automatically and effectively sealed off upon slack off. it grips and suspends the casing string. 4. drop and drive it until it is flush with the Body Flange.3. 10.7" / 5½” Install the Secondary Packing group by dropping the lower support with its lip receiving face up and then install the packing and upper support as described in Step 10.3 7" / 5½” CASING AND WELLHEAD EQUIPMENT 10.Casing Hangers is an automatic suspend and seal unit.3.4. Note: If entrapped air hinders seating of packing.2. It can be wrapped around the casing and lowered through BOP.4. No. Ensure that the slips have gripped the. After the outer lips have fully entered the bevel in the bowl. 2. Caution: Do not cut or gouge the lips of the Packing during installation. with the lip receiving face down over the casing. 10. 9. In case of Control line provision. Run the Test Plug assembly on the drill string and land it in the Tubing spool bowl. 4. Nipple up BOP and riser. Back out and retrieve the landing joint. Reinstall Seal plug. Run in the Anchor Screws around the Tubing Spool to hold the Tubing Hanger in place. install the control line assay in the following manner: a) Install swage lock fitting in the bottom of Hanger body. Note : Remove Check Valve from test port before testing. 3. Tighten the fitting. Note : It is recommended to use BHEL 7-1/16"Bore Protector while drilling to protect the Tubing Spool inner surface from damage. 10.3. 7. 3. 2. taking into consideration wing valve directions and lower it over 7"/ 5½” Csg. Note: Anchor screws on the Tubing head are to be backed out before lowering the 7-1/16" Nom. 3. 6.Drilling Operation Practices Manual 10. 5. in case Control line provision is required) with the last joint suspended in the rotary slips. Hook up test pump to test port on lower flange of tubing spool. Make up 7-1/16" Test plug assembly to the drill string. Connect the Back pressure valve Plug in the Back pressure valve and install the Assembly in the Hanger. Test to maximum Working Pressure or 80% of collapse pressure of casing whichever is minimum. 10.4. 5. 4. Ensure that the Neck Seals are fitted in their respective grooves. 4. 8. Make up the Tubing Hanger bottom connection to the last joint of tubing to be run. 7. Bleed off test pressure. remove test pump and install check valve. 94 . Run the Tubing (along with Control line simultaneously. Place Ring Gasket in place on the Casing Spool flange. Pick up TUBING SPOOL and orientate it. 2.5 Running the 7-1/16 "Nom. Test the BOP and connections above the 7-1/16" Test Plug Assembly by pressurising through the drill string and bypass in the 7-1/16" Test Plug assembly.1 Installation of 7-1/16" Nominal Tubing Hanger 1. Lower the Tubing Hanger through the BOP stack into the Tubing spool bowl. 2. Make up the bottom flanged connection with stud bolts and nuts. Ensure that the Anchor Screws around the Tubing Spool are backed out.3.5.4 Installation of tubing spool 1. Strap the control line with the Tubing.4. Drill hole to suit the 3½” / 2-7/8" Tubing. Remove the test Plug after testing. b) Connect the control line to the Tubing Hanger inlet. Test Plug Bushing 1. 5. being careful not to damage the sealing surfaces on the Tubing Hanger.5 3½” / 2-7/8" TUBING AND WELLHEAD EQUIPMENT 10. Nipple down the BOP stack and riser. 6. carefully. Test plug assembly. Connect the control line to Bonnet Exit. 10. 7. 3.5.2 INSTALLATION OF X-MAS TREE The complete X-mass tree has been assembled and tested in the plant prior to delivery to the well site. Inspect Ring grooves at the bottom of X-Mass tree and top of Tubing Spool. Test Tree to the Rated Working pressure. 2.Well Head Fitting 10. Open all Valves. In the case of Actuator operated valves. connect the control line in the following manner: 6. Test the connection through the test port on the bottom flange of X-mass Tree Bonnet. Install Ring Joint Gaskets in the Tubing Spool. 5. 8. Tighten the fitting. 1. remove the 1/2" NPT Seal Plug and apply the Rated Control line pressure through the 1/2" NPT Inlet Port. 9. 95 . Install swage lock fitting at the Bonnet exit location. Reinstall the Thread protector. 4. Then remove the Thread Protector and Shipping Washer. Lower the X-MAS TREE on to the Tubing Spool and make up the Flanged connection using the Stud bolts and nuts. In case of provision for Control line exit through Bonnet. Minimum requirement criteria a) BOP stack must withstand the maximum well head pressure estimated as per calculations. b) The internal bore should be large enough to pass the drilling tools and tubulars required for the subsequent operations. 3. Environment operations i. If the rated working pressure and size of wellhead flange does not match with the BOP stack. it leads to the use of adopter flanges. D. casing slip and seal assembly. A. rural or isolated place to ensure required degree of protection for men. 2. storage facilities (specially for rubberized parts). inventory management. Space between top of cellar pit and bottom of rotary table Blowout preventer stack configuration is to be selected on the basis of available space and for different types of rigs owned by ONGC. bit and other drilling tools likely to be used and the following points must be kept in mind while selecting the BOP stack.11 BOP STACK 11. Infrastructure facilities to repair test and replace BOP and its sub assemblies.e.1 BLOWOUT PREVENTER SIZING The required BOP equipment must be selected in such a manner that vertical bore is sufficient enough to pass the casing. c) The stack must have provision for inlet and outlet of fluid under controlled pressure. 4.Drilling Operation Practices Manual CHAPTER . Some blends of drilling and completion fluids can have detrimental effects on elastomer compounds.g. urban. equipment and ecological environment. The original equipment manufacturer should be consulted regarding compatibility with drilling and completion fluids. H2S environment requires H2S trim blowout prevention equipment to resist Sulphide stress cracking. the BOP stack is installed on various section of wellhead. Nitrile elastomeric components may be suitable for H2S service provided drilling fluids are properly treated. etc. 96 . Matching connection to the size & press rating of w/head flanges At different stages of drilling. Availability of BOP spare parts at drill site. While designing BOP stack efforts should be made to use minimum number of flange connections on the stack. B. casing hanger. d) Annular BOPs may have a one step lower rated working pressure than the ram BOPs. Corrosiveness of drilling fluids and formation fluids: e. Service conditions Service conditions refer to the following aspects: 1. C. Working pressure rating of wellhead should be equal or more than the maximum expected surface pressure as estimated for selection of blowout preventer. BOP Stack Table Rated working pressure, psi Min. vertical bore, in Ring joint gasket R / RX 2M 3M 16 ¾ 21 ¼ 7 1/16 9 11 13 5/8 20 ¾ 7 1/16 11 13 5/8 16 ¾ 18 ¾ 21 ¼ 7 1/16 9 11 13 5/8 16 ¾ 18 ¾ 21 ¼ 7 1/16 9 11 13 5/8 65 73 45 49 53 57 74 46 54 BX 160 162 163 165 156 157 158 159 162 164 166 156 157 158 159 5M 10 M 15 M / 20 M M = 1000 psi 11.2 NOMENCLATURE Blowout prevention system consists of blowout preventer stack, kill line, choke line, choke and kill manifold, closing unit, diverter and auxiliary equipment. Component code adopted for designation of BOP stack configuration as per API RP-53 is given below: G - Rotating head A - Annular type blowout preventer R - Single ram type preventer Rd - Double ram type preventer with two sets of rams. Rt - Triple ram type preventer with three sets of rams. S - Drilling spool with side outlets for connecting choke and kill lines. M - 1000 psi rated working pressure. 97 Drilling Operation Practices Manual Components are listed reading upwards from the uppermost piece of permanent well head equipment or from bottom of the preventer stack. A blowout preventer stack may be fully identified by a very simple designation such as : 5M, 13 5/8”, RSRdA. This preventer stack would be rated 5000 psi working pressure and would have through bore of 13 5/8”. Ram type preventers should be equipped with extension hand wheels for manual locking or hydraulically operated locks. 11.3 BASIC COMPONENTS OF BOP STACK a) Annular Preventer The Annular Preventer is designed to close and seal over the open hole or around different shapes such as square and hexagonal kelly, tool joint etc including wire line except stabiliser and bit. b) Ram Type Preventer Pipe ram is designed to close and seal around a pre designated size of pipe, whereas, presently available variable rams can seal around a pre designated range of pipe size. Blind ram is used to close and seal an open hole. However, these days blind cum shear rams are in use, which can shear the pipe and seal the open hole as well. Note : Pipe rams are not designed to close and seal around tool joint and coupling. c) Drilling Spools Choke and kill lines may be connected either to side outlets of the BOPs or to a Drilling spool installed below at least one Ram BOP. Utilization of the BOP side outlets reduces the number of stack connections and over all BOP stack height. However, a drilling spool is used to provide stack outlets (to localise possible erosion in the less expensive spool) and to allow additional space between preventers to facilitate stripping, hang off, and/or shear operations. Criteria for Drilling Spools a) 3M and 5M arrangements should have two side outlets no smaller than a 2-inch nominal diameter and be flanged, studded, or hubbed. 10M, 15M, and 20M arrangements should have two side outlets of minimum 3-inch nominal diameter and should be flanged, studded or hubbed. b) It shall have a vertical bore diameter equal to that of mating BOPs and at least equal to the maximum bore of the upper most casing/tubing head. c) It shall have a rated working pressure equal to the rated working pressure of the installed ram BOP. For drilling operations, well head outlets should not be employed for choke and kill lines. d) Choke Manifold and Choke Lines The choke manifold consists of high pressure pipe, fittings, flanges, valves and manual and/or hydraulic operated adjustable chokes. This manifold may bleed off well bore pressure at a controlled rate or may stop fluid flow from the well bore completely, as required. Choke Manifold Recommended practices for installation (Surface installation): 98 BOP Stack a) Manifold equipment subject to well and/or pump pressure (normally upstream of and including the chokes) should have a working pressure equal to or greater than the rated working pressure of the ram BOPs in use. b) The choke manifold should be placed in a readily accessible location, preferably outside the rig structure. c) All choke manifold valves should be full bore. Minimum two valves are recommended in choke line immediately after the BOP stack with rated working pressure equal or greater than the rated working pressure of Ram BOP in use. One of these two valves should be remotely controlled. During operations, all valves should be either fully opened or fully closed. d) A minimum of one remotely operated choke should be installed on 10000 psi and above rated working pressure manifolds. Generally, remote operated choke is not installed in 5000 psi working pressure manifold. If conditions dictate like for example the frequency of use of chokes is high, it will be prudent to use a remote choke (in addition to adjustable choke) in 5000 psi working pressure choke manifold. Choke manifold configurations should allow for re-routing of flow without interrupting flow control. e) Pressure gauges suitable for operating pressure and drilling fluid service should be installed so that drill pipe and annulus pressures may be accurately monitored and readily observed at the station where well control operations are to be conducted. f) Rig air systems should be checked to ensure their adequacy to provide the necessary pressure and volume required different controls. The remotely operated choke should be equipped with an emergency back up system such as a manual pump for use in the event air becomes unavailable. Installation guidelines – choke lines The choke line and manifold provides a means of applying back pressure on the formation while circulating out influx from the well bore. The choke line and lines downstream of the choke should: a) 1. Be as straight as possible. Wherever the bends, blocks and tees are provided, they should be targeted to minimize erosion. 2. For flexible lines, manufacturer’s guidelines should be consulted on working minimum bend radius to ensure proper length determination and safe working configuration. b) Be firmly anchored to prevent excessive whip or vibration. c) 1. Have a bore of sufficient size to prevent excessive erosion or fluid friction. Minimum recommended size for choke lines as per API is 2” nominal diameter or 3M and 5M arrangements and 3” nominal diameter for 10M and above rated arrangements. 2. Minimum recommended nominal inside diameter for lines downstream of the chokes should be equal to or greater than the nominal connection size of the chokes. 3. For air or gas drilling operations, minimum 4” nominal diameter lines are recommended. 4. The bleed line that bypasses the chokes should be at least equal in diameter to the choke line. Kill lines and kill manifold Kill lines are an integral part of the surface equipment required for well control during drilling. The kill line system provides a means of pumping into the well bore when the normal method of circulating down through the kelly or drill pipe can not be employed. The kill line connects the drilling fluid pumps 99 Drilling Operation Practices Manual to a side outlet on the BOP stack. The location of the kill line connection to the stack depends on the particular configuration of BOPs and spools employed; the connection should be below the ram type BOP most likely to be operated. Installation guidelines - kill lines a) All lines, valves, check valves and flow fittings should have a working pressure at least equal to the rated working pressure of the ram BOPs in use. b) For working pressures of 3000 psi and above, flanged, welded, hubbed or other end connections that are in accordance with API Specification 6A, should be employed. c) Components should be of sufficient diameter to permit reasonable pumping rates without excessive friction. The minimum recommended size is 2-inch nominal diameter. d) As per API, two full bore manual valves plus a check valve or two full bore valves (one of which is remotely operated) between the stack outlet and kill line are recommended for installations with rated working pressure of 5000 psi or greater. e) Lines should be as straight as possible. When bends are required to accommodate either dimensional variations on sequential rig ups or to facilitate hook up to the BOP, the largest bend radius allowable under the hook up restraints should be provided. For flexible lines, manufacturer’s guidelines should be followed to ensure safe working configuration. f) All lines should be firmly anchored to prevent excessive whip or vibration. g) The kill line should not be used as fill-up line during normal drilling operations. Standard choke and kill manifold The standard choke and kill manifolds in use/ available in ONGC are: i) 4 1/16” –5000 psi working pressure. ii) 4 1/16” –10000 psi working pressure. iii) 3 1/16” –15000 psi working pressure. 11.4 INSTALLATION OF BOP The first step in fitting BOP is the installation of a drilling spool over well head. 1. Clean the casing head flange and put steel ring gasket of correct type and rating. 2. Clean both the flanges of the spacer spool, if required to use. 3. Fit a spacer spool above the casing head. The length of the spacer spool should be so adjusted that the upper face of the spacer spool comes in line with the ground level. Both the flanges of the spacer spool should be of the same rating and size as the casing head flange. 4. Install Ram type preventor equipped with pipe rams matching with drill pipe sizes to be used (incase of 10,000/15,000 psi BOP stack). 5. Install drilling spool on the spacer spool or pipe ram BOP, if needed. 6. Care should be taken to select the drilling spool having flanges of same pressure rating as that of the BOP. 7. The two diametrically opposite side outlets should have the same pressure rating as choke and kill lines respectively. 8. The vertical bore should be at least equal to the maximum inner diameter of the inner most casing. 9. While installing drilling spool, the two side outlets of the spool should point in the direction in which choke and kill lines are to be fitted. 100 BOP Stack 10. Lift double ram BOP so that the BOP’s upper position in on the top side. Top rubber seal of the rams should be on the upper side. The arrow marking on BOP also indicates top position. 11. Place the correct ring gasket in the groove on the drilling spool. 12. Slowly tower BOP (the direction of the BOP handles should be so kept that BOP rams can be easily operated) and rest BOP on the drilling spool. 13. Tighten the double ram BOP on the drilling spool (in case the studs can not be put from below the drilling spool or from above the BOP then the same are to be positioned in the drilling spool before lowering BOP). 14. Clean the top ring groove of the ram type BOP, put the ring gasket of correct size and rating. 15. Lift annular BOP and slowly install it above double ram BOP taking proper care to keep the fluid outlet valves on the sides so that the fluid lines can be easily fitted. 16. Clean the ring groove above the annular BOP and install the ring and the flow nipple to facilitate the flow of mud from the well bore to the shale shaker. 17. Connect BOP handles on the double ram BOPs ensuring that manually operated shafts and wheels must extend beyond the substructure boundary and be easily accessible. 18. Erect a shield of wooden planks over control wheels of preventers and on the wall in front of the hand wheel, the direction and number of turns which are required for preventer closure should be displayed by an arrow in red paint. Installation of Choke and Kill Line Kill Line 1. Fit the adapter spool with the drilling spool. 2. Using proper ring gasket and studs and nuts tighten two valves of proper rating with the adapter spool. 3. Install one tee after the valves and fit a pressure gauge in the blind flange having threaded opening for fitting the pressure gauge. 4. Install one non – return valve. 5. Install one tee of proper rating. 6. Install the line from mud pump on one side and a line from the cementing unit from the other side of the tee. Install valve on this line. Choke Line 1. Install the adapter spool (if required). 2. Connect one valve (stand by valve). 3. Install the remote control hydraulic valve. 4. Connect choke flow line having flanges of required rating at both the ends between the hydraulically operated valve and the choke manifold. Choke Manifold 1. As chokes get worn out due to erosion or plugging with large formation particles it is essential to provide chokes in parallel to the flow line, thereby necessitating the installation of a manifold called the choke manifold. 2. Hydraulically operated or manually operated chokes are installed in the choke manifold. 3. Strategically placed gate valves will permit the use of one choke while the others are disconnected. 4. Two valves should be installed ahead of each choke to be used for regulating the flow. 101 Drilling Operation Practices Manual 5. The choke manifold should have one connection from the manifold after the choke to the mud tank and one connecton to the flare line. 6. The pressure rating of various valves in the choke line prior to choke and in the full bore line should be equal to or more than the pressure rating of the BOP. 11.5 RECOMMENDED PROCEDURE FOR TESTING BOP STACK AND ALLIED EQUIPMENT Since all the equipments used in well control are essential to the safety of the well, the crew members, the rig and the surrounding environment; testing procedures of these vital surface BOP equipment becomes an important integral part of the drilling programme. For optimum control of any well kick situations successful functioning of the blowout preventer stack, choke and kill lines and other related equipment at their rated capabilities becomes pertinent. The only way to make certain and ensure that the equipment will perform at its rated capacity when needed is by adhering to regular test procedures. The situation requires both rigorous test procedures that evaluate pressure integrity of all parts in the system and at the same time exposing the equipment to periodical function tests will keep the equipment in readiness for operations in addition to suggesting if any maintenance work is required to be carried out in advance. All the important considerations for BOP stack testing and the test procedures are discussed. 11.5.1 Need of Periodic Testing Considering many likely causes of failure of blowout preventer equipment, the need for periodic testing of BOP’s assumes a great importance and is a must. The purpose of various field tests of BOPs (well control equipment) is to verify: a) Those specific functions are operationally ready. b) The pressure integrity of the installed equipment. c) The control system and BOP compatibility. It becomes pertinent to identify the causes and take remedial measures in order to rectify the same. 11.6 REASONS OF FAILURE OF BOP STACK AND CHOKE AND KILL MANIFOLD • Equipment may not have been installed properly. • Vibrations and extra loading during drilling operation may cause leak. • Lines and fittings may be abraded by mud flow. • Cement, baryte and sand may sometimes accumulate or settle out and plug. • Corrosion may cause damage to choke lines & equipment. • Partially closed valve may get eroded. • With passage of time, rubber sealing elements may get deteriorated and fail when subjected to test conditions. • Badly stored items, when used may not perform at rated capacity. • Normal wear and tear also results in malfunction of the equipment. • Rubber sealing elements and packers may not be compatible with the mud system or subsurface environment such as temperature. 11.6.1 Important Considerations Important considerations in blowout preventer testing are : 102 BOP Stack • • • • • Test fluids Test pressures Testing equipments Test procedures and their frequency Test duration A. Test Fluids In normal application, clear water is considered as the best test fluid, as drilling fluid may plug small leaks. It should be ensured that air is removed from the system before test pressure is applied. B. Test Pressures All BOP components that may be exposed to well pressure should be tested first to a low pressure of 200 to 300 psi and then to a high pressure. i. Low pressure test: The stack is generally washed and cleaned with water before testing. However, it is possible that existence of dry mud particles may be covering a potential leak spot. In such cases high pressure test may pack the mud particle in the leak spot and affect a temporary seal. Hence low pressure test of 200 to 300 psi is recommended for rams , annular preventers, manifolds, lower kelly cock, etc. Also in performing a low pressure test, do not apply a high pressure and bleed down to low pressure. Should a leak occur at low pressure, corrective remedial measure may be taken accordingly at this stage. ii. High pressure test: After initial installation of BOP on well head, i. Rams, choke manifold and choke/ kill lines should be tested to the rated working pressure of the ram BOPs or to the rated working pressure of the well head on which the stack is installed, which ever is lower. ii. Annular BOPs may be tested to 70% of the rated working pressure or to the test pressure applied to the ram BOPs, which ever is lower. iii. Lower kelly cock, kelly, upper kelly cock and drill pipe safety valve should be tested to the rated working pressure. iv. In case of instances where available BOP stack and / or the well head has higher working pressure than are required for the specific well bore conditions due to equipment availability, a site specific well control test programme can be followed. Subsequent high pressure test of ram BOPs and choke manifold should be limited to a pressure greater than the maximum anticipated surface pressure but not to exceed the working presure of the ram BOPs. The maximum anticipated surface pressure should be determined by the operator based on specific well conditions. Annular BOPs should be tested to a minimum of 70% of their working pressure or to the test pressure of ram BOPs, which ever is lesser. In case of downstream valves of choke and kill lines, test pressure on initial as well as subsequent tests should be limited to 50% of its rated working pressure. C. Test Duration A stable low test pressure as well as stable high test pressure should be maintained for at least 5 minutes. 103 Test Plug Fig. Testing Equipment Following equipments are usually used while testing BOP equipment : a) Pumps: The pumps used to generate pressures for testing may be any type i. test plug must be used to isolate the entire casing and open hole from the applied test pressures. Test Frequency Function test: All operational components of the BOP equipment systems should be function tested at least once a week.Drilling Operation Practices Manual D. Cementing units with of desired high pressure rating can safely be used if conveniently available. c) Not to exceed 21 days. Cup Tester Fig. A small high pressure pump is generally used in most of the testing applications. c) Commonly used test tools are : • cup tester • test plug Fig. Pressure test: Pressure test on the well control equipment should be conducted at least a) Prior to spud or upon installation b) After the repair/ disconnection of any pressure containment seal in the BOP stack. b) Test plugs: While testing BOP stack and other equipment. These test plugs are set in the bottom of the preventers.e. Testing BOP with Cup Tester / Test Plug 104 . E. 3. capable of attaining the desired pressures. 2. there by preventing communication of pressure below the test plug. but limited to the affected component. 1. choke line or choke manifold. At the time of pressure testing. BOP pressure test will be limited to 70-80% of the burst rating of upper part of casing. Higher grade of drill pipe to be used as test pipe other wise yield strength of drill pipe may limit the test pressures. i. So. 105 . Different makes of well head have different types of test plugs. Testing Procedure Testing procedures are integral part of the drilling program and as such a specific programme of equipment testing is mandatory. It can be connected between the test plug and test joint after making suitable end connections so that the sub is positioned against the casing ram to be tested. The test (ram BOP and annular BOP) should be conducted when the drill string is inside casing. while lowering test plug it should be confirmed this plug is compatible with the well head used other wise it may get stuck and can lead to another problem which will result in loss of valuable rig time.BOP Stack Cup Tester It has a mandrel with box connection on top. leaving the test plug resting on the well head. Care must be taken while using test plug for its designed compatibility with the existing well head used. Test should be conducted after installing FOSV/ inside BOP on drill string. This plug is to be lowered and landed into the well head with a test drill pipe joint after adding few stands of HWDP or equivalent weight to the bottom. To test the blind or shear blind ram. The cup of the tester gives effective sealing in the casing. Pressure is built up by pumping down the kill lines to provide desired pressure. 3. With seal on the body it isolates the upper part of the well head and the well bore. Test Plug Test plugs have mainly a box on top to connect test pipe and pin on bottom to add some weight on it. The limitations of the cup tester: 1. These test plugs are designed to seat in well head. 2. tension load on pipe will increase with increase in test pressure. After filling the stack with water. F. the pipe rams or the annular is closed. iii. This added weight of drill collars will help in seating properly in the well head and give proper sealing. Testing procedures are discussed under heads: • function (actuation) testing • pressure (hydraulic) testing FUNCTION TEST Function test is performed to verify the component’s intended operations. Both pneumatic and electric pump of accumulator unit should be turned off after recordinginitial accumulatorpressure. d) Casing ram test sub: To facilitate testing of casing ram it is essential to have the casing ram test sub. a cup and a sub with pin connector on bottom. Since cup tester is freely hanging in the casing. the cup tester is made up on drill pipe and should be lowered to be placed in the casing opposite to the slips in the casing spool or casing head. ii. test pipe should be removed. This can not be used to test blind/ shear blind rams. iii. Check closing line and preventer for leaks. Retest the blind ram as detailed above. test up to final test pressure as decided. Close valve nos. Flush all the lines and BOP with water. Apply pressure by cementing unit or high pressure test unit through main kill line and pressurise upto 200 to 300 psi and hold for 5 minutes. If pressure is holding. vi. Blind ram should be operated for function test when drill string is out of hole.3 on kill line and close valve no. Function test should be carried out alternatively from main control unit/derrick floor panel/ auxiliary panel. 7. Open all the valves and chokes in choke line and choke manifold and allow water to flow through each out let. If leakage is observed corrective action may be taken after releasing pressures and opening blind ram. Set the plug in casing head seat. Make up appropriate casing head test plug on a stand of drill collar and run in the same on a joint of drill pipe. xii. xi. Open both the valves on casing head below test plug seals to recognize leaking seals as well as well activity and prevent formation or casing damage in case of any leakage through test plug. Closing time should not exceed 30 seconds for all ram preventers and annular preventers smaller than 18 3/4” closing time should not exceed 45 sec for annular preventer of 18 3/4” and larger size. shape and contour matches with that of casing head where it will seat. viii. vi. and seals that are under pressure. Record final accumulator pressure after all the functions should not be less than 1200 psi or 200 psi above the pre charged pressure of accumulator which ever is maximum. Close blind ram with 1500 psi closing pressure. v. All the ram preventers ( except blind/shear) and HCR’s in choke/kill line should be functiontested and closing time should be recorded. check all the valves. ii. x.43. 4) i. ix. Again hold for at least for 5 minutes. Open blind rams with 1500 psi. xi. PRESSURE TESTING Testing of Blind Ram (Ref fig. flanges. All the gate valves and blow out preventers should be returned to their original position and continue normal operations. Fill preventers with water. Operation of shear ram should be kept to bare minimum. Also check blind ram and test plug for leaks. Check opening lines for leaks. v. Ensure that test plug size. Record test results. If there is a drop in pressure.9 on choke line and valve nos. Pipe ram should be closed against correct size pipe in the hole. viii. ix.Drilling Operation Practices Manual iv. vii. 106 . iv. x. vii. 2. Back off and remove drill pipe joint. All the results should be recorded in the prescribed formats. Fill and top up BOP with water. Run in appropriate size (smallest size of drill pipe to be used in case of testing of annular BOP) of drill pipe and make up with test plug. vi. iv. Testing of Blind Ram Testing of Annular BOP and Pipe Rams (Ref fig. Flush lines flushed with water. viii. ii.9 on choke line and valve no 3. Close annular preventer with appropriate closing pressure as per manufacture recommendation.6 on kill line. v. vii. 4. Check closing line and annular preventer for leaks. Close valve No 7. Make up test plug with sufficient weight and rest test plug at well head.BOP Stack TESTING OF BLIND RAM 35 36 34 33 39 38 40 37 41 42 LEGEND FLOW DIRECTION VALVE CLOSED VALVE OPEN FROM MUD PUMPS ANNULAR 29 CHOKE MANIFOLD PIPE RAM 13 14 BLIND RAM 43 20 15 KILL LINE 4 5 6 9 10 PIPE RAM 18 1 CASING HEAD 2 3 7 8 19 28 TESTING PLUG WITH PORTS 31 CHOKE LINE 11 12 16 17 21 26 25 FROM CEMENTING PUMP 23 24 22 30 27 Fig. iii. Make up FOSV on top of drill pipe. 5) i. Ensure that integral port in the test plug is open. Fill up drill pipe with water. 107 . then increase the pressure upto final test pressure and hold for at least 5 minutes. If the pressure is holding.Drilling Operation Practices Manual TESTING OF PIPE RAMS AND ANNULAR BOP 35 36 34 33 37 40 TEST PRESSURE THROUGH DRILL PIPE 39 38 41 42 LEGEND FLOW DIRECTION VALVE CLOSED FROM MUD PUMPS ANNULAR CHOKE MANIFOLD VALVE OPEN 29 PIPE RAM 13 14 43 FROM CEMENTING PUMP 32 KILL LINE BLIND RAM CHOKE LINE 15 20 21 26 25 4 5 6 9 10 PIPE RAM 11 12 16 17 18 23 24 22 30 1 CASING HEAD 2 3 7 8 19 27 28 TESTING PLUG WITH PORTS 31 Fig. Test pressure should be limited to the pressure rating of the weakest member exposed to the test pressure. xiii. 5. apply test pressure through drill pipe and raise pressure upto 200 to 300 psi and hold for five minutes. Check for any leakage. xiv. xi. xii. xv. Testing of Annular BOP and Pipe Rams ix. Check for any leakage. Check for leaks and release pressures. Again. If pressure is holding. x. Check closing line and preventer for leaks. Apply test pressure through drill pipe and raise pressure to 200 to 300 psi and hold for 5 minutes. Check for leaks and release pressures. increase the pressure upto final test pressure and hold for at least 5 minutes. xvii. Open annular preventer. Open pipe rams with 1500 psi. xvi. Now close upper pipe ram with 1500 psi. 108 . 30. Choke Line. Repeat step 3.21. open valves 15.16.24 and close valves 25.45 and close 46. open valves 3. Flanges and Fittings (Ref fig. xix. Make sure that the pipe rams size fits the drill pipe size in the well. v. Kill and choke lines and manifold fittings are flushed with water.38. if not change the drill pipe and then test the rams. xv. close upper pipe ram and open all valves and chokes on choke manifold to allow the flow of water through each outlet.7 and 9 and close 2. Check for any leakage. corrective action may be taken after releasing pressure and retested as per procedure detailed above. Now open chokes 13. x. Open valve 43 and close valve 37 and open valve 11 and close valves 15.26. Repeat step iii.34. Repeat step 3.45 and open valve 2. Manifold Valves.39 on kill line side. Remove the spring loaded valve in the check valve no.32 and open valve 2. If there is any leakage.6.26. so that other valves in the kill line can be tested.22 and 23. Testing of Kill Line.20.28 and close valves 29.Check opening lines and preventer for leaks.35. 109 . Repeat step 3 to test check valve 4.10.BOP Stack xviii. Repeat step 3 to test 46. Repeat step iii.25. iii. Test all other pipe rams in this manner by repeating step no. Repeat step xi.23 and close choke 13.27 and 28. xvii.12 and open valves 8.6.16 and 17. To test check valve 1.40.42 on kill line side and open valves 14. Apply test pressure through drill pipe and raise pressure upto 200 to 300 psi and hold for 5 minutes. ix. xi. Re test the rectified components. Finally. For this purpose. Open valves 44. Next.18.8 and 10. vi. then increase the pressure up to the rating of the weakest member exposed to test pressure (same as that of ram BOP) and hold for 5 minutes. Apply test pressure and raise upto 200 to 300 psi and hold for 5 minutes. Repeat step iii. the procedure mentioned below is followed to conduct the above test: i. Next close valves 44. xii.27. Check for any leakage. 3) From the previous test with the test plug seated in casing head. xvi. ii. vii.24 on the manifold. Repeat step 3 to test 44 and 45.11.20. On choke manifold. Variable bore rams should be initially pressure tested on the largest and smallest OD pipe sizes that may be used during the well operations xx.39 and close valves 33. open valve 2 and repeat step 3. xiii. Close valves 6. increase the pressure up to 50 % of the rated working pressure of components down stream of chokes. Now close valves 43. iv. If pressure is holding.19. viii. 4 . ix to xiv.18 21.17 and close valves 14. Open valve 37 and close 36. If pressure is holding. Hold pressure for at least 5 minutes. flanges and seals which are subjected to test pressure for leaks. Check all valves.19.5. Release pressure and rectify the leakages if any. Close valves 3.7 and9 keeping upper pipe ram closed. Next open valves 36.41.31. xiv. open valves 22. Testing of Kill Line. Choke Line.Drilling Operation Practices Manual TESTING OF CHOKE AND KILL MANIFOLD VALVES 35 36 40 LEGEND FLOW DIRECTION VALVE CLOSED VALVE OPEN 34 33 37 39 38 41 42 TEST PRESSURE THROUGH DRILL PIPE FROM MUD PUMPS ANNULAR 29 CHOKE MANIFOLD PIPE RAM BLIND RAM 43 15 CHOKE LINE 6 9 10 PIPE RAM 18 1 CASING HEAD 2 3 7 8 TESTING PLUG WITH PORTS 11 12 16 17 13 14 20 21 26 25 FROM CEMENTING PUMP KILL LINE 4 5 23 24 19 22 30 27 28 31 Fig. Open appropriate stand pipe valves and kelly valves. xx.Record test pressures. Using an adapter. An alternate method for testing kelly cocks and rotary hose will be to apply test pressure through kill lines with test plug seated and pipe ram closed. install full open safety valve on bottom of lower kelly cock. connect to a high pressure test pump or cementing pump. Fill system with water and close stand pipe valve. it is to be ensured that the port provided on the test plug body should be open. Flanges and Fittings xviii. 11. 6. 110 .7 TESTING OF KELLY COCKS AND ROTARY HOSE Pick up kelly. Here. Install check valves on the auxiliary and main kill line respectively. Pressurise to test rotary hose and kelly cocks in sequence. xix. Remove test plug along with drill collar. Manifold Valves. Drill cement at 3 – 4 tonnes of weight on the bit and rotary rpm as 50-60 only. Calculate the shoe test pressure. The shoe is considered OK if the pressure does not fall more than 10% of the test pressure during this time.8 MUD LINE SUSPENSION SYSTEMS Mud line suspension systems provide temporary abandonment and re-entry capability for exploratory.. 2. 8. After testing of BOPs and choke and kill manifold. 111 . 1. Continue drilling till 0.5m below the casing shoe – formation should not be opened. Both the volumes should be almost equal. Run in drill string and bit.BOP Stack Casing Test 1. squeeze cement and report all the procedure for testing shoe. and other wells drilled from bottom-supported rigs. Close pipe ram BOP and kelly cock. 7. compact casing hangers with casing threads top and bottom. Do not exceed 80% of the burst rating of the casing. template. up to the top of the cement. If the shoe is hermetical. Circulate the cuttings out of the well. kill and choke lines with water.1 MLH Mudline Suspension System The MLH midline suspension system has short.8. Open Kelly cock. Note: In case the shoe does not hold up to the required pressure. Flush the BOP stack. 9. 4. Break circulation and test casings to 200 psi greater than the anticipated shoe test pressure. Float Collar and Float Shoe 1. Make cementing unit connection with choke line. Pull the drill string in the casing. Close gate valve on kill line. 2. The various MLS systems available in the market of leading brand Vetco are: 11. and measure the volume of fluid recovered and compare this with the volume pumped. 10. 2. 6. This is the sum of surface pressure and the hydrostatic pressure of the fluid being used during the test. Drilling of Cement. 3. delineation. 4. (for plotting the graph see leak off test). 11. 3. Drill float collar and float shoe carefully. Hold the required test pressure for 15 min. the following sequence of operation are followed to test casing. 3. Release the pressure through choke line. 5. It is equal to the hydrostatic pressure at the shoe of the heaviest mud that will be used in the well before running the next string of casing volume pumped. Shoe Test This test is done to determine the complete of cement job around the shoe. the plot will be linear. Drilling Operation Practices Manual 13-3/8” Mudline Hanger 20” Mudline Hanger 20” Landing Rig 9-5/8” Mudline Hanger This system is used when a casing load suspension system is required but it is not to be used to run and tieback at the mud line. and allows a major portion of the casing loads to be suspended at the mud line during drilling and completion of platform wells with traditional surface equipment. transferring the loads through the collet to the previously installed hanger. 112 . It can also be used during jack-up drilling operations. The MLH system is ideally suited for use on development platforms. There is standard casing connections on top and bottom of each mud line casing hanger Shoulders support the loads of the concentric casing strings. Mud line MLC-E Suspension System 20” Running Tool 20” Tieback Latch and Lock Tool 13/38” Running Tool 13/38” Tieback Latch and Lock Tool 9-5/8” Running Tool 9-5/8” Tieback Latch and Lock Tool 20” Mudline Casing Hanger 30” Landing Rig 13/38” Mudline Casing Hanger 9-5/8” Mudline Casing Hanger RUNNING MODE TIEBACK MODE 113 .2.BOP Stack 11.8. 00” Wall RL.8. MLC emphasizes simplicity and economy without sacrificing high pressure and hanging weight capacities.3 Slimhole Mudline System for Jack-up Drilling 30” x 1.Drilling Operation Practices Manual 11. 4LH Pin 13-38” Running Tool 20” MLC Casing Hanger 9-5/8” Running Tool 7” Running Tool 13-38” Casing Hanger Clamp 9-5/8” Casing Hanger 7” Casing Hanger Landing Joint Split Centraliser 30" x 20" x 13-3/8" x 9-5/8" Casing Program This is ideal for most jack-up drilled exploratory or development wells. 114 . Long lead in stab guidance Maximizes thread and seal protection. - - 115 . Over-torque protection on all running. All casing hangers have robust left-hand threads Allows for rapid operation and ease of removal at suspension. 13-3/8" and 9-5/8" casing hangers also have finer right-hand tieback threads Allows for careful makeup of permanent metal-to-metal seal in tieback/production applications.BOP Stack Features and Benefits . Indication at the rig floor that the wash ports are exposed.Generous washout ports in the running tool Ensures no cement contamination around the running tool to give reliable well suspension. Three metal-to-metal seal areas for running tool. corrosion cap and tieback tool on 13-3/8" and 9-5/8" hangers This gives a new seal area for each tool that is run into the hanger. hence giving maximum seal reliability. giving maximum seal reliability. tieback tools and corrosion caps Protects the seal area from damage due to incorrect installation. If the hole does not take the calculated volume of mud. it is assumed a formation fluid has entered the wellbore. TERTIARY WELL CONTROL It involves the techniques used to control a blow-out once the primary & Secondary Control are lost.12 WELL CONTROL KICK It is defined as an influx or flow of formation fluid into the well-bore & can occur any time the formation fluid pressure is greater than the bottom hole pressure being exerted in the well bore. The maintenance of sufficient hydrostatic head exerted by drilling fluid to hold back the formation fluid pressure is termed as “Primary Well Control”. or in other words secondary well control involves detection & safe handling of kicks so as to re-establish primary well control. b) Swabbing. the primary control may be temporarily lost and a proper use of blow out preventers & kill procedures will provide Secondary well control. c) Abnormal formation pressure. BLOWOUT It is an uncontrolled flow of formation fluid at the surface or sub surface from the well bore. 12. The main factors which can lead to this condition can be classified as : a) Improper hole fill up on trips. Even though gas or salt water entered the hole.Drilling Operation Practices Manual CHAPTER . e) Lost circulation. the mud level decreases by a volume equivalent to the steel volume. f) Gas cut mud More than 50% of the kicks occur due to first two of the causes listed above.1 CAUSES OF KICKS Kicks occur as a result of formation pressure being greater than mud hydrostatic pressure which causes fluid to flow from the formation into the well bore. a) Improper hole fill up on trips When the drill string is pulled out of the hole. This primarily involves a re-establishment of the secondary control system such as : the well bore conduit. PRIMARY WELL CONTROL During normal drilling operations the hydrostatic pressure of drilling fluid is greater than the pressure of the fluids in the formation. well head & BOP equipment & subsequently establishing the Primary Control. formation fluid may enter in the well bore & if so happens. SECONDARY WELL CONTROL If due to any reason hydrostatic pressure in the well bore falls below the formation pressure. A Blow-out is the result of an uncontrolled kick. the 116 . d) Insufficient mud density. the problem may become more severe. There are various geological reasons for abnormal pressures. If the hole is not filled to replace the steel volume. hole configuration and effect of balling up of BHA & bit. At the same time the pulling out of drill string causes a reduction in BHP due to swabbing effect. trip tank should be used to monitor displacement volume correctly at regular intervals. If at any stage during pulling-out it is observed that the actual filled in volume is significantly less than volume of steel that has been removed. annular clearance. e) Lost circulation Lost circulation is another factor which reduces the hydrostatic pressure. Similarly while running in drill string. while pulling out the well should be filled continuously by using trip tank and differences of calculated and actual mud volume be recorded at regular interval. 117 . Therefore. The best solution is to maintain the mud density slightly greater than that required to balance the formation pressure in order to avoid mud loss. most often the formation pressures are not known accurately. Therefore to avoid the possibility of any formation fluid entering the bore hole due to combination of above two factors the hole should be properly / regularly filled during tripping out. It is a recommended practice to keep the annulus always topped to avoid considerable reduction in BHP when lost circulation is encountered. Irrespective of the practice being used an accurate method of measuring the amount of fluid actually being taken by hole should be monitored and an accurate record of actual volume v/s theoretical volume should be kept. b) Swabbing Swab pressures are created by pulling out the drill string from the borehole. While drilling. the formation fluid may begin to flow into the well bore.Well Control well may not flow until enough fluid has entered to reduce the hydrostatic pressure below the formation pressure. Various factors conducive to swab pressures are pipe pulling speed. It reduces the bottom hole pressure. As a result the mud hydrostatic pressure becomes less than the formation pressure and may cause a well kick. sometimes the bit suddenly penetrates an abnormal pressure formation. When a kick occurs due to lost circulation. filtration cake. Kicks caused by insufficient mud density seem to have the obvious solution of drilling with high mud density. A large volume of kick fluid may enter the hole before the mud level increase is observed at the surface. it means that some formation fluids must have entered the wellbore. c) Abnormal pressure In case of wild cat or exploratory drilling. d) Insufficient mud density If a formation is drilled using a mud density that exerts less hydrostatic pressure than the pore pressure. a potential kick may enter the well bore. the fluid column in the wellbore shall go down and reduce the hydrostatic pressure. If the reduced bottom hole pressure becomes less than the formation pressure. mud properties. In the field normally the practice is to fill up the hole either on a regular fill up schedule or to fill up continuously with a re-circulating trip tank. In soft formation. A 200% to 300% increase in drilling rate is not unusual. An increase in drilling rate can be masked by an increase in mud weight. As differential pressure is reduced due to increase in formation pressure. They are listed below : i) Rate of Penetration Trends When abnormal pressure formations are encountered. it expands and reduces the hydrostatic pressure sufficient to allow a kick to enter. The early warning signs are indications of approaching higher formation pressure which means that the well may go under-balance if no appropriate action is taken. Early warning signs The detection of increasing formation or pore pressure is very essential in maintaining primary control of a well and preventing a kick. differential pressure & shale density are decreased causing a gradual increase in ROP. the 118 . For reservoir fluid to enter the well bore there must be a permeable section of reservoir rock. Increase in rotary torque is a good indication of increasing pressure and a potential well kick. the hydrostatic pressure is not reduced significantly since the most gas expansion occurs near surface & not at the bottom. Closing up of the hole may also increase torque. This will cause a change in drilling rate.Drilling Operation Practices Manual f) Gas cut mud Gas contaminated mud will occasionally cause a kick. A normal trend line is established and any deviation should theoretically indicate changes in pore pressure. v) Change in Cutting Size and Shapes Cuttings from normal pressure shale are small in size with rounded edges and are generally flat. The increase in drilling rate varies. A. a sand section usually causes a sudden increase in drilling rate. Cuttings drilled from abnormal pressured formation often become long and splintery with angular edges. Similarly bit weight changes can also mask the increase in drilling rate but careful observation of drilling rate or some such related parameter as “d” exponent can provide a timely warning of increasing pressure. The density of cuttings can be determined at surface and plotted against depth. iii) Increase in Torque & Drag As the difference between the mud hydrostatic pressure and formation pressure decreases (as a result of increasing formation pressure). the bit makes larger cuttings and the cuttings pile up around the collars and increase the rotary torque. Drag & fill up on connections and trips increase when high pressure formations are drilled. 12. iv) Decrease in Shale Density Shale density usually increases with depth but decreases in abnormal pressure zones. In hard formations a reverse drilling break to a slower drilling rate occurs in the reservoir like sandstone that are harder than the shale body. Although the mud density is reduced considerably at the surface.2 KICK INDICATION Following are the early warning signs & positive indications for kicks while drilling. As the gas is circulated to the surface. ii) Drilling Break The first indication of a possible well kick is a drilling break. The most common error with gas cutting is the tendency to maintain the mud weight at its original value with addition of barite and without removing all the gas. This increases chloride content of the drilling fluid and its filtrate. A change in cutting shape will be observed along with an increase in the amount of cuttings recovered at the surface and this could indicate that formation pressure in the well is increasing. Increase in back ground gas is not very reliable in detecting pore pressure increase. mud weight will effect d -exponent.) in transition zones. The temperature may take a sharp increase (5-7oF/100 ft. bit size and rotary speed in the equation as below: d Where. Connection and Back-ground Gas An increase in trip and / or connection gas should be considered as an indication that pore pressure is increasing. Gas readings are arbitrary and are not proportional to actual gas concentration in the mud. weight on bit. viii)Increase in Flow Line Temperature The temperature gradient in abnormal pressure formation is usually higher than normal pressure formation. Connection gas will normally occur on bottoms-up (calculated lag time) and if not re-circulated will not change the overall trend line except for short interval of time. The amount of feed in will determine the intensity of the trend change. Since moderate gas cutting contributes so little to bottom hole pressure reduction. This is because gas concentrations can change drastically in the formation being drilled without any increase in pore pressure. more cuttings & cavings will dissolve into the mud and increase the viscosity of the mud. The continuous measurement of the mud temperature at the flow line gives an indication of change in temperature gradient associated with abnormally pressured formation. x) Change in ‘d’-exponent Jordan and Shirley developed an equation for normalized penetration rate in which it was defined as a function of measured drilling rate.Well Control cuttings have a tendency to explode off bottom. ix) Increase in Trip. additional barite may increase the mud weight enough to cause lost circulation. A higher chloride trend can warn about increasing pore pressure. vi) Change in Mud Property As the pressure in the formation increases faster than the pressure of the mud column.Gas analyzers are used to establish trend line which is called background gas. These vary considerably from one mud logging unit to another. A gas feed in from a permeable zone will change this trend line. vii) Increase in Chloride Content in Mud Filtrate Drilling through high pressure formations having higher porosity results in contamination of drilling fluid with considerable volume of saline water from pores. Therefore absolute values of gas readings do not have much significance in detecting abnormal pressures. R N W Db = log (R/60N)/log (12W/103 Db) = = = = rate of penetration in ft/hr rotary speed rpm weight on bit in 1000 lbs bit diameter in inches Since the d-exponent tends to indicate the pressure differential between formation pressure and well bore pressure. The original calculation should be corrected as follows: 119 . 120 . basic requirement is that hole must be kept full of mud and the volume of mud required to fill the hole must be equal to the steel displacement of drill string pulled out. dc = MW1 = MW2 = d× (MW1 ÷ MW2 ) modified d-exponent mud density equivalent of formation fluid at normal pressure condition mud density being used in well dc values are plotted on a semi log graph paper at every 15 or 30 ft. Whenever such situation is noticed the pipe should be run back to bottom and mud is circulated to clear the hole. pump speed slowly increases. If the well does not flow. so flow check is a reliable method of checking for a well kick. If an increase in pit volume is seen. Abnormal pressure transition zone top is detected at the depth where dc exponent values against shale tend to decrease in comparison to normal values. The sequence of events to a kick while making a trip-out of hole is : • Hole remains full or does not take proper amount of mud. i) Increase in Return Flow (Pumps On) After the early warning signs the first positive kick sign is increase in flow rate at the flow line withpumps on. Any of them indicate regular flow checks. They indicate that the kick has already entered the well bore. The entrance of any fluid into the well bore causes the flow rate to increase. iii) Pit Volume Increase An increase in pit volume is obvious & positive indication of flow into the well bore & can be easily verified.Drilling Operation Practices Manual dc = where. • Flow from the flow line • Increase in pit volume The sequence of events leading to a kick while tripping-in the hole is: • The hole does not stop flowing during making connection between the stands • Increase in pit volume In order to avoid well kicks while tripping. Therefore circulating pressure gradually decreases and unless the pump throttle is changed. trip schedule must be made and trip tank must be used to monitor the hole fill up (in case of tripping-out) and mud displacement (in case of tripping-in). shut off the pump and make a flow check. B. a reduction in BHP equal to annular pressure losses occurs.3 KICK WHILE TRIPPING When the pump is switched off. ii) Flow from Well (Pumps Off) Stopping the pump causes a reduction in bottom hole pressure equivalent to the annular pressure drop. If the well does not flow when the pump is shut off and remains static for two or three minutes. iv) Decrease in Pump Pressure and Increase in Pump Stroke In case of kick there is under balanced condition between the fluid in the drill pipe and the mixed column of mud and influx in the annulus. interval depth to give normal trend line. Positive Kick Sign Positive kick indicators are different from kick warning signs. no kick is entering. To prevent kick while tripping. 12. then no well kick is entering. 25 ppg 12. Kicks have to be circulated out at slow circulation rates to ensure that the sum of this back pressure and system losses does not exceed the rating of high pressure lines and other rig equipment. This decreases BHP when pipe is in motion. For normal drilling operation trip margin is kept 0.4 TRIP MARGIN During pulling out. Another practice to tackle the problem is to keep mud weight gradient greater than the formation pressure gradient. However.5 SLOW CIRCULATION RATE During well control operations. upward motion of the drill string in the borehole (which is assumed to be full of mud) creates a swab pressure.25 = 11.Well Control 12. some margin has to be added to the drilling mud density which is known as riser margin. To compensate this reduction in bottom hole pressure. to avoid further entry of formation fluid it is essential to keep BHP minimum equal to formation pressure.2 to 0. One way of minimising this is to use safe tripping speeds and having close monitoring of pipe volume pulled out & mud volume pumped in to keep the hole full.3 ppg.5 ppg 10000 ft Solution : RISER MARGIN (ppg) = [ Air Gap + Water depth] x Mud density – [ Water Depth x Sea Water Density] ———————————————————————————————————— TVD – Air Gap – Water Depth [ 50 + 700] x 11 – [ 700 x 8. 121 .33Yp ÷ 98 (dh-dp) Where Yp = Yield point of mud in lbs/100 sq.ft Dh = Hole diameter in inches Dp = Pipe outside diameter in inches Effect of riser margin on maintaining bottom hole pressure In the event of riser getting accidentally disconnected due to vessel drive-off or riser failure etc. This is done by imposing certain calculated back pressure in addition to system pressure losses on the well bore as long as old mud is in the well. This extra mud weight is called trip margin.25 ppg 10000 – 50 – 700 Mud Density including Riser margin = 11+0. trip margin can be calculated as follows:Trip margin (ppg)= 8. the swab pressure being a function of yield point (yp) of mud. The resulting overbalance permits safe tripping and connection operations. the bottom hole pressure shall be reduced due to loss of hydrostatic pressure as the riser mud column is replaced by sea water.5] —————————————— = 0. Various reasons for circulating out the kicks at slow circulation rates are :a) To ensure that the slow circulation pressure plus the shut in drill pipe pressure is a convenient total pressure for the pump and does not exceed the surface line ratings. Example: Water depth RKB to sea level Mud density Seawater density Well TVD 700 ft 50 ft 11 ppg 8. so beyond 500ft water depth choke line friction losses should always be considered while planning well control operations. The value so obtained does include circulating pressure losses in the riser but that is negligible. Close BOP. e) To reduce the annular pressure losses. Choke line friction losses In subsea operations when circulating through choke. a compromise has to be made which can meet all the requirements. b) Record circulating pressure at slow rate through riser with BOP open. driller’s console. of places where drill pipe pressure gauges are installed such as stand pipe. flow resistance in the extending choke line running up from the sub sea BOP to surface is considerable. But since at minimum pump speeds more time will be required to kill the well. If pressure losses in choke line are not taken into account during well killing. an excess pressure unnecessarily may be applied in the hole. ii) After change in drilling fluid density.) in a shift. c) Pump down the choke line at slow circulation rate taking the returns through kill line with BOP closed. if available on the rig. Recording of slow circulation rate It should be recorded near to the bottom for each pump at regular intervals and / or when drilling conditions change such as:i) At the beginning of each shift.These are : a) Pump down the choke line at slow circulation rate taking the returns into the riser through open blow out preventer. The pressure thus shown on the choke manifold gauge is the choke line friction losses. v) After pump fluid end repair. iv) After drilling a long section of hole (500 ft. This practice was fairly good with duplex mud pump earlier in use on drilling rigs. The common practice so far had been to select a rate which is about half the pump speed at the time of drilling. The difference of the two values is the choke line friction loss. On the rig there are a no. So. c) To allow longer reaction time for choke adjustments. Therefore slow circulation rate should be 1/2 to 1/3 of pump SPM at the time of drilling. Now with the use of triplex pumps this convention gives much higher speeds than the actual requirements. d) To allow sufficient time for disposal of kick fluid /de-gassing at the surface.Drilling Operation Practices Manual b) To allow mud returns to be weighted up and re-circulated within the capabilities of available mud mixing system. choke & kill manifold and remote choke panel. Since fracture gradient generally decreases with increased water depth. mud pumps. it should be recorded at remote choke panel. 122 . open choke line fail safe valve and record pressure with full choke open. Slow circulation pressure should be recorded from the gauge that is to be used for well killing operation . Theoretically speaking the kill rate or slow circulation rate should be the minimum possible pump speed at which pump can run smoothly without any knocking etc. The pressure thus shown on the choke manifold gauge is twice the choke line friction losses. iii) After change in bit nozzle size or BHA. Measurement of chokes line friction losses There are three ways to find out choke line friction losses. In case of self flow well can be shut-in in two ways: a) Soft shut-in b) Hard shut-in 12. 1 Shale shaker LINE-UP FOR SOFT SHUT-IN Choke line manual valve HCR Line between HCR & Choke Remote choke Line from choke to MGS : : : : : Open Close Open Open (partially) Open 123 .6 LINE UP FOR SHUT IN When one or more positive kick signs are observed. 12. Choke line pressure should also be measured over the same range of rates. flow check is made.Well Control Corrected choke line friction losses for new mud density can be calculated as follows:New mud density Choke line friction losses with old mud × -———————— Old mud density Drill pipe pressure should be recorded at two or more slow circulation rates. Both drill pipe pressure & choke line pressure losses can be plotted separately on Log-Log paper and extrapolated to provide respective estimated pressure losses at various pump rates because due to high friction losses in the choke line it may be necessary to circulate out a kick at a very slow rate if formation breakdown is to be avoided. a) Line up for soft shut-in : Manual choke MGS Distribution Block Drilling Spool HCR HCR Manual valve Bleed/Vent Line B U F F E R To T Waste pit A N K Remote choke Fig.7 SHUT IN PROCEDURES As per API RP 59 As per following are the shut-in procedures for land/jack-up rigs & floating rigs. monitoring casing pressure. Allow the pressure to stabilise and record SIDPP.7. b) Pick up kelly to clear tool joint above rotary table.No. check for self flow. close the well as follows Sl. i) ii) iii) iv) Soft Shut In Open hydraulic control valve (HCR valve) / manual valve on choke line. c) Stop mud pump. Hard Shut In Close Blow Out Preventer (Preferably Annular Preventer) Open HCR / manual valve on choke line when choke is in fully closed position. SICP and Pit Gain.1 While Drilling on Land and Jack Up Rigs a) Stop rotary. 2 LINE-UP FOR HARD SHUT-IN Choke line manual valve HCR Line between HCR & Choke Remote choke Line from choke to MGS : : : : : Open Close Open Open (partially) Open 12. Close Blow Out Preventer (Preferably Annular Preventer) Gradually close adjustable choke. SICP and Pit gain. If yes.Drilling Operation Practices Manual b) Line up for hard shut-in : Manual choke MGS Distribution Block Drilling Spool HCR Valve HCR Bleed/Vent Line B U F F E R T A N K To Waste Pit Remote choke Shale shaker Fig. Allow pressure to stabilise and record SIDPP. 124 . pick up the string to hang off point and remove slips.3 While String is Out of Hole on Land and Jack Up Rig (Soft Shut In) a) Open HCR valve on choke line. Make up kelly and open FOSV Allow pressure to stabilise and record SIDPP. Sl. c) Stop mud pump. Following methods are recommended for shut in the well. Bleed off stand pipe pressure and break away kelly above kelly cock. SICP and Pit Gain. d) Close annular BOP (Preferably upper annular) e) Open fail safe valve on choke line when remote choke is in close position. 12.7. Hard Shut In Close Blow Out preventer (Preferably Annular Preventer) Open choke line HCR valve with choke is fully closed position. Make up kelly and open FOSV Allow the pressure to stabilise and record SIDPP. If yes. vi) Open Lower kelly cock.7.7. iv) Reduce hydraulic pressure on annular hang the string and ensure rams are locked. monitoring casing pressure. c) Close choke. check self flow. following steps should be followed after step e) : i) Set slips and close lower kelly cock. Close Blow Out Preventer (Preferably Annular Preventer) Gradually close adjustable choke.2 While Tripping on Land and Jack Up Rig a) Position tool joint above rotary table and set pipe on slips. hang the string and ensure rams are locked. i) ii) iii) iv) v) Soft Shut In Open HCR Valve / Manual valve on choke line. d) Record SICP and pit gain. SICP and Gain.No. v) Open annular BOP after bleeding trapped pressure between annular and pipe ram. h) Open annular after bleeding trapped pressure between annular and pipe ram. g) Reduce hydraulic pressure on annular. proceed further to shut in the well. 125 .4 While Drilling on Floating Rig (Sub-sea) a) Stop rotary table. iii) Close the upper pipe rams. SICP and Pit gain. If motion compensator is not working or not reliable. f) Close the upper pipe rams. 12. b) Raise kelly to hang off point ensuring that lower kelly cock is above rotary table and kelly is at the pre-designated level so that tool joint is clear of ram preventers.Well Control 12. i) Record SIDPP. Note : In case of hard shut-in the sequence at a) & b) above shall be interchanged. b) Install full opening safety valve (FOSV) in open position & close it. ii) Pick up circulating head make up the same above lower kelly cock. b) Close shear or blind ram. c) Record shut-in pressure & pit gain. Since annulus is contaminated with formation fluid (Oil. the drill string remains uncontaminated whereas annulus becomes contaminated with influx. If SIDPP is added to hydrostatic pressure of drilling fluid.6 When String is Out of Hole or Above the BOP on Floating Rig (Sub-sea) a) Open fail safe valve on choke line when choke is in close position. ii) Install full open safety valve (FOSV) in open position.8 SHUT IN PRESSURE INTERPRETATION A. Once the well is closed initially the SIDPP starts increasing till the BHP becomes equal to the formation pressure. Shut-in Drill Pipe Pressure (SIDPP) The shut in pressure on the drill string side is the difference between the hydrostatic pressure of drilling fluid and the formation fluid pressure. iii) Open Fail-safe valve on choke line when remote choke is in close position.5 While Tripping on Floating Rig (Sub-sea) i) Set slips below tool joint. Open Annular BOP after bleeding pressure.7. 126 . it is recommended to read and record the SIDPP immediately after the closure and subsequently after every 3-5 minutes. gas. iv) Close annular BOP. 12. Since true SIDPP is determined for the calculation of kill mud density. 12. SICP and Pit Gain. SIDPP is used to determine the kill mud weight required to balance the formation pressure by using the equation given below SIDPP(psi) Kill Mud Density (ppg) = —————————— + Original Mud Density(ppg) 0. salt water or combinations) therefore SICP can not be used to calculate kill mud density however it is used to determine kind of influx which has entered the well bore. The time taken for stabilisation depends upon the permeability of the formation. Shut-in Casing Pressure (SICP) The shut in pressure on the annulus side is the difference between the combined fluid hydrostatic pressures and formation fluid pressure. b) Close blind shear ram. The recorded values of SIDPP should be tabulated/plotted to ascertain the true value of SIDPP. the resultant pressure will be the pressure of the formation. Reduce operating pressure on annular BOP. B. ix) Record SIDPP. v) Calculate the length of the pup joint and /or length of stick up above rotary table to ensure that the tool joint is clear off the pipe ram to be closed. During kill operation casing pressure will allow us to determine the pressure being exerted at various points in the well bore and also pressures on the BOP equipment and choke lines. vii) Close upper pipe rams.052 × Well TVD( ft) The shut in drill pipe pressure should be read & recorded from the gauge on the choke control panel. When a kick enters during drilling. viii) Lower drill string & hang it off on the rams. 12. close it & remove slips.7. vi) Make up kelly & open FOSV. SICP and pit gain.Drilling Operation Practices Manual vii) Record SIDPP. SIDPP may further increase but at a slower rate if the influx is gas/gas mixture. given below are the tabulated values of SIDPP and SICP.e. Find out the stabilized value of SIDPP. Time 0600 0605 0610 0615 0620 0625 0630 0635 0640 SIDPP(psi) 100 200 275 340 400 405 415 430 450 SICP(psi) 150 270 370 450 520 525 535 550 570 Note : Pressure recording should be done at every two minutes interval. given below are the tabulated values of SIDPP and SICP.Well Control Example A well was shut in after a kick. SICP is increasing faster than SIDPP up-to 0620 hrs but later both the pressures are rising by same amount. Example A well was shut in after a kick. The proper recognition of stabilised value of SIDPP is very important as this value is used for the calculation of kill mud weight and formation pressure. Time 0800 0815 0830 0845 0900 0915 1000 1100 1115 1130 1145 SIDPP(psi) 150 250 340 420 500 500 500 500 505 510 520 SICP(psi) 200 320 420 510 600 600 600 600 605 610 620 127 . Therefore the value recorded at 0620 hrs i. This shows that the pressures have stabilised at 0620 hrs and subsequently due to close well gas migration both the pressures are rising by same amount. 400 psi is the true SIDPP. Solution As evident from tabulated values. Find out the stabilised value of SIDPP. 500 psi is the stabilised value of SIDPP. b) When the pump is at the desired kill speed follow the pressure schedule according to the kill method being used. The various kill methods are as follows: 1) Driller’s Method 2) Wait and Weight Method 3) Volumetric Method In the first three methods the influx is circulated out and the heavy mud is pumped in the well keeping the bottom hole pressure constant. for bringing the pump up to kill speed. Pump should be brought to kill speed patiently. 12.1 Driller’s Method In Driller’s method the killing of a well is accomplished in two circulations • In first circulation the influx is removed from the well bore using original mud density. 12. a) Bring the pump to kill speed slowly holding casing pressure constant by manipulating choke.e. SIDPP and SICP were increasing considerably up to 0900 hrs & later there is no change in the pressures up to 1100 hrs Therefore the value recorded at 0900 hrs i. Volumetric method is a non circulating method in which the influx is brought out & heavy mud is placed in the well bore without circulation. To prevent this. During this period if the casing pressure is allowed to increase it can cause formation breakdown or if the casing pressure is allowed to decrease it can cause entry of more influx into well bore. • In second circulation the kill mud replaces the original mud and restores the primary control of the well.052 × TVD (ft) (ppg) b) Initial Circulating Pressure (ICP) = SIDPP(psi) + KRP (psi) 128 .9.Drilling Operation Practices Manual Solution As is evident from tabulated values. Note : While bringing the pump to kill speed keeping casing pressure constant. Formulae Required SIDPP (psi) a) Kill Mud Weight (ppg) = Old Mud Weight + ———————0.9 WELL KILLING PROCEDURE The main principle involved in all well killing methods is to keep bottom hole pressure constant. Further increase in both the pressures is due to closed well gas migration. The fourth method i.e. there might be slight reduction in bottom hole pressure due to expansion of gas but this is compensated by the annular pressure losses. Bringing the pump to kill speed on land / jack up rig It is important to understand the start up procedure. irrespective of kill method. following procedure is suggested. 129 . Open & observe the well. gradually closing the choke. it indicates trapped pressure in well bore. maintaining drill pipe pressure constant equal to FCP. b) Bring the pump up to kill speed in steps of 5 SPM. c) Circulate out the influx from the well maintaining drill pipe pressure constant. maintaining casing pressure constant. Whereas if SICP is more than original SIDPP. • First Circulation a) Bring the pump up to kill speed in steps of 5 SPM. d) When the influx is out. e) When the kill mud reaches surface. • Second Circulation a) Line up suction with kill mud. gradually opening the choke. holding casing pressure constant. Add trip margin before resuming normal operation. Note : In case recorded SIDPP & SICP are equal but more than original SIDPP value. Record pressures. c) When the pump is at kill speed. SIDPP and SICP both should be equal to zero. SIDPP and SICP should be equal to original SIDPP. maintaining casing pressure constant. gradually closing the choke maintaining casing pressure constant. stop the pump reducing the pump speed in steps of 5 SPM. gradually opening the choke holding casing pressure constant. it indicates that some influx is still in the well bore.Well Control Kill mud weight (ppg) c) Final Circulating Pressure (FCP) = ———————————— × KRP(psi) Original mud weight (ppg) Drill string volume (bbl) ————————————— Pump output (bbl/stroke) Open hole annulus volume (bbl) —————————————— Pump output (bbl/stroke) Annulus volume (bbl) ————————————— Pump output (bbl/stroke) d) Surface to Bit Strokes = e) Bit to Shoe Strokes = f) Bit to Surface Strokes = Killing Procedure (Drillers Method) In this method the well is killed in two circulations. stop the pump reducing the pump in steps of 5 SPM. b) When the pump is up to kill speed. d) Pump kill mud from bit to surface. maintain drill pipe pressure constant. Record pressure. pump kill mud from surface to bit. Drilling Operation Practices Manual Fig. Casing pressure reduces sharply as influx is removed from the wellbore. 130 . Casing pressure again rises as influx now expands in drill pipe annulus and it becomes maximum when influx reaches surface at point ‘D’ on the graph. Casing pressure decreases as influx crosses over from drill collar annulus to drill pipe annulus & losses height. 3. Pressure Profile.1st Cycle of Driller’s Method A-B B-C C-D D-E Casing pressure rises as influx expands in drill collar annulus. Drill Pipe Pressure Graph I-J Drill pipe pressure is held constant till the influx is removed from the well bore. Drill Pipe Graph L-M Drill pipe pressure reduces as kill mud is pumped from surface to bit. influx which is on its way up the annulus expands continuously and gains volume / height. 131 . this causes the drill pipe pressure to fall.2nd Cycle of Driller’s Method Casing Pressure Graph F-G Casing pressure is held constant till kill mud is pumped from surface to bit. At the same time. 4. As the kill mud moves from surface to the bit the hydrostatic pressure in the Drill Pipe increases. On the whole drill pipe pressure reduces from ICP to FCP.Well Control Fig. G-H Casing pressure reduces to zero as kill mud is pumped from bit to surface. for maintaining BHP constant a calculated step down plan for the drill pipe pressure must be used while pumping the kill mud from surface to the bit. M-N Drill pipe pressure is held constant as the kill mud is pumped from bit to surface. 12. thereby causing the hydrostatic pressure in annulus to fall and casing pressure to rise. During this period SIDPP drops & becomes zero whereas KRP increases to FCP value. Because of this. In this method operations are delayed (wait) once the well is shut in.9. Pressure Profile.2 Wait and Weight Method • • In Wait and Weight method well is killed in one circulation using kill mud. while a sufficient volume of kill (weight) mud is being prepared. maintaining drill pipe pressure as per step down schedule (during this step drill pipe pressure will fall from ICP to FCP). . SIDPP and SICP both should be equal to zero. Record pressures. holding casing pressure constant.Drilling Operation Practices Manual Formulae required SIDPP (psi) a) Kill Mud Weight (ppg) = Old Mud Weight + ———————(ppg) 0. More time on choke operation. 2. maintaining drill pipe pressure constant equal to FCP. sand settling around BHA is minimum.052 × TVD (ft) b) Initial Circulating Pressure (ICP) = SIDPP(psi) + KRP (psi) Kill mud weight (ppg) c) Final Circulating Pressure (FCP) = ————————————— × KRP(psi) Original mud weight (ppg) d) Surface to bit Strokes = Drill string volume (bbl) ——————————— Pump output (bbl/stroke) Open hole annulus volume (bbl) —————————————— Pump output (bbl/stroke) Annulus Volume (bbl) ———————————— Pump output (bbl/strokes) e) Bit to shoe Strokes = f) Bit to surface Strokes = ICP – FCP g) Pressure drop / 100 strokes = —————————— × 100 Surface to bit strokes Killing Procedure (Wait and Weight Method) a) Line up suction with kill mud. Minimum two circulations are required. b) Bring the pump up to kill speed in steps of 5 SPM. c) When the pump is at kill speed. gradually closing the choke maintaining casing pressure constant. pump kill mud from surface to bit. gradually opening the choke. 3. stop the pump reducing the pump speed in steps of 5 SPM. e) When the kill mud reaches surface. d) Pump kill mud from bit to surface. 132 Disadvantages Higher annulus pressure Higher casing shoe pressure in gas kick. COMPARISON OF METHODS Driller’s Method Advantages 1. Add trip margin before resuming normal operation. Open & observe the well. Simple to understand Minimum calculations In case of salt water kick. E-F Casing pressure reduces sharply as influx is removed from the well bore. 4. C-D Casing pressure again rises as influx now expands in drill pipe annulus.Wait & Weight Method Casing Pressure Graph A-B Casing pressure rises as influx expands in drill collar annulus. 2. Calculations are more. Disadvantages High non circulating time. 3. In case of salt water kick. Pressure Profile. F-G Casing pressure further reduces as original mud is replaced by kill mud. I. 5. Fig. Lower casing shoe pressure when open hole volume is more than string volume. 133 .J Drill pipe pressure is held constant at FCP as kill mud is pumped from bit to surface. Lower annulus pressure. Well can be killed in one circulation. sand settling around BHA is maximum. B-C Casing pressure decreases as influx crosses over from drill collar annulus to drill pipe annulus & losses height. Drill Pipe Pressure Graph H-I Drill pipe reduces from ICP to FCP as kill mud is pumped from surface to bit. later on casing pressure increases at a faster due to rapid expansion of gas. Less time on choke operation. More chances of gas migration. D-E Casing pressure continues to increase but initially at a slower rate as at this stage kill mud starts entering the annulus.Well Control Wait and Weight Method Advantages 1. In this method the influx is brought up to the surface by means of migration & controlled expansion. This process involves bleeding of calculated volume of mud at the surface till the influx reaches the surface. The goal of maintaining the BHP constant is achieved through corresponding reduction in annular hydrostatic pressure by bleeding calculated volume of mud which in turns reduces the mud column height in the annulus and allows the gas to expand.3 Volumetric Method of Well Control The volumetric method is a non circulating killing method used for removing gas influx when there is little or no drill pipe in the hole. In lubrication process annular hydrostatic pressure is increased by injecting a calculated volume of same or heavy mud through kill line while the BHP is maintained constant by bleeding gas through choke and reducing surface pressure by the same amount. if the casing pressure rises mud can be bled from the well according to the psi/bbl value calculated to maintain a constant bottom hole pressure. a wash out in the string or when the hole can not be circulated. It works equally well for a situation where the well is closed-in and waiting on orders or equipment or for stripping in or out of hole. Once the bit is at the bottom. thereby allowing the casing pressure to increase to maintain BHP constant. After the gas influx is brought to the surface in this manner of controlled expansion.Drilling Operation Practices Manual 12. the well can be killed / circulated with appropriate kill weight mud. In the bleeding process the gas influx is allowed to migrate in the annulus and thereby causing an increase in the annular surface pressure as well as the BHP. Volumetric method is implemented mainly in two steps namely the “bleeding” and “lubrication” process. The process may be repeated several times till all the gas influx is fully removed from the annulus and the annular surface pressure is brought down to zero or at a level wherein tripping /stripping of the bit to the bottom or removing/ replacing of choked or damaged string becomes feasible. The basis of the volumetric method is that each barrel of mud contributes a certain pressure to the bottom of the hole.047 bbl/ft (8 1/2” × 5”) 500 psi 0 psi 134 . Once the gas is at the surface the process of lubrication starts.000 ft 20 bbl 10. the calculated volume of mud is pumped in to the well & gas influx is bled thereby allowing the casing pressure to decrease while maintaining BHP constant. Volumetric method is used to control BHP within limits by co-ordinating the increase (because of gas migration) or decrease (because of bleeding of gas ) in annulus surface pressure with the corresponding decrease or increase in annular hydrostatic pressure (by decreasing or increasing height / weight of mud column in the annulus). Volumetric Kill Calculations Example Well TVD Influx Mud weight Annular volume SICP SIDPP = = = = = = 10.0 ppg 0. The volumetric method works by bleeding off (or adding) mud because the BHP is the sum of the casing pressure & the pressure exerted by the mud column. The Volumetric method of well control should not be equated with classic well killing methods. This may be measured as psi/bbl. The bleeding process has to be repeated several times till the gas reaches the surface. A record of casing pressure is kept.9. This term of psi/bbl must be co-ordinated with pit volume or trip tank volume so that the number of barrels can be read directly. 52 ft = 194 ft Volume of Mud for 100 psi hydrostatic pressure = 194 × 0. this causes the BHP to increase by 150 psi. therefore the well has to be killed by Volumetric method.052 – ———————— Height of influx Since kill mud is to be placed only in the top section of the well which is being occupied by gas.52 × 2553 Kill mud gradient = 13.052 = 0.047 = 6.52 × TVD As the SIDPP may not be known SICP may be taken in place of SIDPP. 135 .Well Control As indicated by SIDPP value (0 psi) the bit nozzles are plugged. Bleeding a) Allow the casing pressure to increase to 650 psi.04 bbl b) For Lubrication Process Calculation of kill mud weight for lubrication SIDPP KMW = OMW + ————— 0.715 psi/ft Height of kill mud column for 1 psi of Hydrostatic pressure = 1 / 0.57 bbl Killing Procedure (Volumetric Method) Volumetric killing is accomplished in two steps. But if the value of SICP is very high then SIDPP can be calculated by assuming some gas gradient by the following formula :SICP – SIDPP Influx gradient = Mud Weight × 0. namely ‘Bleeding’ & ‘Lubrication’.76 ppg 0.047 = 9.76 × 0. the height of gas column is to be calculated.047 500 KMW = 10 + —————— = 13. don’t start bleeding now (this 150 psi may be kept as safety margin).76 × 0.52 ft Height of mud column for 100 psi of Hydrostatic pressure = 100 / 0.052 × 10 = 0. 1.52 psi/ft Height of mud column for 1 psi of Hydrostatic pressure = 1 /0. Total pit gain = Initial pit gain + Total amount of mud bled = 20 bbl + 100 bbl (say) = 120 bbl 120 Height of gas column when gas is at the surface = ——— = 2553 ft 0.7155 = 139.715 ft Height of kill mud column for 100 psi of Hydrostatic pressure 100 / 0.76ft Volume of kill Mud for 100 psi hydrostatic pressure = 139. Calculations a) For Bleeding Process Let the incremental increase in casing pressure would be 100 psi Mud Gradient = 0. Measure the volume of mud pumped.12 36. Allow the mud to fall through the gas. calculate the hydrostatic pressure of that volume in the annulus and bleed sufficient gas to drop the casing pressure by the amount of hydrostatic pressure plus any increment of trapped pressure because of pumping operation. Lubrication The lubrication technique is used to Kill the well / reduce the casing pressure when gas is at the surface so that other operation such as tripping / stripping can be performed. c) Allow the pressure to increase by another 100 psi to 850 psi and bleed 9. In no case mud is to be bled off. d) This procedure should be repeated until gas reaches surface. Repeat the process until all of the gas has been bled off and the well is killed or the desired surface pressure is reached. This is a slow process. stop pumping. Note : During the pumping and gas bleeding process. 6. but can be speeded up by using a low yield point mud.Drilling Operation Practices Manual b) Allow the Casing pressure to increase by another 100 psi to 750 psi. it will usually be necessary to decrease the volume of mud pumped before gas is bled off particularly near the end of the operation. While bleeding mud the surface casing pressure should not be allowed to reduce more then 100 psi which may require the bleeding to be completed in number of steps.04 bbl of mud in the same way. 2. Mud Bleeding Process 2. this causes the BHP to increase by 250psi.16 45. Bleed gas from the annulus until the surface pressure is reduced by 100 psi or the amount equal to the hydrostatic pressure of the mud pumped in. 136 . 1. 3. This is because the annular volume occupied by the gas decreases with each pump & bleed sequence.28 500 Volume of mud bled off from annulus (bbl) Fig.57 bbl) which shall give 100 psi equivalent hydrostatic pressure into the annulus. Lubrication technique is to be used for reducing the casing pressure.20 54. 1100 C A 1000 S I 900 N G 800 P R E S S 700 600 Bleeding is continued until gas is at top Safety margin 150 psi Initial SICP 500 psi 9. Thereafter.08 27.24 63.04 18. we can now reduce 100 psi of BHP by bleeding 9.04 bbl of mud. Since it is planned to keep only 150 psi extra pressure at the bottom as safety margin. Watch the pumping pressure closely and when it reaches 50-100 psi above the shut in casing pressure. Slowly pump the calculated volume of mud (6. 41 91. Another way of lowering choke line pressure would be to utilize both choke and kill lines. The pressure loss is related to water depth.71 26. the mud in choke line is quickly displaced out by gas causing a sharp reduction in hydrostatic pressure.99 52.28 32.14 19.55 105.57 13.56 59.Well Control Volume and Pressures during Top Kill (Assuming maximum surface pressure of 1900 psi at the end of bleeding operation) Volume to lubricate.83 Pressure to Bleed (psi) 0 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 100 Remaining casing pressure (psi) 1900 1800 1700 1600 1500 1400 1300 1200 1100 1000 900 800 700 600 500 400 300 200 100 0 12.13 65. and internal diameter of choke and kill lines.10 SUB-SEA CONSIDERATIONS RELATED TO WELL KILLING Consideration of Choke Line Friction The effect of long choke lines can be very significant.70 72. The problem can be handled by measuring the choke line friction pressure before drilling out of casing.26 124. Pressure Changes When Gas Reaches Choke Line When gas reaches the choke line. The casing pressure could then be reduced by the amount of choke line friction pressure while bringing the pump to kill speed.85 39. When gas leaves the choke 137 . The pressure loss effect of the choke line applies to all points in the well bore and is especially critical at shallow or weak casing seats.27 78. bbl (cumulative) 0 6. circulating rate.42 45. Choke line friction can be reduced by lowering slow circulation rate. The initial circulating pressure (SIDPP + Slow rate pressure through riser) will be approximately the same if the casing pressure is reduced by the amount of the choke line friction pressure.69 118.98 98.84 85.12 111. This may cause sharp bottom hole pressure reduction if choke is not properly adjusted to establish the correct drill pipe pressure. Normally both lines are utilised specially towards the end of the kill operation. As such well can not be closed because flow might broach to the outside of the shallow casing. Cutting carrying capacity of the drilling fluid is poor since hole is about 30% to 40% larger than nominal size & high annular velocities can not be obtained. 12. ii) Use a large diameter choke line. rig & equipment. This makes choke line displacement one of the most difficult stages of the well killing operation. c) Annular velocity is very low (due to large hole) and top-hole mud has a poor cutting carrying capacity. Moreover.Drilling Operation Practices Manual line and is replaced with mud. 138 . There can be rapid drop in BHP when gas displaces mud in the choke line. time for action is very limited. which if happens can lead to a shallow formation flows. displacement even at kill rate gives very short time to make the adjustments on choke to keep the BHP constant. The only reliable indicator is differential flow sensor. since there is rarely a sharp boundary between gas and mud. As the capacity of choke line is very less. which further reduces the hydrostatic head and allows more and more influx to enter the well bore. b) Soft. the situation is reversed when the trailing mud displaces gas in the choke line. more so in a marine well since part of the overburden there consists of seawater rather than formation. iii) Use both choke and kill line in parallel without changing the pump rate. another sharp fluctuation will take place and could result in over pressurizing the formation if not quickly adjusted to re-establish correct drill pipe pressure. The shallow gas kicks are difficult to detect at an early stage because most of the standard flow detection techniques fail. hole sizes are large & porosity is very high. Mud volume is continuously being added to active mud system therefore pit level indicator at times can not be made use of. several severe and sharp changes in BHP and d/p pressure are encountered. Flow checks on drilling breaks become impractical as drilling rates generally are very fast & penetration rates vary tremendously. The various problems faced while drilling top-hole section are as below: a) The formation being weak is vulnerable to bulk mud losses.11 TOP HOLE DRILLING In upper part of the hole. drilling rate is normally too fast. If the choke does not respond equally fast then a second influx or formation breakdown may occur. As such while drilling a top-hole section the chances of bulk mud losses are high. The major hazards of shallow gas influx i) It can lead to blow-out. Effect of Different Density Fluids in Choke & Kill Lines In deep water well killing. ii) It can cause serious damage to the personnel. Some of the actions suggested to avoid sharp changes in BHP are: i) To displace the line at an extremely slow rate when gas top reaches the BOP stack. Formation strength in the top hole section is normally low. the displacement of one density fluid by another can cause sharp changes in the BHP. fast drilling formation generates large volumes of cuttings that tend to accumulate in the bore hole. On the other hand reaction time is minimal since gas expands almost immediately upon entering the well bore. d) Kicks occur quickly & since shallow reservoir can have high permeability. This leads to concentration of cuttings in the annulus thereby increasing the equivalent mud density in the annulus. Well Control iii) It can broach through outside of shallow casing leading to instability of bottom supported rigs. b) Mud Density:. Connect Kelly or circulating head. fire & loss of rig is very high. b) Open diverter overboard line valves depending upon wind direction. 12. The diverter system is designed to pack off around Kelly. hole enlargement with under reamer should be preferred as it can be collapsed before starting pulling out in order to reduce the swabbing effect. casing or drill string. iv) Risk of crater. During Drilling a) At first sign of flow.1 Shallow Gas Control Procedure Diverter system should be used to control shallow gas kicks as discussed below. a) Penetration Rate:. e) Remove the non essential personnel from the rig. it is useful to control some critical drilling parameters to prevent shallow gas kicks. upper formations areusually sticky (more so in offshore) & has more tendency to ball the bit thus enhancing the probability of swabbing. Whenever the pilot hole has been drilled. It can lead to fracture of formations & bulk mud losses & therefore result in shallow gas influx. c) Close diverter packer. A typical approach to a shallow gas kick is to allow the well to flow through a diverter. Circulate out with available drilling fluid at maximum possible pump rate. Well is allowed to flow and simultaneously mud or water is pumped through the drill string at maximum rate to keep as much fluid in the well as possible. Either the well shall flow till the formation depletes (or annulus bridges) or the well is brought under control by increasing the mud weight.11. Close diverter packer. If necessary the drill string should be pumped out of the hole to limit swabbing. It does not shut in the well. raise the kelly until tool joint is above rotary.e.Avoid mud density increase down hole by (i) Drilling large diameter holes in two stages (i. Thus there is need for limiting the actual penetration rates to a value less than that can be achieved. Install FOSV and close it. 139 .The rate of drilling is normally very fast in top holes. but allows the flow to be diverted through a vent line to a safe distance away from the rig. d) Circulate out with available drilling fluid at maximum possible pump rate. Open diverter line valves depending upon wind direction. immediately stop rotary. it adds tones of drilled cuttings in the hole to create mud density much higher than what is required. c) Tripping:. While a) b) c) d) e) f) g) Tripping Set pipe on slips. Open FOSV. drilling a pilot hole) (ii) Circulating out the cuttings with viscous mud sweeps. (Note : Step b and f are not required if string contains a float valve) h) Remove the non essential personnel from the rig.Higher tripping speeds should be avoided. Control of some critical drilling parameters Since shallow gas kicks occur quickly and time for action is limited. they should be sealed before drilling ahead. Periodic flow checks should be made while drilling in potential gas zones. 140 . Bits should have large nozzles to allow pumping of LCM material. iii) Active Mud System & Flow Checks Mud pit volumes should be continuously monitored so as to detect any change in active mud volumes. i) Heavy Mud A minimum of one reserve mud tank weighing about 2-3 ppg more than the drilling mud should be kept reserve. following measures are suggested.Drilling Operation Practices Manual In addition to above. ii) Mud Losses When ever losses are encountered. iv) Float Valve A float valve may be run in the string to prevent sudden flow through the drill pipe. 2. e) Mud loss. 3. casing lowering. cementation. Casing failure.1 STUCK UP Stuck up occurs due to one of the following reasons: a) Differential sticking. A force (F) equal to the net force exerted against the sealed area multiplied by the coefficient of friction is required to move the assembly to release the stuck pipe. d) Well bore instability. 5. 6. 4. Assuming the weight of the drilling assembly below a certain point is W & hole angle is á then the side force acting on the drill string which causes the string to press against the well bore is equal to W x sin α. production testing and completion of a well. The differential pressure so caused results in the string being pressed against the well bore and subsequently getting differentially stuck although circulation is normal. logging. At all times the drill string is in contact with the well bore. remove or recover tubular or any material left in the well bore that affects drilling. production testing and well completion. Fishing is any operation or procedure to release. f) Cement sticking. Stuck up. b) Mechanical sticking. Bit failure. During drilling through a porous & permeable formation a thick mud cake is deposited on the side of the well bore due to filtrate loss into the well bore. Force F = P x A x C Where F = Force required to release the stuck pipe 141 . String cannot be rotated and movement of the string will be ceased.13 DOWN HOLE COMPLICATIONS Complication is a problem in the well bore that prevents safe drilling. 13. a) DIFFERENTIAL STUCK UP As it is well known. casing lowering. logging. Mud loss. 7. no well is perfectly vertical. the string is lubricated by mud and the hydrostatic pressure acting on all sides of the string is equal.Down Hole Complications CHAPTER . c) Key seating. When the drill string is stationary the portion lying on one side of the well bore against a permeable & porous formation is isolated in such a way that the mud cake restricts pressure communication due to the seal. During drilling or tripping. String failure. Well activity. Cementation failure. cementation.. The pressure acting on the side in contact with the well bore is equal to the formation pressure whereas on the remaining side it is equal to the hydrostatic head of mud. Common types of drilling complications are: 1. 3) PREVENTION & REMEDIAL MEASURES Minimize contact area of bottom hole assembly against well bore by running stabilizers and spiral drill collars in the hole. Use lubricants in the mud to reduce friction factor. Never work the up jar with torsion in the string. Work the pipe within safe permissible limits during this period otherwise the force required to release the string may exceed tring capacity after the cake dries out (friction factor will become 1). Maintain recommended mud properties relative to the formation being drilled. operate the down jar. Never by pass the shale shaker screen during drilling. PRIMARY METHOD OF RELEASING DIFFERENTIALLY STUCK PIPE Reduce the pump strokes (do not stop the pump – general rule of thumb reduce the SPM to a third). Use controlled drilling rates especially in large size holes to avoid increase in mud weight in the annulus. keep string under compression. Work right hand torque to the stuck point & bump down. Higher contents of drilled solids increases the viscosity. Use the minimum length of the largest size of drill collars.Drilling Operation Practices Manual P = Differential pressure = Hydrostatic head of mud column – Formation pressure A = Area of contact C = Friction factor (For sand it varies from 0. thereby increasing the water loss. Do not keep pipe stationary in open hole unless it is mechanically impossible to reciprocate/rotate the string. If there is no sump at the bottom work the pipe in tension (operate the up jar). Always work within safe limits of the string. If it is not possible. Loading of the annulus by cuttings increases the hydrostatic pressure and consequently the differential pressure. Run a drilling jar in the bottom hole assembly so that it can be activated as and when required. From studies carried out in the laboratory by simulating actual field conditions it was found that it takes approximately 1 1/2 hr for the cake to dry out. Maintain undesirable solids content as low as mechanically possible. Slack off at least the weight of the bottom hole assembly to keep it in buckling condition and thereby minimizing the contact area to reduce the chances of differential stuck up. minimize water loss and cake thickness. Clean the settling tank after each phase of drilling. Maintain optimum hydraulics to remove cuttings from well bore. 142 . While drilling with a premium bits perform a wiper trip frequently to prevent build up of filter cake in the previously drilled section of the hole. If there is a drilling jar in the string.05 to 0. This results in thicker filter cake and increases the chances of differential sticking. Time is of greatest importance in releasing a differentially stuck pipe. Drill with minimum overbalance to minimize differential pressure. otherwise presence of cutting in the mud system will increase the mud weight. In case of mechanical shut-down pull out the string inside shoe. Calculate the volume of spotting fluid required such that the entire annulus from the stuck point to the bottom of the string is covered by the spotting fluid & the height of spotting fluid inside the drill string is 100 to 150m more than that of the annulus. Pump the spotting fluid into the drill string and displace it by mud such that the height of spotting fluid inside the string is 100-150m more than in the annulus. within 1 ½ hour of stuck up. In such cases. it is recommended that all arrangements for oil spotting are made in advance so that spotting can be done at the earliest after stuck up. The pipe is generally kept in compression during soaking period except in exceptional circumstances. If the string is not released then spotting fluid inside the drill string is displaced into the annulus in a phased manner at equal intervals (e. Note: In areas prone to differential sticking (like depleted horizons of Barial in Geleki field of Upper Assam). (ii) Spotting Mud Acid In cases where oil spotting is not found to be effective. Surfactants (2.g. before going for a time consuming and expensive fishing operation it is recommended to go for acid spotting. Work the pipe as the spotting fluid rises in the annulus. (Although a logging unit is preferred. The string is worked intermittently to try and release the string otherwise it is left in compression. After the soaking period the string is worked vigorously. The chances of releasing a stuck pipe are better if the spotting is done before the mud cake dries out completely i. The annular volume should consider the caving factor assuming that the hole is not gauged. Driller’s method of free point location may be used). The soaking period is generally 8 hours but may vary according to operational requirements. The technique is similar to 143 . it may not be readily available especially in wells drilled onshore.Down Hole Complications SECONDARY METHODS OF RELEASING DIFFERENTIALLY STUCK PIPE (i) Spotting Pipe Lax Spotting is done against the stuck zone which penetrates the filter cake and breaks the seal formed due to the filter cake.e. (Migration of spotting fluid can be reduced if a weighted spotting fluid is prepared but an un weighted spotting is more effective than weighted spotting). Also in areas where there are chances of well activity due to oil spotting a weighted spotted fluid may be used otherwise a non weighted spotted fluid is preferred. 100 liters every hour). Acid spotting has been used to free stuck pipe in wells of Lakwa. Find out the free point of the drill string. This will ensure a back pressure on the spotting fluid reducing the chances of its migration during soaking period. After displacing the spotting fluid close the kelly cock or the stand pipe valve to prevent migration of fluid into the drill string. Before going for second spotting in case the stuck pipe is not released a free point location may be done to ascertain the effect of the first spotting. Mehsana & Ahmedabad oil fields. In case of stuck drill string the minimum weight that should be slacked off is equal to the air weight of the assembly below the stuck point.5% to 3%) are added to the spotting fluid to reduce surface tension between contacting surfaces by creating a thin layer between the pipe and the mud cake. This reduces coefficient of friction thereby helping in mechanically releasing the pipe. It is a good practice to pump a high viscous pill ahead of the spotting fluid to reduce the chances of migration especially in wells where mud weights are high. b) MECHANICAL STUCK UP (i) Hole pack off – improper hole cleaning The behavior of drilled cutting & cutting beds vary according to the angle of the well bore. If Kelly is connected at the time of stuck up. 100 liters every hour). The string is worked intermittently to try and release the string otherwise it is left in compression. it should be backed off and string made up to surface. Acid being corrosive. As in the case in Ahmedabad & Mehsana after back off. it may not be readily available especially in wells drilled onshore. and 65 deg. After the soaking period the string is worked vigorously. – transitional. In case of stuck drill string the minimum weight that should be slacked off is equal to the air weight of the assembly below the stuck point. Find out the free point of the drill string. The pipe is generally kept in compression during soaking period except in exceptional circumstances. least difficult to clean. Acid spotting is not done through the rotary hose or in case the fish is caught with an over shot as it corrodes the rotary hose & damages the seals of the over shot. Displace it by mud such that the height of acid inside the string is 100-150m more than in the annulus. Calculate the volume of acid required such that the entire annulus from the stuck point to the bottom of the string is covered by the acid & the height of acid inside the drill string is 100 to 150m more than that of the annulus. The other draw back is if the fish is caught by an over shot where as oil spotting can be done. Line is to be made to the acid pumper. a suitable anti corrosive inhibitor is added to the acid to prevent corrosion of the string. acid spotting cannot be done. – horizontal. – vertical. the hole angle is as below. If the string is not released then the acid inside the drill string is displaced into the annulus in a phased manner at equal intervals.g. The soaking period is generally 4 hours but may vary according to operational requirements. and 90 deg. Since acid is corrosive and although its corrosive effect on drill string is controlled by using anti corrosive inhibitor. Work the pipe as the acid rises in the annulus. Note : Unlike diesel / crude oil spotting technique the spent acid once discarded into the cuttings pit is neutralized and hence is non-polluting. most difficult to clean. cutting beds are more stable but more difficult to clean than wells with angle less than 30 deg. still it should not be pumped into the well using mud pumps and circulatin hose as it will corrode the rubber elements in the circulation system. Acid pumper should be used. The degree of difficulty of hole cleaning vs. Angles between 30 deg. This will ensure a back pressure on the acid reducing the chances of its migration during soaking period. the fish was engaged by a matching pin and acid spotting could be done to release the stuck up. After displacing the acid close the kelly cock or the stand pipe valve to prevent migration of acid into the drill string. (Although a logging unit is preferred. Angle less than 30 deg. Pump a spacer of diesel such that it occupies a height of 50m of drill pipe inside volume. The annular volume must consider the caving factor assuming that the hole is not gauged.Drilling Operation Practices Manual that of oil spotting except that diesel is used as a spacer between acid and mud. In such cases in normal wells driller’s method of free point location may be done). 144 . Angles between 65 deg. (e. Higher the mud weight greater is the buoyancy & lesser is the slip velocity. shape & quantity Slip velocity increases with size & density of cuttings and if the cuttings are more spherical. The larger the cutting more is the force at which they are pushed to the wall & fall into the well – this results in cuttings recycling. Higher YP / PV ratio provides a flatter profile. Large quantity of cuttings interferes with each other & flow profile reducing the cleaning effect. shape & quantity. Note: We do not increase the mud weight to improve hole cleaning as it can result in differential stuck up. The contribution of annular velocity depends on mud weight. In laminar flow the flow regime is parabolic & heavier cuttings are pushed to the wall & subsequently fall back in the well. Circulation time. Turbulent flow better hole cleaning as it has a flatter flow profile – however turbulence increases hole erosion & may also result in mud loss. Annular velocity. The lifting force is directly proportional to annular velocity in laminar flow. Plastic viscosity (PV) does not. Frictions provides greater lift & drags the cuttings off the wall. poor ROP. poor log quality & poor productivity. Drilled solids also increase the PV. Provides lifting force through momentum transfer & friction. Yield point (YP) contributes to good cleaning efficiency. It affects the momentum of the fluid. Pipe rotation & eccentricity. This results in the flow profile becoming more parabolic & cuttings stick to the wall. Fluid reology & flow regime There are three flow regimes a) Laminar flow b) Turbulent flow c) Plug flow. Cutting size. Cutting size. 145 . Fluid reology & flow regime.Down Hole Complications Factors affecting hole cleaning in wells less than 30 degrees Mud weight. – if mud weight was zero there would be no contribution to hole cleaning from annular velocity. Mud weight It provides buoyancy to help lift the cuttings – better transport ratio. Efficient hole cleaning can be provided with a laminar flow if the YP / PV ratio is high without causing hole erosion / mud loss. It affects the friction the fluid can impart to the cuttings. Annular velocity Second most important factor affecting hole cleaning. – Vertical 30 to 65 deg. the cuttings migrate to the wall. Time If sufficient time is not given to circulate out the cutting prior to tripping it can result in stuck pipe. At higher angles they form beds and roll on the side of the well At 65 deg the beds are stationary unless disturbed by pipe movement Homogenous suspension is the most efficient method of cutting transport. cuttings form beds but are more packed but harder to disturb. the cuttings slide down even while circulating. As the angle increases to 30 deg. Loading of the annulus with drilled cuttings will result in hole pack off / plugged nozzles. 146 . As the angle increases they tend to migrate to the low side and move up in a heterogeneous section. Factors affecting hole cleaning in high angle wells > 30 deg Hole inclination.Drilling Operation Practices Manual Rate of penetration Controls the size & quantity of cuttings. As the angle approaches 45 deg. The re-cycling of cuttings is more severe as the angle is greater than 30 deg. Cutting transport mechanisms Suspension Bed transport In vertical sections the cuttings are well mixed with the drilling fluid. Cutting rolling or bed transport is the least efficient. Higher the ROP more is the hole cleaning efficiency to be improved. ROP. Hole inclination Angle 0 to 30 deg. In the transitional angles the cutting beds are always unstable. – Transitional 65 – 90 deg. Pipe rotation & eccentricity Pipe rotation improves the cuttings transport ratio – better hole cleaning. Sliding of cuttings is more with OBM than WBM. Pipe eccentricity (pipe sticking to the wall) reduces the transport ration – poor hole cleaning. At angles above 65 deg. Cutting beds. At angles between 45 & 65 deg. Time. Drill only as fast as the cuttings can be removed. – horizontal. Pipe rotation & eccentricity. Mud properties & flow regimes. Flow rates. The time cuttings spend on the wall greatly increase. Sliding of cuttings is reduced at higher MW.Down Hole Complications The hardest to clean is the 30 – 65 deg section because the cutting tend to slide and are unstable even with circulation. An increase in mw makes it easier to erode the cutting beds. Laminar flow is desirable in vertical sections Turbulent flow in angles greater than 55 deg. Cutting and cuttings beds Are formed during low or no pipe rotation When BHA is pulled through these sections they form a hill and pile up around stabilisers. It slows the boycott settling effect. mud than with low vis. In absence of pipe rotation cutting beds are always present Cutting beds do not exist in turbulent flow. Cutting beds are more fluidized in heavier mud and more easily disturbed The minimum velocity needed to initiate cutting rolling is less with heavier mud. Change in reology has less effect when pipe is rotating Pipe rotation is required more with high vis. Most challenging is the 45 – 55 deg section. mud. Mud properties As angle increases the effect of mud weight is less. Increases drastically between 35 – 45 deg at low MW. This will result in very high flow rates and surface pressures. Cutting bed height is substantially reduced with slight increase in MW. Flow rates Annular velocity is the most important factor in hole cleaning of high angle wells. 147 . In the horizontal section the cutting will be transported as a heterogeneous suspension above the cutting beds. When it is high it causes pack off. It also distorts the flow profile. Yield point and plastic viscosity In directional wells an increase in YP generally has a detrimental effect on hole cleaning because: Higher viscous mud cannot penetrate the cutting beds as easily as low viscous mud. It has same effect on momentum transfer The cutting con. Height of cutting beds decrease a viscosity reduces Conclusions Water in turbulent flow provides the best hole cleaning in angles more than 65 deg. In absence of pipe rotation there will always will be cutting deposition Cutting beds slide more with OBM than WBM. When the bed is small we experience drag. Intermediate viscosity mud perform the best at any angle and at all laminar flow rates when pipe eccentricity exits. Annular velocity that prevents cuttings deposition is desired. 75 Preventive measures Maintain adequate flow rates specially in high angle wells Rule of thumb for vertical wells – annular velocity should be twice the cuttings settling rate. It is a good practice to wash last few stands to bottom. As more cuttings are generated they are transported above the bed height. Maintain a high YP / PV ratio Use high viscous pill sweeps for vertical wells. Time It takes more time to transport cuttings along an inclined well bore than a vertical well. Pipe rotation and other methods are required to disturb the cutting beds. Inclination 0-30 30-65 65+ 27 1/2” 2. of bottoms up to clean hole.25 2.75 2 8 1/2” 1. In higher angles of inclination cuttings beds are well packed and tend to be stationary Rate of penetration. If pumping out of hole circulate with same or more discharge as was being done during drilling. At high angles the pipe is lying in the low side of the well bore. high viscous pills sweep combination for high angle wells Minimise connection time Establish over-pull limits. Plan wiper trips Circulate cuttings out prior to tripping out and away from the bha prior to connection. Use low. CSF or no.5 1.5 1. Has no effect in high angle wells. At moderate angles cutting beds are formed on the low side and easily disturbed. Pipe rotation and eccentricity Has significant effect in high angle wells It affects the flow profile At high angles the reduction of velocity in the low side of the well greatly hampers the cutting transport. Smaller the cuttings more is the effect of pipe rotation Rotation cannot handle large cuttings at higher ROP. Control the rate of penetration.25 1. At higher viscosities we need to rotate at higher rpm than at low viscosities. Circulation stroke factors (CSF). Pulling too hard into a pack off will prevent the pipe from being freed downward Use small increments of over-pull.75 2.Drilling Operation Practices Manual At low angles cutting are recycled on the low side of the well but they are heterogeneous and no beds are formed.5 3 12 1/4” 1. It has no effect on bed height. Stop drilling when hole conditions dictate.75 3 17 1/2” 1. 148 . Ensure that there is no torsion in the string while working or jarring upward. An increase in PV. More solids coming out of the shaker than being drilled. Drilling trends A linear increase in pump pressure. Generally the string packs off during trip out In high angle wells it can get packed off during trip in – jar up in this case.Down Hole Complications Ensure the pipe is free in at least one direction. Evaluate torque and drag trends and rate of cutting removal. pick up weight. Record all tight spots Warning signs Insufficient cuttings return for the rate of penetration.Bleed off pressure and apply 200. Only done when ever thing else fails. Jar down if jars are in the string. Increase in pump pressure to break circulation. Primary freeing procedure First action . Sometimes we can pump the string out of the hole again not first choice. Increase in both torque and drag. mud weight out. Tripping trends Swabbing. Back ream carefully at high angle wells. Jar with incremental increase in trip load.500 psi to try to establish circulation. viscosity. Secondary freeing procedure Pulling hard –not the first choice. slack off weight. String pistoning during pumping out. Erratic returns. The driller must know the maximum amount of over-pull. Early warning signs are the best way to stay to stay out trouble. Monitor drilling trends. Excessive or erratic drag. sand content. Apply torque and slack off. or low gravity solids. 149 . Erractic pump pressure. The above pistons the assembly harder into the pack-off. Connection trends Increase in over-pull over slips and a pressure surge to start circulation. If bit is bottom work up ward with low pressure. Record the free rotating weights. off bottom & on bottom torque and circulating pressure. Wash over pipe tend to get differentially stuck. gravel or its conglomerate. Hydro Pressured Shale: It account for a vast majority of stuck pipe. the hole condition will deteriorate. torque and drag increases. Observing excessive amount of loose solids coming over the shale shaker and being discharged from desander and/or desilter. 150 .Drilling Operation Practices Manual Fishing procedure Backoff above free point & wash over. Pressure surges by tripping too fast are to be minimized. After wash over run a fishing assembly with both up & down fishing jars. Wash over and recover the fish left in the hole. 2. While making connection under caving hole condition. gravel or conglomerates in top hole. This could cause the drilling assembly to get stuck or plug the bit resulting in another trip to unplug it. Reaming or back reaming is likely to disturb the bore hole and is to be done very carefully. Due to presence of caving in the annulus. Loose / Unconsolidated Formations: These are found at shallow depth and usually comprise of loose sand.formation instabilty Formation like shale and coal is subjected to caving Excessive caving may form a bridge leading to mechanical stuck up and cease of circulation. Well bore instability is caused by 1. Seepage & partial loss may aggravate the situation. pull out the wash over pipe. Minimize the exposure of the troublesome formation by faster drilling and casing the section. Tripping through the troublesome zone should be done slowly so as to minimize swab & surge pressures. Prevention & remedial measures Provide adequate support by gradually increasing mud density. If the pipe cannot be released by working with circulation. In case of stuck pipe Work on pipe to establish circulation and try to release the string by giving pull within the safe margin. (ii) Hole pack off . Most important factor that contributes to shale becoming unstable or remaining unstable is mud. These formations may slough in the well without warningwhile drilling. Washing over should utilize a heavier mud weight than was used during drilling. the bit may be set into the caving while trying to get the kelly drive bushing into the rotary. Mud type. density & reology are of critical importance. it may lead to shearing of drill string. Select the minimum number of stabilizers to drill this section as for as possible. If mud filtrate invasion into the well bore takes place. If proper care is not taken about the drag. Indications Drilling of loose uncemented sand. Put cement plug above the fish top & side track the fish. Carefully select the length of the wash over pipe. back off above the free point. During wash over if sticking of the wash over pipe is being observed. Avoid pressure surges during tripping and break circulation carefully. 3. case the problematic interval. Ream back to bottom cautiously and sweep the hole at regular intervals. Erratic torque and vibration when drilling ahead. attempts should be made to control losses. the well bore will destabilize resulting in large pieces of formation dislodged from the well bore. Use large size nozzles during drilling of loose unconsolidated formations to reduce the stand pipe pressure. chalk or shale can be naturally fractured and / or run along fault line(s). place cement plug against this interval. Use efficient hole cleaning practices. There are two options available. It will restrict circulation and could ultimately result in a complete pack-off of the annulus. Erratic drag. Select the BHA so as to maintain required angle through the fault/fracture. it is crucial to take immediate action to cure it.T. Before going in hole. Indications Large pieces of cuttings or dislodged formation observed over the shale shaker during the drilling phase. Include a jar in the string. As this phenomena is time dependent. Prevention & remedial measures Drive or grout the conductor as deep as practically possible. particularly during loss situation. Fractured & or Faulted Formations: Formations like limestone. Cement will provide reinforcement and may be required to be done as often as necessary to allow total penetration of the interval. 151 . over pull and fill after connections.Down Hole Complications Erratic drag / over pull after connections. Prevention & remedial measures Reduce the exposure of the fractured/faulted interval by preventing the bit from drilling along the dipping formations. The string should be pulled above fractured zones. Tendency for hole to pack-off. If there remains a portion of the interval yet to be drilled and if there are chances of pipe sticking. will provide valuable information in this regard. If the horizontal stress distribution is unfavorable. Avoid planning a kick off in these formations. Reaming during or after wiper trip/round trips. Experiencing seepage or partial loss. drill through the troublesome section with optimum rate of penetration with out compromising on hole cleaning. Note : Previous experience of drilling in the area along with information provided in the G. Washing over a fish left in the hole after back off may not be viable option as the chances of wash over pipe getting stuck are great. If the entire loose unconsolidated section has been drilled through. the recovery can prove difficult. its position being above the troublesome formation.O. This will reduce the tendency to become unstable. Sweep the hole regularly with high viscous pills. hole pack off will occur. If the instability is on account of severe losses. If the circulation rate is unable to lift these cuttings. Recovery of drill string stuck in loose unconsolidated formation Once the pipe gets stuck in unstable formation. Only option remaining is set a cement plug above the fish and side track the hole. Put cement plug above the fish top & side track the fish. attempt to cure before drilling ahead. Washing over should utilize a heavier mud weight than was used during drilling when the pipe got stuck. Pull out the string upto the problematic zone before situation deteriorates. Consider use of saturated salt based mud while drilling through salt sections. will have the potential to reduce the hole clearance. the longer will be the length of stuck pipe.O. although an accurate prognosis remains difficult. The hole may become under gauged during the drilling phase or when the string is pulled above the zone. Recovery of drill string stuck in fractured/faulted formations Work on pipe to establish circulation and try to release the string by giving pull within the safe margin. Saturated salt in the mud will prevent dissolution of formation salt into the mud there by to prevent hole enlargement & hole instability. Recovery of drill string stuck in mobile formation If the pipe is stuck due to salt creep. Standard wash over is also possible so long as fresh water flushing is done to prevent further creep in of the salt. Mobile Formations: Drilling of plastic salts or shales. Maintain the mud properties as specified. Plan wiper trips carefully. 152 . No significant change in the circulating pressure. which have a tendency to deform plastically or creep into the hole. Use large size nozzles during drilling of fractured formations to reduce the stand pipe pressure. Indications Mobile salts or shales mentioned in the G. Spend additional time to circulate the hole clean. back off above the free point. Tight pull while pulling out BHA across plastic salt or shale zone. High and erratic torque while reaming to bottom after a wiper trip or round trip. Ream back cautiously if needed.T. The longer the pipe is allowed to remain stuck by salt creep. Place the drilling jar preferably above the troublesome zone. Wash over and recover the fish left in the hole. During wash over if sticking of the wash over pipe is being observed. Time is of great significance. 4. Salts or shales which have the tendency to be mobile must be highlighted in the planning and preparation phase. pull out the wash over pipe. perforating and circulating fresh water will often dissolve the salt and allow for recovery of pipe.Drilling Operation Practices Manual Use the mud motors to reduce the whipping action of the drill pipe to prevent caving . If the pipe cannot be released by working with circulation. Use low / high viscosity sweeps as required. If mud loss is significant. Consider use of bi-centre bits. Prevention & remedial measures Trip & ream cautiously to avoid a sudden increase in over pull and torque respectively. O for monitoring during the course of drilling.g. Indications Significant problems during running in and pulling out. If the pore pressure prediction of is inaccurate and hydrostatic pressure exerted by the mud column is less than pore pressure.T. 6. Avoid excessive swab & surge pressure. In such a case after every recovery prove the hole with a bit and stabilise well conditions prior to further wash over. spalled fragments of shale. Indications During the drilling phase. Recovery of the fish may be in parts if the entire length of fish cannot be washed over in one attempt.O. The presence of cavings is usually accompanied by increasing levels of background gas. If these indications are ignored.T. Cavings can be small in size in the initial stage. round tripping. Reduce the time spent on activities with no circulation (e. logging.O. Emphasis is on accurate pore pressure prediction and the same is be to included in the G. Geo–pressured formations: These formations are commonly shales in a pressure transition zone. block size cavings can fall around the drill string resulting in stuck pipe. This can also result in key seat formations preventing the pulling out of B. Keep watch on the amount of pressure induced by cavings and the return flow. it is likely to result in hole instability that is recognized by distinctly splintery. Depending on the thickness of the section. / bit. bridging and hole pack off will occur.H. Optimize hole cleaning. consideration should be given to the length of fish washed over in the first attempt. offset well data. Large block size cavings on the shale shaker. Distinctive splintery and spalled cavings. drag and over pull. if it is confirmed that cavings are due to geo –pressure.P. Use heavier mud weight while washing over. the cavings are likely to cause an increase in torque. geological correlation etc prior to incorporation in the G. which should not be confused with cavings coming out from shallower zones. and the rate of deformation. Tectonically Stressed Formations: Tectonically stressed formations have unusually high horizontal stresses in one or more directions that can result in sedimentary rocks being fractured or squeezed.Down Hole Complications 5. 153 . trip gas & higher R. Prevention & remedial measures Emphasis is to be given on pore pressure prediction based on seismic data. Recovery of drill string stuck in geo-pressured formation Back off & wash over is the recommended procedure for recovery of fish.A. This data is to be supplemented with the data available during the drilling phase like R. Increase in stand pipe pressure indicating hole pack off. If the rock fails. BOP testing etc). Gradually increase the mud density. Monitor for the effect of the mud density increase.P.O. back ground gas & trip gas. sidetrack immediately selecting a more favorable well path. If the location is in a mountainous area offset well data. 154 . Ream and perform wiper trips in the interval where over pulls are encountered. If the original hole turns out to problematic. Recovery of the fish may be in parts if the entire length of fish cannot be washed over in one attempt. or polyglycols. If necessary. Increase the mud density to the maximum possible. Increase of pump pressure. Coating polymers like PHPA & Soltex will also reduce water invasion. and the rate of deformation. rock mechanical data with the seismic data can be used to assess the severity of tectonic stresses. 7. by using inhibitors like salts (K. However this might not have the desired effect or might not be possible if other zones are exposed. Include contingency hole size/ casing in the drilling program. Prevention & remedial measures Optimize of well path based on best available prognosis. consideration should be given to the length of fish washed over in the first attempt. Attempts should be made to reduce water invasion and subsequent hydration. When running in with stiff B. Na or Ca).Drilling Operation Practices Manual Erratic drag during drilling and while making connections. Plan to case the hole section as soon as practically possible. but without excessive sacrifice to inhibition. Try to recover the fish by washing over and if fails go for side tracking. YP and MBT mud reology parameters. Prevention & remedial measures Ensure timely inhibition with salts (K.H. In such a case after every recovery prove the hole with a bit and stabilise well conditions prior to further wash over. Recovery of drill string stuck in reactive formation (sloughing shale) Thoroughly condition the mud so as to maintain inhibited properties. Indications An increase in PV. dump and dilute. Na or Ca). Always break circulation slowly & carefully after trips. take extra caution when wiping or reaming the hole. The invasion of untreated water causes hydration stress resulting in cracks and swelling of the shales. During roundtrips. Reactive Formations: Formations that fall under this category are relatively young shales (sloughing shales) that react to untreated water. bit/ BHA will get balled up with clay causing over pull and/or swabbing. Use heavier mud weight while washing over. Cuttings will be mushy and if not dispersed sufficiently might cause clay balls to reach the flow line. Minimize exposure time in open hole. Depending on the thickness of the section. Recovery of drill string stuck in geo-technomic formation Back off wash over is the recommended procedure for recovery of fish. torque and drag are also possible particularly in larger size holes. Maintain the specified mud properties.A. Crooked hole country with hard & soft inter-bedding. In longer key-seats the number of tool in this interval will provide cyclic drag. The string is usually in compression while rotating through the dog leg. Hardness of the formation at the dog leg In vertical wells the shallower the key seat the more troublesome it will become. Reasons for sticking due to well bore geometry: a) Doglegs b) Ledges c) Squeezing formations d) Under gauge holes a) Doglegs Majority of well bore related sticking is due to doglegs. When to expect key seats High side loads. There must be dog leg for a key seat.Down Hole Complications (iii) Well Bore Geometry Mechanical stuck due to well bore geometry is due to the conflict between the shape of the BHA and shape of the well bore. usually no restriction in circulation. Warning signs: Increase in torque and drag during drilling. Doglegs result in: Key seats Ledges High side loads Torque Poor cementation of casing Trouble running casing & logs String failure. casing wear during drilling Key seats Rotating drill pipe against a dogleg cuts a slot in the formation which is smaller than the BHA. Long rotating hours. While tripping out the drill pipe can pass but the larger and stiffer BHA cannot. High side loads exists when the dog leg is at a shallow depth. Interval of over-pull spikes at 30’ interval. 155 . Rotating off bottom creates more tension at the dogleg. Cyclic drag during tripping – as the tool joints pass through the key-seat. A side force is necessary Pipe must be rotating & rotating long enough. In horizontal wells although a huge dog leg is created it does not create troublesome key seats because the side load is less. Factors affecting key seat formation. production equipment failure. Driller must be aware where his BHA is with respect to well bore geometry. Use greater length of HWDP so as to have more set down weight. Freeing procedure for key-seats Jar in the opposite direction the pipe was moving before it got stuck. Spot a lubricating pill. Warning signs Sudden set down weight as the BHA enters a dogleg. If the key-seat is in a carbonate formation -try an acid pill. If the key-seat is in a carbonate formation try an acid pill. Once free down ward back ream out Secondary freeing procedures for key seats If string is not free by down jarring or surface jarring then: Back off above the key-seat and run in with fishing jars. BHA changes to be minimised. Ream and wipe out doglegs when suspected. High torque when rotating into a dog leg. Minimise the set down weight in doglegs. 156 . Low frequency resonance tool may knock the pipe out the key-seat Secondary freeing procedures for key seats If string is not free by down jarring or surface jarring then Back off above the key-seat and run in with fishing jars. Be always aware where the BHA is with respect to dogleg section. High torque and drag during pull out Prevention of stuck pipe due to stiff assembly Limit dog leg severity. Ream the dogleg section. Avoid rotating off bottom. Take totco frequently. Since all stuck up in key seats takes place during trip out – apply torque and jar down. Spot a lubricating pill. Casing being stiff this type should be anticipated past build sections or doglegs. Tripping in with a stiffer BHA. Stiff assembly sticking Occurs when a stiff BHA jams into the dogleg.Drilling Operation Practices Manual The most indicative of the key-seat presence is increase in over-pull in subsequent over-pull. Low frequency resonance tool may knock the pipe out the key-seat. In the same interval of the key-seat tripping in is not a problem Prevention of stuck pipe due to key-seats: Avoid sharp doglegs specially high in the well. Pull slowly when BHA is passing the keyseat. Wear on stabilisers or part of the BHA. Install a key-seat wiper in the string. Acid pills in carbonates. Back off and run fishing jars Micro doglegs or crooked hole Are caused by directional changes or natural drilling tendencies in soft hard alterations. Making several directional changes or sliding with motor Prevention of micro deg leg sticking Minimise directional changes. When the stiff BHA is in tension it cannot pass the reduced diameter. Increasing torque while drilling Trend of bottom & off bottom torque. While jarring up never apply torque. Low frequency resonance tools. When to expect ledges Hard & soft inter bedding – leads to bit walk. b) Ledges Mainly caused in inter-bedded formation Harder formation in gauge . Increase in torque & drag while picking up. spotting agents. They give trouble when running casing. Frequent back reaming will wear the rough edges of the micro doglegs. 157 . Pipe usually gets stuck while picking up. softer formation washed out Doglegs can lead to ledges. Also form around factures & faults. Stiffer assemblies and casing can get stuck while moving down. Avoid high WOB with slicker BHA. Driller must be aware where the BHA is with respect to the doglegs.Down Hole Complications Freeing procedures Jar in the opposite direction the pipe was moving prior to getting stuck. A number of micro dogleg together cause excessive trouble They reduce the effective diameter of the well. Stabiliser blades can also hang up on ledges. Spot lubricants. acid in carbonates. High dipping formations Warning signs Fluctuating ROP. Wire line resonance tools. Secondary freeing procedure A spotting fluid is placed to reduce friction. Freeing procedure Jar in the opposite direction the pipe was moving prior to sticking. Squeezing is caused by overburden. Salt is very plastic. Care during tripping. Sudden set down of casing or drill string. Graded salt where salt dissolves at different rates. A lack of cuttings. Known inter bedding. & bit wedge into lesser diameter. No problem drilling. tectonic forces. fractures. 158 . Increase in ROP. Increase in torque & drag Prevention Avoiding the salt or creeping formation. marls. Acid pills in carbonate formations c) Squeezing Formations Commonly salts. Temperature. Mud weight and mud type Warning signs Presence of salt or coal. plastic shale. · Ream troublesome ledges. Freeing procedure Jar with light strokes initially to prevent fall of loose formation. If the casing is stuck going down upward motion may be free and the casing may be rotated to bottom. If assembly going down is free. Purity and thickness of salt. or faults Prevention Prevent doglegs. Raise mud weight. but during trip out the stab.Drilling Operation Practices Manual Fractured & faulted formation. or hydration swelling. Factors affecting salt deformation or creep Overburden and tectonic stresses. then rotate past the ledges while trip out. Use better mud program to prevent hole enlargement – inhibitive mud. Any type of dog leg Warning signs Fluctuating rate of penetration Cyclic over pull during trip out Sudden & erratic over pull at the stabiliser blades or bit hits a ledge. Increase in chloride concentration. Bi-center bits. hole pack off and well bore influx is extremely hazardous. A situation in a well where there is mud loss. The drop in level of mud in annulus causes a reduction in hydrostatic head and may lead to lesser wall support of an exposed shale section causing sloughing. 13. To prevent pipe from getting stuck due to mud loss the following is suggested: 159 . Freeing procedure Jar up when the pipe is stuck going in. In case of salts ROP increases.2. Cuttings may accumulate in the low velocity region and may fall back into the bottom of the hole resulting in stuck pipe due hole pack off. partial loss or total loss against natural factures. The reduction in the annular velocity of the mud in the zone above the loss zone reduces the carrying capacity of the mud. Acid pills. Ream any under gauge hole intervals. Always check the gauge of all tools going in and out of the hole. This will further deteriorate the well bore stability and may cause the pipe to get stuck against the shale section also. Mud flowing into the formation implies that there is less mud return at the flow line than is being pumped or that there is total loss of circulation. loss due cavernous and vugular formation or induced losses. A fresh water pill can be spotted to dissolve salt d) Under gauge hole Due to under gauge bit or stabilisers.1 Mud Loss Lost circulation is the loss of borehole mud to the exposed formations in the well and may result in stuck pipe.2 OTHER CAUSES OF STUCK UP 13. The reduction in hydrostatic pressure against a permeable formation may result in well bore influx. Spotting fluids.Down Hole Complications Use salt based mud. Running built up stabilisers. Prevention of stuck up due to under gauge hole Care while tripping. Prevention & remedial measures The measures to be taken to control the mud loss will depend on whether the loss is a surface seepage loss. Drilling of abrasive formation. Plastic formations. Regular reaming of the salt interval. Freeing procedure Jar in the opposite direction the string was moving prior to sticking. Warning signs Poor ROP due to bit wear. time consuming and expensive. Cement is displaced for a pre-determined length into the string annulus and some is also left inside the pipe so that as the pipe is pulled out. 13. allow the well to cure by resting without circulation with the bit inside casing shoe. In case of activity the primary task is to shut in the well immediately. Unable to pull out the cementing string.. Provide extra storage to ensure sufficient mud supply. In case the loss is not severe or is due to surface seepage. Loss of circulation can occur against any weak zone in the open hole. Identification Unable to reverse circulate. leaving a clean uncontaminated plug in the well. foam. the pull out the string inside casing shoe keeping the annulus full. air. The string must be pulled inside casing shoe and keep the annulus full. The flow fill line indicator must be installed prior to spudding the well. A provision for another contingency string of casing or drilling liner is to be made if severe loss is expected. 160 . The potential danger lies in the unlikely chance of flash set causing the string to be cemented in the hole. cement is pumped through a string of drill pipe or tubing.Drilling Operation Practices Manual All potential loss zones are to be indicated in the G. Minimum numbers of the largest size drill collars are to be used in this section of the hole. A properly placed drilling jar will not only help in releasing a stuck string but also help in regaining circulation in case of hole pack off. Control of loss in smaller hole sizes is much easier. Is case the loss does not result in well activity but causes hole sloughing.O. the cement inside fills the pipe displacement. Adequate stock of loss control material is to be maintained at site.T. or aerated mud or if hole conditions permit. In areas known for mud loss drilling must be done using larger size nozzles. dry drilling are to be worked out. Always use drilling jar in mud loss prone area while drilling. whether the hole is sloughing or not and whether the loss also results in well activity. The decision to place loss control material against the loss zone prior to pulling out will depend on the severity of the loss.2. While setting a balanced cement plug. Feasibility of drilling the loss zone using gas. In case the loss is in the larger diameter of the hole (>121/4”) the feasibility of drilling a pilot hole with reduced discharge and large size nozzles is to be worked out. In case of partial loss which does not result in well bore instability or well activity a loss control material should be pumped into the well. Adequate supply of technical water is to made in advance in loss prone areas. Drill the loss control zone with a minimum mud weight and optimum discharge. This will help to take remedial measures as soon as well bore starts to take mud. The cement is designed based on hole conditions and should be retarded or accelerated as required.2 Cement Sticking During placing a cement plug in open hole by a balanced plug. Minimize the surge pressure during tripping and while breaking gel after tripping in the hole. with minimum number of stabilizers/reamers. it allows close monitoring. The casing being squeezed can leak from a point above the packer setting depth. Cementing units and mud pumps should be checked prior to taking up cementing job. Unseat the packer and reverse out the cement in the annulus. Preventive action While carrying out a squeeze job using a open end string is to place a balanced cement plug. Attempt to circulate at a higher pressure than that available with rig pumps ( use cementing unit). Another option is sidetrack from above the stuck pipe or plug and abandon. The squeeze operation should be stopped immediately. the pressure in the annulus will indicate it. the annular clearance between the cemented string and the casing rules out wash over as a means of recovery. During a cement squeeze job using a packer. Make all arrangements for reversing out in advance. The depth at which the pipe is cemented. Even when a packer is utilized for a squeeze job. several problems may result in cementing the pipe in the hole. Preventive action Technical water should be tested for designing cement slurry.Down Hole Complications Immediate action Pull to the maximum safe limit of the string. Reverse out 11/2 times the annular volume and then squeeze. Contamination of the cement with mud should be prevented by using spacers. Recovery process Back off and wash over the cemented string. Except in large size casings. Recovery process If the pipe is cemented in place inside a casing the following will decide the recovery techniques to be followed: The length of the cemented section. depending on techno economics. The packer can leak. 161 . While using a packer to squeeze monitor the annulus pressure. Any build up of pressure will indicate a leaking packer. Immediate action If there is any pressure change which indicates cement is entering the annulus of the cementing string. The annular clearance between the cementing string and the casing. The strength of the cement bond. is to mill out the cemented string. Unseat the packer and reverse out the annulus volume. Should there be leak occur. One option. anywhere. Both these instances can lead to the string getting stuck above the packer identification: If a pressure gauge is installed on the annulus of the cementing string. Simulate down hole conditions prior to cement job. Pull the string above the cement plug. Stop the squeeze job. c. The heat checking in the presence of mud causes alternate heating and quenching. f. a) Fatigue failure Mostly drill pipe failures are caused by fatigue. Twist off d. It is usually the result of a fatigue crack penetrating the wall of the pipe. Tool joints which are rotated under high lateral force against the wall of the hole may be damaged as a result of frictional heat checking. tong marks. Surface imperfections caused by slip marks. Failure of the drill pipe due to fatigue takes place in the pipe body generally in the area where slip is set. Fatigue is the combined effect of tension. Tensile failure. Fatigue also results in heat checking of tool joints. Wearing out and tool joint gets worn out and connection not made up to its recommended torque.Drilling Operation Practices Manual 13. The heat generated at the surface of the tool joint by the friction with the wall of the hole under high radial thrust may raise the temperature of the tool joint steel above its critical temperature. The rate of propagation is related to the applied cyclic load. Since the crack develops from the inside of the drill pipe and no plastic deformation occurs these cracks are very difficult to detect. in drill collars it takes place in the connection with the pin being left in the box. grooves caused by rubber protectors. e. Down hole vibrations. Slip crushing. torsion and bending. This type of failure usually occurs in the following manner : 162 . h. cuts. Washout. Collapse. welding and down hole notches caused by junk greatly affect the fatigue limit. This results in numerous irregular heat check cracks often accompanied by longer axial cracks sometimes extending through the full section of the joint and wash outs may occur. Fatigue results in washouts and twist off. g. c) Twist off Usually caused by the fatigue crack extending around the pipe and causing the pipe to break. Fatigue results in washouts and twist off. Fatigue failure. b. Fatigue is accelerated when string is rotated in a section of directional & crooked hole. Fatigue fractures are progressive beginning as micro cracks that grow under the action of cyclic stress. Burst. Wash out may also be caused by a damaged shoulder of box and/or a damaged pin. The cyclic reversal of stress that results in as the string is rotated. b) Washout A washout is a place where a small opening result in forcing the drilling fluid through pipe.3 STRING FAILURE: The main causes of drill string failure are: a. The hardness of the affected surface is normally 3/16” below the OD. Down Hole Complications Most failures occur when rotating or when picking the pipe off bottom immediately after drilling rather than pulling on stuck pipe. etc. severe down hole vibration can cause drill string fatigue (washout / twist off). 163 . This condition usually occurs during drill stem testing and may result in collapse of the drill pipe. the total weight of the drill stem member together exceeds the pipe yield value. crooked drill string. welding arc spots.e. Although this type of failure is usually near the top of the string. premature bit failure and reduced penetration rates. Tensile failure usually occurs if Error in the weight indicator. Progressive growth is indicated in such damages. f) Burst failure: Also this type of failure is extremely rare but it can occur in any operation with a high differential pressure from inside the pipe. The pipe is of lower class than assumed because of improper inspection or excessive wear since last inspection. Tension factures surfaces often show extensive plastic deformation. failure frequently occurs in a location where a fatigue crack has developed but has not progressed to the point of failure. weight. g) Down hole vibrations Although some down hole vibrations are inevitable. e) Collapse failure: Drill pipe may be subjected to an external pressure higher than the internal pressure. The design of the drill stem for static tensile load requires sufficient strength in the top most member of each size. d) Tensile failure The drill string can fail due to tension alone i. weight or grade of string is in the hole due to improper design or due to mix up during tripping. Failure that originate from the outside of the pipe are usually associated with slip marks or other surface damages such as gouges. The actual tensile strength will be more because the yield strength is normally high than the minimum specified tensile strength. In tensile failures the pipe body usually bottle necked near the fracture. While pulling accidentally or purposely more than the rated capacity. marks made by drill pipe protectors. Tensile failure of the tool joint is rare because the tool joint has a greater cross sectional area than the pipe body. The exception is when a slim undersized connection is used or the tensile capacity of a pin neck is weakened by higher make up torque. Rated tensile capacity is the product of the minimum yield strength and its cross sectional area. Facture surfaces will be oriented 45 degrees to the axis of the pipe. Most failures occur within 1m of the tool joint on either end of the pipe. for example when well testing or fracturing. The tensile failure will in most cases be located between the upsets. grade and class of drill pipe to support the buoyed weight of all hanging load below it. but variation in wall Fthickness and tensile strength between different pipes can cause pipe to fail somewhere lower in the string. In case of stuck pipe. The drill pipe will be mashed flat or into a half moon shape. The collapse pressure is the maximum in the lower most drill pipe. The wrong size. lift bit off bottom and stop rotation. drill with reduced RPM. consider changing bit (flatter profile. To control this. Primary symptoms are surface torque fluctuations (greater than 15% of average).15 to 1. their symptoms and methods of control are described below : i) Slap stick Non uniform bit rotation in which the bit slows or even stops rotating momentarily. lift bit off bottom and stop rotation. fatigue cracks and reduced ROP. cutter impact damage. To control this run shock subs. Symptoms are: cutter damage.25 times WOB. ii) Drill string whirl The BHA (or drill pipe) gears around the hole.Drilling Operation Practices Manual These vibrations cause three component of motion in the drill string and bit axially. drill string washout/ twist off. adjust stabiliser placement. reduce stabiliser torque. pick off bottom before stopping rotary use stabilised BHA with full gauge near-bit stabiliser or reamer. change length of BHA. causing the drill string to torque up and then spin free. adjust WOB/RPM. uneven bit gauge wear. use non rotating stabiliser or roller reamer). All three dynamic motions may coexist and one motion may cause the other. The violent action slams the bit against the hole. then reduce RPM & increase WOB. h) Slip crushing: A majority of the drill pipe failures occur in the slip area. consider changing bit style. localized tool joint or stabiliser wear. These type of failures are caused by: 164 . Symptoms are large axial vibrations (shaking of hoisting equipment) large WOB fluctuations. increased average drilling and off-bottom torque. Avoid drill collar weight in excess of 1. The mechanism can cause torsional and lateral vibrations. anti whirl). This causes high frequency lateral vibrations of the bit and drill string. To control this. adjust stabiliser placement. This can be controlled by reducing WOB & increasing RPM. cutter and/or bearing impact damage. reduce stabilizer torque (change blade design or no. iv) Bit bounce Large WOB fluctuations causing the bit to repeatedly lift off & impact the formation. of blades. Symptoms are: drill string washout/twist-offs. consider drilling with down hole motor. smooth well profile and rotary feed back system. over-gauge hole & reduced ROP. use packed hole assembly. iii) Bit whirl Eccentric rotation of a bit about a point other than its geometric centre. For mechanisms. modify mud lubricity. torsional and lateral). connections over-torque or back-off. modify mud properties. This mechanism sets up the primary torsional vibration in the string. use slower RPM when tagging bottom and during reaming. There are number of mechanisms which can cause severe down hole vibrations. increased MWD shock counts. This mechanism often occurs while drilling with roller cone bits in hard formation. a hard formation mill tooth bit run with a junk sub will break up the cone. Magnets are less effective in recovery of cones in loose formation as the cones are covered by cuttings and stuck in the bottom of the hole.versa. the entire set of dies on the slip must be changed. it can be rotated with circulation to release the cones allowing the magnet to catch them. Never use re-sharpened dies. When wear or non uniform gripping of the slip dies is observed. Do not use new master bushing in a worn rotary table and vice. which if the weight is sufficient will elongate the drill pipe in this area. and at this point the axial load is less than the hook load. This condition exists because the collapse strength of the drill pipe in the slip area is exceeded. The presence of transverse load diminishes the total load in pure tension which causes yielding. Proper handling techniques Do not stop the downward movement of the drill string with the slips instead of the brake. Part of the junk will be walled off and the remaining will be collected in the junk sub. 13.Down Hole Complications Highly concentrated stresses originating from axial and transverse loads that are not equally distributed over the full gripping surface of the slip. This elongation yields the pipe and renders it useless. If the slips are caught in the tool joint area. This result in the area immediately below the last gripping surface of the rotary slip to an increased tensile load. Recovery of bit cones in soft formation This depends on the size & number of bit cones left in the well. The calculated axial load verses the transverse load factor must always be considered when designing a drill string with excessive hook loads. there is a possibility of damage to the slip. Maximum axial and transverse loads do not act at the same section in the slip area. If only one cone is lost in the well. The critical section occurs at the zone of maximum crushing pressure. Always use slip of correct specifications of tubulars. Do not overlook the effect of transverse load. Always use back up tong when breaking or making connection. Improper handling methods which result in abnormal markings and stressing in the slip area. The following is a generalized procedure for recovery of lost bit cones. bottlenecking or crushing will occur when excessive hook load is prevails. Never allow the pipe to rotate in slip. 165 . Run a reverse circulation junk basket if two or more rollers are left in the hole. Drill pipe failure in the slip area can be prevented by Maintaining rotary master bushing and slips to correct API specifications and by good handling techniques. Usually the junk walled off will not fall back in the hole. with adverse conditions of equipment or handling techniques. However if a recessed magnet with circulating ports dressed with a mill type shoe is available. Inspect the slip immediately when this happens and carry out repairs if necessary. Use thick wall tube drill pipe. The transverse load acts as a compressive force on drill pipe and. Do not let the slips ride the pipe.4 BIT FAILURE Fishing of bits especially roller bit cones is one of the most common fishing operations. If the bit has turned over especially in large diameter holes. A magnet may be more effective if the formation against which the cones are lying is trap or basement. There have been cases of the junk basket getting mechanically stuck against a cone which is partially embedded in the wall of the well bore. especially prior to running a junk basket. Run this bit only for a short time to prevent leaving teeth. The most effective way to remove bit cones is to mill them with a concave mill run along with a junk sub. Recovery of lost bit cones is more commonly done with junk basket. A number of trips with a mill may be required to clear the junk. and possibly more cones. If the junk is small enough to enter a junk sub. A clean out trip with a hard formation bit with junk sub may be required after milling. If the top of bit is a clean pin then run a matching box and screw into the pin of the bit. When run on drill string. Junk baskets are less effective in hard formation. A clean out trip with a hard formation mill tooth bit and junk sub will clear the bottom of the hole. magnet must be dressed with a mill type shoe and have circulation ports to permit rotation with circulation to remove cuttings from the top of the cone/s. There have been cases of the junk basket getting mechanically stuck against a cone which is partially embedded in the wall of the well bore. The most common method of removing a bit which cannot be removed by a matching pin or a tap is to mill it into small pieces. The mill shoe often gets worn out before a core can be cut of sufficient length to hold the junk in the basket. If the magnet can be run on wireline (sandline) time taken for tripping with drill pipe can be saved. A junk sub should always be run with the mill. A junk basket run with a milling shoe will invariably be able to cut a core of sufficient length to accommodate the lost cones and other minor junk. Parted bits and large junk Bits and other large pieces of junk are almost always removed or walled off by milling. any accumulation of cuttings on the junk will not permit recovery of cone/s. Longer time taken to cut the core can damage the fingers of the junk basket. A taper tap may be used to catch the bit which is lying with pin up. Unless a magnet can be run on wireline. Run a junk sub along with the mill. make a trip with a impression block. Magnet being a contact tool.Drilling Operation Practices Manual Recovery of bit cones in medium hard formation Since there is a possibility of the bit getting under gauged prior to its failure it is advisable to make a bit trip to prove the hole to bottom. Recovery of bit cones in hard formation Since there is a possibility of the bit getting under gauge prior to its failure it is advisable to make a bit trip to prove the hole to bottom. then run a junk basket. A flat mill will break up the junk although it will not be as effective as a ribbed cutting face mill or concave mill in breaking up and walling off the junk. it may not be economical to run it on drill pipe. 166 . especially prior to running a junk basket. 2 Casing Split or Burst Split or burst casing occurs from many causes. Some failures that cause casing leaks may also cause split or burst casing. especially with long. Failure to fill the casing during running. Collapse & burst casing.5. Operations or mechanical failures due to improper construction. such as being lowered rapidly lowered and stopped abruptly.5. 167 .4 Collapsed Casing Casing collapse due to various reasons some of which are the same which cause casing leaks. 13. or worn casing at the point where liner setting tool slips engage the casing. 13. heavy liners. 13. Casings can also split due to high density perforation specially in the higher strength steels. heavy casing strings. Casing may split while hanging long. The extent of casing failure covers wells offshore and onshore varying in size from 13 3/8” to 5 ½”. Casing may also split due to structural defects. Wear out of intermediate casing due to tool joint of drill string /junk inside casing.5 CASING FAILURE AND REPAIR Failure of casing is an area of increasing concern. Split or burst casing may also part due loss of structural integrity. Improper design.Down Hole Complications 13. General causes include inadequate strength due to improper design. Other causes can include excess wear and resulting loss of tensile strength. Applying excess internal pressure sometimes in combination with high tensile loading.3 Parted Casing These types of failures are caused mainly due to: Improper design.1 Leaks Casing leaks are the most common failures and often occur in association with most other failures. Corrosion and to a lesser extent erosion and mechanical wear during production life of the well.5. Parted casing usually occurs at the connections especially in lesser strong connections. Some of them are: Improper design. 13. pulling hard while working stuck casing and bumping the plug too hard during cementation. Failure of casing occurs mainly due to: Leakage from joints due to improper make up. Bumping the plug too hard during cementing. Mechanical wear during fishing and specially milling.5. The major causes for leaks are: Improper make up during running. Wear due to running stabilizers in cased hole. Excess internal pressure may occur while testing liner top or testing casing before drill out. Drill pipe wear during drilling. Casing may part during running due to improper handling. 168 . Can the failure be repaired by normal future operations? A casing failure may not pose a problem in current operation and can be effectively repaired or effectively eliminated by future operations. If this does not create an immediate drilling hazard. Age of the well. repaire the failure. If the well is deepened later. Can an extra casing be run? It may be possible to repair the casing by running another string of casing. pressure. Some times casing collapse may be due to shifting or flowing formations like massive salt sections. Casing may collapse due to squeezing or treating below a packer set in the casing. Can the casing be plugged off and repaired later? This applies mainly to production casing. Formation type. size & depth of failures. The hole can be covered later by a production casing or liner that extends over the hole. Production testing of the upper objects can be done.5. For example a drill pipe can cause a hole in deep surface or intermediate casing. A partially collapsed casing above a conventional completion like an intact packer and tubing with no annulus pressure build up may not be repaired. Whether the problem is in cemented or un cemented section. 13. If the casing fails in the lower section. Whether the option of using extra string of casing is available. Severity of failure. Worn or poorly designed production casing may collapse when the hydrostatic head is reduced by compressor / nitrogen application. Casing repairs are best reviewed & evaluated by considering the following How does the failure affect future & current operations? The first thing that needs to be evaluated is whether the failure needs to be repaired. Productivity from the well. fluid in the formation & transition zone. and no other hazardous conditions exist. The failure may not have an adverse effect on operations. or a stub liner. There are some exceptions like a partially collapsed larger diameter casing above a drilling liner which is not impeding the normal operations. Anything that reduces wall thickness.5 Factors Affecting Casing Repairs Casing type. one procedure would be to set a plug and isolate the failure. do not repair the casing. Can the failure be patched off or packed off the leak? Some casing repairs can be made by a simple casing patch or packing off the leak. including wear or corrosion increases susceptibility to collapse. Is the internal diameter restricted? An immediate repair may be needed if the restriction is preventing the running of full gauge tools / completion string and other operations. if not. Current status of the well (drilling or production).Drilling Operation Practices Manual Wear reduces body strength so the external pressure may cause the casing to collapse. drilling operations can continue without making a repair. a liner. Failure in casing not cemented: When possible. Pressurize the casing to ensure that the cement does flow back into the well. but it is not applicable in many cases. pull the casing. The disadvantage of this method is that it leaves a potentially weak section that must be considered during future operations. perforate below the failed section and perform a primary cement job in a similar manner.5. In case of a retrievable packer or open end tubing or drill pipe. Repair a failure at the bottom of the hole above a liner with a tie-back liner. Clean out with bit. retrievable packer or cement retainer. it should be covered by production casing. Consider plugging back and sidetracking. Squeezing of cement can be done through open end tubing or drill pipe. Alternately run two packers on tubing or small size casing separated by the length of damaged casing. take precautions to ensure that this assembly does not get stuck in cement. A damaged section can be isolated from the remaining well bore by running a packer on tubing or small size casing. Inside patch reduces the inside diameter of the casing by a small amount. it is the fastest and most economical type repair. Back off or cut the casing below the ailed section and pull it. In a few cases if the casing has been set at bottom in a gauged hole. Patch off the failure: Various types of inside casing patches are available. Expand the sleeve by pulling the mandrel through it to form a sheet of metal inside the casing. Squeeze and clean out: Generally this is the simplest method of repairing a casing failure such as a leak.6 Casing Repair Methods Type of failure must be acknowledged. Repair parted casing in place: One of the best methods where possible is to establish circulation through the failed section and perform a primary cement job under a retrievable packer or cement retainer. The external casing patch can be a lead seal or lead seal cementing type. Nevertheless. Pull. Run it into the cased hole and position it over the failure (usually a hole).Down Hole Complications 13.wall steel cylinder. repair. Generally they include a ribbed or corrugated. replace it run and reconnect in a way similar to parted casing. In general make the simplest repair possible that will accomplish the desired results. or plugging back and abandoning the hole. Another method is to squeeze the section till it holds the desired pressure. If the failure creates an immediate hazard. thin. Then run a full gauge mill and ream as necessary to ensure full gauge hole. plugging back and drilling another well. Loose casing shoe joints: These are generally repaired by cementing the joints to fix them in lace and prevent movement. Replace the damaged section and either screw back into the lower section or connect it with an external casing patch. it may not be necessary to cement the loose joint and operation can continue. Alternately. Squeeze the section and run a full gauge tool through to ensure that the hole is full gauge. Pack off the failure: Pack off the failure by isolating it. Otherwise try to cement the casing in place with a primary 169 . it may be squeezed off and covered by casing or a liner. If a failure is in the bottom of intermediate casing. Disadvantage of this method is that it reduces the working inside diameter of hole and usually restricts operations below the failure. Run another string of casing or stub casing or tie-back liner: If the casing is large enough run another casing or stub casing or liner. which can cause burst and collapse strength to reduce. Pull the cementing assembly above the damaged section of casing and reverse out so that all excess cement is circulated out. The objective or status of the well is also to be considered. rerun and reconnect parted casing: This is one of the best casing repairs. SPLIT OR BURST PARTED REPAIR CASING IN PLACE MILL OR REAM OUT SET INTERNAL CASING PATCH PACK OFF DAMAGED SECTION CUT.7 Summarised Casing Repair Flow Chart COLLAPSED LEAK.5. If the failure is such it restricts the inside diameter of the casing then the diameter should be restored by rolling out or swaging or milling out and squeezing if necessary. CLEAN OUT TEST LAND CASING NIPPLE RESUME OPERATIONS 170 . Failure in cemented casing: This is one of the more difficult casing repair job.Drilling Operation Practices Manual cement job. 13. Running another string of casing or liner may be a viable alternative. WASH OVER CASING B A C K O F F SWAGE OR ROLL OUT MILL TOP CLEAN BACK OFF LEAVE THREA D UP RUN CASING WITH EXTERNAL PATCH RUN CASING WITH ALLIGNMENT TOOL AND MAKE UP SQUEEZE. Pulling the uncemented pipe and milling the remaining casing till the bottom of the damaged casing is removed may not be an economically viable alternative. Running another string of smaller diameter casing or tie back or stub liner may be applicable. Generally the cemented casing cannot be repaired by replacing the casing above the failure. MILL AND FISH OUT THROUGH THE PARTED SECTION. 33 65. 19.05 x L Note: This method is fairly accurate in straight wells.53T 48.P1 = Differential pull (T) Considering a correction factor of 1. 1500m of 5". Note : The pull must be within the safe limits of the margin of over-pull of the string.02 Kg/m.5 ppf# (NC50) G grade class 2 drill pipe weight per meter 32. Example String stuck at 4200m in 8-1/2" hole with mud density 1. Weight of the drill collars in air = 200 x 136. The mid point between the two marks is taken as the upper reference mark A.4.64T 0.4 Weight of E grade drill pipe in air = 1500 x 31. A pull (P1) of 10-15T greater than the air weight of the drill string is applied to the stuck string and a mark is made on the kelly or pipe as the case my be. Step I : Calculate the margin of over pull (MOP).1 Method of Application of this Technique Prior to measuring the differential stretch the string should be thoroughly worked so as to minimize the effect of residual stress in the string.945T 33.Down Hole Complications 13.64 Buoyancy factor in mud of 1. Another mark is made on the kelly.5 ppf# (NC50) E grade class 2 drill pipe weight per meter 31.P1 Where : L = Length of free pipe (m) A = Cross sectional area of drill-pipe (cm2) e = Differential stretch (m) P2 .63 Weight of S grade drill pipe in air = 1000 x 33.1.4 SG is 1 .63 Kg/m.5 ppf# (NC50) S grade class 2 drill pipe weight per meter 33.5 171 = = = = = 27.02 Weight of G grade drill pipe in air = 1500 x 32. A pull P2 (P1+ 10-15T) is applied and a lower reference mark B is made following the steps mentioned above. 19. This pull is released and equal pull (P1) is applied once again. 19. 13.6 DETERMINATION OF THE LENGTH OF FREE PIPE IN A STUCK STRING Find out the length of free pipe by the following equations. Drilling String: 1500m of 5".6.05 for tool joint the equivalent length (Leq) of free drill pipe is given by: Leq = 1.822 . 1000m of 5".4 Kg/m.1 x 103 x A x e ———————— P2 .280T 46. The distance between the two marks A and B is measured as ‘e’.4 x 8.64 Kg/m. L = 2. The two marks do not coincide due to the friction in the hole. 200m of 6-1/2" x 2-13/16" drill collars weight per meter 136. 822 x (27.67T) is: 122.05 x 103 x 34.628m Step III: 2 Apply the formulae with A = 34.73T) is: 171. Make another mark of the string.03 cm . = 49.e.945) = 53.56 + 49.3T Step II: Apply a pull (P1) of 160T and make a mark of the string. Put the neutral point on a level with the joint to be backed off. Let us assume this distance is 62.73T Buoyant wt. e = 0.280 + 46.8T) is: 220. 3. 175-160 = 15T. Release the string weight to 128T and again pull to 160T.280 + 46.822 x (27.9 .8 cm i.0. etc.64) = 70. hook. 0. (tons) P = Hydrostatic pressure at the point of back off (kg/cm2) A = Area of the mating surface of the tool joint.945 + 33. of drill string is: 0. The distance between A and B is the stretch for a differential pull of (P2-P1) i.53 + 48. Make up the string to the maximum of 80% of the torsional limit. 128.9 . W = Buoyant weight of free drill string plus weight of kelly.4T 0.65T MOP of S grade drill pipe (class 2) with tensile strength (220. traveling block.822 x (27.9 .Drilling Operation Practices Manual MOP of the drill string is given by Tensile strength of the pipe x factor of safety (0.16T Hence the MOP of the string is the minimum of the three i. Before back off first determine the free length of drill string by either the differential stretch method or more accurately by electro-logging technique. cm2 172 .280 + 46.67T x 0. Mid point between these marks is point B.280 + 46.e.56T.8 x 0. MOP of E grade drill pipe (class 2) with tensile strength (122. Apply a pull (P2) of 175T and make a mark on the string.56 Air of wt.e.73 = 178.8m.0.64) = 128.822 Hence while working on pipe or during calculation of the free point the hook load of the string should not exceed 128. The weight indicator tension is given by: PxA T = W + ———— 1000 where T = Weight indicator tension in tons.93m 15 Back Off of a stuck pipe 1. 2. Mid point between the two marks is point A.822 x (27.53 + 48.53 + 48.945 + 33.1 x 1. of the string = ———— = 156. P2-P1 = 15T 2.8 Length of free pipe = —————————————— = 4001.53) = 49.0.9) minus the buoyant weight of the string.73T MOP of G grade drill pipe (class 2) with tensile strength (171.73 x 0.03 x 0. Release the weight to 128 T and again pull to 175T. then in this case the weight of kelly & swivel etc.26 T Minus 52.6. in air = 61. pull = 5T WEIGHT TO BACK OFF FROM TOP OF 8” D/C = 45. friction & pipe lying on the low side of the hole is 48. of block = 11 T TOTAL WT. starting the calculation with wt. we have 1500m x 31. due to buoyancy.4 T 25. = 48. In that case use rotational weight.86 T 192m x 75 Kg/m HWDP = 14. Work 80% of left hand torsion of that applied in step 2 to the point of back off. in the hole = = = 39 T 87.22% buoyancy & friction etc. of pipe in the hole would be = 50T Minus the wt.4 T Total Wt. Run in the string shot to point of back off desired and detonate the string shot.27 T Plus wt. 13.2 Back-off Procedure in Highly Deviated (ERD) Wells When backing off in a deviated hole it is difficult to calculate the loss of weight due to buoyancy.102 T In this case assume that the weight indicator reading before pipe got stuck was 50 T.102 T Loss of wt.3 Precautions While Backing Off with String Shots (Deviated Holes) When taking the free point with a logging unit. 5. reamers = = = = 46. then the joint is partially opened and by working the torque down the joint may get fully opened. in the hole = 29. 6. friction in the hole & weight of pipes lying on the low side of the hole.842 T 25. is not be considered.102 Kg. stab.6. If the string is not fully opened.22 % .) The wt. If it is less than that applied in point 4. of what is left behind in the hole. = 31. Note: If back off is done without the kelly connected. To back off at the top of the D/C. Example Assume that following drill string is in the hole : 1500m x 31. IN THE HOLE Wt. 173 . of the block = 11 T Plus 5000 Kg.24 Kg/m drill pipe 192m x 75 Kg/m HWDP 118m x 219 Kg/m of 8” D/C.99 T Total wt. reamers 118m x 219 Kg/m of 8” D/C. stab.102 T 39 T LOSS OF WT.27 T Note : Another method that could be used.24 Kg/m drill pipe = 46. count the number of turns released.86 T 14. in air Wt.842 T TOTAL WEIGHT IN AIR = 87. 13. the tool pusher and logger should be in the logging cabin with the logging engineer to study the behavior of the tensionand torque indicators and to get an idea of the string reaction to the pull and torque required to overcome friction. (this should be recorded in the driller’s daily log book.Down Hole Complications 4. or 52. Run in the string shot to 500 m below the sea bed/wellhead As an example. Transmitting Torque Down the Hole The following information is required 1.) = 80T Loss weight due to buoyancy and friction = 31% (calculated same way as in example) Make up torque equivalent = 200 Amperes 174 . What is the string weight while rotating? This is considered the neutral weight. 3. assume that: Rotating weight (neutral) = 95T Weight going up = 135T Weight going down = 70T Free weight (to back off pt. then the total string weight to the next lower back off point can be calculated as : The neutral weight of the fishing string PLUS the weight of the stuck string down to the new back off point MINUS the percentage buoyancy and friction loss previously calculated for the original string. even if it is required to back off high up the hole first to be able to install the kelly. What is the weight going down? 4. Counter check this figure again with the remainder of the fish in the hole and the neutral point of the string when it was still free. When this fishing string has been latched onto the fish. What is the free weight of the string to the back-off point? For accurate determination. rotate the string a few turns to the left to get rid of any residual torque. 2. When running back in the hole with a fishing string. After the free point is determined. Remove the rubber protectors because they can account for approximately 10% of the total friction.80% of this value should be used. and preferably 60 .Drilling Operation Practices Manual Always record the tension reading first. What is the equivalent in amperes or ft-lbs or m-kgs of the drill string make up torque? This value should not be exceeded when applying left hand torque. After every torque reading. · Sometimes in deviated holes it is necessary to use the kelly to work down the torque. assume that the rotating weight is slightly less than 50% of the difference between weights pulling up and going down. What is the weight pulling up? For an estimate. Note : If a fish is left in the hole after a back-off. which is the weight of the string above the stuck point. recheck all connections and make them up to maximum tightness. 5. see the calculation in example above. residual torque can give false indications of the pipe being free when applying tension. Check any reading taken on the indicators with the logging unit monograph to see if the meter point readings confirm. then the actual weight of the fishing string is known. the left hand torque has to be worked down the hole before the string shot. prior to taking torque readings. Especially in deviated holes. Do not confuse this weight with the free weight of the string. added to the weight going down. Procedures 1. Once all the required turns are worked down. work the string only down to the free weight (80T) and not lower. 10% of the friction is caused by the protectors. If failed to stab in fish with matching pin in right hand rotation after tagging. d) 3-4 singles of drill collars. 4. check the ampere meter. as follows a) Pick up the string to the weight going up. Reciprocate the pipe again as outlined above. d) Lower the string to the neutral weight (do not pick it up to the neutral weight). and apply another turn of torque. 13.g. f) When applying the next turn of torque.Down Hole Complications From the observations during the free point indicator runs.g. always use oversize guide or wall hook guide with overshot in the first run itself. between 120T and 75T. the lip of the overshot should be in line of the direction of deflection. Assume that with 1 rubber protector per 2 singles. While jarring apply required pull to activate the jar. While engaging fish with matching pin. If after the initial reading the ampere meter remains around 200 Amps or higher do not apply the additional turns but continue to work down the previous turn again until the Ampere meter only indicates a slight increase over the previous reading. 8. 1 turn per 1000 ft for 5" drill pipe). Always use strongest catch tool available for the particular size of the fish.7 GENERAL GUIDELINES ON FISHING 1. to prevent backing off at a random depth. 5. c) Reciprocate the string between weights going up and going down. FAvoid using welded guide in the fishing assembly. 2. b) Bumper sub (min 18" stroke). The torque must be worked down the hole. While using overshot with deflection tool like knuckle joint/bend sub. b) Apply 1 turn of torque (observe Ampere meter) and lock the rotary table (assume kelly is used). 3. When 50% of the total required reverse torque has been applied. 6. turn by turn. because only then the torque has been worked properly down the hole. say 20-25 times e. 3. then lower down to the free weight. it was observed that there was a lot of friction in the hole (see the weights going up and going down). Always use threaded connection guide for centering of the fish. c) Hydraulic up jar. A tension of 5T – 10T at the back point is desirable for a successful back off. 2. then lower down to the neutral weight. This is most important because coming to the free weight on the upward stroke means that the pipe is most likely still in compression at the back off point and will not back off. If washout hole is suspected. 7. try to stab in by giving one or two turn left hand rotation after tagging the fish. the jar / bumper sub pin should be protected by using an end connector. e) Continue in the same manner until 50% of the required number of turns has been worked down (e. 4. Standard fishing assembly should consist of : a) Overshot or any other catching tool. 175 . pick up the string to the free weight PLUS the % buoyancy. 31. pull out the string using pipe spinner or manila rope. Make a bit and junk sub trip prior to run in diamond bit. 12. A casing Spear may be equipped with a mill type nut in place of the standard bull nose. 30. After backing off. use type “B” or type “C”.D. 10. 25. of jar is sufficient to pass string shot or free point indicator tool. In case of bit cone loss in medium hard / hard formation. For smooth cutting by internal mechanical cutter use bumper sub above predetermined weight of drill collar. 34. 33. In case of suspected mud cut or string failure. of the fish. Select the proper shoe for RCJB prior to assemble the tool. ensure that the catcher rotates freely. before dropping the ball ensure that the hole bottom is flushed. if the top of the fish is distorted. Cutting casing against joint must be avoided. 14. Before lowering jar make sure that I. reciprocate with gradually increasing tension before trying to lift. Record all the dimensions of all fishing tools lowered in the well. After engaging fish with catching tool. before picking up the string ensure that all the torque is consumed or neutralized.D of jar.Drilling Operation Practices Manual 9. 27. of fish. never rotate the rotary to avoid dropping of string. Before lowering junk basket. 28. use finger shoe. If key seat is suspected in the hole. When reduction of tool joint is around 1/8”. 17. Use of RCJB may lead to breaking of junk retaining fingers of the catcher. 22. If the formation is relatively soft and the junk is lying loose. Use positive catching tools as far as possible. If the junk is large & lying loose at the bottom. While fishing wire line inside casing. stop plate should be used above wire line spear to avoid wire line coming above the spear and getting stuck inside casing. In RCJB operation.D. tag the fish top prior to pulling out so as to have an idea of the hole size at the fish top.D of casing should be half the diameter of wire line. 15. 29. 32. In case of mechanical back off or string failure always count the number of stands and singles pulled out. 24. While backing off keep the neutral point at the back off point. 20. After string shot. Prior to starting fishing operation or engaging the fish always circulate thoroughly. 16. use junk mill and junk sub to clear junk.D. use grapple size 1/8" less than anticipated O. 11. use jar accelerator along with the jar. 23. 19. 13. 8. 26. Try to avoid using Rotary male tap as string shot tool cannot be lowered through it. The clearance between the stop plate and I. Dress the over shot with the same size of grapple as the O. A sub type nut may be installed in place of the bull nose nut should it be necessary to run a packer below casing spear for establishing circulation through fish. In directional wells or when in doubt it is better to have the shot in tension. Drill collar size above jar must not be more than O. In crooked hole for maximum effective jarring. For hard formation and if fish is lying embedded. 21. 176 . Be aware of the limitations of the fishing tools. Non positive are to be used only when positive catching tools cannot be used. dress the over shot with over size guide or wall hook guide. use type “A” mill shoe. ITCOLOY faced mill shoe. Jar accelerator should be placed above the drill collar which is put above the jar for better impact. weight etc.. are also necessary before lowering of casing pipes. xiii.14 CASING OPERATIONS PREPARATIONS PRIOR TO LOWERING OF CASING PIPES AND TUBING It is essential to inspect the damage / defect incurred during transportation and storage of casing pipes and tubing at site prior to lowering in the well. as given in casing policy of well. In deep wells. viii. vii.1 GENERAL PRECAUTIONS i. v. The casing policy should be available at well site stipulating the design of the casing string. x. Filling should be done with drilling mud weight. For moderate depth wells. It should be ensured to lower the pipes in exactly the same order. Short casing pipes may be used as per loggers’ requirement for faster calibration of well depth. ix. It should be ensured that connectors / pup joints do have the adequate thread capacity to support the load and are compatible to the size & type of casing / tubing. In case the specification of any pipe is not identified. Stabbing board to be set up in advance properly especially when spider elevator is used for casing running. Pipe sticking tendency / drag to be noted down in the last bit trip and remedial measures taken accordingly. xii. xiv. In case of lowering of mixed string. iv. weight of casing & type of the connection etc. Mud to be thoroughly conditioned for achieving proper parameters to avoid complications during casing running. it should be laid aside until it is identified. two joint spacing and for deep wells three joint spacing may be kept to avoid cement contamination around shoe. of different grade. Make wiper trips with the existing BHA especially through tight spot sections. the various grades of steel. short pipes. inspection of handling tools. running the casing empty might collapse the casing especially when heavy mud is in the annulus. In case of conventional Float collar / Shoe. It should include the location of Float shoe & collar. For deep / critical wells. ensure that appropriate casing is accessible on pipe rack as per the program. the casing should be periodically filled with mud while being run keeping a check on the weight of the casing string. The settling of pipes on bottom of the well or otherwise in compression stage should be avoided to prevent buckling of pipe. ii. full engage casing spinning / tightening tong should be used. Generally filling after every 5 – 6 joints should be adequate. There should be at least one joint in between Float Collar and Float Shoe for shallow wells. vi. iii. Additionally. Proper handling equipment should be used to prevent damage to the casing by slip and tong marks. 177 . In deep / critical wells.Casing Operations CHAPTER . xi. hydraulic testing of casing pipes should be carried at DTYS before dispatching for lowering. using a conveniently located hose of adequate size with quick opening and closing plug valve in another mud hose. preparation of pipe tally etc. 14. 14. iii. 14. this position is to the shoulder on the externally threaded end. Make shift arrangement is not desirable. For more detail OISD Std. Instrumentation at Driller’s console including Weight indicators & torque gauge etc. Inspection of all handling tools viz. stacking and running in so as to avoid shock loading that might arise due to Rolling casings from trailers over a sharp wedge. Side door elevators. etc. Note : The foregoing mud fill up practice is not required if automatic fill up float shoes andcollars are used. Prepare the pipe tally. ii. Thread compound should be applied to the entire internal and external threaded areas as recommended in API 5A2 or equivalent prior to stabbing. The measurement of pipes should be made from the outermost face of the coupling to the pin end. However.1 Preparations of Casing / Tubing Tally i. Pup joints. check the coupling for tightness. shall be carried out prior to taking up lowering of casing pipe and tubing.1.1. Manual & Hydraulic Tongs. v. Bumping casing against stacked pipes. In case thread protector are used for taking up pipes from pipe rack to derrick. ii. The pipes with damaged threads should not be used. iv. Spiders. • On buttress thread pipe. this position is to the base of the triangle stamp on the pipe. Each coupling should be checked for make up before taking up the pipe to derrick. 178 . air blow technique should be employed to ensure actual mud fill up indication. • On extreme line casing. Inspection of all handling equipment is necessary before starting the lowering of pipes. Heavy duty elevators. 14.1.2 Inspection of Handling Tools Handling tools of appropriate size and capacity should be selected. vi.3 Threads Preparation The following precautions should be taken regarding preparation of casing pipe threads prior to make up: i. Clean and inspect the threads. this position is to the thread vanish point on the pipe. If the standoff is more. single Joint Elevators. A steel tape calibrated in centimeter should be used. where coupling or the box stops when the joint is made up power tight as explained below: • On round thread joints.Drilling Operation Practices Manual xv. 190 should be referred. Hand slip.. Casing pipe should be handled with utmost care during transportation. clean thread protector properly tightened on the pin end of the pipe should be used. iv. iii. Setting slips against moving pipes. Improper handling tools. Quick release coupling should be used while taking pipes from rack to derrick in order to avoid damage to threads of pin end. Adequate number of thread protectors duly cleaned should be available. The measured length of each pipe should be written on the pipe with paint preferably near the coupling end. 2 percent of the total length of the pipe measured from one end of the pipe to the other end. All pipes should be visually examined for straightness.1/2” and larger O. To stop wobbling. or chord height. the authorized person should ascertain the welder’s qualification. Welding is not recommended on critical portions of the string where tension. ii. 179 . Welding of Float Shoe / collar with joint shall be done only with extreme caution. This does not indicate that the coupling on the box end is too loose but simply that the pin end has reached the tightness with which the coupling was screwed on at the manufacturer’s facility. with cylindrical mandrels conforming to specification given in Annexure 3. burst or collapse strength properties are important. it could be due to non alignment of thread with the axis of the pipes. While making up the pin end. should not exceed either of the following. iv.5 Straightness Check at Dtys i. Preheat temperature should be maintained during welding. In case of XL threads. the speed of rotation should be decreased. 14. Prior to taking up the welding job. i.2. ii.4 Drifting Each casing pipe should be drifted for its entire length before lowering in the well. the casing should be rejected. 14.6 Field Welding of Attachments on Casing Pipes Following precautions should be taken before taking up the welding job on casing pipes. Measurement of the deviation should not be made in the plane of the upset and coupling area.1.1 General Precautions i. 14. If found defective. Pipe sizes 4. i. should be checked for straightness by using a straight edge or taut string (wire). the pipe should be rejected. Wobbling during make up lead to galling of threads. polished metal to metal sealing area of both the pin and box ends should be checked properly.125 inch in the 5-foot length at each end. iii. Welded joint should be lowered after normal cooling only.Casing Operations vii. as the heat from welding may affect the mechanical properties of high strength steel. ii. Field welding may have adverse effects on various types of steels used in all grades of casing pipes and tubing unless due precautions are taken. vi. Deviation from straight.2 LOWERING CASING PIPES The following practice should be adopted for making up of casing pipes: 14.1.D. it is possible that coupling may rotate on the box end slightly.1. 0. v. Welding on high strength steel should be avoided. In case wobbling is observed while making up the pipes. Preheating of 3” on each side of weld locations should be done to a temperature of 205 to 315 degree Celsius. 0. If it still persists despite reduced rotational speed. Casing that does not pass the drift test should be rejected with proper marking. 14. 180 . For premium casing pipes. except 9. casing should be tagged bottom with circulation having circulating head connected above. • The manual tong should be provided with a reliable torque gauge of known accuracy. For the proper number of turns beyond hand tight position the following is recommended.3 Casing Running In i. recommended guidelines of the manufactures should be followed. first 5 to 10 joints should be tightened to the base of the triangular mark and torque noted. which should be made up about four turns beyond hand tight position. C) In case of BTC threads. In order to avoid shock loads during lowering of casing string. ii. iv. Unless warranted.5/8” and larger. Avoid casing fill up when inside open hole as stagnant time might lead to stuck pipe. 14. it should be picked up and lowered carefully with proper care while setting slips. Generally Running in speed of 45 seconds to 2 minutes per single is practiced. The casing should be filled up completely within the previous casing shoe. Special attention is to be given while passing through tight spot sections as found in the last caliper log. The connection / stationary time should be kept the bare minimum to avoid stuck up. B) The joint should be made-up beyond the hand tight position at least three turns for sizes 4. vii. pipes should not be tightened as these may be indicative of crossed threads.1/2” through 7” and at least three and one half turns for sizes 7.Drilling Operation Practices Manual iii.2. vi. lower the single slowly and stopping briefly in between 2 to 3 feet interval. casing should be made hand tight to the possible limit. Remaining joints may be tightened to the average torque with occasional checks for the triangular mark. Avoid dropping foreign materials such as Hand gloves etc during casing fill up as it might clog the floating equipment. then the same should be done within the previous casing shoe. In case any irregularities are observed during initial stage of make up. iv. v. Casing should be run at a controlled optimum speed to reduce pressure surges that could lead to lost circulation. Do not circulate with the shoe in open hole as cuttings could accumulate around shoe to form a bridge ceasing circulation. • Subsequently the average of these torque value will be reference for further tightening of casing joints. ensure that casing is made up to the base of the triangles marked on pin end and note down torque readings on the gauge.5/8”and 10.2. Preferable. • For Round threads.3/4” grade P-110 and size 20” grade J-55 and K-55. the casing should be circulated after reaching TD. In case of emergency shutdown. A) When conventional tongs are used for casing make up. 14. caving etc. or other unfavorable conditions. If mud condition / breaking gellation are required. tighten with tongs to proper degree of tightness.2 Making up Casing Pipes • While lowering first few joinst of casing. iii. dirty or damaged threads. c) Where excessive specific gravity of mud is used. b) Casing should be landed in such a manner that the casing at the top of cement is either in tension or completely balanced so far as tensile and compressive stresses are concerned. casing should be landed with exactly under same tension that was present when cement displacement was completed in the wells in which mud specific gravity does not exceed 1. b) In case of Internal corrosion.3 CASING LANDING PRACTICES Selection of proper casing landing procedure is important to avoid excessive stresses and unsafe tensile stresses at any time during the life of well. In arriving at the proper tension and landing procedure. consideration should be given to factors viz. Sucker rod and Electrical submersible pumps. • Wells having pumps like. Also ensure during design of casing that standard safety factors were considered and outer most casing have sufficient strength to withstand the landing loads. The following methods and measures should be used to control corrosion of casing: a) In case of external corrosion and stray electrical current surveys indicate that relatively high currents are entering the well. the following practices are recommended: • Good cementing practices should be adopted. it may not be possible to anticipate all the changes of physical conditions that may occur during life of well. temperature developed due to cement hydration. • Electrical insulation of flow lines from wells by the use of non-conducting flange assemblies to reduce or prevent electrical current from entering the well. d) The approach suitable to well requirement to keep required tension or compression at the freeze point should be adopted. well temperature. and adequate amount of cement to keep corrosive fluids away from contacting outside of the casing. Any of the following casing landing methods should be adopted a) After the cement has set. The condition of the casing can be determined by visual or optical instrument inspection. 14. pressure.5 gm/cc (12. • The use of highly alkaline mud or mud treated with bactericides. including the use of centralizers. scratchers. • In flowing wells. as a completion fluid will help alleviate corrosion caused by sulfate reducing bacteria. the following practices should be employed. Casing caliper survey should be carried out to determine the condition of the inside surfaces which indicate the location and severity of corrosion. Landing casing in “as cemented” condition would be a reasonable approach.4 PRECAUTIONS FOR CORROSIVE ENVIRONMENT Casing pipes can be damaged by internal and external corrosion. In practice.5 ppg). mud temperature & change in temperature during production operations. packing the annulus with fresh water / low salinity alkaline mud / Inhibitors. the pump assembly should be placed as close to bottom to minimize the damage to the casing from corrosive fluids. 181 .Casing Operations 14. casing should be landed with top of freeze point in tension. should be carried out in such a way that specification of finished casing shall conform to API 5CT.D. b. • Loss of wall thickness in the heavier upset sections could be permitted to higher Loss of nominal thickness of new pipe in the threaded portion and/or upset section. Inside surface sucker rod wear (tubing only) g. Casing and tubing should be classified according to the loss of nominal wall thickness listed in Table 1 Following points should be considered while going through Table 1.5 REUSE OF CASING & TUBING AFTER RETRIEVAL A) DAMAGED PIPE BODY Retrieved casing pipes should be inspected by visual. • New coupling shall be replaced and pipes shall be subjected to hydraulic test as per API 5CT. Inside surface wire line (longitudinal) damage c. electromagnetic. • Loss of wall thickness in the heavier upset sections could be permitted to higher percentage depending on the intended service. mechanical gauging and by NDT techniques e. Inside surface drill pipe wear (casing only) e. eddy current. whether threaded and coupled external upset or integral joint. is not to be classified in accordance with Table 1. These inspection techniques should be adopted to segregate the repairable pipes keeping in view the following damages: a. B) DAMAGED COUPLING • Connector joints of 18 ½ “& larger size O. The colour code identification system used to denote the other defective conditions is provided in the Table 2. Outside and inside corrosion damage. The colour coding should consist of a paint band of the appropriate colour approximately 2 inches wide around the body of the pipe approximately one foot from the box end. Welding procedures shall be followed as per API standards.Drilling Operation Practices Manual c) When H2S or CO2 is present in the well fluids. d. Following points are to be included while carrying out the repair: • Drifting of all pipes 182 . Transverse cracking (tubing only) f. 14.g. is not to be classified in accordance with Table 1. ultrasonic and gamma ray. Pipes shall be replaced and casing shall be subjected to hydraulic tests. • Loss of nominal thickness of new pipe in the threaded portion and/or upset section. whether threaded and coupled external upset or integral joint. C) REPAIR OF CASING PIPES Repair of casing pipes. casing of suitable grade should be selected keeping in view the effect of corrosion cracking. • Damage and /or wall reductions affecting the threaded ends of pipe require individual consideration depending on the anticipated service. Outside transverse and longitudinal slip and tong cuts. Small pits or other localized metal loss may not be damaging depending on the application of the pipe. Drill pipe being run inside casing should be equipped with suitable drill pipe protector to avoid damage to casing inner wall.2 COMMON FIELD PRACTICES TO AVOID CASING & TUBING TROUBLE i. 14. • Improper thread compound and torque • Improper cut threads and or dirty threads • Couplings that have been dented by hammering • Excessive rerunning Table: 1 “Classification and colour coding of used casing and tubing Class Colour Bond Loss of nominal Wall thickness (Percent) 2 3 4 5 Yellow Blue Green Red 0-15 16-30 31-50 Over 50 Remaining minimum wall thickness(Percent) 85 70 50 Less than 50 183 . If external surface corrosion is evident.5. Dropping a string.1 Performance Properties of Used Casing There is no standard method for calculating performance properties of used casing & tubing. ii. it must also be taken into account. even a very short distance.5. burst and tension. but this type of metal loss should be considered and evaluated.Casing Operations • • • • • • • Thread inspection on each pipe Thickness gauging on each pipe Checking and straightness of each pipe Hydro testing on each pipe Reconditioned pipe must conform to API standard Marking of specification on each pipe Rust preventive coating to be applied 14. under external or internal pressure are a common trouble and may be due to the following. iii. Thread condition also require attention to evaluate resistance to leaks. Performance properties should be based on a constant OD. Leaky joints. Final rating of a length of pipe for further services requires consideration of the inside wall condition and remaining wall thickness to evaluate resistance of the body to collapse. The re -use of retrieved casing pipes after repair should be decided. may loosen the couplings at the bottom of the string. depending upon the end use considering required performance properties vis-à-vis re-estimated performance properties of retrieved casing / tubing. Use of worn-out and wrong types of handling equipment. b) Pulling too hard on a string to make it free. e) Buckling of casing in an enlarged & washed out un-cemented cavity due to release of tension in landing.Drilling Operation Practices Manual Table: 2 “Colour Code Identification” Conditions Damaged field or pin end Colour One red paint band approximately 2 inches wide around the affected coupling or box end One red paint band approximately 2 inches wide around the pipe adjacent to affected threads. 184 . Ensure all necessary arrangements as per the check list. c) Landing the casing with improper tension after cementing leads to failure of casing during subsequent rotary drilling inside the casing. 14. V. Excessive sucker rod breakage c. Onland / Jack Ups 1. 2 inches wide at the point of drift restriction and adjacent to the colour band denoting body wall classification Damaged coupling or box Pipe body will not pass IV.6 CASING LOWERING PROCEDURE A. Replacement of worn couplings with Non API couplings e. Excess doglegs in deviated holes. tong’s die and pipe wrenches.upset tubing reduces chances of failure. f) Application of high Torque on casing. leak resistance. and in severe cases lead to abutment of pin ends near center of couplings. use of upset tubing over non . spiders. or occasionally in straight holes where corrective measures are taken. d.eads. Improper selection of type / grade of tubing. Tubing that has made multiple round trips in the hole. This condition may reduce joint strength. Causes of casing troubles a) Forcing casing through tight places in the hole. may loosen the couplings at the top of the string. especially during breaking out. b. cause bending affects which lead to galling of thr. d) Drill pipe wear while drilling inside casing is particularly significant in deviated holes. f. These should be re-tightened with tongs before finally setting the string. In case of fatigue failure at the last engaged thread. especially of non-upset where upset tubing should be used. Tubing failure a. may have pins reduced in diameter due to successive yielding by repeated makeup. One green paint band approx. result in concentrated bending of the casing that in turn results in excess internal wear. 14. 6. Open the protector and apply the dope on threads. Attach centralizers / scratchers as per the cementation programme. Safety clamps are no longer required when adequate casing load prevents the slips from opening manually. of threads. 4. Apply thread lubricant with the joint of casing in the “v” door. Pick up first single fitted with guide shoe from catwalk using rope. When picking up casing from the casing deck is completed check that the correct number of joints remains on deck. 12. Ensure that the running tool does not back out. 10. 16. Raise and lower the joint to check the operation of the shoe. Pick up the shoe joint and set in the slips. 11. also break the gelation of mud before entering the open hole. 185 . Fill the hole regularly as per the plan. Make up the circulating head for mud conditioning prior to cementation while circulating reciprocate the string till cementing arrangements are being made. 18. 7. 6. B. 3. Lift the string. 9. Check it with the help of gauge. 11. Lower it in the hole through rotary table. Never while the casing is set in the slips in the rotary table. Fill the shoe joint with mud. 3. Check accessories like shoe / collar for proper functioning before make up. Pick up the second single from cat walk with the help of crane / air winch. In case spider slips are used. Run the drill pipe landing string drift all drill pipe run. 8. 5. 8. Continue this procedure till the casing is lowered to the desired depth. Make up the casing hanger joint. Pick up the single with the bottom part of the cement head and make up to the landing string. Ensure the flow of return mud. 2. Install casing centralizers as per casing program. 12. 5. Use rope for the initial tightening of 4-5 no. Fill the casing with mud and reciprocate the casing when the float collar joint is made up to ensure the correct function of the float. Continue the lowering of casing pipes keeping an eye on return mud. 19. On Floaters 1. 13. Remove the slips and gradually lower the casing pipe. Latch it in the elevator. One man should be assigned to cross check the lowering schedule as per the plan. Lower the casing hanger below the rotary table and install rotary insert bowls #3. Then use manual or power tongs for tightening of joints to recommended torque. 10. 15. Remove the rotary insert bowls to allow the casing hanger to pass through the rotary table. Use thread locking compound on all threads between the shoe and float collar. Fill with mud each joint of casing run and top up every fifth joint of casing run. 13. then Safety clamps may be used to avoid casing drop out from slips as it could be inadvertently opened by Derrick man.Casing Operations 2. 4. 7. Stab it in the box of first single carefully to avoid the damaging of threads. 17. Latch it in the elevator. 9. 28. liner as per plan plus 10% extra 2. 17. torque gauge and power unit 9.Drilling Operation Practices Manual 14. 24. Stroke open the motion compensator. 15. lower the casing string and land the casing hanger in the well head. 29. Release the running tool. Pick up the slips. liner hanger with setting tool 4. 20. thread locking compound 14. liner rotary bowl . 25. Install 13. five turns to the right. Remove the elbow Chickson lines between the cement manifold and the choke and standpipe manifolds. Line up the Chickson line to the rig pump. casing dope. 22. 26. Rubber clamp-on protector – 6 nos. Install the top part of the cement head and attach two lengths of the Chikson line to the cement head.four turns to the right. API modified – 1 bucket 10. back up line. Re-route the Chickson line to the cementing unit.375” wear bushing.. liner shoe . Break the Chickson line just above the rotary table. 27. Close the choke and kill lines on the BOP stack. Bleed down the air pressure on the motion compensator until only the weight of the landing string is held.liner slip 5. 18. manila rope 12. Pull out of the hole with the running tool and the landing string. Circulate the contents of the casing string. 14. wire brushes 186 .7 LINER HANGER Required handling tool 1. 23. Service the universal direct drive casing hanger tool and install thread protectors. 19. 13. liner fill up line 11. hydraulic casing tong dressed for liner with hydraulic hoses. Pressures test the pack-off assembly. 30. 21. single joint elevator with lifting slings 7.000 ft/lbs. jaws for manual power tongs 8. 32. side door elevator 6. 16. 31. Open the choke and kill lines on the BOP stack and line up so they are vented to the atmosphere. 33. Pressure test the BOP stack. Pressure tests the surface lines. landing collar 3. Cement the casing.approx. Energize the pack-off assembly to 18. 8. Fill joint of liner immediately above landing collar. raise. number them and drift the same. Circulating head should be ready on the rig floor 7. 10. Lift the joint carefully without damaging the shoe. 15. 2.Casing Operations 15. 4. damage and drift. Pick up the shoe joint directly with crane to the rig floor through v-door and place it in the side door elevator. 18. 12. 187 . fill with mud and raise/lower joint to check operation of shoe. Insert bowl in rotary for liner 3. Hang hydraulic casing tong. Usually overlap should be kept 100-150 meters if well plan permits. 7. Run in liner up to required depth.7. lower and check. when making the last round trip prior to logging of the well. Tighten all joints to recommended torque. 14. Make up Float Collar (optional) with pipe lock on the bottom of the second joint 11. Further run in liner with drill pipe. Check liner hanger equipment for dimension. Fill all the joints during running in. Clean and apply thread locking compound. Liner wiper plug and Running tool to recommended torque. Rig up liner fill up line 6. Do not allow any right hand rotation as this may release the liner. Set in slips. Make liner tally and drill pipe tally for liner run in. 3. gauge and hydraulic hoses 2. Check the float shoe setting depth and overlap of liner after consulting well site geologist and tool pusher/DIC.2 Liner Hanger Preparation 1. Take measurement of liner. 17.7. 20. Take the drill pipe stand count to avoid running errors. Make up Float shoe with pipe lock compound on first joint 9. Run liner with centralizers as per plan.1 Procedures for Lowering Liners 1. joint as prescribed in cementation plan. Rig up single joint elevator with sufficient length of 16 mm or19 mm rope to the hook block 4. Set Liner Hanger as per manufacturer’s recommendations / setting procedure. liner drift gauge cement and chemicals as per cementing plan circulating head with 2” x 10. Take the measurement of the drill string. 16.000 psi hammer union connection cementing head large chain tong 16 mm x 5 mm rope sling for lifting pipe from catwalk – 2 sets 14. Install centralizer on body as per plan if not installed in the deck earlier. 6. / 3rd. Make up Liner hanger. 14. 13. 19. 16. install back up line with torque cylinder. 5. Make up Landing Collar with pipe lock on the bottom of the 2nd. Check up Liner grade 8. Rig up main elevator with links 5. Excess cement slurry should be circulated out. 18. 14. 16. In some cases.7. 3. Wash the last 20 m to bottom. Set Liner Hanger as per procedure. Circulate one cycle. Check for any increase in rotary torque. lower the string and 5000-10000 lbs (2 to 5 tons) weight on the hanger. Pull back to the setting depth and note the free hanging weight of string with pump on and off. Locate bottom and watch out for a sudden pressure increase. until well is free from cuttings and mud is free from gas. 6.Drilling Operation Practices Manual 9. 20. for hydraulic liner hangers. Continue turning of string until maximum of 16-20 turns. Try to back out the running tool and retighten same with chain tong at rotary table. slight jerking down has to be done to get the initial grip. 5. Back pressure may be applied during the initial setting of cement to avoid gas migration through cement. Lower string again and set liner. 14. Circulate with cementing head installed on the string and string should be reciprocated during circulation. If hanger is not set. After ensuring that drill pipe is free from liner. 17. Keep an accurate record of the various string weight 4. 15. 19. maximum circulating pressure should not exceed 600 psi (40 ksc) or recommended value. Lower liner at moderate speed to avoid pressure surges. Turn string slowly right hand. Pick up free drill pipe weight leaving 1 to 5 tons on hanger. 11. 13. 2. Install DPWP in cementing head and check. Increase pressure to recommended value so that Liner wiper plug shears off 24. Circulate for 5 minutes to ensure that all conditions are normal. Calculate cement and displacement volumes as accurately as possible. Pump in required quantity of cement 21.3 Precautions 1. 10. pull back to 1 ½ feet above the liner setting depth and increase the setting pressure in stages of 100 psi. Displace further with mud till DPWP and Liner wiper plug sits on the Landing Collar completing Liner Cementation. Drop the Drill pipe wiper plug 22. Ensure that slick joint does not come out of DPOB / RPOB / Hanger seat. Displace with mud till DPWP sits on Liner wiper plug 23. Pick up drill string weight and raise 1-2 feet. 188 . 12. 15 DRILL STEM TESTING Drill stem testing (DST) is a method that is used to evaluate the sub-surface formation or reservoir. Flow / Shut-in Valve – to enable flowing or shut-in condition during testing 6. Various DST tools such as Reciprocating type.3) into the hole with “Tester Valve” in closed position.Drill Stem Testing CHAPTER. DST requires opening of a well bore section to atmosphere or to reduced pressure. 3. Choke Manifold and Chickson Lines The schematic of a typical DST assembly is shown in Fig. Surface pressure read out system etc are used. Tester Valve – to enable the string to be run in closed condition during tripping and keep the string in open condition during testing. Safety Joint – to disengage stuck string in case jarring fails to release the string thereby retrieving the main DST tools 8. DST sampler also traps Formation sample under in-situ condition. Tighten all the joints. Connect Reverse circulating sub on top of Drill collar stand or any other position deemed fit. wherein Drill stem or Production Tubing that acts as a conduit for fluid flow is also used as a manipulating tool for down hole valves. 4. Dual shut-in / flow. Multiple shut-in / flow. Make up adequate number of Drill collar stands 5. Packer – for isolating annular hydrostatic head 2. The DST assembly primarily consists of : 1. This is possible because Recorders form a part of the Reservoir. 5. Jar – to facilitate release of DST string in case it gets stuck 7. 189 . in either Cased hole or Open hole.1 PROCEDURE 1. Rotating type. By-Pass Valve – to equalize pressure across packer and to avoid surge / swab during tripping. Control Head – connected to the topmost pipe at surface having series of valves for controlling and diverting flow 12. with power tongs to their recommended torques. Perforated Pipes – to arrest sand intrusion inside string 10. Any amount of drawdown limited to Packer rating could be given as the tool is run in closed condition. This method provides an accurate method of formation evaluation. Reverse Circulating Valve – to allow communication in between string and annulus 9. Pick up DST assembly one by one and hand tight on rotary table 2. 15. The assemblies / sub-assemblies of a DST string performs the basic task of isolating the annulus and reducing hydrostatic head and allowing formation fluid to flow on its own thereby recording the flow rate and measure Shut-in pressure and temperature accurately and at the least time. Annular responsive type. Opening / Closing of the valve is done through pipe movement. Lower the testing string (fig. 2. 3. to prevent entry of well fluid into drill pipe. Sampler – to trap formation fluid under in-situ condition 11. both working and service. Pressure and Temperature recorders – to record down hole pressure and temperature against time scale 4. open Reverse circulation valve / port and circulate out all the influx for the drill string with kill mud Open By-pass valve. • Multiple CIP (Halliburton) and MFE ( Flopetrol Johnston) can provide multiple flow and shut-in operations and are especially required to evaluate reservoir depletion. Open the valve for second flow and measure flow rate through various bean sizes. Close tester valve and unseat Packer P/O the string filling up hole and monitoring flow check intermittently.in pressure down below. • Open hole DST is also performed. 20. • DST also evaluates the efficiency of cement job carried out for water shut-off or after performing cement squeeze job. then sample can also be collected after breaking out each stand for finding out constant salinity. are used to investigate choked string apart from acting as alternatives. 15. Upon completuion of test.1. if required. i. Make up and lower Drill pipe or Tubing pipe to desired depth Position Packer at 2 – 3 Mts. whereas opening/ closing of “Tester Valve” is done by either lowering down or by lifting up the string. • If formation fluid influx is primarily water (identified easily during testing) and the flow volume is insufficient.1 Important Notes • The operation of Dual CIP (Halliburton tools) closing / shut-in is done by rotating the string. one each above and below packer. 9. the Vernier needle slowly looses weight indicating slow string travel downwards. for prolonged flow and flow rate measurement At least two flow and two shut-in curves are recorded. Break open DST assembly and lay it down cautiously and carefully. 190 . 8. First flow is given for 5 – 20 minutes depending on the formation permeability and flowing characteristics so as to bleed off the supercharged pressure Close the Shut-in valve and record shut. 18. 12. only two flow and two shut-in’s are possible. to determine water level • Gas Oil Ratio (GOR) can also effectively be found out through DST. In some cases. Above the zone Set Packer and inflate it Close By-Pass valve and open Tester valve that opens after a time delay giving an indication of a jerk at the Drillometer Vernier scale. • DST packer is often the preferred technique to determine casing leakage and identifying the leakage point. • Hook wall packers are used for cased hole testing wherein packer could be set at any point within the casing whereas generally Open hole packers are energized by resting string on bottom and applying compressive load. In case of Dual CIP.e. 15. 7. three flow /three shutin or more are taken for proper reservoir evaluation. 19. Duration of shut-in period depends on the permeability. • At least two recorders. 17. 10. Close the valve for second shut-in Open the valve. During hydraulic time delay. detach sampler and hand it over for PVT analysis or nipple open ports to record pressure at ambient conditions and drain formation fluid to measure Gas / Oil / Water ratio sand fluid characteristics. 11. pressure transmission rate. 14. 16. Shut-in curves should cross the After Flow effect and be in the steady state condition for fruitful reservoir evaluation.Drilling Operation Practices Manual 6. After DST assembly is P/O to Rotary table. 13. 15. if well flows. It is important to have a caliper log of the well for Packer Seat identification before running in the tools. shall preferably be done during day time. 5. Packer should be set against competent formation that is capable of bearing the pressure difference above & below the packer during opening of Tester/ CIP valves. Carry out flow measurements. opening of Tester valve. 4). For open-hole test. Line up cementing unit through Kill line and arrange adequate volume of Heavy weight mud before running in for contingency well killing measures.2 PRECAUTIONS BEFORE/ DURING DST 1. Following interpretation can be obtained from the chart that is generally carried out by Reservoir department: Production : Expected production rate of oil and gas and GOR (from Sampler). is a record of bottom hole pressure Vs time. Allow the Shut-in curve to reach steady state condition so as to extrapolate it later using Horner’s method for proper reservoir evaluation. 12. 8. 2. 6. annular level is the prime indicator of a leaking Packer or Drill pipe. using various bean sizes. 7. 4. Pressure Depletion : Detect depletion so as to differentiate between big reservoirs and small reservoirs (commercially not viable). Hence. if well killing is required.. 11.e. i. Any drop in the level indicates improper seating of packer during which annulus fluid shall rush into the string due to huge pressure differential owing to U-tube effect. During DST. it can also be done at night with adequate lighting arrangement. Water / N2 cushion should be given as per required pressure drawdown. Floor manifold and Chickson lines should be properly anchored with the help of chains attached to the Chickson lines. Reservoir : Calculates static reservoir pressure. However. for improved Productivity Index (PI). Follow IWCF Well Killing/ control procedure. after observing the well’s ability to produce during first flow. Follow good safety procedures during the total test duration. 191 . if any. during flow of formation fluid and shut in (fig. In case of Open hole DST.3 CHART INTERPRETATION DST chart produced by a recorder. Permeability : Direct means of evaluating average effective permeability vis-à-vis actual formation fluid produced Well Bore : Extent of well bore damage or skin effect so as to decide well stimulation Damage stimulation measures. Initiation of well flow. it should be always checked from time to time through out the test. 10. 3. 9.Drill Stem Testing 15. Maximum information about reservoir is studied on the basis of the patterns & readings of the chart only. Choose the correct time interval for flow & closed-in pressure periods. Fill up water cushion inside string after every 5 – 10 stands allowing passage for air displacement. A high viscous mud pill of 1 – 2 stands could be given inside drill string before water cushion to avoid choking of DST tools due to accumulated solid scale particles of drill pipe interior during water fill up. Hole should be kept full before tester valve is opened. hole should be in good shape & condition. faults etc. Radius of reservoir that has been investigated during test period.PORTS B. PRESSURE RECORDED (A. 1 Two Typical Systems of Surface Equipment for an Open Hole Land Test BT PRESSURE RECORDER (BLANKED OFF) Fig. One Hole Single Packer Test Radius of Investigation Reservoir Analysis Barrier Indication : : The radius of the Reservoir which has been investigated during the test period. Barrier or any other anomaly can be detected such as existence of different fluid contacts.P. : 192 . TYPE) HYDRAULIC JAR ACCESS VALVE V R SAFETY JOINT BY-PASS PORTS EXPAND SHOE PACKER ASSEMBLY ANCHOR PIPE SAFETY JOINT FLUSH JOINT ANCHOR HT 500 TEMPERATURE RECORDER (a) NIPPLE DRILL PIPE Fig. 2.Drilling Operation Practices Manual DRILL PIPE DRILL PIPE LIFT NIPPLE HOLLOW PIN IMPACT REVERSE SUB ADAPTER BAR DROP SUB FLOW TEE MANIFOLD FLOW LINE PRESSURE BALANCED SWIVEL MASTER VALVE NIPPLE DRILL PIPE BAR DROP SUB REMOTE CONTROL SAFETY VALVE MANIFOLD FLOW LINE HYDRAULIC CONTROL LINE LT-20 SWIVEL MASTER VALVE DRILL PIPE OR DRILL COLLARS DUAL CLOSED IN PRESSURE VALVE REVERSE CIRCULATION PORTS HANDLING SUB A CHOKE ASSEMBLY (OPTIONAL) HYDROSPRING TESTER BYPASS . Useful for determining well spacing requirements and other volumetric calculations.T. P. RETRIEVABLE VALVE TREATING FOR SQUEEZING Fig.I. OPEN FOR TEST SUBSEQUENT REVERSING C.Drill Stem Testing Fising Neck Choke Circulating Valve Cup Locking Mechanism Testing Valve BT Pressure Recorders Bypass Valve RTTS Packer RUNNING IN OPEN FOR TEST TAKING FIRST C.P.I. 3: Hydrospring Retrievable Valve Tester 193 . B.T.T GAUGE NO. INITIAL 291 537 . (a) PRESSURE RECORDER CHARTS SHOWING A BARRIER FINAL (b) EXTRAPOLATION OF PRESSURE BUILD-UP CURVES INDICATING A BARRIER Fig. 4 194 EXTRAPOLATION PRESSURE GRAPH TICKET NO.Drilling Operation Practices Manual Diagrams Above Packer B. Blanked-Off B.T. LT .Drill Stem Testing A .Lift Nipple Two of the ways of making up the Unitest Tree surface control equipment are as follows : (from Top to Bottom) (1) (2) A B C E D G F H H I B . 5 components of the unitest tree 195 .Master Valve I .Adapter C .Master Valve H .Remote Control Valve F .20 Swivel H .Bar Drop Sub S-15 Manifold Flo-Thru Manifold is not shown E .Pressure Balanced Swivel G .Quick Disconnect Fig.Bar Drop Sub D . • Remove inner tube thread protector. • Lower core barrel. remove inner barrel from outer.(a) Upper sections & (b) lower sections (fig-2). 4). • After making middle stabilizer place drill collar clamp above slips. Pick up inner tube approx. Tighten with chain tongs using cheater bars. • Back out elevator sub taking care not to damage inner tube connection. core head pin connection and core catcher at lower end. • Remove bottom protector.1 CORE BARREL ASSEMBLING • Before picking up barrel sections ensure that all outer tube connections are sufficiently tight to prevent backing out in the derrick while assembling. exposing inner barrel. 2b) and tighten thread connections to the recommended torque using rig tongs and rope on cathead and lower in the rotary table. 6-9 inches. 196 . below middle stabilizer.Drilling Operation Practices Manual CHAPTER . • With inner tube still connected to the elevator sub. • Check core catcher is present. Note: Bottom Protector must be tight.16 CORING The 60 feet core barrel consists of two sections. Avoid setting slips or placing tongs on box connections (fig. • Place core barrel inner and outer tube protectors on elevator sub. • Make up upper and lower sections of inner barrel. the bottom section of barrel have two stabilizers and an elevator sub at top. swivel assembly and top stabilizer. Make up API connection turning the sub upside down on elevator sub to connection on the top section of core barrel. • Finally tighten to recommended torque with rig tongs. • Back out elevator sub from outer tube using chain tongs. 16. allowing sufficient space for drill collar clamp. 3). Also ensure core marker is present. • Pick up upper section in elevators. • Back out safety joint using chain tongs. The upper section contains safety joint with an API box connection. • Pick up on elevators and remove inner tube clamp. • Reset slips as near as possible to top stabilizer. torque up top stabilizer and safety joint cross over sub above stabilizer. • Make up outer tube connections using chain tongs. • Pick up lower section (fig. • Make up inner barrel clamp to the inner barrel leaving sufficient space above on inner barrel box connections (fig. Make up safety joint fairly tight. Ensure steel ball is not in ball seat. • Volume of mud to be circulated will be determined by mud type. Back out cartridge cap and add or remove shims as necessary. • Weight on bit will be determined by size of bit.Coring • • • • • • • • • • • • • • • Barrel Tighten inner tube shoe lower and upper halves using chain tongs and cheater bars. If not ensure cross over is available. a slow rotary speed of 40-50 should be applied and gradually it can be increased. Incase of doubt run reverse circulation basket or magnet to ensure complete removal of junk from bottom. 197 . Put inner tube clamp on inner barrel.7) For adding or removing shims. Pick up required cross over or drill collar and make up to API torque rating. • Check core barrel connections with drill collar for its compatibility. • Ensure availability of adequate number of drill collars for giving sufficient weight. Pull assembled barrel out of the rotary table. Run inner barrel back into outer tightening middle connection. 5.(fig. top connection (at swivel assembly) and all connections on swivel assembly. Break off bottom protector and check lead. take off protector and check lead using CB gauge. Make up core head. • Ensure that there is no restriction in the string to stop passage of pressure relief plug ball. make up collar clamp and back out safety joint. bit records and formations to be drilled. circulate the hole thoroughly and make wiper trip before coring to avoid sticking of core barrel.6. • In case of dog legs. • Select core head based on previous experience. Check rotation of the inner tube. 16. • Use correct combination of weight and rotary speed to avoid excessive or fluctuating torque. Set slips below blades of top stabilizers. When starting coring apply minimum weight and then increase in small increment (1-2 Ton) until optimum performance is achieved. run barrel back into rotary table . run the junk sub to clean the hole from any junk. size of core barrel and nature of formation to be cored. Pull barrel out of rotary table. in open hole. tight spots etc. Do not use more than recommended weight on bit for the specific core barrel. In general a rotary speed of 70-120 RPM is sufficient to core most formations. pick up. pick up until 8 inches of inner tube is exposed. depth of hole. • When starting coring. 8) Once spacing is corrected. Run core barrel back into rotary table.2 CORING PROCEDURE Preparation • On the last bit run prior to coring. remove inner tube clamp and make up safety joint with chain tongs.Set slips below top stabilizer. pumps and type of formations drilled. Torque safety joint to recommended torque with rig tongs. is now ready to be lowered.(fig. • Run adequate number of stabilizers to keep core head steady on bottom. • Avoid mixing LCM in large quantities which could possibly block core barrel or core head fluid passage. Tag bottom and mark Kelly. Figure 8 On reaching bottom make up Kelly and start circulation with recommended flow rate (note down pressure) at least one single before drilled depth. Lift 2-3 feet off bottom. 198 .Drilling Operation Practices Manual • • • • • • • • • Check pump liners and stroke for desired flow rate. circulate for 5-10 minutes. Wash down slowly picking up periodically and checking Kelly measurements with pipe tally. When true bottom is reached a WOB gain accompanied by a pressure increase will be noticed. Abnormally high pump pressure indicates that there may be debris in the barrel or core catcher and it should be cleared before starting coring. Run back to bottom and check Kelly measurement. Wash down to bottom and watch for tight spots. Start pump at normal rate. • If pressure increases then either bit has been damaged (If on lifting bit off bottom the pressure returns to normal and on retagging bottom it increases immediately then bit is damaged) or due to inner barrel or swivel assembly backing out and sitting in core head. add spacer sub. Pump ball to bottom. • Start rotary and bring it slowly to 40-50 RPM. maintaining pull until core breaks. • Increase rotary speed to approx. • Lower barrel until minimum starting weight is reached. First check pumps strokes and condition. 199 . if necessary. If core does not break at this point then circulate at normal coring flow rate. making sure that barrel goes back to bottom without meeting any obstruction caused by core left in hole. weight and RPM can be varied to achieve maximum performance. 16.3 CORING OPERATION • Check pump strokes to ensure correct circulation rate is delivered to core head. Then pull out of hole. Make up Kelly. • Pick up approximately 10 feet. Mark the Kelly. • Pressure decrease could be due to core jamming or filling of core barrel. permitting the passage of new core into the core barrel.Coring • • • • • Once bottom is reached circulate for another 10-15 minutes to clean out inner core barrel. • Record pressure and maintain it throughout the coring. • Then increase the weight slowly in 2000 lbs. • Lift the drill string until normal coring weight is reached. Or it may be due to wash out in drill string. This additional weight will release the core from the core spring.1 Possible Causes of Pump Pressure Change Pressure change could be due to changes in flow rate. when ball seats on pressure relief plug a slight pressure increase will be indicated. • When bit has touched bottom maintain starting weight till one foot has been cored. watch the weight indicator. If there are large variations. increments. again note circulating pressure. • When two to three feet has been Cored. break off Kelly and drop steel ball. 16. is reached. • To resume coring after connection. 50% higher than normal coring weight. It can be found by lifting string off bottom as in this case most likely pressure will remain high.4 CORE BREAKING Stop rotary table and shut off pump. then lower slowly back to one feet off bottom. Start circulation. • Minor fluctuations in pressure can be due to changes in formation. continue picking until core breaks (this will be indicated by reduction in string weight – with a sharp reduction in string weight once core is broken) or an over pull of 20000 lbs. while mud is being mixed or unbalanced mud in hole after a trip. debris in pump valve seats or washed liner. • Pick up Kelly until weight indicator shows core has been caught. • Ensure that pump pressures are normal when coring recommences. it should be immediately analyzed and corrective action should be taken.3. 16. Pick up. Bring rotary up slowly to normal rotation and continue to core. run to bottom without rotary or circulation and add approx. 60 RPM. Record final off bottom pressure with ball seated. • When core barrel reaches surface put collar clamp above slips.11) • Put core tong handle on core tong shoe. • Run core barrel back into rotary table and visually inspect core barrel. • Check core head wear change out. • If core marker or further core does not appear. • In case of fiber glass inner core tube. coring is performed in exactly the same manner as coring with conventional steel inner tubes. replace collar clamp. • Make up elevator sub. • Pick up barrel. pull out inner barrel. torque up sub using rig tongs. • Remove steel ball from the core barrel using pick up tool. Exert pressure on core tong handle and pick up inner barrel slowly. replace them. • Check bearings and “O” rings if defective. Use pump out bean and plunger with water as medium to pump out core. The exposed core then can be removed and boxed. • Make up core head. by placing hand inside core catcher and rotating. • Regrease safety joint and make up to recommended torque. make lower shoe up onto inner barrel. • If still core cannot be removed then lay down inner tube and pump out core. Now the core can be removed from the inner barrel as inner tube is picked up. if required. clean off core catcher and lower shoe. lower inner tube onto floor and knock inner barrel with sledge hammer until core falls. fiber glass tube 200 . • Run inner barrel back into outer tubes. rotate out using chain tongs. • Continue this procedure until core marker comes out of the inner tube.(fig-10. • After complete removal of core. • Make up core barrel protector tightly.5 RECOVERY PROCEDURE • Break core and pull out of hole. Ensure inner barrel is rotating freely. stabilizers etc. replace if necessary. After laying down the inner tube. • Break off inner tube shoe lower half ( catcher) using chain tong or pipe wrench. • Now barrel can be lowered back into hole for further coring. • Set slips below top stabilizers. • Lower barrel. While pulling out set slips slowly on rotary to avoid jarring the barrel as core loss may occur. • Pick up inner tube again exposing core. The shoe should be backed out on the rig floor preventing core from falling out of the inner tube. • Do not repeat the sledge hammer blows to the same area on the inner barrel as this will damage the tube. In no case pressurized air should be used. • Pull core barrel out of rotary table. • Break off last stand of drill collar and stand it in derrick. keeping pressure on core tong handle until core in core tong is resting on the floor. and tighten with chain tongs using cheater bars. • When desired boxing length is reached exert pressure on core tong handle to break core. • Remove the inner tube shoe. • Break out safety joint.(fig-9) • Place core tong shoe on inner barrel. The pressure on the core long handle can now be released. • Break off protector.Drilling Operation Practices Manual 16. Break off bit. • Tight pulls while pulling out and the attendant rotations. 201 . • Avoid drilling with roller core heads as there is no provision for efficient cleaning as in jet bits. • Avoid reaming with core bit through tight zones while running in. should be avoided as it may cause the core to slip down. Available sizes for fiber glass inner tube are. • Breaking off the core should be done as per the norm. • Try to prevent drill string vibrations while coring. • Adhere to uniform feeding of WOB for better core recovery. • Unless the coring is complete or otherwise warranted by bad condition of hole.Coring • • can be cut into sections at the rig and then sealed with plastic caps at end and sent to lab for testing. swivel assembly etc.) for straightness before starting coring. bearing. 6 – 3 / 4 “ x 4“. core catchers. In fiberglass inner tube pin threads are molded on both the upper and lower ends which will accommodate internal flush connections. • The hole should be free of junk at the bottom otherwise it will result in worn out diamond core head. core barrel.g. the bit should not be lifted off-bottom. and 8” x 5 1 / 4“ Precautions while coring • Inspect the coring equipment thoroughly (e. jerks and reciprocations to release it.6-3 / 4" x 3". • If there is any junk in the hole. bearing retainer cartridge cap and plug. pressure relief plug. Lay safety joint on floor to do this. • Check the roller cutter head for rollers and worn teeth. • Back out bearing retainer and change bearing . place inner tube clamp on inner tube as shown. 15) • Break out safety joint. • Secondly check for vertical movement .Drilling Operation Practices Manual 16. • Even after changing bearing if vertical movement exists then check wear on bearing retainer.7 CORE BARREL SERVICING After the initial make up of the core barrel. • Clean and re dope all threads and make up cartridge plug ensuring it is tight.14. • Check the vent valve and if the ball or seat is worn out. and core springs.6 CHECK LIST FOR CORING OPERATION • Check the core barrel for crookedness. “O” rings. • Pick up safety joint exposing bearing and bearing retainer. before coring. 2. • Break out inner tube plug. cartridge plug and cartridge cap. check looking from one end. • Check the core catcher for defects. severe dents etc. if rotation is difficult or rough it indicates that balls have broken. hammer up.17) • Set inner tube clamp as shown. • While making up the complete core barrel assembly. • Check mast centering if it is not proper it may cause drill string vibration while coring. check the condition of hole for any tight pull. • Rotate inner barrel at inner tube plug. • Check the Kelly and drill pipe stand for crookedness. B. • During round trip. • Break out pressure relief plug. 16. Replacement Of Thrust Bearings• After every core check for bearing wear. • Check ball seals and change out.If excessive this also indicates worn bearing and should be changed. 202 . Swivel Assembly1. Changing Bearing (fig. worn out threads. • Pick up inner tube. • Clean and dope all threads and make up inner tube plug. • Using spanner wrench back out cartridge plug. Changing Pressure Relief Plug (fig-16. it should be checked at regular intervals for wear of thrust bearings. fish it out before starting coring operation. • Before breaking out bearing retainer place rags etc around slips to prevent balls dropping back into hole. whether the same is straight or bent. if necessary. A. replace it. inner tube shoes upper and lower. • Clean and dope retainer. • To save rig time and loss of core it is suggested to change bearings after 3-4 cores. Coring 203 . 400 183. • Check swivel joint for free rotation. Ream if necessary. 500 275. 000 204 . • Circulate one foot off bottom at least for half an hour for cleaning bottom before starting coring operation.000 9. Inner Tube Shoes (Upper & Lower) and Core Catchers (fig-18) • Check threads on inner tube shoes and general condition at every core. • Check vertical play in bearing. DO’S AND DON’TS • Inner core barrel should be always be coated with chain oil before laying down. • Keep the steel ball outside while running the core barrel into the hole. from bottom of outer tube sub with the help of gauge supplied. • Do not keep barrel in hole if appreciable decrease in penetration rate is noticed. • Check length or inner tube shoe lip.00 5. ii) FRICTION RINGS • Ensure that friction ring is free moving. 700 137.LBS.00 5. MAKE UP TORQUE (FT. clean it with diesel if it becomes clogged up. for coring – which is an optimum flow rate.000 MAXIMUM PULL (LBS.00 15.) 101. 000 322. • Do not forget to crack all joints of core barrel before laying down. • Ensure that core spring is in good condition. Safety Joint i) “ O” RINGS • Check condition of “O” rings regularly and change them when they are damaged. 1 2 3 4 5 6 7 8 CORE BARREL SIZE 4–1/8“ 4–1/2“ 4–3/4“ 5–3/4“ 6 – 1 / 4 “ X 3” 6–1/4“X4“ 6–3/4“ 8“ RECOMM.change if required. 000 290.00 7.Drilling Operation Practices Manual C. • Make sure that tungsten grit has not been worn flat. It should be kept inside the core tube. • Make up all joints of inner barrel using chain tong only and check inner tube threads. • Do not change the bearing on rotary as the steel balls of thrust bearings may fall into the hole. • After core recovery do not keep the core marker out side. 400 194. • Do not push the core head down through tight spots. 16. It should be less than ¼” .500 20.9 RECOMMENDED MAKE UP TORQUE FOR “CHRISTENSEN CORE BARREL” SR.It may affect core recovery. • “O” rings can be changed while changing bearing or after core recovery by sliding them up while inner barrel is being lowered back into outer barrel. • Keep circulation rate around 16-19 lt/ sec.NO. 000 193.000 8.) 3. • Do not run in the core barrel without adjusting shims in case the length of the inner tube shoe lip below outer tube sub is not as per recommendations . D. Directional Drilling CHAPTER . Prior to the start of any directional well a pre spud meeting should be conducted. The directional drilling plan for the well should be discussed and following topics should be included: • • • Wells that may be approached during the course of drilling a directional well to avoid collision.3 Driller/Assistant Driller Drilling parameter given by directional driller during the course of drilling a well must be strictly followed to avoid any extra trip for the control of well path.1 RESPONSIBILITIES 17. • Directional driller must be informed before any pull out of the hole is made due to any reason to avoid any extra trip for change of the BHA which may be required during next run. The Driller and Directional Driller are responsible for the dimensional inspection of the BHA.1. 17.17 DIRECTIONAL DRILLING Directional Drilling is usually accomplished (at shower depth) by jetting using a jet bit with one large size nozzle and two blinds or by a mud motor with a bent sub or an adjustable bent housing. Directional Driller must be called on rig floor when the required survey depth is reached. 17.1. It must be ensured that BHA has the correct length of non-magnetic components to prevent magnetic interference while using magnetic survey instruments. The gauge of bit to be run into the hole and integrity of nozzles should also be checked.2 Tool Pusher / DIC • Directional driller must be called on the rig sufficiently before the kick off operation begins. Directional drilling procedures and surveying requirement that will be used to maintain adequate well to well separation. In this regard a brief report regarding the well being drilled and behavior of the well may be handed over to directional driller to help the reliever to take quick and correct decision immediately after reaching the site. 205 . depending on the type of formation to be drilled. This is especially critical following a crew or tour change. Directional driller may be called on the rig floor whenever a BHA is made to be run in the well.1 Directional Driller The Directional Driller is responsible for drilling the well and performing directional survey calculations.1. • The bit change program must be discussed with directional driller so that it can be clubbed with BHA change program if possible. It must be verified that all personnel directly involved with carrying out the directional drilling operation are aware of all important aspects of the operation. HSE issues regarding the survey winch etc. He must help the directional driller in making survey barrels and in lowering it into and pulling out of the hole. 17. He is to liaise with all responsible personnel during drilling operation. The Directional Driller is also responsible for The BHA to be run into the hole is given by directional driller. proximity checks and ensuring that correct survey correction factors are applied to each survey in accordance with well programme requirements. 1 Stabilizers 1. Drilling a straight hole • Drill with packed hole assembly i. Do not stop rotary abruptly. Formation properties 2. or higher) may be considered as full as gauge. • If clear trends are observed continue drilling with desired drilling parameters till the required inclination is reached. 17. However.Drilling Operation Practices Manual 17. Reaming is acceptable to reduce angle but to avoid unscrewing the drill pipe due to doglegs higher in the hole. drill with stabilizer above the bit and stabilizers in the string (given in tables later). However a slightly under gauge stabilizer (up to 1/ 8” or lesser) at 90 ft. • Ensure the angle drop by survey.2 DEVIATION CONTROL Causes of hole deviation 1. If Angle Builds due to dipping formations • Restrict the rate of angle build with a packed BHA. On floaters. Ensure both the sets are functional by using them regularly. slow down gradually before stopping.2 • • • Precautions At least two sets of survey instruments should be available on rig. All the stabilizers should be full gauge. • Drill 40-50 metres.3. Don’t use dull bits as these contribute to an increase in hole angle in crooked hole formations. Dogleg should be worked out as per well plan.2. A third stabilizer at a distance of 30 feet from the second stabilizer may also be used which gives still better results. • If inclination does not drop.3 DIRECTIONAL DRILLING AIDS 17. Use rotary brake to stop backlash. • Before maximum permissible limit of inclination is reached (normally 3o-5o). deviation in 36” hole should not exceed 1-1/2 degrees. Use of “average angle” directional survey calculation method in the field is acceptable. 206 . the “radius of curvature” or “minimum curvature” method should be used to prepare the final directional report. Improper mechanical arrangements of bottom hole assembly. use high rotary speed with reduced WOB to enhance pendulum effect. drop angle by changing the BHA to a pendulum BHA and continue drill with reduced weight on the bit.e.. the following should be taken care of : Use minimum BHA required. 17. • To avoid angle build up when using a near bit stabilizer place the near bit stabilizer immediately above the bit and place a string stabilizer 10 to 30 feet above the near-bit stabilizer. c. Integral blade near bit stabilizer is preferred during jetting. 10. 4. a stabilizer having 360o wall contact placed at the top of collars is often helpful. The bottom 90 feet of BHA should be appropriately stabilized for proper control in a directional hole. Generally torque developed by stabilizers will fluctuate widely.D. • It is also important to see the direction of the well. 2. Stabilizers should have A Brinell hardness between 300 and 321. Restrict the drilling torque to less than the make-up torque applied to the weakest connection in the drill string. 6. Slot should be selected so that the distance between the well increases as they are drilled.g. 3. 7.3 blades having wall contact of 360o. 9. Precautions 1. Use non-rotating blade (rubber) stabilizers. c. Reduction in rotary speed &WOB to control torque is not recommended. The common practices of controlling torque are: a. Using a smaller string on bottom (tapered string). b. Stabilizers are often the source of high torque. Drill pipe. Using an oil base mud when conditions are severe. Stabilizer should have either: Open design (Vertical Holes) . of drill collars. • Central slot may be selected for vertical well.D.2 Preplan Slot selection for a particular well should be done according to the target direction of the well.) b. If the formation have tendency to develop key seats. Stabilizers should be gauged in each round trip 3.3. or Closed Design (Deviated Holes) . Preferably the near bit stabilizer should have a box down to avoid cross over. Using a full string of smaller drill pipe (e. Use more number of heavy weight drill pipes and accordingly reduce No. 17. The torque meter on any rig should be calibrated at least once per well. • Wells which require more drift or inclination should be allotted outer slots and those with lesser drift the inner slots. drill pipe to replace 5” O.Directional Drilling 2.3 blades having a wall contact of + 1400. As a rule. Condition the drilling fluid to have high lubricity & low solids. 5. Torque developed by extremely large hang-down weight below a dogleg or kick-off point can be reduced by: a. cement drilling inside casing should be done with slick assembly. 207 . but have a short life span in some formations. d. 8. The inside diameter of the stabilizer should preferably be the same as the inside diameter of the drill collar string. These stabilizers are generally acceptable for straight holes. using a 4-1/2:” O. 17. stabilizer sleeves. Back off the Monell drill collar above the UBHO sub. Loosen the set screws in the UBHO sub. Use extension bars in the lower section of survey barrel to space compass in NMDC. Do not consider the length of muleshoe stinger for deciding the position of compass in NMDC.6 • • • • Positioning Compass in the Nonmagnetic Drill Collar Select the length of NMDC & decide positioning of compass using standard guide lines. Set the slips keeping the set screws of UBHO sub above the slips. conducting a multishot survey is preferred to determine the condition of the well bore from surface to kick off point. so add this 9”to extension bar length for calculating the position of compass. 3.3. Once the bit reaches bottom directional survey should be conducted to ascertain the tool face. Based on directional survey orient the tool face in the desired direction.3. Align the key of the UBHO sub with projected scribe line of bent sub or open jet and tighten the set screws of UBHO. short drill collars. HWDPs and other required subs.3 Kop Selection Procedures • On Offshore platforms if most of the wells have approximately same drift in different directions their KOPs must be varied at least by 10 or 20 m to give the wells some initial separation to avoid collision of the wells directly underneath the platform. 3. 4.Drilling Operation Practices Manual 17. Lower the deflection tool (Jet bit/Mud motor bent sub assembly) and the Muleshoe sub through the rotary table. 5.3. When the kick off point (KOP) has been reached. bent subs. • Functioning of survey winch and its proper grouting for on land operation. NMDC. 17. 17.5 Procedure for Muleshoe (UBHO) Sub Sleeve Alignment 1. Orientation Procedure 1. Take a check shot survey to confirm tool face setting. KOP must be selected so that the angle required to hit the target is at least 20o or more.4 Checking of Instruments/Equipments • Functioning of all single shot & multishot instruments. • Functioning of sand line • Availability of down hole motors. 2. 4. Orienting snubber is 9” long. • KOP must be selected in relatively softer formations. 6. stabilizers. • KOP selection for a given well also depends on the TVD and drift of the well and directional technique used. 2. UBHO. Check the Muleshoe sleeve with key alignment wrench by rotating it in either direction to ensure that sleeve doesn’t slip. 208 .3. 3. 6.Directional Drilling Alignment of the scribe line on the compass face with the keyway of the Mule Shoe Stinger After determining the appropriate length of extension bar. 3. to the T-head of the orienting snubber. 209 . Loosen the set screws of T-head of the orienting snubber. The required length of the extension bar must be calculated using charts. For this another survey barrel is used. 5. Load the single-shot instrument 2. 17. The reader must be held in such a way so that the arrow which indicates hole direction points up. Connect the protective casing and survey barrel and tighten the same with wrench. Insert the single-shot instrument into the protective casing. Align the T-head and the compass face with the projected line from the top of the keyway so that the scribe line 180o away from the keyway. A short piece of pipe (OD equal or slightly lesser that OD of Drill collar) may be welded at the centre of the baffle plate. 4. Lower the Survey barrel assembly inside the drill string through wire line /sand line to take survey. 7. Set the mechanical clock and synchronize the surface watch or use monel sensor in survey instruments. • Once kick off operation is over normally a packed hole assembly is used. It will prevent the baffle plate from tilting when survey barrel sits on it. Tighten the set screws Insertion of Tattle tale (Lead Pin) into the Mule Shoe Stinger Before survey barrel is lowered into the drill string a tattle tale (Lead Pin) is inserted into the hole at the top of Keyway of Mule shoe stinger to make sure that blade /key of the mule sub has reached the key way.1 Reading of Single Shot Survey a) Holding the reader 1. After survey barrel is retrieved the tattle tale should be bent or crushed. connect the mule shoe stinger to the lower end of it and connect the orienting snubber to the upper end. • Mule shoe sub is removed and a baffle plate is put below the non magnetic drill collar. Put the single-shot instrument onto the T-head of the oriented snubber. Rubber guide fingers must be inserted into the holes of mule shoe stringer/bottom shock absorber and finger guide holder installed above the protective casing. 4. 17.4 RECORDING OF SINGLE SHOT SURVEY 1. • Use internal shock absorber in place of orienting snubber and bottom shock absorber in place of mule shoe stringer. Align the scribe line as follows: 1. up the lower extension bar. Project a vertical line from the top of the keyway. 2. Always use drill pipe thread protector before lowering the survey barrel into the drill string. Check it with monel ring on surface.4. Read the position of the straight line under the hole direction line on the reader to indicate the direction of the hole with the least count of 1/20. This will indicate tool face in degree left or right of hole direction. When held correctly. (Tool face) with respect to hole direction.e. The number and letters on the survey record are oriented in the proper fashion. 210 . In order to correct for this reverse image. c) Reading single shot survey 1. and the word “right” should appear on your left-hand side. Read the position of the long line of the cross hair on the edge of the reader in degrees with respect to left or right to indicate T.Drilling Operation Practices Manual 2. The hole direction line on the reader passes through the center of the concentric circle and through the center of the crosshairs on the survey record. towards right or East of N North) the numbers are in reversed order as shown in fig. it results in a reverse image.. the word “left” should appear on your right-hand side. 4. Read number of concentric circle/ curved line under the cross hair to indicate the inclination of the hole with the least count of 1/40. Read drift angle and hole direction in the usual manner. b) Placing the single shot record on the reader 1. 2. 2. below. Place the survey record in the reader correctly. Take the reading long line of cross hair from the edge of the reader on left or right side asthe case may be. left and right are reversed on the reader. It is because when a picture is taken of the face of the compass during survey. d) Procedure for determining toolface 1. 3. Orient the tool face in desired direction. 2.F. 3. The numbers 1 through 8 between the N and W are in forward order and while moving towards right on the picture i. 2 Survey Calculation Method Though minimum curvature method gives most accurate results. e) Correction of magnetic declination Magnetic Survey which is read by the reader must be corrected for declination (East or West available from geological office. Sand and solid contents should not be more than 2% by volume or as indicated by the manufacturer. the direction of the well should be kept slightly towards the left depending upon the field behavior. Always use a mud filter below the Kelly. 17.1 Operational checks 1. Rags etc. given above) Details as read from above figure: Inclination 4-1/4o Direction N17oW Tool face 115o R R denotes right side.Directional Drilling Example: (refer fig. Methods for applying correction for East/West declination 1. 17. 5. accidentally dropped down the system into the circulating system can plug and damage the motor. assembly is pulled out of hole even if maximum angle may not be achieved after the desired direction has been achieved. So desilters should be continuously used while drilling with a mud motor. The elastometers of PDM gets damaged when oil based mud is used. Tool face is 115o right of hole direction N17oW or tool face in S82oE direction. 211 . The mud motor is designed to handle lost circulation materials but particle size should not exceed the recommendation of the manufacturer. Lifting sub should be used for picking up motor. Rotary assemblies normally have right walking tendency. After this. build up is done by using a near bit full gauge stabilizer into the string. Note : When kick off is done by a mud motor. average angle method may be used in field because it is easier to calculate survey data by this method using scientific calculator and it generates fairly accurate results. 17. 4. It is therefore. 2.4. For East declination rotate the observed direction in clock wise direction by an amount equal to degrees of east declination and find the corrected direction. recommended that before the kick off assembly is pulled out of the hole. upto 275oF. For west declination rotate the observed magnetic direction in counterclockwise direction by an amount equal to degrees of west declination and the corrected direction. Sometimes well may travel towards left due to formation characteristics.Following points should be considered: 1.5 DRILLING WITH MUD MOTOR For proper working of mud motor care should be taken regarding mud properties. 3. Operationally PDM has a working limit of bottom hole temp. in such cases the well direction is kept slightly towards right. 2.5. 7. 1. liner hanger etc. 4. especially if diamond bits are used. 5. special care must be taken when passing the well head. Hang the motor freely and measure the distance between the lower end of bearing housing and drive sub as X1.2 Drilling Generally a string with a PDM can be run into the hole like a standard bottom hole assembly.5.play (X1 .X2) in mm. 8. Check axial play of the bearings. • Start the mud pumps and increase the number of strokes to the desired flow rate.3-0. casing shoe.Drilling Operation Practices Manual 2. the PDM is started as follows:• Pick up the bit to a distance of 1 to 2 feet (0. The differential pressure created simultaneously must not exceed values on manufacturer’s recommendations.It should be free.5 4 4 6 6 8 8 8 6. Rest the PDM down on the rig floor and measure the same distance as X2. Check dump valve for its easy operation using wooden handle of hammer. increase weight on bit. Pump pressure will rise with increasing weight on bit. lower the bit and tag the bottom and increase weight on bit slowly. extreme care should be taken. When a deflection device (Bent sub) assembly is used.6 m) off the bottom. Calculate (X1-X2). It should be within limits as tabulated below: Tool Size (diameter in Inches) 1¾ 2 3/8 2¾ 3¾ 4¾ 6¼ 6¾ 8 91/2 11 -1/4 Allowable Max. 212 . After one meter is drilled. When the bottom is reached. Test the mud Motor by connecting kelly. Test should not be performed for more than 15 minutes. using safety clamp.(Off bottom pressure) • After thorough circulation. Set the mud motor in rotary table. 3. • Record the total pump pressure and flow rate. Note : If reaming becomes necessary when tripping into the hole. 17.7 2.3 1. Directional Drilling In case of Drilling with PDM stand pipe pressure gauge acts as WOB indicator. Bit weight variations, formation changes and bit wear will change the torque at the bit. This is indicated by an increase or decrease in stand pipe pressure. A sudden rise in stand pipe pressure occurs if the PDM stalls. If this happens, pull the bit off bottom. After the pressure decreases, the PDM and bit should be lowered carefully to the bottom again and drilling is commenced. In order to drill with constant speed and torque, keep the flow rate and pump pressure at a steady level. Since the speed of the motor directly depends on the flow rate, the bit RPM will remain constant, as long as the flow rate is kept constant. 17.5.3 Testing of Mud Motor • A Screen should be used during surface testing • Before starting the pumps it should be ensured that bypass valve ports are below the rotary table. • Slowly increase the pump speed and note the flow rate & pressure drop across the motor at which by pass valve closes. • While by pass valve is in closed position, lift the motor above the rotary table until the by pass is accessible and checked for any leakage from the ports, indicating faulty seals. • Test the motor at different flow rates (at least 3 values) within the expected working rangeand note down the corresponding pressures. The amount of flow through the bearing should also be noted. A small amount and flow should be through the bearings. A back up line should be fitted over the stator during testing at surface to prevent back torque. • After making allowances for surface equipment pressure losses and mud weight, the pressure should be in accordance with the performance curves. • Lower the by pass valve below the rotary table before the pumps are shut off. After testing of the motor, motor assembly can be made up for lowering into the hole. The pressure drop across the bit nozzles for specified mud discharge should be minimum or as per the manufacture’s recommendation. Minimum back pressure of 500 psi will force the mud to lubricate the bearings. The pressure drop beyond the maximum recommended pressure may reduce the bearing life. Precaution • As PDMs will permit circulation only when rotor is rotating, idle circulation for mud conditioning should be kept to a bare minimum period. • Excessive WOB will stall the motor. Stalling will be indicated by sudden increase in stand pipe pressure. Lift the motor immediately when pressure shooting is observed. Repeatedstalling damages the elastomers. • While drilling with PDM a screen should be used below the kelly in the drill pipe. When adding next drill pipe this screen should be removed and kept in the new drill pipe which is added. • While drilling with mud motor a left hand torque is created on the stator and thereby on the drill string. This torque must be compensated for orienting the tool face, by an amount equal to reactive torque, more towards right which is actually required to achieve desired direction. • Remaining procedure for orientation will be the same as described in orientation procedure with a jetting bit. 213 Drilling Operation Practices Manual 17.5.4 Trouble Shooting Many common down hole drilling problems can be identified by giving careful attention to mud pressure variation. Table given below gives some information about identification of the problem and corrective measures to be taken which may save costly additional trips. Trouble Sudden pressure increase Pressure increasing Slowly above normal Possible Reasons • Tool Stalls • Internal tool plugging foreign bodies • Bit plugged Actions to be taken Pull out and replace tool. Change of formation. Slow decrease of pressure Decrease in ROP Circulation loss Washout in the drill string Formation change Pick up and check pressure. If differential pressure is higher than starting differential pressure; try to clean bit by varying circulation and reciprocate the string. If not successful, pull out. Pick up and check pressure. If drift pressure equals starting drift pressure go ahead. Pull out for check Try with variations in drilling parameters. Change WOB, change circulation Pull out for bit change. Pick up and start again after pressure check, with less WOB. Bit worn Tool stalls / NO ROP 17.6 BUILD UP ASSEMBLY Near bit stabilizer is used for building angle in build up section. Near bit stabilizer acts as fulcrum which forces the bit up and a reaction force developed on the stabilizer forces the stabilizer to the low side of the hole So while using a near bit stabilizer assembly for kick off a stabilizer with a sleeve having larger blades or integral stabilizer should be used. Following points regarding this assembly should be considered A short Drill Collar is normally added between the bit and the near bit stabilizer. The extension sub gives extra leverage (side force) below the fulcrum point and accentuates the amount of drift angle increase. Note : Higher WOB generally causes an increase in angle build rate and decreasing WOB results a decrease in angle build rate. Rule of Thumb regarding right hand walk In order to slow down the degree of right-hand walk: • • Reduce WOB Increase rotary speed 214 Directional Drilling Second stabilizer A second stabilizer is added either 30, 60, or 90 feet above the near bit stabilizer. This stabilizer influences the amount of bend in the drill collars between it and the near bit stabilizer and the bend in the drill collar causes the fulcrum effect. The shorter the distance between these stabilizers, the lesser the bend created between them. The less bend between the stabilizers produces the less fulcrum effect and thereby the less angle will be built. 1. If the distance is 30 feet approximately 0o-0.75o build per 100 feet. It can be used as holding assembly. 2. If the distance is 60 feet, you can expect approximately .25 o-1.25 o build per 100 feet. 3. If the distance is 90 feet, you can expect approximately 1.25o to 2o build per 100 feet. This assembly is also used as angle build assembly. Drill collar stiffness A second method to increase the amount of bend between the near bit stabilizer and the second stabilizer is to change the size of the drill collars. Weight on bit Another way to affect the rate of angle build is by changing weight on bit. An increase in weight on bit when using a build up assembly will, generally, cause an increase in the angle build rate. A decrease in weight on bit will generally, cause decrease in the angle build rate. This occurs because the amount of bend in the drill collar between the near bit and second stabilizer will increase or decrease with an increase or decrease in weight on bit. There are four variables which control the rate of angle builds up of build up assembly. 1. By increasing or decreasing the distance between the near bit stabilizer and the second stabilizer, you can increase or decrease the amount of bend and the amount of angle build. 2. By increasing or decreasing the O.D. of the drill collars, you can decrease or increase the amount of bend and the amount of angle build will change w.r.t. to amount of bend. 3. By increasing or decreasing the amount of weight on bit, you can increase or decrease the amount of bend and the amount of angle build. 4. By increasing the rotary speed the amount of angle build decreases. By decreasing the rotary speed the amount of angle build increases. There are four variables which control the rate of angle build up as given below. 0- 30’ Build Up Assembly EXISTING DRIFT ANGLE WEIGHT ON BIT ESTIMATED BUILD RATE /100’ 0 o - .5 o .5 -.75 o 0 o -.25 o .25 o -.50 o MORE THAN 20o 0-15,000 lbs. 15,000-40,000 lbs. LESS THAN 20o 0-15,000 lbs. 15,000-40,000 lbs. 215 Drilling Operation Practices Manual 0- 60’ Build Up Assembly EXISTING DRIFT ANGLE WEIGHT ON BIT ESTIMATED BUILD RATE /100’ MORE THAN 20o 0-15,000 lbs. 15,000-40,000 lbs. LESS THAN 20o 0-15,000 lbs. 15,000-40,000 lbs. .25 o -.75 o .5o -1.25 o .25 o -.50 o .50o -1o 17.7 PENDULUM ASSEMBLIES OR DROPPING ASSEMBLIES Angle dropping assemblies are based on the pendulum principle. Pendulum effect results when the near bit stabilizer is removed completely or reduced in size, and the upper stabilizer is retained. The upper stabilizer holds the drill collar off the low side of the hole providing a pendulum point. Gravity acting on the lower drill collars tends to pull them back towards vertical. The bit is forced to the low side of the hole, and the angle of the hole is decreased. Points to be considered regarding pendulum assemblies: • As the distance between the bit and the pendulum point increase, the angle drop rate increases. • As the drill collar thickness increases, the stiffness of the assembly below the pendulum point increases. • As the existing drift angle increases, the angle drop rate increases. • As weight on bit increases, the angle drop rate decreases. • As rotary speed increases, the angle drop rate increases. 90’ Drop Assembly EXISTING DRIFT ANGLE 30 o -45 o 20 o -30 o 5 o -20 o 0o - 5o WEIGHT ON BIT 0-15,000 lbs. 15,000-30,000 lbs. 0-15,000 lbs. 15,000-30,000 lbs. 0-15,000 lbs. 15,000-30,000 lbs 0-15,000 lbs. 15,000-30,000 lbs ESTIMATED RATE /100’ 2 o -2.5 o 1.25 o – 1.50 o 1.25 o – 1.50 o .75 o – 1 o .75 o – 1 o .50 o - 0.75 o 0 o - 0.50 o 0o 216 Directional Drilling 60’ Drop Assembly EXISTING DRIFT ANGLE 30 o -45 o 20 o -30 o 0 o -20 o WEIGHT ON BIT 0-15,000 lbs. 15,000-30,000 lbs. 0-15,000 lbs. 15,000-30,000 lbs. 0-15,000 lbs. 15,000-20,000 lbs ESTIMATED DROP RATE /100’ 1.25 o 1.00o 1.00o 75 o – 1 o 0.75 o 0.50 o 30’ Drop Assembly EXISTING DRIFT ANGLE 20 o -45 o 0o -20 o WEIGHT ON BIT 0-15,000 lbs. 15,000-30,000 lbs. 0-15,000 lbs. 15,000-30,000 lbs. ESTIMATED BUILD RATE /100’ 0.75 o 0.50o 0.25o 0.125 o Packed hole assemblies are used when it is necessary to keep angle and direction change to a minimum. On most directional wells, packed hole assemblies are used after achieving maximum drift angle to hold inclination. 17.8 RIGHT-HAND WALK AND PACKED HOLE ASSEMBLIES Packed hole assemblies are designed to minimize right-hand walk, however, some degree of right-hand walk may still occur when using packed hole assembly. A commonly accepted method reducing walking tendency is to decrease the weight on bit while increasing the rotary speed. If this does not solve the problem, you can change to a stiffer packed hole assembly, or use larger size drill collars to increase stiffness. An extension sub between near bit stabilizer and the bit in packed hole assemblies induces the tendency to build angle slightly. An increase in rotary speed will slow down the build rate especially if combined with a decrease in weight on bit. Commonly used packed hole assemblies are: 1. 0-10-40-70 assembly. 2. 0-30-60 assembly 17.9 SIDE TRACKING Side tracking is done to: 1. By pass a fish that can not be recovered. 2. Correct the crookedness of a hole. If a well has inadvertently gained angle, especially at shallow depth, it is brought back to vertical with this technique. 217 Drilling Operation Practices Manual 3. Re-drill a hole if the geophysical data indicate missed geological target during the course of drilling a well 4. Drain hole drilling or multiple hole is also a kind of side tracking operation. Technique of side tracking Place a 50-100 mts. long cement plug. The open end d/pipe assembly should preferably have a diverter pipe. 17.9.1 Slurry Design Sufficient WOC depending upon type of cement & additives should be given before testing the hardness of cement plug. If it does not harden in the given time, give more time or drill out and set another plug. 1. Put about 10 tons of weight on the plug gradually and take off the weight immediately thereafter for testing the hardness of cement . 2. Drill About 2-4 mts. of cement top so as to dress down the cement plug top. The plug is to be drilled uniformly at the rate of 5-6 minutes per meter with 3 ton weight on bit, 50 RPM and moderate pump pressure. Once a sufficiently hard plug top is established, the well is ready for side tracking. Thereafter, drill string assembly is pulled out and kick off assembly lowered. 17.9.2 Time Drilling Side tracking, through an application of directional drilling technique, requires to be initiated by adopting time drilling process. Time drilling implies to drill first five meters of interval in a manner so as to permit bent sub motor assembly to allow cutting of a wedge. For this the procedure is as under: 1. Reciprocate the assembly about 8 to 9 times. This helps in cutting a groove in the high side of hole. 2. Circulate with both pumps for about 15 minutes just about 15 centimeters above kick off point. This will facilitate enlarging the hole right above the KOP which will permit quick take off from the cement plug. 3. Drilling parameters are described below: 1st mts 40-45 minutes 2nd mts. 30-40 minute 3rd mts. 25-30 minutes 4TH mts. Normal time 5TH mts. Normal time WOB, should not exceed 2 Ton. • • • WOB-1/2-1 TON WOB – 1 ton WOB-1-1/2 TON WOB-1.1/2-2 TON WOB- 1.1/2-2 TON The time drilling will permit drilling laterally and establishing a shoulder on the side of the hole. A close watch will have to be kept on the cutting at the shale shaker. The cement cuttings should graduate to formation cuttings by the time first 5 mts. is drilled out. If this pinching out of cement cuttings is not observed, next five meters is also to bedrilled with time, otherwise normal drilling is continued hereafter. 218 Cementing Operations CHAPTER - 18 CEMENTING OPERATIONS 18.1 PRIMARY CEMENTATION The success of cementing operations can be improved significantly by following the standard best practices as detailed below. Major factors requiring detailed attention are: • Slurry design / job planning • Blending of cement and additives in bulk handling plant. • Casing lowering, hook up, pre-job arrangement. • Slurry mixing on location, pumping and job execution • Displacement of cement slurry • Job evaluation 18.1.1 Cement Slurry Design and Planning 1. Gather the data, obtain and assess all the necessary information prior to preparing any cement job design and operation programme. The information should include the following points: • Rig, Well No., Field location • Type of job - casing or liner - conventional or sub-sea operation. • Casing sizes, grades, weights and threads. • Casing depths, deviation, hole size, caliper (if available), drilled depth. • Type of mud to be used, mud parameters and rheology. • Bottom Hole Circulating Temperature (BHCT) & Bottom Hole static Temperature (BHST), expected pore and fracture pressures. • Interested zone intervals with Oil Water Contact (OWC) or Gas Oil Contact (GOC) • Any special well problems (high pressure gas, Lost circulation, salt dome etc.) • Cement rise needed • Any other specific requirement from casing cementation. 2. At job planning stage, the availability of equipment and additives for the job execution should be assessed. 3. Calculate the cementing parameters which include the quantity of cement, total mix water, pump rate, well head and bottom hole pressure during displacement, mixing time, mud displacement volume, surface pressure and other related information. This will assure that well will remain under control during the cementing operation. 4. Design maximum allowable down hole slurry density to prevent fracturing. Slurry density should be at least 1 lb/gal (preferable 2 to 3 lb/gal) heavier than the drilling mud. 5. Determine bottom hole circulating temperature (BHCT) from logs and using API Temperature data. Temperature logged approximately 24 hrs. after the last circulation ceased can be used as BHST for API table. 6. Design fluid loss as under, as per API test a) For preventing Gas Channeling: Less than 50 ml/30mins. b) For Liner Cementing: Less than 100 ml/30mins. c) For casing cementing: Approx. 250 ml/30mins. 7. Design cement slurry or preflush / spacer to be displaced in turbulent flow to obtain minimum 10 mins. contact time at the top of pay zone. Preflush i.e. aqueous solution of dispersant and surfactants are not recommended in high pressure wells. 219 4% or less. 16. In case of primary cementing of gas wells with expected high pressure. The best results are obtained if not only the density but also the rheological properties of the spacer fall between those of mud and cement slury. Use 35% Silica flour (BWOC) at BHST above 230° F (110°C) to prevent strength retrogression of set cement. 18. Therefore. compressive strength test should be performed at the TOC temperature also to confirm the setting of cement at the cement top. In the case of certain types of cement jobs. 11. Cement absorbs moisture from its surroundings and changes its properties. To prevent gas channeling and in cementing highly inclined wells. before following API test schedules for increasing temperature and pressures. whereas liquid additives are to be mixed with water only 3. special chemicals need to be added to cement slurry for effective blockage of gas leakage possibility and the slurry should be tested for its gas tight property in the lab prior to its use in the field. Dry chemical powder can be blended with dry cement or can be dissolved in mix water. Use the same mixing water. If additives are dry blended. Compressive strength of set cement stone should be: • 500psi for drill out • 2000psi for perforations 19. then design the job for mud displacement in effective laminar flow using rig pump rate as fast as possible within the limitation of fracture gradient. quantity and name of each additives going into the cement with design composition. Determine cement slurry thickening time at BHCT and bottom hole pressure. 2. Count the additive sacks and cement sacks for each blend. Excessive slurry thickening time should be avoided.e. cement should be purchased in lot preferably meeting the requirement for 4 months only and stored properly. Cement additives are used with Oil Well cement (API Class ‘G’) in order to get the desired properties of cement slurry as per job requirement. Since sometimes slurries are mixed heavier in the field. When field slurries are to be batch mixed. 15. so check consistency in the lab for 1 ppg heavier slurry also. 12. 220 . 9. Weighted buffers i. such as long cement column rise or long liners where the static temperature at the top of cement is lower than the BHCT. During blending of dry additives with cement. control free water separation to 1. while running the thickening time test in lab. 10. If turbulent flow is not possible.2 Blending of Bulk Cement and Additives 1. a blended cement sample must be collected and tested in the cement test lab before the execution of the job. Minimum thickening time should be job time plus one hour thickening time to a consistency of 50 Bc. the slurry should be stirred in the consistometer at the surface temperature and atmospheric pressure for the estimated batch mixing and holding time on drill site prior to pumping slurry into the well.Drilling Operation Practices Manual 8.1. 18. spacers are to be used in high pressure wells and preferably to be designed for turbulent flow. cement and additives in Lab testing that will be used on the wells for the job. zero free water control should be a primary objective. Slurry consistency for all normal turbulent flow slurries should be 10 to 20 BC. Design the spacer such that it is compatible with both the cement slurry and the drilling mud. verify weight calculations. For normal slurries. The cement additives are available in dry form or liquid form. 13. 14. Landing joint(s) should be spaced out so the cementing head can be installed from the stabbing board or rig floor after casing is landed. mud rheology. 8. Placing of Centralisers should be done with the help of cementing software in order to have minimum stand-off 67% for deviated wells and near to 100% for vertical wells. Verify with the rig-in-charge the displacement rates. 6. and how many barrels (or cubic meters) over the calculated displacement volume will be pumped.3 Preparation and Hook-up for Cementing A. 3. check the size of the ball for actuating them properly. 4. Use scratcher against the permeable formation and 200ft.Cementing Operations 4. 5.1. 2.a float shoe and a float collar. Lowering of casing 1. Running in speed of casing should be controlled to prevent fracturing and lost circulation. 10. the hole conditioning. Casing lowering should be so regulated that the maximum annular velocity caused by the movement of the pipe does not exceed the annular velocity during normal circulation. 7. Ensure that the supply rates of both mud and water required for the job are sufficient for uninterrupted operation. 3. Welding of stop ring on casing and use of welded steel bows should be avoided. Conduct fluid loss and thickening time test on samples taken from each container to verify blending. If extra empty tank is not available on site. flow channel return. transfer the blended material at least twice between silos before loading on mobile silos or bulk supply boats for drill site delivery. 6. Casing centralisation is a critical parameter that must be part of the cementing programme. To ensure proper blending. 221 B. When different blends are used. Verify that correct chemicals are loaded with correct weight and volume. 4. density. Check the mud volume on the site. above and below the pay and water zones in case of casing reciprocation. Check its functioning on surface before make up. In case of differential float equipment. Otherwise. Pre-cementation job arrangements 1. then fluff or percolate air through each tank from the bottom for 15-20 minutes to redistribute additives. 7. calculate the slurry volume required and displacement volume using actual parameters and also total water requirements including the water needed to flush cementing unit and high pressure lines. . 9. After arrival at site. Collect and save sample of each composition for post job analysis if failure occurs. Use double float protection . Last two casing joints should be lowered at a very slow speed. pressure to apply when plug lands. Transfer dry blend to empty tank and back to original tank just prior to slurry mixing. Use same type of float collar and float shoe. 2. each blend and tank should be clearly identified. Visually inspect empty tanks prior to transferring blended materials to ensure that they are empty. Put float collar and shoe 2-3 joints apart as depth increases. 18. Use API approved centralizers. throw away the samples after the job. if the plug fails to land considering the rig pump efficiency. 5. Check to see that all materials required for job are loaded and identified on the transporting vehicles. D. clean if needed. Check the cementing head. 3. safety hazards during pumping operation and maximum allowable pressure. 18. the pipe is rotated as slowly as possible. Large percentage of annular open hole (at least 90 to 95%) should be “circulatable”. Check the discharge of each cementing unit physically for their capacity in accordance with the liner size. Start the pumping operation to break circulation to ensure that the casing shoe is open and check the mud return. Check the air compressor operation. the volumetric efficiency of mud pump. Cementing equipment 1. functioning of stroke counter and mud line flow meter should be checked. 4. before the cementing 222 . For critical jobs such as production casing cementation fresh mud having low rheology may be pumped ahead of cement slurry.4 Job Execution A.5 to 2 cycles (minimum). Check the tanks of cementing unit thoroughly. using a 2 min. 4. plug dropping indicator and review the number and placement of rubber plugs in proper sequence. 3. plug release mechanism. When reciprocating. 9. If not the entire pneumatic system comprising of compressor.1. material mixing and pumping sequence. The casing movement should continue throughout the circulation period.5 times the maximum pressure expected during the job. a mandrel is used for carrying top and bottom plugs. fluff the cement of silos. prime the pumps and mixers prior to the starting of operation. lay out of high pressure lines. Do not premix the cement additives in the water more than 5-6 hrs. usually between 10 and 15 rpm. Condition hole with good surface conditioned mud at a rate anticipated for cement pumping rate for 1. interval for the cycle. In case the displacement is to be performed by the rig pump. Mud conditioning 1. one has to ensure the proper working of air dryer. pump rates. In case of floater rigs. Adjust Plastic Viscosity (Pv) and Yield Point (Yp) of the mud to the lowest possible values without dropping solids during mud conditioning. For rotation. surge tank and lines may get clogged and free flow of cement will not be there. C. Conduct a pre hook up meeting to review equipment placement. 10. Check and calibrate the pressure gauges. Begin pipe movement and mud conditioning immediately after the casing is lowered. Pressure test the cementing head and all connecting lines at 1. 2. Check the cementing units and bunkers to avoid any breakdown during the operations. Ensure that this has been serviced immediately after the last use. In case of offshore. before the cement job to achieve the best results. Cement slurry mixing and pumping 1. 7. 2. 8. 3. 5. 2. Pressurize bulk units to 15-25psi just prior to starting mixing slurry. A detail cementation plan indicating the step by step job sequence duly approved by the concerned well-site incharges should be made and circulated prior to the operation. silos.Drilling Operation Practices Manual 5. slurry densities. 6. the pipe is usually moved through a 20ft stroke. 11. Field validated computer programs should be used to calculate the highest possible displacement rate within the constraints imposed by formation strength and surface/down hole equipments limitation. Inspect plugs before loading. Check order of plug loading. Bottom hollow plug is loaded first and then Top solid plug is loaded.8 m/sec to achieve sufficient zonal isolation with reasonable degree of certainty. Use pre-flush or spacer volume equal to 150-200 m annular height. Turn bottom plug upside down and inspect hollow core and rubber diaphragm. This will cause reduction in slurry density and will result in poor slurry at shoe joint and outside bottom joints. Before premixing additives in water. mud and cement slurry. then the maximum permissible/ attainable discharge for high laminar flow is recommended for displacement. Use top and bottom cement rubber plugs. 5. B. Displace top plug out of cementing head without shutting down operations. A bottom plug is not recommended with large amounts of lost circulation material in the slurry or with badly rusted or scaled casing. as it will allow the well to suck in air and cause honey combing of cement around the shoe joints. one ahead of pre-flush and one ahead of cement slurry. Alternatively use continuous mixing devices like Precision Slurry Mixer (PSM) or Recirculating Cement Mixer (RCM). better to wait until the final circulation is started after casing lowering to the target depth. Rotation at 3-10 rpm is satisfactory. When liquid cement additives are mixed in displacement tanks. continue to agitate chemical water thoroughly until the job is complete. Do not puncture diaphragm of bottom plug prior to loading. if possible. Better use two bottom plugs. 6. (2cu.Cementing Operations 4. Determine displacement rate on the basis of the type of casing string to be cemented. Be sure to conduct compatibility test with pre-flush. 10.3 m/sec and preferably 1. However when turbulence all around the casing cannot achieve mainly due to stand off. pump or fracture gradient limitations. Continue pipe movement until the top cementing plug is bumped or casing tends to become stuck. Keep casing pipe in motion to improve mud displacement. Cement displacement rate should be as high as possible but at least 1. Check calibration of densometer as well as mud cup balance with fresh water to ensure the reliability of density readings. job. Reciprocation should be on a 2 minute cycle over 15-20 ft. 8.m) slurry pumped which is very critical. Control slurry density with pressurized mud cup balance. Displacement 1. 6. To ensure good control of slurry density and other properties. Pump pre-flush or spacer ahead of bottom plug. 7. Do not open cementing head to drop top plug and better to use a two plug container. 2. Do not try to get the last few quantity of cement out of the cement bunker or surge tank. 11. batch mix all cement slurries. measurement of mixed water is absolutely necessary as tanks are alternately filled and emptied. as such material may collect on the ruptured diaphragm and bridge the casing. Verify metering device if liquid additives are pre mixed in water. 223 . Maintain constant density of the last 10-12bbls. intervals. 9. 4. The mix water for cement should be measured through displacement tank because it helps to calculate easily how much quantity of cement has been pumped in the event of unplanned shutdown. 3. Displace top plug out of cementing head with minimum down time. 5. Turbulent flow displacement is usually accepted as being the most efficient techniques for achieving good mud removal. Waiting-On-Cement 1. Calculate material balance for mix water. 9. the casing should be kept closed at pressure equal to the differential pressure till the cement slurry thickens and rig-in-charge should be cautioned to release the casing pressure by bleeding it off after thickening time of cement to prevent the formation of micro annulus. Completion interval cement should have compressive strength of at least 2000 psi before the well is perforated. For a period of hours after the plug is bumped. 8. Do not over displace if the plug has not bumped when calculated displacement volume has been pumped. 12. Compare data with calculated predictions and carry out post analysis of the job. 17. 10. density measurement. mixing rate. time. Maintain log of operations to include operation in progress. 16. Cement used to cement an intermediate casing string should have compressive strength of at least 500 psi before drilling is resumed. Monitor the displacement and bumping of plug. then also cementing unit must remain completely lined up until plug bumps. Prepare a summary of the completed job. 4. 15. C. Pressures test the casing for leaks immediately after the top plug bumps in cases where the displacement fluid is water. the cement is rigid but has very little strength. and any damage sustained by the cement sheath during this period does not “reheal”. During cementation a person should be designated to monitor returns from annulus on mud channel. 11. cement and cement additives and compare with volume of each slurry pumped. Mud return is measured in trip tanks or by other means.Drilling Operation Practices Manual 7. Sufficient WOC time must be observed for the cement to develop adequate strength before operations are resumed. All specific events occurring throughout a cement job must be recorded along with other relevant points for post job evaluation. Use a cementing monitoring van to collect data and to enable job supervisor to observe entire operation. 2. The plug hitting must be observed carefully and pressure recorded in cementation job reports. volume of fluid pumped. In the event of failure of float valves. The required period of WOC time varies depending on the cement and down hole condition of temperature and pressure. Slow return is an indication of lost circulation. To check the fluid return. 3.5 Cement Job Monitoring 1. 224 . 14. 13. 4. funnel viscosity and density. displacement rate etc. observe pH change. High return rate is predicted during the free fall period. Check the flow back by releasing the pressure. A small amount of back flow is expected because of thermal expansion and cement reaction. 18. 2.1. Even if the rig pump performs the displacement. Calculate the anticipated mud return rate throughout the job. Leave casing open during WOC. 3. pumping pressure. This method is essentially a graphical solution. The general rule is that the cement bond log should not be run until 48 hrs.1 Multistage Cementing It is the conventional placement of cement slurry around the lower portion of the casing string followed by placement of successive upper stage through ports of stage collar.5 feet of 60% bond 5-1/2" Casing . This again is highly dependent on the cement type and additives used in the slurry and bottom hole conditions. Rough handling prior to or during installation can “egg” or misalign the moving parts. 3. However.SPE . One must also be absolutely sure that the float collar and the stage collar are compatible. 225 . A complete post job analysis comparing field job parameters with actual results is the best way to reasonably understand what happened in down hole and accordingly necessary corrective measures for future operation may be applied. The first-stage wiper plug (if used) and the first-stage displacement plug must fit and seal against the float collar. Always record CBL-VDL under 700-1000psi pressure to eliminate micro-annulus effect. production results are the actual proof of the acceptable quality of cementation. 4. although additional stages are possible.12 feet of 60% bond These guidelines promote a “lean forward” approach and reduced number of squeezes resulting in reduced completion cost. as the equipment is manufactured to close tolerances.2 SPECIALIZED PRIMARY CEMENTING OPERATIONS 18. caution must be exercised in the initial handling of the stage collars.1. Regardless of the type used. 2. causing a failure during job execution. 2. Check before the stage cementing collar is made up on the casing the size of the trip plug/ freefall plug/opening bomb.6 feet of 60% bond 7" Casing . Guide lines of APIT (alliance process improvement team) . Field results show that more than 90% of wells exhibit a micro-annulus on a primary cement job.10 feet of 60% bond 9-5/8" Casing .52810 5" Casing . Design cement slurry for the first stage and second stage at temperature and pressure at the casing depth and stage collar depth respectively. One of the guidelines followed by international operators for deciding on requirement of remedial jobs based on the bond index method given below.6 Job Evaluation/ Post Job Analysis 1.2.D of the opening sleeve and closing sleeve and the size of the seats provided in opening & closing sleeves. CBL-VDL. Most stage cementing is in two stages. 5.Cementing Operations 18. Evaluation of cement job is very crucial to determine the success of a cement job for its objectives. 1. less rig time and elimination of complication results from squeezes 18. which allows determination of amplitude value corresponding to a particular bond index. 4. 3. Caliper. The bond index method is most commonly used for interpretation of amplitude curve in CBLVDL towards achievement of zonal isolation. I. CET or USIT logs can provide accurate and useful information to evaluate post job success or failure. after the cementation in order to achieve the true cement bond reading. Smooth sliding and sealing of the concentric sleeves is necessary for proper operation. 2 Stab in Cementing Stab in cementing is done when large size of casing necessitates high displacement volume in conventional cementing or combined strings do not allow the use of conventional plug. As soon as mud contamination is no longer evident in the cement returns. 1. 5. To open the ports slowly build-up pressure usually approx. 18. mixing should be stopped and the cement displaced.Drilling Operation Practices Manual 5. For closing the cementing ports approximately 1500psi pressure in excess of second stage final / cementing pressure is to be built up over the shut off plug in one continuous operation without slowing down or stopping the pumps. 6. drop the opening plug or bomb and allow it to reach the stage collar.2. Run in the casing in place with a stab-in float shoe/collar and set in the casing slips suspending the string off bottom. Further cement above shut off plug will help in drilling it out. A drop in pressure will indicate that fluid has escaped into the annulus after opening of ports. the pipes are filled with the same fluid as the one placed in the well. This will ensure cement outside the stage collar and minimize the hazards of displacement fluid outside the stage collar. Stop circulation and lower drill pipe so as to enabling the stinger to stab into and seal in the stab-in float shoe/collar in the casing. Mixed cement and pumped through the drill pipe and up the annulus until it reaches the surface. 6. 9.200 to 1500 psi. 7. With the casing set. Test the surface lines and hermeticity of the inner string. When running in. Besides slurry pumping displacement and safety factor. The stage collar should preferably be placed against the shale section. 12. 4. Circulate the well through the stage collar ports for 2 cycles to flush out any extra / contaminated cement from the first stage and the well must be circulated untill the mud is conditioned for the second stage. 1. Continuously monitor the weight on string during displacement to ensure proper engagement of stringer all the time 7. mixing can be stopped and the drill pipe volume displaced. This cementing is carried out with drill pipe with a stabbing unit attached to its bottom end. avoiding the pumping of large quantities of cement into the 226 . Again establish circulation and observed for returns flowing between the conductor pipe and the casing. As much as possible. 2. After completion of first stage cementation job. 10. One centraliser may be placed just above the stage collar and one below the stage collar. fix the stringer equipped with a centraliser at the end of drill pipe string and run in the assembly until it is approximately 3 ft (1 m) above the float shoe/collar. Ensure the seating of freefall plug for opening of stage collar port. 11. If lost circulation is noticed before the cement reaches the surface. 8. 3. Release closing / shut off plug in such a manner so as to have some cement slurry over it. Establish circulation with the drilling fluid and see the returns coming from the annulus between the drill pipe and the casing. the first stage slurry thickening time should include the traveling time of bomb. The drill pipe with stab in unit (stringer) is stabbed into the stab-in cementing collar or shoe and then cementation is carried out. Stage collar should be tightened by putting the tong at the designated place on the outer sleeve of the stage collar only. Confirm the closure by bleeding back. Run in the casing with the stage collar at the desired depth. opening of ports and one cycle circulation through stage collar ports. Opening plug velocity is approx 1m/sec in normal mud. the stringer is engaged only once into the collar or shoe. and also in the open hole in cases of very narrow annular clearance. the following slurry parameters should be carefully considered. In deviated wells rotating type liner is recommended to facilitate mud removal and placement of cement slurry at the lower side of the hole.2. because annular clearance are so small that the liner must be kept clear of borehole wall for effective cement placement. then after lowering of liner the well should be circulated with fresh mud free from LCM (Lost Circulation Material). No lost circulation material should be used in liner cementation to avoid plugging of float equipment or the narrow annulus.3 Liner Cementation A liner is a standard casing string which does not extend all the way to the surface up to the well mouth. Care must be taken to avoid collapsing the casing because of excessive differential pressure between the outer annulus and the drill pipe/casing annular space. but the combined density and displacement pressure must remain below the fracture pressure of the weakest zone. Use combination dart in case of combination string is used for lowering liner. Bow spring centralizers may be used in the open hole if there is sufficient annular clearance. However the wells where high pressure gas is being isolated behind the liner. • Critical points for liner cementation Slurry Design: While designing the cement slurry for liner cementation job. Circulation should be carried out before setting the liner to clean the mud system of any cutting or debris. Swab/ surge pressure can be extremely severe and running speed should be slow to avoid pressure that could break down formations to cause lost circulation. Fluid Loss Control: Fluid loss of the slurry should remain less than 100 ml/30mins so as to avoid building up of cement filter cake and to reduce chances of annulus bridging due to small annular channels. Centralising the liner in the hole is very critical. Preferably use liner hanger with integral packer or with top seal in case of loss prone areas to avoid hanger top squeeze job. Slurry Density: High density low water ratio cement is used to prevent water separation and entry of fluid into the well bore. Rigid centralizers are used in the casing/liner lap region. Thickening Time: It is usually designed to include the time taken for reversing out the excess slurry above the liner hanger top. It is frequently necessary to restrict running speed to one stand of drill pipe every 2 – 3 min. This is particularly true in case of deviated wells. A four arm caliper should be run prior to the liner operation to ascertain the hole size for calculation of cement slurry volume which is very critical for liner cementation. but it is hung from inside the previous casing. generally keeping an overlap of 50 to 100 m A. • • • • • • • • • 227 . Centralizers or positive stand off devices also reduce the likely hood of differential pressure sticking of the liner in the open hole. 18. The length of the liner overlap can be as little as 50ft for a drilling liner or as much as 500 ft for a production liner. The small clearance also makes it difficult to run liners. relatively short thickening and setting time are required to reduce chances of gas penetrating the unset cement. Cutting will come during circulation and at the restricted area of liner hanger it may accumulates causing the rise in pressure. If loss control material is added in mud to combat loss.Cementing Operations fractured zone. Reverse circulation places an extra pressure on the annulus and this additional pressure should be pre-calculated and controlled where necessary to avoid formation break down. 228 . or during the production life of the well. Excess volume increase the likelihood for good cement placement but it is also increases the possibility of operating problems. burst limitation of the intermediate casing must be considered. Since slurry design parameters are critical for liner cementation batch mixing should be done to promote uniformity. A negative pressure test should be equal to any differential pressure that the well may encounter later in drilling or completion. Therefore. the fracture gradient of the zone at the shoe of the intermediate casing must also be considered. A liner packer keeps reverse circulation pressure off the formation. the cement job on the liner top has not been tested. In case of a drilling liner. In long liners. Release the liner setting tool after completion of displacement and if packer type liner hanger is used then set the packer. B. There are two methods that may be used to test the pressure integrity of a cemented liner top. Until the testing pressure is high enough to be above the fracturing pressure of the zone. in either case.Drilling Operation Practices Manual • • • • • • • • The plug arrangement for liner cementing eliminates the opportunities to run a bottom plug a head of the cement. The cement may take very long time to set at the top and as such drilling of cement must be done after the cement develop the minimum compressive strength at the top of liner also. If no packer is incorporated into the liner hanger then reverse out keeping excess cement over the top of the liner so that 8 to 10 joints of the intermediate casing will contain cement to be drilled out after setting. These type environment often can not be pumped into and give a false sense of security. i) Hydrostatic testing Testing the liner top with applied pressure can be done with or without a packer. The amount of cement excess for liner cementing must be carefully calculated by taking into accounts the well conditions and displacement efficiency. To complete the testing of the pressure integrity of a liner top. Displacement efficiency is a key variable in determining cement slurry volumes as it is not uncommon to have 60% to 80% displacement efficiency in liner cementing. pressure applied to the liner top should be equal to or greater than the hydrostatic pressure at the liner top when the maximum anticipated mud weight has been attained in subsequent drilling operations. however. Pull the setting tool free from the liner and reverse out any excess cement above the liner top. Normally a spacer fluid which is compatible with mud and cement is pump between mud and cement to provide a buffer to avoid serious contamination. testing the top of a liner after it has been cemented is absolutely essential to the success of the well completion. Slow down displacement when the pump down plug (dart) approaches the liner wiper plug in order to observe the first pressure surge (about 300psi) corresponding to the shearing of the pins. there may be a considerable temperature differential between the bottom and top of the liner. Testing of liner top A leaking liner top can become a serious and expensive problem during future drilling operations. The volume of cement used on most deep liners is usually rather small. ii) Differential testing A Negative pressure test should be run on liner tops because of the possibility of mud solids plugging up a small channel or the existence of “honeycombed” cement or micro-annulus. 3 SECONDARY CEMENTATION Secondary cementation jobs are mainly classified as • Plug Cementing • Squeeze Cementing. Differential pressure testing requires close scrutiny of the collapse rating of the liner itself. • Carefully calculate cement. • Slurry design Viscous slurries with high gel strength and low density are needed for lost circulation plugs. 229 . This may even require partial evacuation of the fluid from the drill pipe by adding nitrogen or some combination of nitrogen and fluid to lighten the column. Plug failures can be prevented by following the standard best practices as detailed below. 18. use a weighted spacer 1 to 2ppg heavier than the mud. • Select gauge section of a hole.1 Plug Cementation A cement plug of a specified length when placed across a selected interval in an open hole or a cased hole. The most commonly used technique for plug placement is known as “Balanced Plug Method”. • Check the mud system carefully for loss of returns. is called “Plug cementing”. Use densified cement slurry that will tolerate considerable mud contamination.Cementing Operations Differential testing of a liner top requires the use of a packer normally set at 100 to 300 ft above the top of the liner. Ideally. Any movement of the plug after it is placed may cause the cement not to set. • Pump preflush that is compatible with drilling fluid. the plug should extend from a soft shale down to a hard formation. resulting in gas migration through the cement. • However. to restrict flow into voids or fractures. Addition of sand or weighting materials will not improve the compressive strength of lower water content slurry.5 to 2 times the calculated volume) to compensate for contamination effect so as to get the desired plug length.3. water and displacement volumes and always plan to use more than enough cement (1. Consult a caliper log for selecting a location to set a plug and determining the temperature of the formation where the plug is to be set. • For open hole cement plugs in gas wells. if the kicking off is the objectives. • Whenever possible preflush/spacer should be pumped in turbulent flow conditions. • Circulate long enough to condition the well so as to ensure that the entire mud system is uniformly weighted. Shale should be avoided as they are often caved and out of gauge. Logs and drilling rate record should be consulted when selecting a location to set a plug for kickoff. Using water as preflush can cause reduction of hydrostatic head. the plug should not be set in a excessively hard formation. fluid gain or gas entry. 18. • Batch mix the cement slurry to ensure uniform slurry density. This testing is accomplished by lowering the pressure above the liner to a point lower than the highest pore pressure behind the liner. High compressive strength is mandatory in whipstock plug to have a sharp contrast between the plug and the formation hardness. • A cement plug is best set in a competent hard rock. Preflush volume should be sufficient to cover an annular height of 500 to 800ft and the after flush volume should cover the same height in the tubing string as that of the preflush. filter-cake deposition and. While placing a cement plug for kick-off special measures as depicted below are required to be followed for success at first attempt Use either a mechanical or chemical method to provide some static barrier below the intended bottom of the plug When a high viscous pill is used for achieving a static barrier below the cement column. A rate sufficient to allow adequate time for cement placement must be reached before actually 230 . 18. Reverse wash twice the drill string volume to wash excess slurry out of the hole.3.2 Squeeze Cementing Squeeze cementing is defined as the process of forcing cement slurry. under pressure. The key element of a squeeze cementing job is that of placement of cement at the desired point or points necessary to accomplish the purpose.ft.5 .Drilling Operation Practices Manual • • • • • • • Try to rotate or reciprocate drill pipe slowly till the completion of displacement. W. Ample WOC time to be allocated (12 to 24 hours) for a plug job. INJECTIVITY TEST PRIOR TO SQUEEZING Prior to placement of cement slurry.2 times the plug length. A good guide for a squeeze pressure is 500-1000 psi above the pump in pressure with no flow back in 3 to 5 minutes. Also the pill density should be greater than the mud weight and 10 sec gel strength of the pill should be above 50 lbs/100 sq. The slurry. fracturing of the formation. Typically 2 7/8 tubing should be used as tail pipe to minimize contamination during pulling out as it will create less disturbances of the cement plug when the pipe is being pulled. loses part of its water to the porous medium. the pump in pressure increase until a squeeze pressure less than fracturing pressure is attained. conduct injectivity test against the squeeze interval to determine if and at what rate below the fracture gradient fluid can be placed against the formation. The resulting physical phenomena are filtration. As the filter cake builds. Squeeze cementing is necessary for many reasons but probably the more important use is to segregate hydrocarbon producing zones from those formations producing other fluids. A. A basic fundamental of squeeze cementing is that regardless of the technique used during a squeeze job. Always test the cement plug by tagging top of cement with Bit and apply required weight for “Hardness” test.track plug. The length of tail pipe should be 1. Use a “Divertor tool” for placement of cement to achieve uniform placement of cement slurry all around the wellbore and to prevent contamination due to downward movement. Under displace the plug by 200-300 liters to avoid any back flow. At least provide 48 hrs. in some cases. through holes or splits in the casing/well bore annular space and then allowing it to dehydrate by further application of pressure. and a cake of partially dehydrated cement is formed. the cement slurry (a suspension of solids) is subject to a differential pressure against a filter of permeable rock. A common practice is to allow for longer WOC time since well temperature for a cement plug job is difficult to know accurately. subject to a differential pressure.O.C for attaining sufficient hardness/ strength for side. Pull out the drill pipe/tubing slowly (30-50 ft/min) out of the cement to minimize contamination. then the length of the pill should be equal to the cement plug length and funnel viscosity of the pill should exceeds 150 sec. Thickening time must be sufficient to assure slurry placement and reversing out of the excess. it may be necessary to use acid to clean up the perforations. 231 .100 to 200ml/30min High permeability formation (>100md) . The generally accepted API fluid loss rates are listed below:Extremely low permeability formation .200 ml/30min Low permeability formation . it should be done without excess. While taking injectivity test. If suitable injection rate could not be established at the desired injection pressure. special API testing schedules exist for squeeze cement slurry design and must be followed to prevent premature setting. • To estimate the pressure at which the squeeze job will be performed. Consider spotting a clear fluid such as water across the perforations when obtaining an injection rate. The added stringency in the API testing schedules for squeeze cementing simulates the actual temperature the slurry is subjected to when hold near bottom for extended periods. When the fracture gradient must be exceeded to obtain sufficient rate for cement placement. because fluid circulation before the job is usually less. The injection test is performed for several reasons: • To ensure that the perforations are open and ready to accept fluids. • To obtain an estimate of the proper cement slurry injection rate. channel etc.Cementing Operations mixing the cement. requirement of thickening time should be less. and • To estimate the amount of slurry to be used. Following factors may be considered in designing the cement slurry for any squeeze operation: i) Fluid Loss Control Fluid loss and filter cake growth rate vary directly i. while designing the slurry. fluid loss must be tailored to the formation type and the permeability so as to achieve a uniform cake build up against the squeeze interval. and the technique to be used. For running squeeze method. higher the fluid loss. For this reason. Hydrochloric and hydrofluoric acids are commonly used. Squeeze slurry should be designed to have the following general attributes: • Low viscosity: to allow the slurry to penetrate the small voids • Low gel strength: a gelling system restricts slurry movement • No free water • Appropriate fluid loss control. As such. Design of Cement Slurry for Squeeze Job The properties of cement slurry must be tailored according to the characteristics of the formation to be squeezed. faster will be the filter cake build up. Deep perforations require more volume than shallow ones because of the additional hole volumes. raise the pressure very slowly up to the point of injection without fracturing the exposed formation. Proper thickening time: to safely meet the anticipated job time. B.e.35 to 100 ml/30min ii) Thickening Time The temperatures encountered in squeezing can be higher than those of primary jobs. A minimum of ten barrels volumes should be used when obtaining an injection rate. Slurry Volume The optimum amount of cement is the volume required to seal the void. In most cases. • The minimum volume should be 100 sacks if an injection rate of 2bbl/min can be achieved after breakdown: otherwise it should be 50 sacks. therefore special care must be taken in preparing it. if the cement can be placed at the proper point.Drilling Operation Practices Manual Whereas for a hesitation squeeze method. the amount of slurry involved is quite small. and the placement technique to be used. the use of a recirculating mixer or batch mixer is strongly recommended. • Two sacks of cement should be used per foot of perforated intervals restricted to a minimum of 50-sacks. E. a 5-15bbl batch is normally prepared. for job convenience and because of problems in placing the cement into the correct place to provide a seal. a successful squeeze can be obtained with 500 to 1000 psi standing pressure above the injection pressure. • The volume of the void to be filled behind the cement or in the zone plus the volume to be left in casing but not less than 50 sacks. Low-pressure squeeze is recommended where possible. • The volume should not exceed the capacity of the running string. In many cases less than a barrel is sufficient. because it ensures that the properties of the slurry pumped in the well are as close as possible to those of the slurry designed in the laboratory. On most squeeze jobs. higher pumping time must be designed so that cement slurry remains in fluid stage till squeeze pressure is achieved. • The volume should not be so great as to form a column that cannot be reversed out. D. However. C. Squeeze Pressure Squeeze pressure is the pressure at the injection point. this indicates that the squeeze has held and the volume of fluid pumped compensated for tubular expansion. A safety factor of about 300 psi below formation fracturing pressure is reasonable for low pressure squeezing. A low-pressure squeeze requires only enough slurry to build a certain filter cake in each perforation tunnel. The following may be considered when determining the volume of cement to use. The appropriate volume of cement slurry depends upon the length of the interval to be cemented. The squeeze should then be repressured and the volume measured again. After a squeeze is obtained. but the requirements of its quality are quite high. iii) Compressive Strength High compressive strength although desirable but is not a primary concern for squeeze slurry design as a partially dehydrated cement cake of any normal cement slurry will develop sufficient compressive strength. The pressure should be hold for 10 to 15 minutes with no flow back. A high-pressure squeeze. requires a higher volume of slurry. If the volumes are equal. the pressure should be bled off and the volume of fluid measured. in which the formation is fractured. Lurry Preparation When preparing the slurry. 232 . The volume of slurry needed is generally inversely proportional to the injection pressure and directly proportional to the injection rate. the normal cement log (CBL/VDL) should be run to evaluate the effectiveness of the repair by comparing pre-squeeze and post squeeze logs. a fracture may extend across various zones. depending on the completion. Misconception in Squeeze Cementing • The cement slurry penetrates the pores of the rock Only the mix-water and dissolved substances penetrate the pores. The pressure applied at the face of the perforation is predetermined at the job design stage. control of the placement of the slurry is lost. Negative pressure test A negative test or differential pressure testing of the well bore may be obtained either by swabbing and lowering the fluid level or by displacing work over fluid with some lighter fluid. A squeeze job may appear successful when pressure is applied to the well bore but may fail to hold back the pressure from the zone into the casing. High pressure is needed to obtain a good squeeze If the formation fracturing pressure is exceeded. fluid. Both positive and negative test should be used. Mud filter cake is capable of withstanding high pressure differentials especially in the direction from the well bore to the formation and the high pressures may create a fracture before accepting cement filtrate. When the objective of the squeeze is to repair a primary cement job. while the solids accumulate at the formation face and form the filter cake. • • 233 . test the cement by applying required surface pressure for checking integrity of the perforation squeezed. Many squeeze failure may be attributed to subsequent clean up of a previously plugged perforation which did not accept the cement slurry during the squeeze job. Positive pressure test After the W. Negative pressure test should be conducted using pressure no greater than the expected maximum drawdown in the well when it is put into production. Once created.C time. and the slurry enters unwanted areas. Perforations will usually have some degree of mud fill up. G. It would require a permeability higher than 100 darcies for the cement grains to penetrate a sandstone matrix. The universally recognized technique for confirming whether the cement in place will hold the formation fluids under producing conditions consist of applying a negative differential pressure on the face of the plugged perforations. It may be the reservoir pressure or pressure equal to future working pressure in the well from fracturing or acidizing treatments but should not exceed the formation fracturing pressure.Cementing Operations F. Pressure is of no help to place the slurry in all the desired location. Plugged perforation It is rare to find all perforations open and producing.O. and open unwanted channels of communications between previously isolated zones. Evaluation of Squeeze Job Pressure testing is the most common means of evaluating the success of the operation. The only way for slurry to penetrate a formation is through fractures and large holes. c) Water /Gas Shut Off Squeeze 1. Maintain the down hole treating pressure below the formation fracture pressure when carrying out injectivity test or establishing circulation behind casing. follow all the standards as given for a normal cement plug job so as to spot the slurry against the perforated interval. For low pressure squeeze cementing. 3. acid job may be required to improve injectivity. 7. decide to carry out block squeeze using a cement retainer. 4. so that final squeeze pressure is achieved. above and below the cement retainer. Consult a CBL / VDL log prior to squeeze job.Drilling Operation Practices Manual H. 7. For elimination of water intrusion or reduction of gas oil ratio this squeeze cementing is carried out to seal all the perforations and then re-perforate a selected interval. squeeze cement slurry at the maximum permissible squeezing pressure and close the well under squeeze pressure for 4 hours. 4. 2. If injectivity is found to be poor. Carry out injectivity test in water. 2.e. In case of no injectivity. 234 . Calculate slurry volume keeping into consideration the annular volume and slurry required below cement retainer. Close BOP and apply pressure through drill string to squeeze cement. 2. 5. Squeeze Cementing Procedure a) Low Pressure Squeeze Cementing 1. 3. Squeezing to be done by hesitation method. All procedures that of low pressure squeeze cementing are to be followed for placement of cement slurry against the perforated interval. For block squeeze perforate 2 sets of perforation i. squeeze calculated volume of slurry into the perforations leaving a cement plug inside the casing. b) Block Squeeze Cementing 1. Displace cement up to the tip of cement retainer so as to keep the cement inside the string and engage tubing string to retainer. While displacement monitor free falling /U tubing of cement slurry by controlling through choke. Then pull out drill string sufficiently above the cement top. Pull out the string above the top of perforations. Decide the point of perforation and perforate against a permeable formation at least 6 to 8 Shots (Gun Perforation) per foot for achieving better intake. Use spacers ahead and behind cement slurry for a minimum length of 50 to 75m to avoid contamination. 5. 3. 6. Disengage the string from retainer and balance the plug. Squeeze calculated volume of slurry and close the well under pressure for 4 hrs. 4. 8. 6. In case of good injectivity. Establish circulation through cement retainer behind casing with water or cleaned fluid to ensure good clean up of the channels. If the poor bondage is continuous for a longer section. and squeeze to circulate out cement between the two perforations. reverse wash and squeeze cement in the upper perforation (optional) and keep the well under final squeeze pressure. Control lowering speed to prevent fracturing/loss circulation.1 Before Casing Running In 1. g) Staggered delivery schedule should be maintained. 4. f) For offshore use.) of the bottom (floor). d) When stored on pallets. 2. b) Storage of cement / chemicals should be such that oldest stock will be issued first. Use differential type of floating equipment in potential mud loss wells. tight pull. Control torque make up on casing threads. cement additive should be sent to installation in sealed containers and if sent on pallets.4. e) One type of cement additive should be kept together. Well is properly conditioned so that it is free from lost circulation.4. at least once in a month.2 During Casing Running In 1. 3. 235 . Tally the casing and total depth such that the casing can be landed within 1.2 Storage a) Cement chemicals should be kept separately from other chemicals to avoid any intermixing of bags. b) Use of iron hooks be avoided as it will puncture the bags and expose the material to moisture. 2. then it should be properly covered with water-proof tarpaulin. Check the prepared casing running and fill up schedule.5 m (5 ft. cement should be transferred from one silo to another. f) Air dryer must be used for moisture free air in handling cement when storing in silos. either on site or in bulk handling plants. 3.Cementing Operations 18. 18. caving and activity prior to pulling out for casing lowering.5.5 CHECKLIST FOR CEMENTATION JOB 18. cement and additives should be stored from initial stage of receipt of material and on a pallet not more than 20 bags of additives and 30 bags of cement should be placed. Particular care should be taken in offshore bulk cement handling operations to avoid transfer lines becoming wet.1 Handling a) Care must be taken during handling and transportation of cement/ additive bags so as not to allow introduction of moisture. 18. d) Suitable moisture scrubbing equipment should be added in the cooler air lines between compressor and tanks. c) It is advisable to store cement chemical bags on a platform with approximately 6 inches air space and tarpaulin should be spread on the base of stacking in order to form a moisture proof seal. Caliper log should be recorded to know the hole size at various depths and for the calculation of cement slurry volume to be pumped to achieve desired cement rise.5. 18.4 HANDLING AND STORAGE OF CEMENT AND ITS ADDITIVES 18. c) Possible contamination of bulk cement by other cement brands or bulk materials should be avoided in offshore operations. e) While storing cement for a long time in silo. 2. Ensure use of swirlers in washout sections. 4. Stopper pin is checked for its easy movement. ii) Ensure use of stop rings to place the centralizers. To check the following for centralizers : i) Total number of centralisers used. Bottom hollow plug is loaded first and then top solid plug. iii) Ensure the stop rings are not welded on casings. conventional or differential. To ensure float shoe and float collars used are of same type. 18. below and above the zone and the interval of the zone should be properly centralized. Circulation rate and pressure. 3. v) 60 Mts. 6. Condition hole with good surface conditioned mud at a maximum possible rate within the limitation of fracture gradient for 1. 18. 4. 8.4 Circulation Prior to Cementation 1.5. Cementation started only after the mud is free from any gas bubbles /pockets/ cuttings and at least 90% of the hole mud is being circulated. Type of floating equipment.5. If differential type is used.5 Cementing Head 1. Top and bottom plugs are placed in proper sequence viz. 2. 2. Casing reciprocation during circulation was done. 7.5. 3. 18.5 to 2 cycles (minimum). To check float collar and should be placed on one/two/three joints above casing shoe depending upon well depth. Cementing head should be checked for any leakage during cementing operation and proper function of plug release indicator. 6. iv) Ensure centralizer spacing done with computer programme. Mud parameters during final circulation: i) Specific gravity. 236 . ii) Pv iii) Gel vi) Viscosity v) water loss 5. Mud was conditioned to lowest possible Pv & Yp as the system permits without dropping solids. the tripping ball is checked.Drilling Operation Practices Manual 5. Ensure use of scratchers against permeable formation to remove filter cake 3. To see that float shoe is checked and placed on first joint of casing to guide casing into well and minimising derrick strain. Whether single or double plug container cementing head is used. vi) Total cement column is centralized.3 Mechnical Aids 1. 18. 3. The density of cement slurry should be at least 1 ppg (preferable 2-3 ppg) heavier than the drilling mud. Check whether sufficient volume of Spacer/Preflush to be displaced ahead of cement slurry in turbulent flow with minimum 10 minutes contact time or equal to 150-200 mts. drilling mud and cement slurry at room temperature and BHCT. Determine maximum permissible down hole cement slurry density to prevent fracturing or induced losses. The cementing units. 3. 2. Is there a safety factor for placement taken into consideration? b. Check compatibility of preflush/spacer.6 Cementing Equipment 1. Sufficient mixing water is available for the volume of cement to be mixed and enough liquid or solid additives are present at site. pressure to be encountered during cementing. and 48 hrs. is prepared. Silica Flour 35% is used with ‘G’ class cement at temp. Check and calibrate the pressure gauges. 2. 2.5. Free water is controlled as per well requirement. of annulus height. 5. Thickening time: a. Fluid loss control is adequate as per well requirement. Viscosity (Consistency) of cement slurry is low enough for the required displacement rate to achieve turbulence.10 Slurry Mixing and Pumping 1. Has it been laboratory tested with drill site technical water under simulated conditions? 4. 2.Cementing Operations 18.5. the correct percentage of additive is thoroughly mixed with the mixing water. when dry blending is recommended. 2. 6. 3. Mixing pump pressure should be tested for required discharge. 18. above 110°C. 4. Tanks of cementing units are thoroughly cleaned. at BHST. 18. 18. Correct weights (dosage) of powdered additives are mixed.5.9 Cement Slurry Design 1. The discharge of cementing unit is checked physically for their capacity in accordance with the liner size. Cementing head and all connection lines are pressure tested to 1. 7. Comprehensive strength of cement is determined after 24 hrs.5. Correct bottom hole circulating temperature and pressures should be used to design the slurry.5 times the max.8 Preflush / Spacer 1.5. bunkers/silos are thoroughly checked to avoid any break down during the operations. If wet mixing is done. 8. 237 . 5. 4.7 Blending of Cement Additives 1. A minimum of two transfers of cement and additives is a must. Conduct test of each blended cement sample. Drilling Operation Practices Manual 3. WOC time specified is sufficient. necessary directions to be conveyed to shift in-charge for monitoring of pressure during WOC. 18. 4.5. Number of strokes were calculated with 100%. Safety precaution has been taken prior to commencing of actual cementing operation. 6. 2. 8. Continuous monitoring of mud returns during displacement. 18. 238 . Cycle of reciprocation ——————m/mins. Calculate material balance for mix water. The SPM of pump was calculated to achieve desired flow regime during displacement. Last 200 strokes are pumped at slower speed to bump the plug. Data comparisons with calculated predictions and post analysis of the job. Casing left open during WOC if NRV holds after plug hitting. 8. 4.2 ppg. the speed of rotation—————RPM. Displacement volume is calculated as per casing string actually being run in the well. 7. 11. 4. 2. Quantity of cement used and slurry volume pumped is as per plan. 7. 3. 10.12 1. Operational Considerations Necessary instructions to be passed to the cementing officials before starting the job.13 Monitoring 1. 7. 15.gravity of cement slurry is continuously monitored during cementation job.5. Anchoring / rig up of cementing units has been properly made. 12. 18. Supply of water to the cementing unit has been checked. Continuous monitoring of mud returns during cement slurry pumping. 5. Batch mixer/ recirculating mixer/ precision slurry mixer is used for preparing homogenous slurry. Displacement is to be done by a) Rig pumps b) Cementing units. Extra bunker / silo loaded with cement is kept as standby Necessary arrangement for applying back pressure (if it is to be given) has been made. Pressure applied to be calculated in case of NRV failure. 3. 5. If well was kept under pressure. 2. 9.5. Casing was reciprocated/ rotated during cementing operation. 98% or 95% rig pump efficiency. 13.gravity of cement slurry is maintained as close as the lab design with variation of ± 0. 6. 8. 3. cement and cement additives and compare with volume of each slurry pumped. Prepare a summary of the completed job. The sp. If rotated. The discharge of the rig pump is checked physically as well as theoretically. Check function of NRVs. 14. The sp. Displace top plug out of cementing head with minimum down time. The cementing unit pumps are loaded prior to starting the cementation job.11 During Displacement 1. 6. 5. Mud balance or other density measuring device is calibrated with fresh water before actual cement job. 18.1 Onshore Well Abandonment Any oil gas or fresh water show should be isolated with cement. Surface plug: Place a surface cement plug of 100m inside the casing between a depth of 200 to 300m. a cement plug should be placed opposite all open perforations extending a minimum of 30m above and 30m below the perforated interval by the balance cement plug /squeeze method.2 Offshore Well Abandonment Procedures 18.Cementing Operations 18.1 Isolating Perforated Interval To abandon a zone.6. Surface Plug: A cement plug of at least 100m with the top of the plug 100 to 200m below the surface should be placed in the string. squeeze cementing operations should be accomplished using the Braden head method or a cement retainer. 18.6 WELL ABANDONMENT PROCEDURE Well abandoning procedures shall be different between onshore and offshore.1. abandonment cement plug should be set so as to extend a minimum of 50m above and 50 m below the stub.6. If the perforations are isolated from the hole below.6.6. Last object tested. IV. A permanent type bridge plug may be set within casing above the top of the cement plug up to the maximum possible depth run without scrapper trip.1.1 Open Hole Abandonment I. Tag and test the plug prior to placing subsequent plugs. Plugging of casing stub: If the casing is cut and recovered there by leaving a stub inside the next larger string. CBL/VDL was taken after 48 hrs.6. Tag the top of plug and test it to 500psi pressure. The bore hole including the space between the cement plugs shall be filled with drilling fluid of sufficient specific gravity and other properties so as to enable it to withstand any subsequent pressure which may develop in the bore hole. Interpretation of CBL/VDL in terms of Bond Index. 2. 18. If a caliper log is available. / 60 hrs. II. 5. Whether CBL/VDL is recorded under pressurized conditions. should be squeezed with cement and leave a cement plug of minimum 150 m above the zone of interest.2. 3. CBL/VDL taken before or after hermatical test. 18. correct volume of cement should be calculated and placed to cover the predetermined length of cement plug. Evaluation Quality of CBL/VDL: Excellent / Satisfactory / Poor.5. A hydrocarbon producing zones should be isolated by cement squeezing and plugging.2 Cased Hole Abandonment I. 4. Isolation plug: Where there is open hole below the casing. III. place a cement plug of 50m in open hole and 50m inside the casing shoe.14 1. 18. III. II. 239 . 1.6.Drilling Operation Practices Manual 18. Special attention is required when cementation is being carried out in night time. Utmost care should be taken to follow established safety regulations to avoid any untoward accident during cementation. Place a balanced plug of at least 100 Mts. 2. in open hole below the casing shoe and a minimum of 50mts.3/8″ casing 25m above 20″ shoe with 8 shots per foot. 240 . approximately cement plug should be placed inside the casing. Cut and retrieve 9. Cut and retrieve 30″ conductor 1 M below sea bed.5/8″ x 13.2.2.3/8″ annulus and 13.3 Surface Plug Requirement After abandoned plug and squeeze in the last object. 3.5/8″ casing cut point up to 10 to 15m below the sea bed. If loss circulation exists or is anticipated.2 Plugging of Casing Stubs Abandonment may be accomplished by one of the following methods if the casing is cut and recovered thereby leaving a stub inside the next larger string. starting from 25mtr. Check 20″ x 13. 4.6. Several liquid chemicals and cementing additives used in cementation can cause safety hazards which needs proper precautions while handling. A balanced cement plug should be set so as to extend approximately 30m above and 30m below the stub. and closing BOP as well as both the annulus squeeze slurry up to 1000psi. 4. 2.2. 1.4 Testing Plug Cement plug should be tested placing a minimum pipe weight of 15000 lbs. Simultaneous presence of a large crew of different disciplines makes coordination extremely essential. a permanent type bridge plug may be set within 30-45 mts. In uncased open hole of well.5/8″. High pressure and air pressure involved in cementing job execution. Fill both annulus with mud. a cement plug should be placed by displacement method so as to extend at least 30 to 50mts. The cementing of oil well is an important and highly critical operation which is accomplished in a relatively short period of time. execution and evaluation areas related to cementing services and to reduce occurrences of accidents. Simultaneous running of all equipment creating high level of noise pollution. 13. of cement plug on top. Perforate 9. This bridge plug should be tested prior to placing a subsequent cement plug of minimum 50m above it. on the cement plug or testing with a minimum pump pressure of 1000psi. 3. 18. above the casing shoe.6. A permanent bridge plug may be set at least 15m above the stub with a minimum of 50mts. All casing and protective structures should be removed to the satisfaction of the governing authority for the clearance of location.7 CEMENTING SAFETY GUIDELINES This cementing guideline is intended to standardize cementing procedures and safety aspects with a view to improve planning. 5. set a bridge plug in casing at maximum possible depth without scrapper run. below the 9.5/8″ annulus for any activity. 18. Place a balanced cement plug of 100 Mts. Following are some distinctive features /areas of safety concern associated with cementing operations. 18.3/8″ and 20″ casing from MLS.3/8″ x 9. 7. bracelets or neck chains should be avoided while on oil field duty and in repair/ maintenance garage. One should never attempt to perform work or drive a vehicle when he is impaired by alcohol or drugs. 6. auto electrical light indications etc. Inclined or vertical discharge lines should be tied off to prevent them from being dragged. Mobile cementing equipment positioning should be planned for quick removal from the work area in case of an emergency. no person should be allowed to stand underneath the charging pump till the cabin is locked and properly clamped in position. All vehicles should be placed with cabin facing away from the well and wooden wedge support should be placed behind wheels to minimise vibrations and movement of line while pumping operation. Do not suspend discharge lines from cementing head without safety chains. 11. check engine oil pressure. Oil level. While lifting the cab of cementing vehicle for chassis engine check up/ repair. safety glasses. Steering hydraulic oil level. rubber hoses etc. water temperature. After initial warm up of engine. A pre-job planning meeting should be held to ensure proper job layout and placement of cementing equipment following all safety procedures. Onshore cementing operator should be well conversant with traffic signals. One should use the prescribed personal protective safety kits like overhaul. one should be certain that the sides and backing area is clear. 3. 3. spark arrestor in engine’s exhaust pipes and a first-aid kit should be there in all cementing vehicles. 241 . 5.2 m apart from other cementing vehicles and at least 25 m distance from the well head. While reversing a cementing vehicle. Park all vehicles which are not required for the job to safe areas from the well head so as not to block the well site exits. avoid crossing of two discharge lines. Use sufficient number of chicksans to provide more flexibility to discharge lines for reducing vibrations during cementing operations. battery connections. Place cementing pump / bunkers / mobile silos at least 1. brake application. It is the responsibility of supervisor to ensure that all cementing service personnel and rig crew adhere to the procedures outlined below: 18.1 Pre-Departure Checks of Mobile Cementing Equipment 1. should be clamped and fastened to avoid any loss and third party injury while plying the cementing vehicle on road. 2. air pressure. 2. hardhats. swivels. are to be checked. Radiator water level. 9. road safety rules and regulations to minimise road accident. 4.5 . HSD level. 7.Cementing Operations The following guidelines are suggested as good operating practices. tyre pressure etc. Fire extinguisher. 5. valves. One should not reverse a vehicle at the facility or on the work location without a guide. Lines should not be run under cementing trucks. 8.7. 4. Ensure proper anchoring of high pressure lines to prevent accident in case of line failure. Wearing of rings. jet mixers. hard-toed shoes. Accessories like high pressure lines.2 Safety During on Land Cementation 1. 10. In hooking of high pressure lines from cementing units. 18. hand gloves etc. 5 times the maximum pressure expected in pumping operations. iii) The release valve is left open during repairs.7 BPM 2" (1. The pressure test will not exceed the safe working pressure of the equipment. bulk delivery. iv) The flow has stopped from the bleed-off line. Use only high pressure fittings and approved steel pipes which are in good condition and thoroughly inspected. The maximum permissible pressure and pumping rates through cementing lines are as follows: 2" (1. . Only steel lines should be used for releasing pressure and checking back flow from the wells. 19.8" ID)-10000 psi W/Pr. valves and plugs should be inspected. B. In electrical rigs. 17. Always clean an oil line connection before making up cementing lines. C. . Also duties of each person during cementing job including equipment operation. Electrical powered cementing skid unit should also be earthed properly. The cementing operational in-charge must supervise line hook up work and thoroughly inspect prior to testing lines 15. 242 . 18. mixing of chemical. testing all persons should be vacated from the vicinity of high pressure line. Cementing head must be secured to the links by safety chains. all cementing equipment should be earthed to the derrick structure to avoid any electrical shock accident. He should designate the sequence and volume in which fluid will be pumped and at what pumping rate.75" ID) -15000 psi W/Pr. No one will be permitted to step across. cementing in-charge must outline the job procedure. Before. v) The cementing supervisor has personally observed and determined that the system is free of any pressure. safety valves and high pressure lines of cementing units should be checked for operation at stipulated pressure to ensure operational safety and NDT should be carried out at an interval of 3 years. 20.7. 13. 16.Drilling Operation Practices Manual 12. Cementing heads. During a pre-job safety meeting. cementing head and maintenance management. cleaned and lubricated prior to hooking up. Cementing head.5 BPM 21. stand on or straddle or hammer on any pressurised line. Do not allow any one to take up line leakage repair operation until – i) Particular well site personnel are notified by the cementing supervisor with the repair plan ii) Pressure has been released from the line. Thread protectors must be used on all exposed male threads of circulating subs or cementing heads to avoid thread damage. A. Care should be taken to avoid damage to the threaded pin end and stopper of cementing head during handling and tightening to the casing. define pressure limits. operation of valves. manifolds. discuss safety measures and additional briefing on emergency procedure or any unsafe conditions to all personnel designated to participate in the job. High pressure lines should be tested with water at 1. He will also review communication system which plays an important role in monitoring cementing job execution. 14. the cementing unit and the lines should be washed thoroughly so as to remove any traces of acid 5. valves. 3. Primary routes of their entry in human body is by skin contact. additives for cement do not contain hazardous ingredients. cross-over etc. 243 . All valves in discharge lines shall be checked properly to see that they are open before orders are given to start pumping. time and rate. Material safety data sheet should be made available at work-center while handling cement additives. When transferring or venting material through an open ended hose. In floaters. In many offshore rigs. Flammable or combustible fluids are not to be placed in open displacement tanks on cementing equipment. After the job. The end of the hose should be secured tightly to a stationary object. if possible. 10. lines etc. 6. 18. 4. The cementing supervisor should ensure that all exhaust fans are working and that all the personnel present in the cementing room should wear air filters (masks). 24. Surface pumping pressure should not exceed the lowest pressure rating of the union and / or whatever connections used such as chicksans. 8. rubber gloves. dust or vapor masks. Pressure chart should be supplemented with pumping sequence volume. Fluid loss. Proper illumination with adequate flame proof lighting arrangements should be provided in the operational area especially at slurry mixing point and additive mixing system to ensure safe and effective job coordination during night time. mixing. A pressure-chart to record pumping pressure continuously should be made available for all cementing jobs. iii) Start slowly with little throttle to confirm that system is open. appropriate safety goggles. During slurry.3 Pumping Job 1. caps.Cementing Operations 22. Fumes of defoamer should not be inhaled while using. 13. the entire cementing room might be filled with unwanted fluids. respirators. 23. No pumping should take place while any personnel is working on. 7. make extra sure that all the valves. transferring and chemical mixing as well as proper mixing sequence. the cementing supervisor should ensure that the ventine system which facilitates in cleaning is in proper working condition. shoes and hearing protection should be worn. Entire sequence of operation should be controlled by cementing operational in-charge (one single supervisor) to avoid any confusion in following instructions during cementation. adequate precautions must be taken to avoid chemical / additive contact with skin. 11. eyes and clothing. the cementing unit is placed in relatively congested closed space. above or below floor level.7. chemical preparations. face shield. 2. In case it cannot be avoided. Cement bunker or mobile cement silo loaded with cement should be kept on jacks at drill site when parked. If not. a “T” shall be affixed to the end of the hose to prevent the hose from whipping around. are fitted correctly and also the least number of people should be present in the vicinity. When pumping into any system i) Be sure that you have an accurate pressure gauge. ii) Be alert for closed valves also. retarder and dispersant. Acid pumping with cementing units should be avoided. eye contact. 9. inhalation and ingestion. 12. Review method and hazard of handling. When handling cement additives. ear protection etc. All cement silos and other pressurized vessels should be emptied and pressure tested at the specific rating. 2.Drilling Operation Practices Manual 18. 244 . After pumping has been completed. swivels. The discharge of air.4 Rig Down 1. Personnel concerned with bulk handling plant operation must use all personal protective safety equipment including helmet. 4. 2. pressure must be released to zero. 3. Safety valves and pressure gauges attached to each vessel should be checked for proper functioning. Valves in pipe lines should also be checked for proper isolation. Before dismantling the line. all pumps. 6.5 Safety in Cement Bulk Handling Plant 1. valves. lines and hoses will be flushed before rigging down. 4.7. 3. All valves and caps on all piping of each unit shall be opened or removed to allow complete drainage of any fluid in the units piping. hoses with end connections from rig floor to ground should be done by winch line only. Transportation of chicksans. If any leakage is observed during pressure testing of silos.7. 5. Pressurised line should not be hammered. The air pressure in pneumatic bulk silo / mobile cement silo should be relieved before the vehicles are moved off to location. dust and cement from vent line should be directed away from the operational area and preferably in a water pit to avoid air pollution. dust mask. 18. Throwing down these equipment from derrick floor must be prohibited. high pressure lines. Piping choked with cement slurry may damage cementing equipment and lead to major breakdown. goggles. Tightening or loosening of connections under pressure is strictly prohibited. it should be rectified immediately on top priority. Proper functioning of air dryer should be ensured to get rid of moisture in the air line to silos with a view to prevent cement lump in the system and provide consistent dry cement supply for slurry mixing. clean and lubricate the drill string and bit. a prerequisite for its optimal performance. Transport drilled cuttings and cavings to the surface. To minimize settling of cuttings and weight material in suspension when circulation is temporarily stopped. To exert sufficient hydrostatic pressure to avoid formation fluid influx. Kelly. After preparation the fluid it is pumped in the hole by using mud pumps. The direct cost of drilling fluid in ONGC is 3% . drill string and finally leaves the drill 245 . A good drilling fluid therefore not only saves the number of days required to drill a well but also provides a stable and gauged borehole to aid in completion and production operations. Drilling fluid is required to be ready in the mud tanks before the well is spudded.1 FUNCTIONS The principal functions of the drilling fluid are: • • • • • • • • • Deliver hydraulic energy upon the formation beneath the bit.2 PREPARATION OF DRILLING FLUID FOR SPUDDING A WELL The drilling fluid is needed even before we start drilling a well. To ensure maximum information about the formations penetrated. which is circulated in the well bore to help in carrying out a cost effective and efficient drilling operation resulting in stable and gauged borehole to target depth with minimum possible damage to prospective reservoir formations. Clean the drilling face. To cool. This chapter is a humble attempt to bridge this gap of knowledge and experience. its impact on total cost of drilling operations is more important. 19.19 DRILLING FLUID Drilling fluid is an integral part of all drilling operations and hence plays a vital role in designing a cost effective drilling operation. Proper preparation and maintenance of a drilling fluid on site is. 19. The description that follows has been given keeping the man on drill site in view so that it can be utilized as useful ready reference manual of drilling preparation and maintenance on the drill site.5% (approx) of drilling cost as compared to world average of 8% to 10%. It enters the hole through standpipe. The method of preparation stepwise is detailed below. However. Stabilize the borehole. DEFINITION Drilling fluid is defined as any fluid.2. therefore.Drilling Fluid CHAPTER .1 Preparation of Tanks / Circulatory System of the Rig The drilling fluid is prepared in mud tanks. To create an impermeable barrier on the wall. Though volumes have been written about the composition and field performance of a variety of drilling fluids that have been used over the years. 19. a requirement for a simple stepwise description of activities for preparation and maintenance of conventional and popular water based drilling fluid systems is being felt for many years. In the top hole the fluid is required to flush the hole with pills of drilling fluids of high viscosity and gels to keep the hole clean of cuttings. possum belly etc and they provide very useful data to drilling console and mud logging • Ensure that all tanks and the entire circulatory system is clean. These sensors are installed on mud tanks. by washing it with drill water and removing all unwanted / undesirable matter. In application of clay based systems. have proper valves with no leakage. This drilling fluid or bentonite suspension in drill water is used to drill the top hole portion of the well. • Check the return flow line lands properly in the possum belly causing no mud wastage or spill over. flow line. non dispersed and clay free non damaging drilling fluid (NDDF) systems. 19. desander and desilter / mud cleaner are properly installed and are ready for operation during drilling. Gas show. On its return journey it travels up the annulus and comes out through the bell nipple to the flow line. • Check that active pit is properly connected to mud pumps. • Check that active pit is properly connected to incoming water line. tested for operation and has been found to be working all right. therefore. Desander and Desilter tanks back to active pits through mud flow channels. • Check that solids control equipment like shale shaker. (superchargers) Desander and Desilter have been properly placed and connected for their smooth operation. The following steps are required. • Check that bell nipple is properly lined up and aligned with the return flow line and there is no leakage through welded joints and where it is aligned with return flow line. • Check all valves for proper functioning and leakage. The fluid then flows through settling tanks.2 Preparation of Gel Mud The most commonly used drilling fluid being used is water based drilling fluid. which are the first in the battery of solids control equipment.2. which is used to prepare initial drilling fluid. It is.Drilling Operation Practices Manual string through bit nozzles. flow line delivers it to the possum belly of the shale shakers. • Check that motors of hoppers. • Check proper functioning of agitators in the tank. • Check that the sensors of measurement of pit volume. • Check that degasser has been placed properly and has been installed. bentonite clay is one of the most important purchased clay mineral. • Check that active pits and all other tanks are properly placed in order and inter connected properly. Its preparation requires the following steps: 246 . • Check that flow line is of sufficient diameter so that it can handle drilling fluid flowing under maximum discharge without getting wasted by spillage. which are clay based dispersed . and other tanks of the circulatory systems are properly lined up. necessary to check and prepare the tanks and the circulatory system of the rig before spudding a well. Also ensure that these motors have been properly protected / insulated from drilling fluid waste & other water flows etc to avoid their short circuiting and break down. Further it shall also be able to provide allowance for volume enhancement due to gas in flux. Fluid density etc. Flow rate. • Check that settling pits. • Check that there is proper gradient in the return flow line from bell nipple to possum belly to ensure that the flow of mud is smooth and free. have been properly installed and secured for their rugged field application. If it is between 9. lime. Run agitators continuously and mud guns intermittently.Drilling Fluid • • • • • • • • • • • Clean the mud tanks thoroughly by flushing them with drill water. Avoid contamination of drill water with salt or lime or cement etc. However. 19.0 and 10. the bentonite gel based drilling fluid is converted to treated and dispersed (or non dispersed) inhibitive drilling fluid using Speciality chemicals for control of rheological and filtration properties of drilling fluids. Minor treatment with thinner may be required to smoother the fluid flow.5% of the mud volume.5% bentonite powder weight/volume is sufficient for the purpose.5 (depending upon the actual requirement) stop the addition of caustic soda. Or a combination of Soda bi carb and Citric acid to treat out cement and control the viscosity hump. The well is drilled to a depth of 200 mts / 300 mts and the first casing called conductor casing is set to isolate top hole portion from the fluids below. Soda bi carb. Normally 7. cement etc. The fluid is treated with soda ash. • Maintain ratio of CL : CLS always as 1 : 2 when ever fresh additions of these chemicals are made.3 CHANGE OVER TO TREATED MUD SYSTEM IN TOP HOLE The bentonite gel prepared in the mud tanks is used for spudding the well. This shall ensure sufficient alkalinity of drill water when bentonite powder is mixed with it. • Convert the bentonite gel based drilling fluid to inhibitive drilling fluid system during mud circulation with or without drilling ahead. This drilling fluid is then continued for drilling ahead. The initial concentration of Chrome lignite be maintained as 0. Keep the gel undisturbed for hydration for 6-8 hours the agitators must be kept off during period of hydration. Add caustic soda through a small stream of water flowing through a caustic soda bag kept on the tank. For drilling ahead first the cement set inside the hole is drilled which causes the fluid to get a viscosity hump. Continue bentonite powder addition till the desired viscosity is achieved. Check the pH of the gel under preparation. • Add these chemicals through hopper at a uniform rate. Add Chrome lignite and chrome Lignosulphonate in the ratio of 1 : 2. The conversion of bentonite gel to inhibitive dispersed system involves following steps. Avoid contamination of bentonite powder and caustic soda with salt. 247 . otherwise it shall not hydrate to give desirable viscosity. Mix bentonite powder through hopper using the water of active pit. The rate of addition of dry bentonite powder is controlled to avoid choking of hopper nozzle. However best conversion is achieved if it is done only during circulation. without any specific treatment. Close / plug all water lines to avoid inadvertent entry of water in the gel. Take sufficient quantity of water in the mud tank. After the reasonable portion of top hole is drilled and problematic shales / clays are likely to be encountered. thick gels of 10% or more bentonite may also be prepared for keeping as reserve mud in other tanks.75% of the mud volume and that of chrome lingo Sulphonate as 1. • Initial viscosity and solid content of the mud needs to be brought down to the practically and operationally affordable limit. 5.22. if the specific gravity requirement is more than 1.2 Density (Mud Weight) Specific gravity weight of a drilling fluid is a very important parameter specified in GTO. Add EP lubricant specially while drilling directional wells of ‘S’ or ‘L’ profile to minimize torque and drag. The initial dose being 1% of the mud volume in circulation. SIGNIFICANCE& MEASUREMENT 19.20 / 1. initial dose being 1% to 2% of the mud volume.4 DRILLING FLUID PARAMETERS. However. Add drilling detergent if soft clays are being drilled to avoid bit & stabilizer balling.22 or lower. 19. Add Resinated lignite to this treated inhibitive system at deeper depths to provide better filtration control and formation stability.4. A standard API form should be provided for reporting the results of these tests. Add Sulphonated Asphalt before encountering troublesome shales. The value of specific gravity required may vary in different sections of the hole depending upon control function required either for pressured shale’s / shale’s with dipping beds or it is required to control high formation pressures of permeable formations charged with sub surface gases or liquids. The 248 . Add maintenance dosages of these mud additives at regular intervals to ensure that properties of drilling fluid remain within the limits set in GTO. Ensure that all the above listed additions are made slowly over one or two cycles of drilling fluid circulations to ensure that there is no formation of patches and drilling fluid remains homogenous. The frequency of these tests will vary in particular areas depending upon conditions. The above two additives are added slowly and directly to the drilling fluid system because these additives are liquids and easily miscible with drilling fluids. inhibitive drilling fluid to ensure that they fall within the limits detailed in Geo – Technical Order (GTO).5% w / v of the circulating mud volume. Add Carboxyl Methyl Cellulose (Low Viscosity Grade) through hopper slowly to ensure that the chemical gets mixed uniformly and properly in the drilling fluid. In case the salinity of the drilling fluid is high add Poly Anionic Cellulose (PAC) or Pre Gelatinized Starch (PGS) for fluid loss control.1 Testing of Drilling Fluid It is necessary to perform certain tests to determine if the mud (drilling fluid) is in proper condition to perform the functions. to ensure that pH of the drilling fluid in the tank always remains above 9. no weighing material is added and solids control equipment are run properly and efficiently to maintain the desired specific gravity.4. barites powder is added in drilling fluid in measured / calculated quantities to achieve the desired higher specific gravity. The additive shall help in control of filtration loss. In case the specific gravity of the drilling fluid is required to be maintained in the region of 1.20 / 1. Measure the properties of this treated dispersed.Drilling Operation Practices Manual • • • • • • • • • • • Simultaneously add caustic soda in active mud tank through thin stream of water by putting bags on the active mud tank. The dose of EP lubricant addition is 0.5% w / v of the circulating mud volume. The dose of Drilling Detergent additions is unto 0. 19. 1 Mud balance (Source : Manuel du technicien fluides de forage. Or 1. The stepwise monitoring of viscosity includes. put on and rotate the cap until firmly seated. per gallon Calibration The instrument should be calibrated frequently with fresh water. (0.3 lb/cub. = 8.01 gm/cub.3 lbs per cub.ft.1 lb/gal or 0. 19. • Read the density at the side of the rider towards the knife-edge.5 lb/cub. grams per cubic centimeter. Milkpark CKS). specific gravity.cm. pounds per cubic foot. The following instruments are used to measure the viscosity and /or gel strength of drilling fluids 249 .ft. • Report the density to the nearest 0.33 lb/gal or 62. Procedure • The instrument base should be set up approximately level. • Wash or wipe off the mud from the outside of the cup. The mud balance is generally used for mud weight measurement. If it shows wrong reading then the balancing screw should be adjusted.33 lbs.00 gm/cub. • Fill the clean.3 Viscosity and Gel Strength Viscosity is one the most crucial parameters of a drilling fluid as it determines the cuttings carrying capacity of the fluid. A level bubble is mounted on the beam. dry cup with mud to be tested. stepwise monitoring and control or specific gravity is done as Density may be expressed as pounds per gallon.) • To convert other units: • Specific gravity = 62.4.Drilling Fluid Lid Level bubble Graduated arm Rider Counterweight Cup Base Fig. at 70 °F. Attachments for extending the range of the balance may be used. Make sure some of the mud is expelled through the hole in the cap to free trapped air or gas. • Place the beam on the support and balance it by moving the rider along the graduated scale.ft. The weight of a mud cup attached to one end of the beam is balanced on the other end of the beam by a fixed counterweight and a rider free to move along a graduated scale. Fresh water should give a reading of 8.cm. The beam is horizontal when bubble is on centerline. Procedure 1. by following standard procedures.) mark. A graduated cup is used as a receiver.75 mm Fig.8 mm Inside diameter 4. Direct Indicating Viscometer Determination of marsh formal viscosity is not enough for proper monitoring and control of drilling fluid viscosity behavior. upright funnel until the liquid level reaches the bottom of the screen. the out flow time of one quart (946 cub. Direct Indicating Viscometer A. Marsh Funnel B. Marsh Funnel The marsh funnel is dimensioned so that. Cover the orifice with a finger and pour a freshly taken mud sampling through the screen into the clean. Report the result to the nearest second as Marsh Funnel viscosity. 3. Quickly remove the finger and measure the time required for the mud to fill the receiving vessel to the one (quart/946 cub. A six speed Fan make viscometer is used to measure different components of viscosity and this analysis is known as Rheological Analysis. 2 Marsh viscosity meter B.5 seconds. 250 .Drilling Operation Practices Manual A. cm.cm) of fresh water at a temperature of 70 + 5 °F is 26 + 0. ∅ 152mm 20 mesh sieve 1500 cm2 946 cm2 50. dry. 2. Read the deflection of the bob in degrees from a scale on the dial.3.4. 3 Direct . Place a sample of drilling fluid in a suitable container and immerse the rotor sleeve exactly to the scribed line.ø 300 in centipoises] 19. 4 Diagram of a direct .Drilling Fluid 19.Reading at 300 rpm. [P.4.V.4.3 Plastic Viscosity (PV) SPRING DIAL DIAL ROTOR BOB ROTOR Fig.1 Apparent Viscosity The apparent viscosity in centipoises equals the 600 rpm reading divided by 2 [A.3. Plastic viscosity = Reading at 600 rpm .2 Yield Point 300 rpm reading .V.P.4. = ø600.PV in lb/100 sq-ft. = ø 600/2 in centipoises] Friction force between two particles is known as Plastic viscosity. if 251 .4 Fan Viscometer Procedure i.indicating viscometer.plastic viscosity [Y.] 19.3. = ø 300 . . Measurement should be made with minimum delay (within five minutes.3. Fig.indicating viscometer 19. The step wise discussion of its monitoring and control is given below. wait for the dial reading to reach a steady value (the time required is dependent on the mud characteristics). • If increase in viscosity of the drilling fluid is due to increase in yield point and gelatin of the drilling fluid add deflocculated like chrome Lignosulphonate to keep the viscosity under control and desirable limits. Record the dial for 600 rpm. the 10 second gel strength is known as gel0 and the 10 minute gel strength is known as gel10.e. observed for making a zero error. These two values. Two values. add soda ash to remove contaminating calcium ions and viscosity returns to normal. iii. • If increase in viscosity of the drilling fluid is due to increase in plastic viscosity i. enhance the viscosity by adding high viscosity reserve mud bentonite gel preferably over one cycle time of the drilling fluid. • If there is an abrupt enhancement of viscosity due to gas influx. Then again slowly rotate at 3 rpm. Record the dial reading for 300 rpm. 252 . • Avoid using mud samples which have high foam entrapment.Drilling Operation Practices Manual possible) and at a temperature as near as practical to that of the mud at the place of sampling (not to differ more than 10 0F or 6 0C). 19. With the sleeve rotating at 600 rpm. Allow the mud to stand static for 10 minutes. use degasser to keep the viscosity rise in check. • If the viscosity has gone down below acceptable levels due to inadvertent addition of undesirable quantities of water etc. • If there is an abrupt enhancement of viscosity due to contaminants like calcium ions from cement drilling. as they shall give false and very high readings of viscosity. Shift to 300 rpm and wait for the dial reading to come to a steady value. • If there is an undesirable increase in viscosity. ii. 19.4. The place of sampling should be stated if required when reporting the values. Then slowly and steadily rotate at 3 rpm. can be determined as follows: Allow the mud to stand undisturbed for 10 seconds.4.5 Filtration (Water Loss) The filtration properties of a drilling fluid determine the amount and type of cake it shall form on the face of any permeable formation.4 Gel Strength Thixotropy can be estimated by observing the change in strength taking place in a gel as function of time. The monitoring and control of this property is an important as all other properties discussed before. Analyze the fluid rheology in the drill site lab using multi speed viscometer. amount of undesirable low gravity solids then add bentonite gel for dilution and run solids control equipment more efficiently. By this calculate gel0 and gel10 in lb/100 sq-ft from dial readings after 10 seconds and after 10 minutes respectively. Presses are equipped with pressure regulators and can be obtained with portable pressure cylinders.1 sq. of a mud is determined by means of a filter press.6 esq. particularly the screen is clean and dry.2mm) and a height of at least 2 1/2 inch (64 mm). 5 Filter Press for measuring filtrate (Source : Milpark CKS).). The tests consists of determining the rate at which the fluid is forced from a filter press containing the mud sample. API high temperature high pressure tests are conducted at 300 deg. the filter press consists of a cylindrical mud cell having an inside diameter of 3 inch (76. The filtration area is 7. The API filter loss is recorded as the number of cc’s lost in 30 minutes. either gas or liquid. Pressure can be applied with any non hazardous fluids medium. inch (45. temperature and pressure. Procedure i. filter paper can be placed in the bottom of the chamber just above a suitable support. The entire assembly is supported by a stand. Description Essentially.8 + 0. under specified conditions of time. Wheel Gasket Filter Paper Sieve Gasket Base Air inlet Lid Cell Measuring cylinder Fig. Arrangement is also such that a sheet of 9 cm. and is so fitted that a pressure medium can be conveniently admitted into. Be sure each part of the cell. Pour the sample of mud into the cell and complete the assembly. and bled from the top. 253 . Sealing is accomplished with gaskets.1 + 0. and measuring the thickness of the residual solids film deposited on the filter paper by the loss of fluid. This chamber is made of materials resistant to strongly alkaline solutions. Below the support is drain tube for discharging the filtrate into a graduated cylinder.Drilling Fluid Equipment The filtration or wall building property. F and at 500 psi and recorded as the number of cc lost in 30 minutes. and that the gaskets are not distorted or worn. due to its abrasive nature and hence it is always kept at the minimum possible levels by running desander and desiltters regularly specially when sand stone formations are being drilled.T.) as the API filtrate.T.O. The measuring tube is marked for the volume of mud to be added in order to read directly the percentage of sand in the bottom of the tube. This shall ensure a more or less stable API fluid loss value within the G. Disassemble the cell. 254 . add fluid loss control additive like CMC. Report at the start of the test mud temperature. which is graduated from 0 to 20 percent. the time of pressure application. • In case the value of API fluid loss increases beyond the acceptable limits as per G. It may be desirable to use a one-hour filtration tests for oil muds: the time interval shall be reported.1 cub. Shut off the flow through the pressure regulators and open the relief valve carefully. measure the volume of filtrate. well serviced and maintained for its repeated use. 19. close the relief value and adjust the regulators so that a pressure of 100 psi (7. Place a dry graduated cylinder under the drain tube to receive the filtrate. • Keep the API filter press clean. iv.4.T.Drilling Operation Practices Manual ii. • Ensure maintenance doses of fluid loss additive in the drilling fluid system commensurate with amount of fluid dilution with water or bentonite gel and thermal degradation etc of the additive at higher temperature. first making certain that all pressure has been relieved.O.) is applied in 30 seconds or less.5 mm) in diameter. • During API fluid loss measurement keep a watch on the pressure value in the gauge. • If it is muddy fluid report that whether there was a sudden fluid loss as soon as the pressure was applied (Which is called spurt loss). At the end of 30 minutes. a funnel to fit to screen and glass measuring tube.356 Kg/sq cm. and use extreme care to save the filter paper with a minimum of disturbance to the cake. Remove the cell from the frame. • Also record and report whether the filtrate is clear liquid or muddy fluid. In case of oil muds diesel may be used in place of water for washing the cake. or PAC or PGS depending upon the type of water base mud employed. Wash the filter cake on the paper with gentle stream of water and measure the thickness of the cake.O.6 Sand Content Sand is a type of undesirable low gravity solids that gets incorporated into the drilling fluid system from the sand stone formation being drilled. it should remain at 100 psi throughout. Report the volume of filtrate in cubic centimeters (to 0. • Check and ensure that its value falls within the desirable value of API fluid loss in G. • Measure & report the API fluid loss every six hours during normal drilling operations. The set consists of a 200 mesh sieve 2 1/2 inch (63. Equipment Sand content of mud is estimated by the use of a sand screen set. It is highly damaging to the equipments like mud pumps etc. range. Report the thickness of the filter cake to the nearest value. discard the mud.03 + 0. • Measure the reduction in fluid loss of drilling fluids at least one cycle after addition of Fluid loss control additive to get the true state of the API fluid loss value. iii. The test period (or duration of time) begins at. dry.cm. % Water by volume = ml of water x 10 ii. of oil x 0.4. Keep the interior of the mud chamber smooth by cleaning after every use. close the mouth of the tube and shake vigorously. of oil) x 10 iv. MT solid = 10 – (ml. Report the source of the mud sample. • Calculate the solids content % by volume as under i. ii. Gms mud = 10 x sp. Procedure will vary slightly. into the clean. the percentage by volume of oil. of mud vii. Wash the sand into the tube by playing of fine spray of water through the screen. Fill the glass measuring tube to the indicated mark with mud. Slowly invert the assembly and insert the tip of the funnel into the mouth of the glass tube.7 Liquids and Solids Equipment A retort is used to determine the quantity of liquids and solids in the drilling fluid. % Solids by volume = 100 – (ml. iii. ii. Read to volume of oil and water collected. From the graduations on the tube read the volume percent of the sands. Report the sand content of the mud in volume percent.Drilling Fluid Procedure i. wet screen. Heat the retort.e. Close the retort. water) ix. oil + ml. From the volumes of oil and water collected and the volume of the original mud samples.gr. iv. Repeat until the wash water passes through clear. 19. Insert fine steel wool above the sample and add a drop of defoaming agent. both suspended and dissolved are determined by difference. i. water and solids in the mud can be calculated. The hole in the lid of the containing vessel must not be blocked. The addition of a drop of wetting agent promotes separation of oil and water droplets. iii. of oil x 10 iii. Put a clean graduated cylinder under the condenser discharge. iv. of solids = (vii) / (viii) 255 . Allow the sand to settle. % Oil by volume (if any) = ml. Wash the sand retained on the screen to free it of any remaining mud. Coarse solids other than sand will be retained on the screen. Mud is placed in a steel container and heated until the liquid components have been vaporized. And more water to the tube. shake and again pour onto the screen. Average sp. Gms of solids = (vi) – (v + iv) viii. of water x 1 vi. Gm of water = ml. Procedure i.8 v. The vapors are passed through a condenser and collected in a graduated cylinder and the volume of liquid is measured. of water + ml. Place a measured volume of deaerated mud in the chamber. above shaker suction pit etc.gr. Add water to next mark. Gms of oil = ml. continuing 10 minutes after no more condensate is being collected in the graduated cylinder. depending upon the apparatus used. Solids. Discard the liquid passing through the screen. Pour the mixture. Fit the funnel upside down over the top of the screen. Compare the colour of the upper side of the paper (which has not been in contact with the mud solids) with the colour standard. The pH of a drilling fluid indicates its relative acidity or alkalinity. provided with the test strip and estimate the mud pH. A standard colour chart is supplied in a wide range type. temperature correction should be made in the electrometric method of measuring pH.4.4. or unless suitable correction factors are applied in using the ordinary electrodes.8.1 Paper Test Strips The test paper is impregnated with dyes of such nature that the colour is dependent upon the pH of the medium in which the paper is placed. Two methods for measuring the pH of drilling mud are used. In addition.xi The conventional water based drilling fluids are dependent on specialized additives for their performance. • The stepwise monitoring and control of pH value of mud is done as under.5 and 10.2 Glass Electrode pH Meter The glass electrodes pH meter consists of a glass electrode system. ii The electronic method. The electrode system is composed of: 256 . Alkaline solution range from just above 7 for slight alkalinity to 14 for highest alkalinity.2 unit.8 pH Measurement = = = (vii) / (vi) x 100 (ix – 2. unless a special glass electrode is used. this point is indicated by the number 7. Allow it to remain until the liquid has wetted the surface of the paper and the colour is stabilized. Low Gravity solids % by volume (2. 19.5 and hence it is necessary to maintain pH of the drilling fluid always within this range. • Keep a regular check on the pH of the drilling fluid used. The paper strip method may not be reliable if the salt concentration of the sample is high.3) xii.Drilling Operation Practices Manual x. 9. Procedure Place 1 inch strip of indicator paper on the surface of the mud. High Gravity Solids % by volume (4.8. Double-distilled water is neutral. If has been observed by laboratory experimentation as well as field experience that the CL / CLS based inhibitive dispersed system perform most efficiently when pH of the drilling fluid lies between 9.5) x 55.4. Solids % by weight xi. Acids range from just below 7 for slight acidity less than 1 for the strongest acidity.5 unit. that is. The electrometric method is subjected to error in solutions containing high concentration of sodium ions. using paper test strips. which permits estimation of pH to 0.6 100 . and in narrow range papers with which the pH can be estimated to 0. it is neither acid nor alkaline. These are: i.5) 19. an electronic amplifier and a meter calibrated in pH units. On the pH scale. using the glass electrode. A modified colorimetric method. The performance of these additives is in turn largely dependent on the pH value of the mud. Drilling Fluid i. Hydrogen peroxide . which consists of a thin walled bulb made of special glass within which is sealed a suitable electrolyte and electrode. ii. grade methylene blue per 1000 cub. The electrical potential generated in the glass electrode system by the hydrogen ions in the drilling mud is amplified and operates the calibrated meter. ii. iii. This helps in planning the treatment for control of rheology by control on solids type and behavior. Wash the tips of the electrodes. record the pH. The glass electrodes. which may require from 30 seconds to several minutes.9 Methylene Blue Test for Cation Exchange Capacity This test is carried out to know the amount of active clay content of the drilling fluid. saturated calomel cell. The reference electrode. i.5 cc of dilute sulfuric acid (about 5N) and boil gently for 10 minutes. Flask. Stir the mud about the electrodes by rotating the containers. While the solids are still suspended. remove one-drop liquid with a stirring rod and place it on filter paper. After the meter reading becomes constant. Procedure i.01 mille equivalent.3% solution. Add Methylene blue solution to the flask from a pipette or burette.cm. or 3 cub.cm. Measure the mud pH according to the directions supplied with the instrument.5 cub. Methylene blue solution (3. gently wipe dry and insert them the mud contained in a small glass vessel. The following materials are required to estimate the cation exchange capacity of drilling mud solids or clays. Make the necessary adjustment to put the amplifier into operation and standardize the matter with suitable buffer solution.74 gm U. When dye appears as a greenish-blue ring surrounding the dyed solids detected. iii. Procedure i. One 2. Add 15 cc of 3% hydrogen peroxide and 0. the end point has been reached. which indicates pH. Dilute to about 50 cc with water. Electrical connection with the mud is established through a saturated solution of potassium chloride contained in a tube surrounding the calomel cell. If the blue ring is again evident. graduated cylinder. continue as before until a drop taken after shaking 2 minutes shows a blue tint. syringe v. after each 0. 19.4. 5N) iv.S. .P. ii. according to directions supplied with the instrument. Dilute sulfuric acid (Approx. which is. filter paper etc.5 cc of methylene blue is titrated into the flask. Add 1 cc of mud to 10 cc of water in a 250 cc flask. shake the contents of the flask for about 30 seconds. iii. Shake the flask an additional two minutes and place another drop on the filter paper.) 1 cm = 0.cm. 257 ii. Hot plate. This gives an analysis of low gravity solids in the sense that what amount of these solids are active and how much is inert solids. If the ring does not appear. Burette. An estimation of lime content can be made based on alkalinity titration of the filtrate and of the whole mud. Mud as methylene blue capacity. Add standard acid drop by drop from the pipette while stirring until the colour of the solution changes from orange to pink. including that of the “P” end point. such as salt or anhydrite. ml. the end point is taken when the pH drops to 4. Record as “Mf” to total volume of acid in the cub. stirring continuously. The number of cub. cc of methylene blue Capacity = ———————————— cc of mud In addition to bentonite that absorb methylene blue. calculated as follows. Bentonite in mud (ppb ) = 5 x methylene blue capacity 19. the end point is then taken when the pH drops to 8.11 Alkalinity Determinations Because the pH scale is logarithmic. the test for alkalinity in high pH muds. 258 . analysis of the mud filtrate to determine the alkalinity yield more significant results than pH measurement. of 0. which in some areas contain dissolved salts. Procedure for The Alkalinity Test Measure one or more cubic centimeter of fresh filtrate into a 125 ml flask. The titration of the mud must be made rapidly to permit titration of calcium hydroxide and sodium hydroxide without interference from calcium carbonate.12 Lime Content Estimation Some knowledge of the amount of excess lime present is of considerable value as an aid in controlling the properties of a lime treated mud. i) Add 2 to 3 drops of phenolphthalein indicator solution. 19. Polyacrylates. of sample taken is called the “P” alkalinity of the filtrate (Pf). of 0.02 normal (N/50) sulfuric acid divided by the cub.cms.cms. which has been titrated to the “P” end point. 19.Drilling Operation Practices Manual iv. ii) Add 0.02 normal (N/50) sulfuric acid from an automatic burette or a pipette. iv) Report the methyl orange alkalinity of the filtrate. until the sample turns from pink to colour less. the alkalinity of a high pH mud can vary up to a considerable amount with no measurable change in pH. Treatment with hydrogen peroxide is intended to remove the effect of organic materials such as CMC.4.cms. add 2 to 3 drops of methyl orange indicator solution. In highly alkaline system. lignosulfonates and lignite.3 using the glass electrodes pH meter.10 Filtrate Analysis Such chemical tests are made on mud filtrates to determine the presence of contaminants. If the sample is so coloured that the change in colour is not evident. used to reach the methyl orange end point. The same tests can be applied to make up waters.3 as measured with the glass electrode pH meter. which affect mud treatment. if the sample is so coloured with chemicals that this end point is masked. as the total cub.4. or to assist in the control of mud properties.cms. If other absorptive material is not present in significant amounts.02 normal acid per cubic cm of filtrate required to reach methyl orange end point. iii) To the sample. For example. the bentonite content of the mud can be estimated as follows.4. 02 N acid for P of mud ix.cms. CC of silver nitrate x 1. cm. v. can contaminate the drilling fluid in the hole.02 acid divided by cub. 0. viii. until the colour changes from pink to the colour of the mud. The chloride content test procedure follows.Pf) = equivalent calcium hydroxide (lb/bbl) vii. ii. A pink colour develops. per liter (0. or on the sample from the alkalinity test to which a pinch of calcium carbonate has been added.13 Salinity Analysis / Salt Concentration [Chloride] Test The salt or chloride test is carry significant in areas where salt can contaminate the drilling fluid. from one cc to 10 cc. Add standard silver nitrate solution a drop at a time stirring continuously. Salt tests are among the means of detecting these flows when the chloride content exceeds 600 PPM. Determine the lime content as follows: vi. Measure a sample of any convenient volume.0282N) CC of silver nitrate x 10. If phosphates have been added in large quantities. stirring continuously.02 normal (N/50) sulfuric acid rapidly from a burette or pipette. A veterinary syringe is satisfactory for measuring even very thick mud.0 cc = 1 mg Cl. into the conical flask and dilute to about 50 cc with distilled water. The end point of the titration is reached when the sample first changes to orange or brick red. of 0. Pm = cc 0. of sample taken is called the “P” alkalinity of the mud (Pm). where. The number of cub. Determine the “P” alkalinity of the filtrate (Pf). or 47. Add a few drops of phenolphthalein indicator.7910 gm of AgNO3 per liter (0.000 or = —————————————————— CC of sample in the standard solution If 1. iii. Calculate the chloride (Cl) content as follows. or 4. i. Measure one cc of mud into a conical flask and dilute to about 50 cc with distilled water. ii. it may be necessary to alter the mud program. Salt water flows.000 Cl content in mg per liter or PPM = —————————————————— CC of sample in the standard solution If 1.282N) 259 . iv. The test is made on a portion of the original filtrate. While a pipette may be used for thinner muds.26 (Pm . iv.Drilling Fluid The procedure for estimating the lime content is: i.4. Add four or five drops of potassium chromate indicator to give the sample a bright yellow colour. Add 0.02 N acid for P of filtrate 19. add 10 to 15 drops of calcium acetate solution. Pf = cc 0.0 cc = 10 mg Cl. iii. Add 4 to 5 drops of phenolphthalein indicator solution. If a pink colour develops add sulphuric acid until it completely disappears.910 gm of AgNO3. 19. The details of various recommended trouble shooting procedure are given below based on the types of trouble encountered. • It serves as a crucial tool in diagnosis of drilling fluid maintenance problems and hence trouble shooting becomes easy. In such case an early action is recommended which involves diagnosis of the cause of trouble and then trouble shooting the same by most appropriate and cost effective remedial action. If there is leakage get it rectified immediately. If however the specific gravity of drilling fluid rises above the desired values the main cause is accumulation or build up low gravity solids which must be curtailed and thrown out to keep the specific gravity of the drilling fluid in check.Drilling Operation Practices Manual 19.O. Following step wise procedure is recommended for trouble shooting this event. silt. • It also helps in monitoring the optimum performance levels of solids control equipment. If torn replace them immediately. • Check the desander cones for their efficiency. • It helps in monitoring the general health of the drilling fluid and also the effect of treatment on various properties. 19. however. fast and focused. • It helps in diagnosis of potential drilling fluid problems and probable down hole complication before the problem gets aggravated. Preferably 60 or 80mesh at the bottom if the prevalent flow rates permit the same. • Make sure that integrity of screens is intact & they are not torn.6 TROUBLE SHOOTING OF DRILLING FLUID RELATED PROBLEMS The foregoing description of methods of drilling fluid maintenance and drilling fluid analysis at drill site with its significance are the key guiding principles of maintaining drilling fluid parameters within desirable limit or as per G.T. Besides control of pressured and highly dipping formations also some times require higher values of specific gravity of drilling fluid. • Check the shale shaker for efficiency and screen size ensure proper size screens are installed. • Check the type of formation being drilled. This analysis is essential and very important as it provides the following types of information. • Always ensure thorough and regular cleaning of shaker screens for its optimum efficiency. This can be done by checking the desirable pressure developed on the head of hydro cyclones. if it is sand.5 DRILLING FLUID ANALYSIS AT DRILL SITE AND ITS SIGNIFICANCE The on site drilling fluid analysis carried out in the well site drilling fluid laboratory provides very useful and valuable information regarding drilling fluids behavior and characteristics. which helps in optimizing the treatment of right type of additive in right amount.6.1 Rise in Specific Gravity • Every section of the hole is drilled with a certain desirable specific gravity range based on the pore pressure and fracture pressure values of the formation exposed in that section of the hole. or compact shales than the specific gravity build up is due to inefficient application of solids control equipment. • Do not bypass shale shakers to avoid mud wastage through them in case of high flow rates instead enhance their efficiency by their proper servicing and maintenance. and a suitable corrective action may be taken well in time if the performance falls below expected levels. the drilling fluid engineer on site encounters situations when these vital drilling fluid parameters go beyond windows of acceptable range. 260 . More often than not. • It also helps in monitoring the efficacy of different drilling fluid additives in terms of a quality and optimum dose. as the case may be. the nozzle size of the desander is correct. and servicing of the desilter also. fluid loss control additive.e. Measure the specific gravity of under flow (i. Once the specific gravity reaches desirable value minimize water or base fluid addition along with other chemicals and additives. The only option for their control and weight reduction is by dilution with base liquid i. barites over one or two cycles. Ensure that the nozzle size of desander is proper. If such is the case rectify the cause of dilution of drilling fluid immediately. Run both desander and desilter simultaneously to remove the undesirable low gravity solids upto silt range. then build up viscosity immediately by adding 261 . Maintenance. It may be due to a leaking tap or valve failure allowing transfer of water or low gravity fluid like reserve bentonite gel in the active system. to a level to maintain specific gravity at that desired level. • Check if there was an inadvertent mixing of water or low gravity fluid in the active circulatory system of drilling fluid. Rope discharge means inefficient operation of hydro cyclone (desander & desilter). If any time rope discharge is observed get the cone checked and corrected immediately.e. However. During round trip. This force is developed due to central portion created in an efficient vortex of a hydro cyclone. an immediate remedial action must be initiated before the control on the formation is lost and the well becomes active. homogenously till the fluid specific gravity reaches back again to the desired value. For every cubic meter of water being added. the rise in specific gravity is due to particles finer than silt range and a good number of them may fall in colloidal size range. • In case the fall in specific gravity is due to undesirably low viscosity of the drilling fluid. clean and service the cones of desander & desilters for their efficient operation in next cycle. This shall give an idea of efficient running of desander.e. • Measure the present specific gravity of the drilling fluid and add calculated amount of weighting material i. This shall certainly reduce the specific gravity of drilling fluid and it may come within the desirable range. which is unable to suspend barites in the system.6. if it occurs. If a distinct force is experienced by the finger tending to suck it in. Add desired quantities of caustic soda for maintaining pH. and other speciality additives composed in the prevalent mud so that their percentage dosages are maintained. Use Linear Motion shale shaker and Linear Motion Mud cleaner if available. Follow all above guidelines for proper operation. discharge of cones. Watch the discharge of cones. Once the specific gravity has come within desirable range maintain it at that level by prudent alternate operation of desander or desilter and efficient use of shale shaker. it must be a spray discharge. water or brine as the case may be hence dilute with water at an optimal rate commensurate with rate of drilling (ROP) to nullify the effect of clay solids getting mixed in the system. This can be checked by inserting finger through the nozzle while desander is running. 19.Drilling Fluid • • • • • • • • • • • • Ensure that cones are in good condition and they are not mud cut. In case the formation being drilled is soft clay.2 Fall in Specific Gravity The fall in specific gravity in case of weighted drilling fluids is a rare phenomenon. The following steps are recommended to trouble shoot this problem. for most efficient solids control results. The causes of high viscosity or unacceptable rise in viscosity may be due to one or more of the following reasons. high viscosity gel. • Compare these results with the results of the fluid just before the rise in viscosity occurred. specially if drilling fluid is subjected to this bottom hole temperature under static condition over prolonged periods eg: while tripping long hole sections shut down due to surface or subsurface complication etc • Accumulation of excessive amount of low gravity solids though un-reactive is due to inefficient operation of solids control equipment. • Add other ingredients of drilling fluid like Chrome Lignite. • Add deflocculant along with caustic soda in sufficient quantities to get the drilled clays all in deflocculated condition.Drilling Operation Practices Manual • • highly viscous bentonite suspension till it is able to suspend barites again for desired specific gravity.3 Rise in Viscosity This is one of the most common problem encountered during operations and needs proper diagnosis after careful analysis of the causes of the problem. • Calculate plastic viscosity. • In case there is a substantial increase in yield point and gel values and that too more in 10 minute gel values of drilling fluid and the formation being drilled are Montmorillonite rich mud making shales. Mehsana etc. dilute the drilling fluid sufficiently to keep the colloidal clay content within limits. • In case there is rise in viscosity associated with rise in yield point and gels but the formation being drilled are relatively inert to the drilling fluid partial thermal degradation of deflocculant along with reaction of clay with caustic soda at this temperature (> 1200C / 1500C or more) may be the cause of this unacceptable rise in viscosity. • Add sufficient quantity of fresh gels (of lower viscosity) and caustic soda to replenish the reacted components. • Maintain the viscosity of this level by frequent and regular treatments of above chemicals so long as the problematic shale section is under drilling fluids is cased. fluid loss control additive etc. • Add replenishment dosages of deflocculant after every 2-3 cycles so that they never fall below minimum required levels. to make up for the dilution rate so that their optimum percentage doses are always maintained in the drilling fluid. yield point and 10 second and 10 minute gel strength of the fluid. caustic soda. 262 . Maintain the desired specific gravity of mud by ensuring the minimum required viscosity to suspend the weight material. Add more barites to compensate for the added low specific gravity.6. • Drilling through bentonitic/ Montmorillonite mud making shales for example gumbo shales in western offshore. drilling detergent. 19. • Effect of high temperature in excess of 1200C. • Analyse the drilling fluid in well site laboratory using a multi speed viscometer. • Continue the above treatment till the viscosity comes back to desired level or range. Depending upon the cause of rise in viscosity following steps is recommended to trouble shoot this problem. • Contamination of drilling fluid with monovalent or divalent cation eg: Ca++ contamination while drilling through cement and Na+ / Ca++ / Mg++ contamination while salt-water flow are encountered through pressured formations. Add barytes to drilling fluid to raise its specific gravity so as to stop the salt water flow from the formation.The steps wise recommendations to trouble shoot this problem is as under: • Add viscosity building thick bentonite gel to the active circulating drilling fluid system in sufficient quantities preferably over a cycle. So as to maintain their dosages after dilution with formation water flows. If it is not rectified promptly it may lead to settling of cuttings and barytes in the well bore causing stuck up due to cuttings pack off and mud loss due to resultant pressure buildup below the packed up well bore. Maintain specific gravity of the mud above the formation pressures to keep any further influx of undesirable formation fluids.5 and 10. • Continue above addition till the viscosity rises again to the desired range. Add other chemicals also like fluid loss control agent. 19. Add resinated lignite for high temperature fluid loss control and Sulphonated Asphalt for better bore hole stabilization. The pH value should not be allowed to fall below 9. • Maintain addition of high viscosity bentonite gels while drilling through patches of inert formations like clean sand stones or other hard rock areas.5 while adding deflocculant. This shall unload the well of any settled cuttings etc and clear the borehole of such undesirable loading of solids. a prudent fluid loss control regime is necessary to avoid uncontrolled flow of drilling fluid’s liquid phase to formation pores and channels. In case the cement is being drilled or there is a significant salt water flow contaminating the fresh water drilling fluid the resultant rise in viscosity shall invariably be associated with high values of yield point and gels.4 Fall in Viscosity Although the unacceptable fall in viscosity is phenomenon of lesser occurrence. Maintain the above treatment plan to ensure viscosity in the desirable range.Drilling Fluid • • • • • • • • • • • • • Always keep pH in the range of 9.5. The drilling fluid in such cases is in flocculated state.6. 19. This combination not only provides a good gauge borehole better mud lubricity but also contributes significantly to the high temperature rheology stabilization of clay based inhibitive dispersed drilling fluids.5 If it is due to contamination by salt water flows etc isolate the patch of mud which is highly flocculated in a separate tank. it is equally important.5 Fluid Loss and Control In relatively deeper sections of the hole. Add deflocculant like CLS to bring the drilling fluid back to in its original deflocculated state. If it is cement drilling Add soda ash to treat out cement. This requirement 263 . • Prepare a viscous pill of bentonite with some lime and CMC and circulate it through the bottom of the hole.6.5 to 10. Shale stabilizer etc. The main cause of this is dilution of mud accidentally or gradually to a level that percentages of viscosifier go down below minimum required limits. Since cement provides for alkalinity maintain pH between 9. chrome lignite. Treat the mud with deflocculant and caustic soda to bring the viscosity back to the normal range. 19. the drilling fluid is flocculated. The loss of circulation may result due to highly permeable and unconsolidated formations at shallow depths and in such case the losses are partial and these are known as seepage losses. CLS and caustic soda till viscosity / Rheology parameter fall within desirable limits • Measure API fluid loss again of the deflocculated drilling fluid system. • Check the mud rheological parameter. • If the new fluid loss value does not fall within desirable range continue addition of fluid loss additive as per above procedure till the desired value of API fluid loss is achieved. these fractures may be natural or induced. otherwise small quantities of fluid loss agents may be required to bring the fluid loss to desirable levels. The losses here may be partial to total depending upon severity of fractures. • If the fluid loss values has gone above desirable limit check the type of cake deposited on the filter paper. This is a condition in which drilling fluid or mud is lost to subsurface formations either partially or completely. add fluid loss control additive over a cycle so as gets its homogenized mixing with the fluid. Also check if there was a spurt loss when the fluid loss was measured using API filter press. the desired percentage of Fluid loss additive is achieved in the system. • If the new fluid loss value falls within desirable range and there is no spurt loss and cake has become thin & tough in appearance. the risk of a differential stuck up gets greatly enhanced due to formation of a thick fluffy bentonite cake against the formation face of the well bore.7 SPECIAL OPERATIONS RELATED TO DRILLING FLUIDS The most important and vital of uncertainties related to drilling fluid are down hole complications encountered during drilling important and specially modified / treated drilling fluid or other fluids are employed to successfully tide over these problems or complications. • If the rise in fluid loss value of the drilling fluid is associated with concurrent rise in viscosity. It is likely to have desired values of fluid loss.1 Loss Circulation-Detection and Control Loss of circulation or mud loss is one of the most common down hole complication encountered during drilling. • Maintain this desired dosage by regular intermittent treatment of the fluid loss additive depending upon the rate of drilling and rate of dilution of drilling fluid with water and / or bentonitic gel. • Let the mud be conditioned for one more cycle after addition of fluid loss additive. Even if the losses are partial initially and suitable measures are not taken in time. 19. It is therefore. If fluid loss values of the drilling fluid goes above the desired limits and permeable formations are exposed. essential to keep the fluid loss value within desirable limits and for that following steps are recommended. • After that measure API fluid loss again and observe and record the drop in fluid loss value. yield point and gels. their amount increases and 264 . Normally both spurt loss and a fluffy cake shall be observed. Add sufficient quantity of deflocculant eg. The loss of circulation at deeper depths occurs in fractures. if the viscosity yield point and gels are within the desired limit. In case of partial losses there are partial returns and in case of complete losses there are no returns. spurt loss if any and quality of mud cake.Drilling Operation Practices Manual becomes even more important when permeable sand stone sections are drilled.7. The down hole complication visà-vis the role of drilling fluid engineer in handling them are given below. • If there is no loss now. • If the loss is contained under static condition after application of LCM pill. Mumbai High L-III Reservoir) due to presence of vugs and cavern. as that shall aggravate the problem. The following is recommended. • Always monitor return from the well at the shale shaker.Drilling Fluid they become total or near total to widening of already existing fractures. • If the well bore and formation pressures permit further reduce specific gravity by bentonitic gel dilution to the lowest permissible safe limits. • Circulate drilling fluid to cut down specific gravity of the fluid by dilution with bentonite gel. pull out the string upto the casing shoe and stop circulation of drilling fluid while LCM pill is being prepared in the pits. • Severe partial loss or total loss is easily detected as there is a fast reduction in active pit volume and almost no return on the shale shaker. • Always try to mix pill with a blend of bridging materials like. Sawdust. • Once the pill is placed against the zone of loss allow time for healing of the fracture by bridging materials of the pill. etc in the separate tank. • Resume drilling to next casing depth and case the section to avoid any recurrence of losses. • Restart circulation at reduced pump rates and circulate for one or two cycles to ensure that problem of loss circulation has bee tackled successfully. • Meanwhile. Baggage. The first and foremost step recommended for loss of circulation is its early detection. stop drilling ahead and circulate drilling fluid at lower pump rates. • Mix sufficient quantity of bridging material to make the pill. Total losses are also common in lime stone formations (eg. • Pump and place the pill slowly against the zone of loss. in competent formations it is usually just below the casing seat of the previous casing. flaky Mica flakes and granular walnut shell be use do to mix an effective LCM pill. • Mix a pill of bridging materials like Mica flakes. • Ensure that hole is always kept full of drilling fluid to avoid well bore instability and influx of fluids from the pressurized formations. if the loss is below the casing shoe. Rice husk. • The moment loss of circulation is observed. and running in of casing pipe etc must be handled very slowly and smoothly. An effective pill should have 30 lbs / bbl of the material mixed in drilling fluid being used. stop circulation and run in the string slowly to the bottom. 265 . • Analyze & identify the probable zone of loss. Monitor active pit volumes for calculating the rate of loss. • Always monitor volumes of active pit closely and regularly any volume additions and transfers must be in variably recorded. • Ensure there are no leakage or surfaces losses of the drilling fluid. Walnut shells. • After a loss ensure that all tripping operations. No pressures surges are allowed. restart circulation of the fluid at reduced pump strokes and observe for any loss of circulation under these conditions. • Any significant reduction in active pit volume along with reduction in return flow is an indicative of loss of circulation. • Use equal portions of different components for blending the bridging material mixture. Since the drill string has an unequal load distribution i.Detection and Control Stuck up is also one of the most common down hole problems leading to drilling complication.e. Diesel oil bentonite plugs (DOB plugs) or diesel oil bentonite cement plugs (DOBC plugs) If the above also fail pump appropriate quantity of cement slurry to seal the zone of loss. pull out of hole and run-in with open end drill pile to pump such material. Whatever may be the type of stuck up.Drilling Operation Practices Manual • • • • • • • • In case bridging materials fail to seal the zone of lost circulation try other materials like Diesel M plugs. it is necessary to act immediately to liquidate the problem because with time the stuck up may become more complicated and severe which sometimes may cause costly fishing sobs. The string forms a seat for itself there and hence this type of stuck up is called a ‘Key-Seat’. The third type of stuck up may occur due to packing off of annulus with cuttings. In this case a portion of the string goes inside the bore hole wall where the hole is crooked (popularly called a dog leg). Always ensure that bridging material particle size is smaller than bit nozzle otherwise it shall choke them. For such losses try thermosetting cross linked Gauss Gum based formulations (Thermo gel).2 Stuck Up. Such a condition is called differential sticking. Losses to buggy or cavernous lime stone formations are not controlled by any of the above formulations. This becomes more complicated and amplified in case of directional wells.7. the cuttings / cavings accumulate in the annulus and pack off the annular space between the string and the bore hole so tightly that it gets stuck. drill blind with water and set casing as soon as the loss zone is drilled through. The plugs then can be drilled through and they provide protection against losses to such severe loss zones. side tracks or even well abandonment. reasons. Never use bridging materials. heavier BHA and no hole is truly vertical (i. if string becomes motion less even for small periods of time and there is sufficient pressure differential i.00) a good portion of the string bears against the side of the well bore. In case losses are severe and total in huge caverns in lime stone formations down hole. Use drillable plugs for controlling such losses. The problem has become more frequent and important in the light of greater number of directional wells being drilled in quest for more oil and greater recovery.e. if available. 266 . Their gels are acid soluble and hence may also be applied for controlling losses in pay zones or reservoirs. These plugs are set inside the borehole including the loss zone.e. If the mud rheology is not proper or the rate of cleaning / cleaning efficiency of drilling fluid is much lower than required for whatever. 19. With such a situation prevalent down hole. Ä P = Pm – Pf (where Pm = pressure of the mud column and Pf = formation pressure). cement etc for controlling losses in reservoir or pay zones as they shall permanently damage the reservoir formation. there is a very high risk of drill string getting stuck up in the filter cake of the borehole wall. Besides the string may also get stuck due to a crooked hole. Differential sticking is only a type of stuck up. In case larger particle size bridging materials is to be used. Follow good drilling practices to avoid pressure surges in the well bore. lime and high viscosity grade polymers if any available on the site. Otherwise loss of circulation shall also start. with immediate well history. 267 . condition the drilling fluid to have sufficient viscosity to clean the hole efficiently. • Displace only small quantities of the pill at a time. type of formation. • If the string does not get released even after 6 hours or so of the above spotting exercise then repeat the whole process of spotting against the stuck zone and follow the steps just as described. BHA configuration. packing off annulus to the well mouth. • Mix a spotting fluid pill in HSD twice the above calculated annular volume to cover the BHA. • Once differential stuck up is established calculate the annular volume required to cover the entire BHA length. drilling fluid rheology and hole cleaning pattern vis-à-vis rate of drilling etc. • If hole is prone to caving due to dipping formations or pressured shales. • The differentially stuck string shall come out free if spotting fluid quality is good and proper procedure as outlined above is followed. follow fishing techniques to liquidate the problem. • If the stuck up is due to a key seat in which case the string can be moved downwards only but it can neither be rotated nor it can be moved upwards. raise specific gravity to minimize this caving so that combination of drilling fluid viscosity and flow rate can effectively clean the annulus. • Prepare a high viscosity pill in a separate tank by using thick bentonite gel. • Pump this viscous pill to sweep off the cuttings etc from the annulus. • Continue circulation at rates low enough to keep the annular pressure losses low but sufficient to raise the mass of cuttings etc. • After every displacement wait for 30-45 minutes for the pill to react with the cake etc. so that it completely soaks the BHA of the string. • Stop circulation or circulate at such a low rate that shall not cause pressure build up and induced fracture below the pack off zone. • Intermittently work on the pipe to see if it is free. • In case. presence of open hole dog legs. • Pimp this pill of spotting fluid slowly through a cementing unit and place it in the annulus against the BHA.Drilling Fluid Trouble Shooting • Identify and record the moment stuck up occurs on the well site. CMC. the BHA is against a highly permeable formation being drilled. • Once the hole annulus is unloaded. • A differentially stuck pipe shall come out free even in one proper application of spotting fluid. • If the stuck up is due to annular pack off associated with poor returns of fluid on the shaker screen. It is very easily to identify a stuck pipe. and the pipe has remained motion less against this formation for a considerable period of time there are no severe dog legs and mud viscosity is sufficient for effective hole cleaning then most probably it is a differential stuck up. which can neither be rotated nor be moved up and down. low viscosity or very high drilling rate or excessive caving which prevents proper cleaning of the annulus stop drilling ahead immediately. the spotting fluid shall not help in freeing the pipe. in which drill string is stuck. • Find out the type of stuck up for this correlate well parameters. A number of times the well gets collapsed and requires abandonment.3 Gas Influx-detection and Control Permeable formation charged with high-pressure hydrocarbons are the objectives of all oil well drilling operations. • Stop circulation for a while and check for self flow.e. The following steps are recommended for detection and control of Gas Influx during drilling operation. • Immediately start the degasser & stop drilling ahead.e. In the process of drilling for exploration of new areas a number of times permeable formation containing pressured fluids. it must be killed by pumping in heavy mud through the string and / or Annulus. • Check for flow rate in the return line with driller. Once a “Kick” is encountered and well shut in. • Check if the pump rate is same or increased. Increase in pump rate reconfirms the gas influx. Pf > Pm. which may be hydrocarbons. • Start raising the specific gravity of ingoing active pit. Such a situation is known as “Kick”. the influx increase exponentially with time due to tremendous reduction of weight of the mud column in the annulus and it may cause entire annulus to become empty of any liquid drilling fluid whatsoever. mainly gaseous. it is possible to avoid complications like Kick and Blowout. • A sudden rise in viscosity of the out coming drilling fluid with an enhanced flow rate at the shale shaker indicates gas influx. material and even the well.7.” If an early detection and control is not taken up. Blowouts need to be prevented because it causes loss of man. are encountered. The gas than flows in large volumes and with great speed to well mouth and well must be immediately shut in by closing suitable rams of blowout preventer. This is a major crisis situation and is known as “Blow out “. This situation is known as “Gas Influx. • Maintain a close watch on viscosity and specific gravity of mud while drilling through a permeable formation like sand stone etc. These gases expand tremendously in their journey upwards due to reduction in pressure and very large volumes mixed in drilling fluids manifest at the well mouth. If the downhole problem of Gas Influx is detected early and a suitable remedial action is properly planned and executed. If the pressures of these formations are not known at the planning stage the existing drilling fluid may not be able to contain or check these pressures and the formation pressure (Pf) at that point of time exceeds the pressure exerted by the column of drilling fluid (Pm) i. • Adjust circulation rate to avoid over flow of drilling fluid at the shales shaker to avoid wastage of drilling fluid. • Measure their parameters of viscosity and specific gravity of out coming mud more frequently say after every 15-20 minutes interval especially if gas influx is anticipated.Drilling Operation Practices Manual 19. an increase shall confirm gas influx. every 5 minutes. 268 . • Prepare kill mud of the desired specific gravity at the fastest possible pace in a separate mud tank. In such a case the formation gases. However if Kick is not controlled immediately the uncontrolled flow of gas or oil & gas both starts from the drilled hole. If this flow is a mix of hydrocarbons it soon catches fire and the entire rig is burnt down. flow into the well bore with great force and in large volumes. • Check the specific gravity of out coming mud immediately and frequently i. • Discuss and decide on killing method with the drilling Engineer and follow the exact guidelines on kill mud weight requirement in terms of specific gravity and volume of the kill mud required. • Shut in pipe rams of Blow out preventer and record shut in pressures developed in the annulus. Drilling Fluid • • • • Once the kill mud is ready coordinate with the Drilling Engineer of the rig for its proper pumping and placement in the well to kill the well. • Keep the hole flushing regime of the annulus commensurate with drilling and caving rate to avoid complications due to annular loading with these cuttings / cavings. resume mud circulation with a higher specific gravity which must be more than formation pressure (i. The indirect cost and losses due to cavings may be enormous. • Follow good drilling practices. avoid pressure surges due to very fast running in etc.8 PREPARATION OF WELL FOR CEMENTATION Though drilling fluid’s primary function is to aid in conduct of a cost effective and smooth drilling operation.4 Caving – Detection and Control Borehole instability is one of the most common down hole complications encountered in oil well drilling.5% or even more) in the drilling fluid composition to ionically balance the caving prone formations. CL. • Also ensure that sufficient quantities of all other components are present in the drilling fluid like CMC. • Simultaneously condition the drilling fluid with sufficient quantities of shale stabilizer like sulphonated asphalt over one cycle. The following steps are recommended for proper detection and control of cavings while drilling: • Monitor the cuttings return both in quantity and type while drilling through caving prone shale sections specially during bottoms up timings. CLS and Resinex (for higher temperature regimes) to ensure the best possible values of Rheology and filtration loss. 19. hole fill up. It is therefore very important to carefully analyze every incidence of caving independently to asses its real cause and then follow the best course of remedial action. raise the specific gravity of the drilling fluid to counter balance these pressure. The success of cementation job depends on getting a good cement bond both at the well bore and at the casing pipe faces which in turn depends on the quality of well bore. because it may result in poor cementation. Though caving always results in an over gauge hole with large washed out sections but the causes of cavings may vary depending upon the type of shales being drilled and drilling conditions and environment. Drilling fluid is therefore. needs adequate importance and attention for its detection and control. Once the high pressure gas influx is controlled by killing operation. Pm new > Pf) Continue circulation with new higher specific gravity drilling fluid for one or two cycles stop circulation intermittently and check for self flow. tectonically stressed and / or highly dipping formations. It therefore. • Stop drilling ahead. There should be no self flow or gas influx. • If the cavings are due to pressure. annular pack off resulting in stuck up and mud loss etc. costly cement repair jobs. its role gets extended as a compatible interface for other related operations like cementation of casing pipe to case the drilled well bore. Most of this instability manifests itself in the form of caving of the shale formations under different well bore conditions of pressure temperature and depth. • Use KCl or NaCl salt (3% .e. circulate with a viscous pill to clear the annulus of cavings.7. Resume normal drilling operation with new higher specific gravity mud. • Large chunks of formation in large quantities at the shale shaker are indicative of cavings. required primarily to provide a gauged and stable borehole so that it is possible to properly place the required amount of cement slurry in place besides the 269 . 19. • In the next one or two cycles treat the drilling fluid with suitable quantities of deflocculant (i. • Maintain at least 1 lbm / bbl [2. 19. perforation is carried out in the selected reservoir or pay zone intervals called objects. of the tank and flow channel. 19. Use non damaging brine (NaCl or CaCl2 brine) for carrying out perforation to minimize formation damage.e. • Always keep the drilling fluid in good usable condition in reserve tanks for any eventuality during production testing operation condition and treat the drilling fluid intermittently if production testing operations get spread over extended period of time. CL/CLS combination) and fluid loss control additive (i. PAC. The low gravity solids should be maintained at less than 5% by volume. There are several methods to test for PHPA concentration in the mud. the best way to ensure that there is enough PHPA in the system is to make sure that an excess is added with each unit volume of dilution.9 WELL PREPARATION FOR PRODUCTION TESTING Production testing is also another operation which has an interface with drilling operation. • Prepare brine as completion fluid in a separate clean tank and it should be free from all debris clays solids etc. The well after successful hermetical testing is taken up for production testing. then massive dilution will be required to retain control of the solids. • Once the desired drilling fluid parameters are achieved. or left over cuttings from the annulus by suitable mud Rheology / hydraulic combination in new annular geometry. If the solids control equipment is inadequate. PGS or Resinex as the case may be) to ensure that drilling fluid has low plastic viscosity and yield point values and it deposited a thin cake on the wall.e.9 Kg / m3] active PHPA in the mud system as determined by a materials balance calculation. • In the first cycle ensure that the casing open hole annulus gets cleared off all debris / cavings. • Use water as spacer between brine and drilling fluid to avoid contamination of brine with drilling fluid solids. displace brine with drilling fluid use water as spacer to separate the two fluids.Drilling Operation Practices Manual following is also recommended from drilling fluid’s angle while preparing a well for cementation job: • Circulate and condition the drilling fluid after the casing pipe has been lowered to the desired depth for 2 or 3 cycles. • Replace the drilling fluid of the hole by this brine and store it in a separate tank. CMC. • Ensure that at this Rheology it shall be possible to effectively remove all drilling fluid from the well bore and casing. • Ensure that the rig has adequate solids control equipment. At present. 270 .10 GUIDELINES FOR RUNNING PHPA MUD The following guidelines for running PHPA muds are based on careful analysis of field operating experience. The PHPA depletes from the system as it coats on the solids and the well bore. start cementation operation without intervening avoidable delays or wait otherwise the well bore condition may deteriorate. The following is recommended as regards managing drilling fluid during these operation: • In cased hole completions. • In case well is required to be killed. if the initial viscosity is too high when mixing new mud. especially in the presence of high calcium levels. To control HTHP at 3000F [1500C]. PHPA should be prehydrated in fresh water for maximum yield prior to adding to the active system. The PHPA polymer is sensitive to higher pH and the hydroxide ion acts as a dispersant to clays. It is recommended to use 8 to 12 lbm/bbl [23 to 35 Kg/m3] Bentonite depending on salinity. If viscosity increases are noted with increasing drill solids. 271 . Higher calcium ion levels will interfere with the PHPA polymer. If it is unavoidable to drill cement with a PHPA system. with an initial gel of 2 lbs/100 ft2 required to prevent settling of the weight material. To control the HTHP at 2500F [1200C]. it is not recommended to drill cement with them unless the system is to be replaced after drilling out. The calcium ion concentration in PHPA muds should be run at 400 mg/L maximum. They are particularly effective in seawater.000 mg/L has been quite effective in many areas. If cement contamination occurs. mud weight and the required HTHP fluid loss control. For this reason. In salt systems.4 Kg/m3] of poly-acrylate deflocculant (in the premix) to minimize viscosity fluctuations in the active system. mix only one-half of the required PHPA. Another effective technique to enhance the inhibitive quality of PHPA muds is to use Sulphonated asphalt in concentrations of 6 to 8 lbm/bbl [17 to 23 Kg/m3] to seal shale microfractures.25 to 0.5 range. For greater inhibition sodium chloride at a chloride ion concentration at 125. Pre-hydrated Bentonite provides base viscosity and is the foundation for fluid loss control. PHPA muds are sensitive to high pH.9 to 5. If insufficient yield value or initial gel strength is obtained from the initial mud formulation.25 lbm/bbl [0. take steps to reduce drill solids through increased use of solids control equipment or dilution and increase the PHPA concentration in the active system. Trying to treat out the calcium completely could lead to self induced carbonate contamination. The premix should be sheared at high shear rates prior to adding to the active system. use high temperature fluid loss control polymers (such as vinyl sulfonate / vinyl amide copolymer and modified lignin) to supplement the Bentonite. Xanthan gum can be used at 0.Drilling Fluid • • • • • • • • • • • • To maintain the mud system. PHPA muds can be run at any salinity from fresh water to salt saturation. Maintain the pH in the 8. mix whole new mud in a separate pit and add this premix to the system.5 lbm/bbl [0. When pre-hydrating Bentonite or when adding barite. it is recommended to add about 0. Yield points in the range of 10 to 20 lbs/100 ft2 are considered optimum. Product concentrations in the premix can be adjusted if necessary to increase product concentration in the active system. dump excessively contaminated mud and renew the PHPA concentration throughout the whole system. When mixing the mud. utilize PAC polymer at 1 to 2 lbm/bbl [2. Maintain adequate yield point in the mud. particularly HTHP fluid loss.7 Kg/ m3]. use a shearing device to eliminate viscosity hump problems. the system should be pretreated preferably with citric acid or sodium bicarbonate to knock out calcium ion and to control pH. Alternatively.7 to 1.7 Kg/m3] for temporary viscosity until the final mix is attained.5 to 9. The premix technique will minimize temporary viscosity fluctuations caused by the addition of new product and will also facilitate the materials balance calculation. The remainder of the polymer can be added to the system as soon as circulation commences. When drilling with PHPA muds. In such areas. use a shearing device while pre-hydrating the PHPA or switch to the next coarser screen size. trip out in the circulate / rotate mode through the new hole section. only filtrate will penetrate in the formation through them due to hydrostatic pressure. watch the weight indictor in order not to pull into a key seat. In order to have a good productive well. If shaker blinding occurs with the PHPA mud in such circumstances.11 NON –DAMAGING DRILLING FLUIDS (DRILL-IN FLUIDS) Formation damage occurring during the drilling of pay-zone sections of vertical as well as inclined wells with or without horizontal drain hole section can be a significant mechanism of ultimate reduced productivity in both oil and gas bearing formations. This phenomenon often occurs only in the new hole section drilled and clears up after the first trip through the section. It can occur when an external solid laden fluid or clean but reactive fluid enters the reservoir. While the external filter cake is formed during the drilling process. either pull through very slowly or break circulation to ream. These mechanisms would include: 272 . A summary of this work is provided in the literature. If the cuttings stick together when squeezed. In some cases a combination of petrographic and special core analysis techniques are used to evaluate the potential effectiveness of proposed drilling fluids and procedures for cost and risk analysis prior to the actual implementation. shales will still be susceptible to hydraulic and mechanical erosion. additional PHPA polymer may be required. forming the internal filter cake. investigate other causes. a spurt loss occurs that carries fluids and solid particles in to the face of the newly exposed formation. With a top drive equipped rig. Observe the cuttings size distribution at the shale shaker/ flow line. tight hole as a result of gauge hole or drill cuttings adhering to the well bore can be encountered. If tight hole across the same section persists on consecutive trips. When this situation is encountered. and monitor bottom hole assembly and tripping practices. We should see a bleed down of over pull. unconsolidated sands and mechanically weak. maintain the proper yield value. Formation Damage During Overbalanced and Under-balanced Drilling A number of authors have provided a detailed discussion of potential formation damage mechanisms which may occur during overbalanced and underbalanced drilling operations. When pulling through. These tests are conducted to obtain a better assessment of the risk associated with the use of proposed drilling fluids and to optimize the fluid and procedures which will be utilized in a given inclined / horizontal or vertical well operation to maximize ultimate productivity of oil or gas. use the lowest practical bit and annular hydraulics. Although PHPA muds stabilize well bores. 19. the internal filter cake and the filtrate must be expelled with the draw down pressure when the well is set to production. The drilling fluid can cause damage with the filtrate and with the internal filter cake that is formed in the face of the exposed sand. Bentonite pellets immersed in a mud sample or one of the analytical titration techniques may be used. the cuttings should have a glossy appearance and have a slippery feel. They should be coarse with a minimum amount of fine particles.Drilling Operation Practices Manual • • • • Observe the drill cuttings across the shale shaker. After the external and internal filter cake is formed. as a supplement to materials balance calculations. Furthermore. Ideally. • Formation damage effects associated with the use of extreme underbalance or overbalance pressure and associated fines migration or spontaneous inhibition phenomena. causing a dramatic change in the water-oil production characteristics of a given completion. 2. Biologically Induced Formation Damage The introduction of bacterial agents during drilling and completion is a major concern as problems associated with bacterial growth in porous media can be of a delayed yet significant onset of formation alterations. 273 . asphaltenes caused by a reduction in temperature or pressure associated with the drilling processes or incompatibility between introduced hydrocarbon fluids and in-situ hydrocarbon fluids results in a destabilization and precipitation of asphaltenes. Major problems associated with bacterially induced damage would include: • Secretion of high molecular weight polysacharide polymers to form plugging bio-films or bioslimes. weighting agents.e. • The formation of insoluble precipitates caused by the blending of incompatible drilling and completion filtrates with in-situ connet water. fluid loss agents. • Colonization of bacteria onto conductive metal surfaces resulting in pitting and corrosion. • The precipitation of waxes. Low salinity or pH shocks may also results in clay deflocculation phenomena which are a disruption of electrostatic forces which are holding clays in a flocculated state. 3.Drilling Fluid 1. • Wettability alterations associated with the use of invert drilling muds or other muds containing high concentrations of polar surfactants or materials. • The introduction of extraneous solids of either an artificial nature (i. • Direct mechanical glazing phenomena associated with bit formation interactions. • The generation of high viscosity stable water in oil emulsions in the near well bore region caused by the invasion of incompatible water-based filtrates resulting in the formation of an emulsion blocks. This phenomena is common in some kaolinite rich reservoirs. or artificial bridging agents) or naturally occurring drill solids generated by the milling action of the drill bit on the formation. Mechanically Induced Formation Damage • Physical migration of in-situ fines and mobile particulates. • Propagation of sulphate reducing bacteria (a classification of anaerobic bacteria which do not require oxygen to survive) and the resulting metabolization of sulphate present in naturally occurring formation or injection water to toxic hydrogen sulphide gas. • Relative permeability effects associated with the entrainment of extraneous aqueous or hydrocarbon phases within the porous medium. Chemically Induced Formation Damage • Clay induced formation damage associated with the reaction of low salinity or fresh invaded fluid filtrates with potentially reactive clays (swelling clays or mixed layer clays). solids. This particular damage mechanism is usually associated with gas drill operations where high bit rock temperature commonly occur. Near well bore wettability alterations can reduce the relative permeability of oil significantly and increase relative permeability to water. Filter cake is generally broken up or dissolved by the action of completion fluids. 500 –1000 ppm) were also done to further enhance performance. • Deposit a non–damaging filter cake that is easily and effectively removed by initial production. • Sp. • PH • Rheological properties (AV. However.Drilling Operation Practices Manual 4. Various reports on the systems have been issued from this institute and in-house expertise is also widely available. safety and environment standards. PV. or the removal process releases the fines into the formation. Many of the problems associated with drilling induced formation damage can be diagnosed through appropriate laboratory simulation techniques and appropriate procedures and fluids developed to mitigate or reduce many of the damages previously mentioned. bactericide (aldehyde or amine type. the best low permeability filter cakes are the most difficult to remove. Most drill-in fluids have various types and concentrations of additives to minimize fluid loss to the formation. • Bridge all exposed pore openings with a specially sized material. Based on above requirement of non – damaging drilling fluid. acid soak. Addition of potassium chloride. and after hot rolling at 90 to 120 deg. 19. HTHP) • Lubricating properties were evaluated. For intermediate section KCl – PHPA system with or without clouding glycol has already been proposed for drilling all development wells. Often. Stubborn Filter Cake A low permeability filter cake serves an important function in preventing the movement of fines out of the drilling fluid into the formation where the fines can plug pore spaces. specifically XC polymer and pregelatinised starch are biodegradable. Gel-0 and Gel-10) • Filtration Loss (API. Drillers switch from conventional fluids to drill-in fluids as the drill bit nears the pay zone. 274 . Gr. 2. • Retain desirable drilling fluid properties. C. These parameters were determined at ambient temp. the filter cake can be a problem when it is difficult to remove. but formulated to minimize formation damage and provide for well cleanup and flow back. These fluids were designed to act as a conventional drilling emulsion from a well control point of views. or during initial well flow. An optimally designed drill-in fluid should : • Conform to acceptable health. All components of NDDF system as mentioned above are environment friendly.12 DEVELOPMENT OF NON –DAMAGING DRILLING FLUIDS Drill-in fluids are among the latest solutions in horizontal and extended reach wells. All desirable drilling fluid characteristics eg. breakers. IDT has formulated the Non damaging drilling fluids with following additives : • Tap water • XC polymer • Pregelatinised starch • Polyanionic cellulose ( L V and R ) • Micronised Calcium Carbonate • Low Solid formate brine based RESULT AND DISCUSSION ON NDDF 1. the depth of this damage . 275 . Calcium Carbonate has been used as the main bridging agent as it is readily available in different grind sizes. by correctly sizing the bridging particles in drilling fluid. Recommended drilling fluids has controlled filteration loss and minimum cake thickness (less than 1 mm). 3. Impermeable nature of the filter cake shows that it can be easily and effectively removed during initial production. Although some solids invasion and formation damage are inherent to all drilling fluids it is possible to minimize both damage caused by solids invasion and. 4. The pore throat data supplied by the projects indicated that IDT formulated Micronised Calcium Carbonate widely being used in ONGC is suitable as bridging agent for NDDF.Drilling Fluid Other important properties analyzed were • Swelling characteristics • Cutting disintegration / cutting recovery studies are excellently well . as well as to provide a hydraulic conduit for the drilling fluid.1. Swelling formations 2. Swab oil & gas 5. drill. Sloughing formations 4. The drill-string is pulled out of the hole each time the bit or bottom hole assembly needs to be changed or the final casing depth is reached. 276 . Casing is then run into the hole to furnish permanent access to the well bore. Casing Drilling – Solutions to: 1. Casing drilling allows operators to simultaneously. the well is drilled with standard oilfield drill bits and other down hole tools are lowered via wire line through the casing and latched to the last joint (bottom most) of casing. Running logs & casing difficulties The Casing Drilling System (CDS) provides an alternative to the conventional drilling system by using ordinary casing as the drill-string which remains in the hole at all time. With casing drilling. and evaluate oil and gas wells.20 EMERGING TECHNOLOGIES 20. Washout 6. A short wire line retrievable bottom hole assembly (BHA) consisting of at least a bit and expandable under reamer are used for casing drilling apart from casing pipes. CASING DRILLING The conventional drilling process for oil and gas utilizes a drill-string made up of drill collars and drill pipe to apply mechanical energy (rotary power and axial load) to the bit.Drilling Operation Practices Manual CHAPTER . case. Hole in casing or keyseat 3. In this casing itself serves as the hydraulic conduit and means of transmitting mechanical energy to the bit Thus the well is cased as it is drilled which may reduce well costs or enable problematic hole sections to be drilled. drag and cleaning problems due to spiraling Reduces open hole exposure time and associated drilling problems Reduces borehole exposure to formation and completion damage Reduces or eliminates well control issues of DP tripping Simplifies well architecture 277 . coring assembly and a directional assembly. which is then stabbed into the top of the casing string in the rotary table. Upon reaching TD. the casing is lowered into the hole. an under reamer is used above a pilot bit to open the hole from the pilot-bit diameter to the final well bore diameter. such as a mud motor. It also provides a mechanism to facilitate insertion and retrieval from the casing string. with no need for an additional trip. Balancing the required procedures for these differing zones has historically been a challenge that can be overcome through casing drilling. A drillable drill bit and valve assembly is made up and run with the first joint of casing. The first technology employed by Tesco. This is particularly key for wells that encounter a weak zone prior to drilling into a higher-pressure zone. As the assembly drills ahead. because it can go deeper Drills straighter holes reducing torque. By concurrently casing while drilling. typically with a spear assembly that provides rotation to the casing. The second technology adopted by Weatherford. The top drive. lost circulation and well control incidents have been nearly eliminated thereby enhancing safety. Single joints of casing are picked up off the pipe rack and set in the mouse hole. uses a bottom hole assembly comprised of a positive displacement motor (PDM).Emerging Technologies The Casing Drilling system simultaneously drills and cases a well with normal oilfield casing as the drill string. The casing string is rotated during drilling. drill bit and hole opener / under reamer. The pilot bit is sized to pass through the casing. The casing transfers hydraulic and mechanical energy to a wire line-retrievable drilling assembly suspended in a profile nipple located near the bottom of the casing. Advantages & Features of Casing Drilling Reduces or eliminates drill pipe or wire line trip times Gets casing to design depth through problem formations Reduces potential requirement of contingency casing Reduces the initial surface casing size. A valve system is run and installed before cementing commences. the casing can be cemented immediately. The casing drilling system uses a top drive to rotate the casing. The assembly is latched to the first joint of casing. The casing string is rotated for all operations except slide drilling with a motor and bent housing assembly for oriented directional work. The drilling assembly below the DLA terminates in a pilot bit and under reamer but may include other conventional drill string components. with an extend feature. One of the most meaningful benefits of casing drilling is the reduction of down hole trouble time. Upon reaching total depth (TD). A drill lock (DLA) in the top of the drilling assembly provides mechanical (axial and torsional) coupling and hydraulic seals to the casing. In most casing drilling applications. utilizes only casing to transmit rotary torque and weight to the drill bit. and the under reamer opens the hole to the size that is normally drilled to run casing. 2. is connected to the top of the joint. The casing joint is drilled down by using the top drive in a conventional manner. the latch-on bottom hole assembly is recovered with a special retrieval tool. 1. The two basic technologies used for Casing Drilling are. The casing connections are normal buttress thread with Multi torque rings for additional torque resistance. either in a static or rotated mode. 5. Less drilling cost. Thus saves the cost transportation. completion fluids and cement slurry. All this eliminates the need for. Less drilling time and less completion time. The axial misalignment of the casing that causes coupling wear also provides a constant mechanical force on the rotating couplings to smear drilled cuttings and mud solids into the borehole wall. junk baskets. This plastering effect mechanically builds an impermeable filter cake. Eliminates use of Drill pipe. Also uses less bottom hole assembly to make a complete Well. 3. Lowers mud and cementing costs due to smaller well bore diameters. Reaming. Lighter weight substructure and derrick means reduced capital and logistic costs. The exact mechanism that provides this benefit is not proved yet. Formation Related Trouble Time Experienced With Conventional Rigs Is Reduced Faster completion of drilling reduces the exposure time. Reduced Stuck Pipe Worldwide experience shows that casing drilling drastically reduces stuck pipe ocurrances. A fishing operation was conducted using conventional tools (mills. Volume reduction for Drilling mud. Unintentional sidetracks while reaming back into the hole. These well control incidents are avoided with the Casing Drilling process because pipe tripping is eliminated. and Casing Drilling will not prevent these. Key seats and wearing holes in previously set casing. There is substantive evidence that the Casing Drilling system can be used to drill through weak depleted zones without the massive lost circulation that so frequently occurs when drilling with drill pipe and collars. Intangibile benefits of Casing Drilling technology. Heavy Weight Pipe. Faster fishing Through Casing by Wire Line It is possible to conduct conventional fishing operations to recover junk from the hole while Casing Drilling. But some kicks are taken while drilling ahead. In fact. 4. Taking a kick while tripping the drill string. Improved Well Control Many well control incidents occur while tripping pipe. 1.Drilling Operation Practices Manual Optimizes reservoir production Preserves well bore integrity. 2. Drilling safely through depleted zones – Smear / Plastering effect One would normally expect lost circulation to be a potential problem with Casing Drilling because the smaller annular clearance between the casing and borehole wall increases the frictional pressure losses. thus increasing the ECD. but it is believed to be the result of mechanically working drilled solids into the face of the borehole. what has been found is that Casing Drilling significantly reduces lost circulation. Uses less horsepower required which translates into lower maintenance and lower fuel costs Increases bit hydraulics due to smaller annular clearance. maintenance and inspection. Eliminates tripping and other pipe-handling which means reduced manpower requirements and related safety incidents. Elimination of tripping reduces disturbance of formation. Hole problems caused by swab and surge pressures. Less chances of mud loss even in weak formations due to smearing effect. 278 . Reduced Cost Due To Faster Well Completion Improved Operational Efficiency Due To Elimination Of The Pipe Tripping Better Deviation Control For soft formations no particular measure is needed for deviation control. This has a direct advantage in situations where the rig and a conventional drill string must be transported by helicopter. such as logging-whiledrilling (LWD) or coring equipment. 279 .” Thus. The casing may actually be used similar to wash over pipe to assist in the fishing operation. 1.Casing drilling with retrievable assemblies The technology uses unique rig and down hole equipment that functions as an integrated drilling system. thus making the process faster than having to trip the drill string each time a fishing run was made. The BHA is attached to the bottom of the casing by a landing assembly so that a wire line unit can be used to retrieve and replace it without needing to trip pipe out of the well. may also be run to perform almost any operation that can be conducted with a conventional drill string. Well deviation is controlled by using a stabilized drilling assembly protruding below the casing. The only difference was that these tools were run in and out of the hole with the wire line. it becomes possible to drill a hole while providing adequate clearance for the drill-casing and subsequent cementing.Emerging Technologies magnets. Spring-loaded dogs located on the landing assembly engage a no-go groove on the casing shoe. Standard oil field casing is used to transmit mechanical and hydraulic energy to the drill bit. A wire line retrievable drilling assembly that is latched into the casing eliminates the need for tripping with a conventional drill-string. Smaller Rigs Can Be Used To Drill Wells Wells can be drilled with the Casing Drilling system with smaller rigs than are required for conventional drilling. For directional applications. Other equipment. It also may allow smaller rigs that have been left on platforms for repairs and re completions to be used for sidetracks and infield drilling without needing to bring in a larger rig. Down hole system A wire line-retrievable BHA attached to the bottom of the casing drills a well bore of adequate size to allow the casing to be advanced freely.The BHA is run below a landing assembly to transport it into the well and mate up with a special casing shoe joint. However for harder formations drilling assembly can be changed as often as required to match the cutting structure as per the rock strength. The BHA consists of a pilot bit and under reamer that are sized to pass through the “drill-casing. the BHA includes a benthousing down hole motor and measurement-while-drilling (MWD) tool. Casing drilling system developed by Tesco Drilling Technology . etc). A torque anchor mates with recesses in the casing shoe to provide rotation and torque transfer from the casing to the BHA. preventing well swabbing and casing sticking when running or retrieving the BHA. Setting-And-Retrieving Tools A custom-designed. A drilling shoe positioned on the bottom of the casing is dressed with either (polycrystalline diamond compact) PDC cutters or tungsten carbide chips.Drilling Operation Practices Manual This positions the assembly so that positive-locking axial keys extend into a profile to transmit compressive (bit weight) and tensional drilling loads from the drilling assembly to the casing. The drilling shoe is also designed to facilitate retrieval of the BHA back into the casing as it is pulled. provides for a straightpull emergency release of the latch in case tight-hole conditions warrant a disconnect. An emergency shear sub. activated when line tension reaches 20. The design and testing of a pump-down pressure set tool is in progress and an electric retrieving concept is being considered for future application. A swivel prevents the rotational twist of the braided wire line so that the casing can be rotated during wire line operations.000 lb. ensuring a full gauge hole is obtained ahead of the casing. wire line setting-and-retrieving tool is used to install and remove the BHA. Seals located on the landing assembly incorporate upward and downward-facing pressure cups that prevent flow around the BHA landing assembly while drilling. A bypass system allows drilling fluid to be circulated. 280 . the larger OD of the casing allows adequate annular velocity to be achieved with lower flow rates than otherwise achieved with drill pipe. A top drive must be used to rotate the casing. as compared to conventional drill pipe and collars. The overall result is that the rig: Is not as heavy to move Requires less capital investment Uses less power Requires a smaller crew. A large wire line unit is needed that is sufficient to run and pull the BHA efficiently. and wire line unit. The initial commercial applications of the casing drilling technology are anticipated to be applied to relatively low-cost land wells. Pipe-handling tools for the casing are also required. and heavy derrick associated with a conventional rig. consequently.Emerging Technologies Casing Drilling Rig Casing drilling can be implemented either with a specially developed drilling rig or by a conventional rig modified for casing drilling. In addition. The hydraulic power and computer control allows the driller to function as the wire line operator from the driller’s control room. 281 . Special equipment is needed to handle casing in a drilling mode and to handle the wire line retrievable BHA. top drive. The casing is picked up as single joints from the pipe rack. and facilitate data acquisition. with frequent rig moves. drawworks. These wells are drilled rapidly. Tesco’s patented Casing Drilling process could lower drilling time up to 30% and reduce unscheduled drilling events. Thus. a split crown and split traveling blocks facilitate effective wire line access to the top of the casing through a wire line blowout preventor (BOP). The hydraulic drive on the drawworks is very similar to that shown for the wire line unit and acts as a brake that allows the drill string to be advanced with the drawworks under power rather than with the power unit disengaged by a clutch. All this equipment is operated under computer control through programmable logic controller interfaces that minimize the potential for human operator error. the mobilization costs can be high. these rigs include other features that allow the entire drilling process to be implemented more effectively. allowing for the construction of a lighter derrick and substructure. it does not need the monkey board. A fourth is under construction. Smaller mud pumps can also be used because larger casing IDs significantly reduce the friction loss. The shorter and smaller derrick reduces wind load considerations. optimize equipment performance. exclusively designed for use with the casing-drilling process. The rigs are designed with hydraulic power units for the mud pump. reducing equipment weight while taking advantage of the company’s top-drive design. The wire line unit is installed as an integral part of the rig and is located adjacent to the main drawworks. setback area. To date. reduce manpower requirements. Furthermore. the system has been used only with a rig designed specifically to prove the entire system and to maximize the efficiencies of casing drilling. In addition to the rig requirements mentioned above. A number of features of the casing-drilling process allow for a lighter rig design. Tesco has built three rigs that are hybrid casing-drilling and conventional-drilling rigs. Drilling Operation Practices Manual The Challenges associated with Casing Drilling are: i. hole cleaning is improved due to higher annular velocities achieved. Drill Bits & Bit Cutting Structure Drilling with casing and wireline retrieving the tools would require that the cutting structure be small enough to pass through the inside diameter of the casing. To achieve this buttress connections are used with multi-torque rings for additional torque capacity. v. Tubulars and Casing Connections Casing used with retrievable casing system is generally of same size. Cleaning the hole more efficiently and removing cuttings faster aids in ECD reduction. lag time and cement returns do not indicate borehole enlargement to be an issue. higher annular velocities and the resultant friction losses in the annulus increase the ECD. iii. As annular volume is reduced dramatically. the annular space along the entire well bore is virtually equal allowing the optimum hydraulics to be “dialed in” based on the fluid properties. Hole cleaning ECD management and hole cleaning are much easier. key seat control and centralization for cementing. Each application must be evaluated to determine the balance that must be struck between flow rates to clean the bit face and clear the annulus of cuttings. experience has shown that flow rates can be reduced substantially in “casing drilling system”. fatigue resistance and flow clearance. Both the issues have been tackled by installing hydro formed stabilizers and wear bands using crimping process. The down hole tools incorporate both an axial and torsional latching mechanism to anchor the tools to the bottom of the casing so drilling can proceed by rotation of the casing or the use of a mud motor. weight and grade that would normally be used in a well. 282 . While no caliper log data is available. Hole cleaning has not been an issue on previous wells. Both integral and coupled connections have been used successfully. cuttings concentration and flow rate. but have the ability to drill a larger hole size than the outside diameter of the casing. Changing The Bit Or Bottom Hole Assembly Casing Drilling eliminates tripping as we know it and retrieve the down hole tools by wireline through the casing. and ECD management. iv. However the casing connections may require a change because casing in this case has to provide adequate torsional strength. Solid centralizers may need to be added to the casing for directional performance. However. ii. This is accomplished by using an under reamer behind a smaller diameter pilot PDC bit. Fluid Requirement Compared to conventional drilling operations. wear management. This can lead to well bore erosion around drill collars and inefficient cutting transport around the smaller diameter drill pipe. With casing as the drill string. Centralization and stabilization No conventional cementing centralizers were found economical and rugged enough to withstand the drilling forces and that could be attached to the casing without altering its performance. This will reduce trip time and eliminate the unscheduled events associated with conventional tripping. Once all factors have been considered. An inherent benefit of drilling with casing is the “mono bore” annulus. even with reduced flow rates. the proper flow rate and nozzle configuration can be selected. Conventional drilling assemblies result in different annular velocities around each drill string component. Logging/Formation Evaluation Drilling with casing requires that the well be cased as drilling commences. The technique for running open hole logs that has been found most effective. Directional Control A limited amount of directional work with steerable motors for both deviation control and to a planned target has been done with the 7-in. the BHA is wire line retrieved. One solution to this problem can be to log while drilling (LWD). This prohibits logging the open hole with conventional wire-line logging tools once the hole section is complete unless the casing is pulled above the zone and logged below the bottom. and then ream back to the previous casing shoe. vii. The directional drilling performance was similar to the directional performance experienced when drilling at Lobo with drill pipe. Other formation evaluation tools such as core barrels and testing equipment can be adapted to the wire line retrieving tools and then used conventionally once latched into the casing. and Casing Drilling will not prevent these. magnets. thus making the process faster than having to trip the drill string each time a fishing run was made. is to drill to TD with the final casing. The only difference was that these tools were run in and out of the hole with the wire line. Well Control Many well control incidents occur while tripping pipe. the casing is reamed back to bottom and cemented. junk baskets. To overcome this problem. xi. Cementing and Drilling Out the Shoe In casing drilling. the displacement plug must land and latch into the casing and serve as a float. cased hole logs can be run inside the casing or open hole logs can be run out the bottom of the casing to log intervals of interest. The plug and cement in the shoe joint must then be drilled out with an under reamer and pilot bit assembly connected to the next smaller size of casing. The casing may actually be used similar to wash over pipe to assist in the fishing operation. A fishing operation was conducted using conventional tools (mills.9 x. This eliminates the need to trip all the way out of the hole and provides a way to continuously circulate the well in case it begins to flow. Alternatively depending on what type of logs or what interval must be logged. But some kicks are taken while drilling ahead. The logs are then run through the casing just as they would be if the well were drilled conventionally. These well control incidents are avoided with the Casing Drilling process because pipe tripping is eliminated. casing during the phase one and two trials. Coring Coring operations with casing can be conducted in two different ways: a) The first method involves running conventional core barrel (both inner and outer barrel) and core bit below the DLA and using an under reamer above the core barrel to open the hole to the full dia. 283 . Core sample can be taken at any time and drilling can resume with little delay after coring. etc). ix. Fishing It is possible to conduct conventional fishing operations to recover junk from the hole while Casing Drilling. Once logging is completed. viii. once the casing is drilled to the casing setting depth. release the bit.Emerging Technologies vi. The casing will not have a float collar to land the cement plug. The directional BHAs could be run and retrieved with the wire line without any difficulty. and the ability to cement almost immediately upon reaching TD. with additional lengths of casing added as the well is being drilled. reduces risk.Drilling Operation Practices Manual b) The second method involves using the bottom joint of casing as the outer barrel and only tripping the inner barrel attached to DLA. Both the DrillShoe tool and the float collar normally would be made-up to a casing joint. Once all the required depth has been reached. Rotary drilling with casing required a method of connecting the top drive to the casing. drill bit and hole opener. In addition. Modern drilling with casing is not limited to only the final string of the well. the latchon bottom hole assembly is recovered with a special retrieval tool. Upon reaching total depth (TD). The next drilling assembly–whether conventional or DwC–is run in to drill out the cement. operating costs. Upon reaching TD. apply rotational torque and containpressure. flat time and operational time. the casing can be cemented immediately. improves well bore quality. To maintain acceptable 284 . Many areas of the world have used the practice to drill-in the final tubing string and cement in place with the drill bit still attached. as well as improved and simplified well construction operations. Extending the depth range required the development of both a fit-for-purpose internal and external grip casing drive system. since a float collar is present in the string throughout the drilling operation. cementing can begin immediately. Casing is rotated using a top drive. This method allows larger core to be taken and also drilling ahead by replacing inner barrel with a drill plug. There are two basic technologies used for Drilling with Casing. 2. improves drilling efficiency by eliminating some flat spots in the drilling curve. DwC Tools Casing Drive Systems The requirements for turning the casing are identical to those for conventional drilling. to drive the casing string. typically with a spear assembly that provides rotation to the casing. Drilling with casing (DwC) Weatherford System Drilling with Casing (DwC) technology utilizes the casing string as a drill string so that casing is landed on bottom during the drilling process rather than later in a separate installation process. The second technology utilizes only casing to transmit rotary torque and weight to the drill bit. This assembly will drill through the center of the previous DwC system without damage. with no need for an additional trip. The hoisting equipment must hold the weight. In fact most modern DwC jobs involve drilling the surface hole and intermediate hole sections. either in a static or rotated mode. The DwC system uses casing as the drill string in a similar manner to a drill bit on drill pipe. The assembly is latched to the first joint of casing. As the assembly drills ahead. The casing string is rotated during drilling. and carry on drilling as required. A valve system is run and installed before cementing commences. drilling stops and the assembly is cemented in place. DwC eliminates hole and casing running problems. Benefits include reduced rig time. A drillable drill bit and valve assembly is made up and run with the first joint of casing. the casing is lowered into the hole. When TD is reached and circulating bottoms-up. The first technology employs a bottom hole assembly comprised of a positive displacement motor (PDM). DrillShoe III. Sizes range from 5 to 20 inches. displacing the PDC cutting blades into the annulus. Once the casing string has been drilled to TD. DrillShoe I is designed for drilling very soft to soft unconsolidated rock. Cementing ports on the inner piston are exposed once the blades are completely displaced. and is designed to replace a conventional hole opener. It is designed for more competent formations and longer drilling intervals. The cutting structure’s design in the first two generations is a balance between the need to drill ahead and the requirement for the cutting structure to be subsequently drilled out. and interchangeable drillable nozzles that optimize performance. the ability to run on most standard casing and liner drilling systems. Weatherford has introduced a range of proprietary drillable bits for casing drilling applications that are made up directly onto casing. Shown in both closed (left) and expanded (right) positions. Drilling With Casing Bits The leading component in this stepchange technology is the Weatherford DrillShoe drillable casing bits.Emerging Technologies load forces for extended lengths of casing. Pumping energizes the packer element. this expandable bit is one of the newest advances in drilling with casing technology. the slip area of the internal grapples was significantly increased to spread the forces over a larger area. meanwhile. The thirdgeneration DrillShoe combines the benefits of a PDC cutting structure with the ability to displace its nondrillable cutting structure into the annulus. typically surface hole. A stop ring is positioned near the top of the spear to ensure the grapples are engaged in the proper location inside the casing. It incorporates many of the features of a standard PDC bit while drilling a 40 percent largaer hole. The tool is designed for quickly connecting in the casing to minimize connection time. Features include PDC cutters along with a proprietary diamond cutting structure. features a PDC cutting structure mounted on displaceable blades. A quarter turn to the left. DrillShoe II is for consolidated formations. in sizes ranging from 95/8 to 20 inches. leaving only drillable materials in the path of the following drill string. 285 . Benefits include rapid and damagefree drill out. resulting in a pressure increase that forces the inner piston downward. DrillShoe I and DrillShoe II have now led to the innovation of a third generation. These casing bits have been designed to emulate the standard features of conventional drill bits in a drillable package. releases the tool. and suitability for applications with standard buttress or premium casing connections. DrillShoe III. A mud saver valve can be incorporated to minimize spillage on connections. a ball is dropped that seals off the flow path. A simple quarter turn to the right engages the spear to hold the casing string and apply rotational torque. without axial load. Drilling Operation Practices Manual Weatherford customers have set more than 400 casing strings with the DwC system in sizes from 51/2 to 20 inches. Drilling with Liners (DwL) Liner drilling systems have been used for penetrating high pressured formations into deeper depleted zones. Liner drilling extends casing points in environments where pressure gradients are increasing with depth. The practice should be considered an alternative for reducing trouble time and reaching objectives in critical, narrow-margin wells. The concept relies on managing annular fluid pressure around the large-diameter liner to create favorable equivalent circulating density (ECD) profiles that allow penetrating farther into narrow pore pressure-fracture gradient windows. However, as liner drilling proceeds beyond normal limits, risks must be managed for making drilling connections, liner cementing and maintaining well control. The approach is consistent with ongoing industry focus on managed-pressure drilling using conventional drill-strings. In this concept, the hole is drilled - with a conventional drillstring - to traditional well control limits, e.g., a kick tolerance limit. The drill-in liner is then run, mud weight is reduced and drilling continues. In some circumstances, this concept may allow significant extra interval to be drilled beyond conventional limits, thus increasing the chances of reaching deeper objectives. Other benefits include reduced stuck pipe consequences and added capability to kill underground blowouts. The liner drilling process results in installation of full-strength tubulars in the well. Liner drilling may also be used prior to reaching conventional casing points to mitigate cyclic fluid losses and fluid gains (ballooning effects) that often plague narrow-margin drilling. Weatherford is the world leader in rotating liner systems, holding records for the longest rotating liner installed (18,233’,) and the heaviest liner run (782,775 lbs.) Applications for Drilling with Liners include: Depleted formations Unstable formations Loss zones Pressure zones Salt dome drilling Moving/swelling formations Excessive hole cavings Future Developments/Applications Deep Water Applications Under Balance Drilling Use Of CWD With Air Drilling Use Of Single String Of Casing From Surface To TD The Ultimate Drilling Solution May Be A Combination Of Casing Drilling With Expandable Tubulars Deep Water Drilling A tight operating window between fracture and formation pressure characterizes most deepwater drilling. The consequence is that as many as seven, eight, or more, casings may be needed to reach deep drilling objectives. Industry has become adept at managing the balance of mud weight, equivalent circulating density (ECD), trip margins, lost circulation material treatments and other operational aspects to try to push the casing points. However, this balance is difficult, and problems occur frequently. 286 Emerging Technologies Deep Water wells are inherently expensive. However, when problems occur, they can be extensive, and cost overruns commonly approach 50% and more. With the introduction of Casing Drilling lost circulation, stuck pipe and well control issues have all but disappeared on wells. This was an unexpected benefit, but clearly one that has tremendous potential in the deepwater environment. Directional Casing Drilling Vertical wells can sometimes be drilled with casing using a simple system consisting primarily of a special bit attached to the casing that can be drilled out to run subsequent casing strings. But when there is a need to drill with a motor without rotating the casing or the section cannot confidently be drilled with a single bit, then a retrievable drilling assembly that can be recovered and re-run is required. Even some sections that can be drilled with a drill-out bit may be more cost effectively drilled with a retrievable system. A retrievable Casing Drilling system is required for directional wells because of the need to recover the expensive directional drilling and guidance tools, the need to have the capability to replace failed equipment before reaching casing point, and the need for quick and cost effective access to the formations below the casing shoe. Casing Drilling of directional wells provides a practical alternative to drilling the wells conventionally and then running the casing as a separate process. It assures that the casing can be run to TD and it captures many of the savings that have been proven while Casing Drilling vertical wells. For larger sizes of casing, no loss of efficiency occurs while drilling with the steerable tools below the casing. This allows the operator to take full advantage of the faster tripping and trouble avoidance benefits provided by Casing Drilling. Tesco typically pulls the BHA with a wireline unit, but this will require a higher capacity wireline unit when a directional assembly is used in the larger casing sizes. Directional drilling with smaller size casing may sacrifice some drilling efficiency due to the requirement to use smaller motors and is most advantageously applied in situations where the Casing Drilling system provides an enabling technology rather than an improvement in efficiency. Underbalanced and Air Casing Drilling Casing Drilling also seems to have application for drilling in under balanced situations. One of the next goals for the Lobo development is to try to eliminate a string of casing by drilling from surface casing to TD with one string of pipe instead of two. This may be accomplished by drilling with a rotating head so the deeper zones can be drilled with a much lighter mud weight than is currently used. An obvious advantage to under balanced drilling with casing is that the well does not have to be balanced with heavy mud to trip out of the hole to run casin, as would be required with a conventional system. Wells can be drilled with the Casing Drilling system with smaller rigs than are required for conventional drilling. This has a direct advantage in situations where the rig and a conventional drill string must be transported by helicopter. It also may allow smaller rigs that have been left on platforms for repairs and recompletions to be used for sidetracks and infield drilling without needing to bring in a larger rig. There are also potential applications that require a little more development. Equipment to allow the Casing Drilling system to be used while air drilling is under development and modifications to the system to allow it to be used in deep water applications are in progress. The ultimate drilling solution may be a combination of Casing Drilling with expandable tubulars, but there are several hurdles that must be overcome for this to be practical. 287 Drilling Operation Practices Manual Use Of CWD With Under Balanced Drilling Advantages 1. Safer than UBD with Drill pipe (no tripping of drill string) 2. Can eliminate intermediate strings of casing 3. Drills faster. Result 1. Improved production 2. Reduced time on location 3. Saves money. Use Of CWD With Air Drilling – Advantages 1. Reduced compression demand 2. High annular velocities 3. improved tolerances for water influxes 4. Improved penetration rates 5. Reduced mud ring build up Result 1. Ability to drill deeper on air 2. Use less horse power to drill. Conclusions The conclusion drawn from initial CWD test wells suggest cost savings of 10-15% for trouble free wells. Elimination of unscheduled events encountered in trouble some wells may increase savings up to 30% or higher. Casing Drilling eliminates all the costs associated with these down hole problems: Swelling Formations Sloughing Formations Washouts Swabbing Hole in Casing or Key Seats Running Logs and Casing Casing drilling, an innovative process for simultaneously drilling and casing a well, is emerging as viable technology for the 21st century. Field studies have demonstrated a 20 - 30% reduction in the time required to drill wells from spud to rig release when utilizing casing drilling. 1. As on date it is mainly used for following categories of wellsTop Hole Sections: Conductor and Surface Casing Trouble Zones: Drilling Liners Directional Sections: Intermediate and Production Casing 2. In ONGC, especially in Geleky area of Upper Assam Asset where wells of depth more than 4000m are taking too long for completion due to one or the other problem, this technology can be tried in 2-3 wells to test whether this can reduce cycle time and reduce the cost of drilling . Although cost is slightly on higher side but may helps us in completing our 8 ½” section in 45 days. 288 Emerging Technologies 20.2 EXPANDABLE CASING The fundamental concept of expandable casing is cold-working steel tubulars to the required size downhole. This process, when exactingly controlled, can be mechanically preformed in a down hole environment. Many technical and operational hurdles have to be overcome when using colddrawing processes in a downhole environment. Solid expandable systems are solid steel jointed pipe that are run in the hole as normal casing and expanded downhole to a pre-determined OD and ID. Once the system is expanded, the entire system will withstand expected collapse and yield pressures. Once the solid expandable system is put on depth, an expansion cone, called launcher, which is placed inside the first casing joint, is used to permanently mechanically deform the pipe (fig. 1). The cone is moved through the expandable string by a differential hydraulic pressure across the cone area, by a direct mechanical pull or push force, or by a combination of both. Solid expandable tubular technology provides feasible options for drilling, completion, and workover operations allowing operators to reach previously unattainable target zones. Solid expandable tubular (SET) installations have increased production, extended production life through remediation of existing pay zones, and provided the ability to reach target depths. In a drilling application, solid expandable tubular technology reduces the telescopic effect created by using multiple casing strings in deepwater or extended reach wells, thereby preserving valuable hole size. Deepwater operators, who were the drivers of solid expandable tubular (SET) technology, will be tremendously benefited from this technology. Since its development, the technology has rapidly moved from the deepwater, to a technology that has been embraced by operators in many basins. At present only 22% of the installations have been in deepwater, with over 65% of the total jobs having been done on land. In 1998 an autonomous new company M/s Enventure Global Technology was formed by Shell Technology Ventures Inc. and Halliburton Energy Services to develop and commercialize expandable casing technology. System Detail The differential pressure required for tubular expansion is created by pumping through an innerstring that is connected to the cone. The hydraulic force acts across the bottom side of the cone area forcing it upward. Mechanical force is applied by either raising or lowering the inner-string (fig. 2). The progress of the cone through the expandable tubular string deforms the steel beyond its elastic limit into the plastic region, while keeping stresses below ultimate yield (fig. 3). Expansions greater than 20%, based on the ID of the pipe, have been accomplished in lab. Most applications using 4-1/4 in. to 13-3/8 in. tubulars have required expansions less than 20%. Expandable technology is seen as a means of reducing the overall cost of a well and its support infrastructure. The application of the technology within the first ten years has been aimed mainly at those well bore construction techniques that have remained unchanged for decades. Telescoping casing designs have existed since the very first wells and reservoir completion practices have remained stagnant, dominated by gravel packing. The basic design of liner hangers, packers and through tubing straddles has not changed either; expandable technology will, and already has revolutionized techniques in these areas. Expandable Casing Technology will enable oil and gas operators to access reservoirs that cannot be easily reached with current methods. By expanding casing in situ, the hole size can be maintained and the target reached with minimal well tapering. This results in improved reservoir 289 Drilling Operation Practices Manual Fig. 3. Stress/strain curve for solid expandable tubular systems. Fig. 1. Fig. 2. Differential pressure pumped through the inner-string. economics by reducing well capital expenditures and improving the success rate of reaching sub salt targets. In addition to rig-time savings and lower well costs, expandable casing technology can result in overall smaller hole size from spud to total depth. Expandable casing offers the potential for a step change in well construction technology. Enventure’s expandable-tubular systems address numerous drilling and completion challenges and can especially enhance deepwater operations, one of the industry’s highest priorities. The choice of comparatively larger final hole sizes that expandable-tubular technology allows can provide access to previously unreachable reservoirs; it can also reduce drilling time and the size of drilling equipment, including lay-down areas and auxiliary equipment required on offshore platforms. In operators’ bottomline terms, expandable-tubular systems should lower overall project costs. Expandable tubular technology has found many applications such as: Expandable solid casing that allows the construction of a mono-diameter borehole or function as borehole liners that permit the drilling of larger diameter boreholes. Expandable perforated or slotted pipe for lining the producing zone. Expandable legs of Level 6 multilateral junctions that permit the drilling of larger-diameter laterals while maintaining pressure integrity with the junction. Expandables for use as liner hangers. Expandable liners for repairing casing SET Systems Solid expandable tubular technology has evolved over the past few years from a radical solution for drilling challenges to a logical well construction process. By incorporating expandable systems 290 Emerging Technologies in the initial well design stage, the downhole tapering effect is reduced or eliminated. Enventure’s SET product line consists of three basic systems: 1) The Expandable Openhole Liner (OHLTM), 2) The Expandable Cased-Hole Liner (CHLTM) and the 3) Expandable Liner Hanger (ELHTM). In addition to the above the technology also includes the following: openhole cladding system monodiameter system Openhole Liner Systems The openhole liner system consists of expandable casing strings planned into the well construction to minimize the telescoping effect of the original pre-expandable well designs. Solid expandables minimize well slimming while adding strings for deeper depth. This slimwell application can lower costs by reducing the following: mud volumes steel consumption per well formation cuttings hence less threat of pollution size of the rig required to drill the well especially in deepwater applications The openhole system can be used as a contingency drilling liner in any well during the drilling phase. Running this drilling liner maintains hole size when an unforeseen geologic anomaly or problem is encountered. These anomalies and problems can include the following: unstable formation over- or under-pressured formation loss circulation pore pressure/fracture gradient Having to install an unplanned casing string because of an unforeseen geological anomaly will no longer be detrimental to the well. The only limiting factor to achieving the target is temperature and well geometry constraints. Ultra long-reach horizontal wells will be possible where an entire field can be produced from a single drilling pad, platform, or subsea template. Wellbore extensions can be accomplished by using an existing non-producing well. A window can be cut and an expandable system could be run to re-direct the well to another target.This expandable application maintains hole size to allow a larger liner to be run into the pay zone. An example would be to cut a window in a 9-5/8 in. existing casing and run a 7-5/8 x 9-5/8 in. expandable system. Once expanded, this system would allow for a 7-5/8 in. special clearance coupling liner to be run into the producing zone. The window exit installation involved expanding an Openhole Liner System below the window, allowing the operator to maintain hole size to total depth. This capability increases the range of applications for the OHL System in sidetracks in existing casing. Cased-hole Liner System The expandable cased-hole liner system enables operators to repair existing damaged or worn casing for deeper drilling or other contingencies. The system makes it possible to upgrade exploration-grade casing to a sturdier production casing with minimal loss of casing ID. 291 Drilling Operation Practices Manual Drill Hole Run Expandable Liner Condition Mud, Cememt Liner Latch Plug Expand Liner Expand Hanger Joint Mill Out Shoe Installation sequence for Expandable Openhole Liner System Running sequence of the Expandable Cased-hole Liner System 292 The system can be used to shut off perforations in production casing for re-completion or for deepening the well. Enventure’s Expandable Liner Hanger. with no moving parts such as slips. This expandable system allows for enhanced control of existing injectors and producers by shutting off unwanted gas or water production.Emerging Technologies The cased-hole liner system is mechanically similar to the expandable openhole liner system except that an additional anchor-hanger joint (elastomer section) is located immediately above the launcher assembly. Expandable Liner Hanger System The ELH System provides a much simpler and cost effective alternative to complex conventional liner hangers and liner top packers. The ELH System simplifies the mechanical and pressure functionality into a single unit. Additional savings are realized by eliminating the need for a separate trip to install the liner top packer or to test the liner top. combines the functional requirements of a liner hanger and liner top seal. The system has also been used to reconnect a severed wellbore due to subsidence from formation movement. Running sequence of the Expandable Liner Hanger System 293 . sleeves or O-rings. while minimizing the need for liner top squeezes. Expanding this system inside existing casing repairs and reinforces the larger casing for completion. and eliminates possible leaks in the annulus during setting and for the life of the hanger. and rock hardness all affect the seal capabilities. This system consists of expandable sealing sections called Flex Hangers. The FlexClad System differs from Enven-ture’s standard expansion systems in that the liner and connections are not expanded. Openhole Cladding System The openhole cladding system is an expandable string that is run and installed in the open hole to address the following: isolate an unstable formation isolate a water flow shut off water influx in a openhole completion The openhole cladding system installation process is similar to that of the openhole liner with the exception that it is not tied back into the base casing. conventional API tubulars that act as spacer joints and flush joint connec-tions. The Flex Hangers are separated along the length of the liner using spacer pipe. Elastomers are configured to seal against the formation.Drilling Operation Practices Manual In addition to the above the following products have also been developed by Enventure 1. The seal efficiency will be a function of the rock properties where it is set. 294 . 2. isolates perforated sections and provides a gas-tight liner. enabling this system to be used in smaller casing sizes. Porosity. FlexClad™ System Enventure’s FlexClad System repairs existing casing. permeability. Emerging Technologies 3. many additional benefits are expected in near future By reducing casing size. Less mud chemical cost Less steel consumption per well 295 .D of SET casing increases thereby decreasing (shortening) its length by approx. Expansion Ratios: Normal expansion ratios of SET expandable tubulars are in the range of 10-15% but it can be expanded even upto 20-25 % for mono-diameter casings. This will reduce the rig cost dramatically and so also well cost.D. well deepenings. On expansion the O. b. 4%. Producing less waste (cuttings) because smaller wells produces up to 50% less cuttings and hence less environment damage. reaching deeper depths with higher casing sizes and as a contingency casing for deep water wells where lot of casing strings are required due to narrow margin between pore pressure and fracture pressure. Monodiameter System Monodiameter technology is currently in the final field-testing stage and already generating results that are impressive and revolutionary. The Solid Expandable Tubulars currently in use are ERW (electric resistance weld) seamed pipe. Enventure’s requirements allow only a 5% to 7% variation in wall thickness. are much stricter than for typical oilfield tubulars. For example. This technology has proved its worth in maximizing production through bigger production casings/ strings.) of base casing against which SET will be expanded Further 7 5/8" becomes the ID for the next well section after expansion. This technology consecutively runs the same size expandable casing strings and expands them into each other to achieve the same ID from top to bottom. c.Means 7 5/8" is the size ( OD) of SET casing pre expansion and 9 5/8" is the size (O. Material: Today. custom-made by Lone Star Steel to high specifications developed by Enventure. reduce defect sensitivity and increase fracture toughness. Land rig size will also be reduced thus reducing foot print and emission. the American Petroleum Institute allows a 12. Sizes Available As on date the SET systems are available in following sizes13 3/8" X 16" 11 ¾” X 14 ½” 9 5/8" X 117/8"OR 11 ¾” 8 5/8" X 10 ¾” 7 5/8" X 9 7/8" 5 ½” X 7 5/8" 6" X 7 5/8" 5 ½” X 7" 4 ¼” X 5 ½” Note: 7 5/8" X 9 5/8" . Depending upon pipe size. which allows the steel to be pushed temporarily into the plastic region during expansion. BOP and Riser size can be reduced in Deep water wells. standard oilfield tubular steel is used for Solid Expandable Tubulars after it is subjected to a special heat-treating process to increase ductility. By reducing telescopic nature of wells. particularly for wall thickness variation of the pipe. The specifications. The monodiameter removes the telescoping effect of pre-expandable well design System Specifications a.5% variation in the wall thickness of standard oilfield tubulars. Running this drilling liner maintains hole size when an unforeseen geologic anomaly or problem is encountered. This technology enables the operator to “reach through” deepwater subsurface environment just under the mud line containing shallow water flow. and will not require the premature plugging of wells costing millions of dollars. There is a multitude of applications for this technology. Application of the Expandable Technology Although expandable products are unique. expandable system. The openhole system can be used as a contingency drilling liner in any well during the drilling phase. etc.or under-pressured formation loss circulation pore pressure/fracture gradient Having to install an unplanned casing string because of an unforeseen geological anomaly will no longer be detrimental to the well. The application of the technology in the subsurface environment has the potential of significantly reducing surface and subsurface costs and increasing the return on investments (ROI) of the operating companies. and interesting in concept and installation. which require so many casing points. hence it is more suited in offshore where production rates are higher and well costs are more but it can be hoped that with the passage of time it will become highly cost effective for less producing fields as well. rubble zones. These anomalies and problems can include the following: unstable formation over. An example would be to cut a window in a 9-5/8 in. This technology was successfully used in ONGC. The use of Expandable Openhole Drill Liners in such cases can give the operator several additional strings of casing above those listed in the casing catalogs This will enable them to reach their objectives.Drilling Operation Practices Manual Once mono diameter well completion becomes feasible it will further reduce time and cost for well completion by1) Standardization of tools 2) Fewer BHA make up / break out 3) Higher operating efficiency 4) Higher safety since bigger sizes of casing will be avoided and fewer BHA’s to be handled . Presently its cost is on the higher side. A window can be cut and an expandable system could be run to re-direct the well to another target. sub-sea equipment as well as sub-surface products. Once expanded. the impact on all aspects of well operations is expected to increase dramatically. they have little value if cost-effective applications cannot be realized from their development. Ultra long-reach horizontal wells will be possible where an entire field can be produced from a single drilling pad. The economics of expandable tubulars must work for the long-term benefit of operators. In one well it was used to tap deeper oil layer from an existing well and in other as a contingency casing to attain desired production casing size. Wellbore extensions can be accomplished by using an existing non-producing well. in 2 wells in Mumbai offshore recently(OctDec 2003). Based on its performance 30 more wells are being completed using this technology in the year 2006-07. The only limiting factor to achieving the target is temperature and well geometry constraints. 296 . including applications for products for optimizing surface facilities. special clearance coupling liner to be run into the producing zone. platform. existing casing and run a 7-5/8 x 9-5/8 in. This expandable application maintains hole size to allow a larger liner to be run into the pay zone. or subsea template. this system would allow for a 7-5/8 in. As costs decline. Figure below illustrates a sample ultra-deep water well. located in more than 5.Emerging Technologies Discussion of Deepwater Applications Expandable casing technology can provide value in deepwater well engineering operations in two areas: 1. Ultra-deepwater well using a 13-3/8 inch X 16-inch SET System 297 . well objectives cannot be reached with a sufficiently large hole size for evaluation and production operations. This results in more casing strings required to drill to an equivalent depth below the mudline compared to a well drilled in a shallower water depth. that reached its objectives by using a 13-3/8 inch by 16-inch SET system.000 feet of water. using conventional casing programs with an 18-3/4 inch BOP stack and a 21inch OD drilling riser. A cost-effective solution in conjunction with smaller rigs in deepwater As operations move into deeper water. An enabling technology for low drilling margin conditions 2. In some cases. drilling margins (the difference between pore pressure gradient and fracture-pressure gradient) become narrower. SET technology can also be used to provide contingency casing deeper in the well. Expansion changes the Charpy impact toughness of the expandable-tubular material. the casing still met API Spec 5CT requirements after 20% expansion. Changes in Mechanical Properties Post expansion strength. ductility.Drilling Operation Practices Manual Next-generation SET systems may allow the equivalent of a “monobore” well to be drilled. however. Well plan utilizing “nested” Openhole Expandable Liners Limitation 1. with expansion— natural results of cold-working the metal. and burst have been studied for selected sizes of pipe and compared to the same values for the pipe as received. with 100% shear fracture in all cases studied. impact toughness at 32°F and higher is still acceptable. impact toughness. collapse. whereby the same hole size is drilled from surface to TD. Elongation tends to decrease. The Bauschinger phenomenon occurs when plastic flow in one direction (expansion) lowers the applied stress at which plastic flow begins in the reverse direction (collapse). Expansion decreases the collapse rating of tubular goods. Hardness and tensile properties of the tested L-80 casing changed after expansion. probably a result of the Bauschinger effect. except for that of the K-55 casing. Figure shows the progression from conventional well construction to slender wells with SET technology and on to monobore well technology. 298 . However. It has been found that. A monobore well opens up further costsaving opportunities for an operator by allowing a slim wellbore to be drilled with a small vessel. Similar results were obtained with grade K-55. Ultimate tensile strength tends to increase. This moment causes concentration of hoop stress on the expansion face. The well flowed @ 686 bopd. and thus uniform hoop stress distributions on the expansion cone face. Expansion was performed in about 8 1/2 hrs.2" size) prior to lowering expandable casing. MWD and Motor assembly was drilled from 2101m to 2600m within B layer using non damaging clay free mud. It was used as an extension of 7" liner base casing from the top of LIII reservoir to the top of B layer (landing point). In case of stuck up Expanding a liner through a differentially stuck section dramatically changes the stress conditions created by the expansion cone in the pipe. If the magnitude of the differential pressure is small. API casing with very strict controls specification only to be used At present restricted to two grades of casing only i.Emerging Technologies 2.5°) to 2105m (angle 88°) up to top of B layer using gel polymer mud system. the liner cannot be freed. which reduce the risk of becoming stuck. The expansion process occurred at propagation pressure of 3700-4000 psi. drill string and bottom hole assembly (BHA). the plug was bumped at a pressure of 2650 psi. and maximum 4500 psi when the hanger joint was expanded against 7" base casing. Cost The cost of using SET technology is at present towards higher side but with increase in number of applications and entry of more companies in production the cost is bound to come down as it has been recognized as a safe. 500 m of 6" drain hole with 5"X 6" Bicentric bit. L-80 and K-55. Presently Lone Star Steels is the only manufacturer of casing pipes. Enlarged 6 1/8" hole to 7" using 6" x 7" Near Bit Under Reamer (NBR) and watermelon mill (6. However. In this phase 8. Directional 6 1/8" pilot hole was drilled with motor& MWD from 1864m (angle 71. this places geometrical constraints on the liner. loss of displacement control and potential rupture of the liner. free up constrained pipe and/or enable expansion through the stuck interval without causing hoop stress concentration. To reliably expand steel pipe beyond its elastic limit. 51/2 “ X 7” expandable open hole liner (OHL) of 290m length was run down hole through the existing 7" base liner to a depth of 2101 m keeping Elastomer hanger top at 1811m. Modifications have been done to the standard BHA. the drill pipe and expansion cone will free up the stuck pipe and expansion can be continued safely. Geometrical constraints cause severe bending in the BHA and a large additional rotational moment is applied to the expansion cone. 2003 ONGC completed the first successful field application of 5 ½” X 7" size solid expandable open hole liner in LIII B layer side tracked horizontal well 1A-4ZH. After cementing. 299 . 4. Operational procedures have been revised to minimize this potential risk. if the pressure differential is large enough. it is necessary to maintain a displacementcontrolled expansion process. ONGC Experience SDST horizontal well IA#4ZH (Rig Sagar Shakti) On December 8. If pipe is differentially stuck.e. efficient and reliable technology for Deep waters Sub salt environments Depleted reservoirs 3. it can cause pipe damage and even rupture the expansion face.6 ppg gel polymer mud was used. Drilling Operation Practices Manual 300 . The well flowed at a rate of 1050bopd Recent Trends in Expandables I. 9 5/8" casing would have set on LIII top but the held up resulted in premature loss of hole size. The directional hole section of 150m length was drilled in Llll reservoir with a 6" x 7" bi centric drill bit from 2351m (Llll top) to 2501m (A2 VII layer landing point). A Clean out trip was made with stabilizer. near bit reamer (NBR) and watermelon mill. To remedy the situation. The post expansion liner length was 185m resulting in 3. is to make possible a well with the same internal casing diameter from surface to total depth.Emerging Technologies SET as a “Remedial measure” in SP#8H well (Rig Pride West Virginia) On January 2. using a smaller BOP stack. The liner was expanded 11. The 7" base casing liner had to be set pre-maturely above LIII top instead of A2 VII layer landing point. which was planned to be completed as a horizontal in A2VII layer ran into unexpected down hole complications. the next generation of solid expandable tubular (SET) technology that Enventure Global Technology and Shell has developed. This system will save significant amounts of time and money by reducing flat time during drilling operations. and standardizing equipment such as drillstrings and bits as well as casing.8% in to 7" base casing and open hole in about 4 hrs using Propagation pressure of 4500 to 6000 psi. Safety will be enhanced because rig crews will not have to handle large diameter casing and drilling 301 .7° angle was run to the depth of 2501m with Elastomer hanger top at 2309 m. 2004 second 5 ½”X 7" Expandable open hole liner (OHL) was safely installed in horizontal development well SP-8H (clamp-on location). Two 6" lateral sections of 400 m each were drilled using bi-centric bit and MWD in A2 VII layer of LIll reservoir.7% decreases in the over-all length. MonoDiameter Technology The ultimate objective of the MonoDiameter System. 51/2"X 7" Expandable OHL system over an interval of 192 m ranging from 72° to 87. Conventionally. 5 ½”” X 7" Expandable casing was incorporated in the drilling plan as a remedial measure for preserving hole size in order to achieve the desired objective of placing the 6" lateral section within A layer. 9 5/8" casing was short landed by 110m above top of LIII reservoir due to tight hole conditions. The well. Applying SlimWell Technology over a multi-well program can substantially impact the bottom line.Drilling Operation Practices Manual equipment. additional savings materialize in onboard drilling vessel storage requirements because a smaller riser can be used. A well drilled using this system will have no diameter loss with each new liner. A hybrid well is one that features conventional casing for the first three or four strings and then moves to a series of MonoDiameter liners. a significant cost in offshore operations. which ultimately results in savings on bits. Reducing the amount of drill cuttings decreases the cost of cuttings disposal. allowing operators to slim down the top of the well while increasing the well diameter at TD. especially when drilling with a zero-discharge requirement. as well as the storage space required for these materials. Offshore. While SlimWell reduces the telescoping effect in traditional well design. less expensive rigs can be used. steel. especially in deep-water in conjunction with smaller riser. Smaller. 302 . each well drilled can potentially reach its reservoir with a casing size that will enable reservoirs to produce at full potential. the MonoDiameter System eliminates telescoping. mud and cement. and the frequency of changing out drilling equipment and bottomhole assemblies will be minimized. Nesting an expandable system inside an already expanded system preserves crucial hole size. This means that regardless of unexpected reservoir challenges. helping to dramatically reduce daily rig costs. MonoDia-meter. In addition.. 36-in. After milling the window and drilling the lateral. MonoDia-meter liners could be run on a 16... or eight could be run for a 35.Emerging Technologies This will be the first step in deepwater.000-ft well. MonoDiameter. 13 3/8-in.000-ft well.. 9 5/8-in. 20in. until the objective is reached. This well design could become standard for deepwater. where the customer might run. With solid expandable tubulars. 303 . where. With the application of solid expandable tubulars. higher-level junction types have developed a more significant drop in hole size through them. 9 5/8-in. say. allowing a larger drain hole to be drilled into the pay zone of interest than might be possible with conventional casing string designs. MonoDiameter. II. operators now have the opportunity to complete multilaterals without the need to compromise on hole size. the openhole drill liner is installed. and so on. only two 9 5/8-in. Expandable tubulars in multilaterals The production and completion advantages of multilateral technology are well documented. for example. Solid expandable tubulars make it possible to start the well smaller than normal without compromising the casing size at the multilateral junction. it may be possible to maintain the same casing size as the mother bore in the lateral. more of the functionality of a conventional well has been added to the multilateral well. 11 3/4-in. 9 5/8-in. Solid expandable tubular technology is applicable in a variety of multilateral applications and in a wide range of casing sizes. reducing well construction costs. As the technology has developed. the casing is expanded from the bottom to the top and the liner is sealed back and hung off in the base casing. The combination of solid expandable tubular technology and multi-lateral window milling systems was expected allow operators to slim their wells resulting in a reduced capital outlay. and create a superior rate of return over conventional development scenarios. The system is pressure tested and the shoe is drilled out. 304 . This involves the recompletion of wells in which the original wellbore is no longer meeting productivity expectations. or it is identified that optimal drainage could be achieved by having the wellbore in another location of the reservoir. situations that require a relatively long expandable casing string. among others. anchor hanger joint. Now that it has been proven that these two technologies can be successfully deployed. minimized environmental impact. the performance of solid expandable tubular systems is proven for use in high-angle and horizontal wells. deepwater wells. The lateral hole section is then drilled as per the well program using conventional bits and mud motors. reducing the reliability of the expansion process. a dart is dropped while seal and pressure is applied down the drillstring. various cementing scenarios. multiple installations in the same well. and launcher assembly – is run as a single assembly. Installation of SET Systems Through Milled Casing Windows Currently. maximized reservoir potential. the solid expandable tubulars can be run into the lateral hole sections using a whipstock deflection device.Drilling Operation Practices Manual The solid expandable tubular system – including casing. In one trip. recent testing and successful field applications proves the viability of using solid expandable tubular systems in these circumstances. III. However. For the early part of its development. Using solid expandable tubulars in conjunction with side-tracking technology a well can be recompleted as a larger completion through a casing sidetrack. the value-proposition of making use of existing capitalized assets and a reduced AFE combined with better reservoir dynamics can create a enhanced economic model over conventional applications Solid expandable tubulars are quickly becoming a viable means to overcome certain challenges existing operations face and to offset some of the higher expense by employing its unique technology in existing wells. One application of solid expandable tubular systems that was not qualified in the past was a sidetrack through a milled window. Once on depth. solid expandable tubular technology could not feasibly enter side-tracked wells because of the potential damage sustained during run-in. In the case of multilateral wells. This creates a pressure chamber in the launcher assembly. horizontal and multi-lateral wells etc. Each solid expandable tubular installation leads to technological advancements and enhancements that maximize hole conservation while minimizing well costs. thereby increasing production. a field trial. and five commercial installations have all demonstrated that solid expandable tubulars can be deployed successfully in casing sidetracked wells. minimized environmental impact. the value-proposition of making use of existing capitalized assets and a reduced AFE combined with better reservoir dynamics can create a enhanced economic model over conventional applications. solid expandable tubular technology has established itself as a viable drilling solution and process. Drilling in formations and at depths once thought too expensive is becoming technically and operationally feasible. and create a superior rate of return over conventional development scenarios.Emerging Technologies With over 209 successful installations in the past four years. These savings are realized in the dramatic productivity enhancements made possible by solid expandable tubular technology in fields where the operator has already capitalized the exploration and development outlay. these two complimentary applications have the potential to reduce significantly an operator’s capital expenditures for the life of a field. But more importantly. extended reach wells. The most obvious advantage is larger ID in the target zone. A lab test. 305 . Slowly but surely the scope of expandable tubular technology is expanding to applications like mono-diameter wells. The combination of solid expandable tubular technology and multi-lateral window milling systems is expected to allow operators to slim their wells resulting in a reduced capital outlay. two surface simulations. Now that it has been proved that these two technologies can be successfully deployed. This technology continues to provide solutions to drilling and recompletion challenges in both conventional and deepwater wells. maximized reservoir potential. It is also quickly gaining a reputation as a proven drilling design technology. Recent technological breakthroughs—developing and deploying a modification on the expandable tubulars and making use of the latest advances in multi-lateral window milling systems—have now enabled solid expandable tubulars to become a reliable and repeatable method to overcome the unique challenges faced by older operations. or packoff.450 m] long or more. and reasonably high load capacities for deeper vertical and high-angle reach compared with wireline and slickline. Modern CT equipment and techniques have several advantages over conventional drilling. double or triple tube core barrels such as are used in mineral exploration or engineering geology site investigation. controlled from a console in a central control cabin drives the injector head to deploy and retrieve coiled tubing.3 COIL TUBING DRILLING Coiled tubing describes continuous lengths of small-diameter steel pipe. The continuous tubing passes over a gooseneck and through an injector head before insertion into a wellbore through well-control equipment that typically consists of a stuffing box. depending on reel size and tube diameters. which range from 1 to 41D 2 in. drilling and well-completion techniques. workover and snubbing units. or prime mover. Coiled tubing drilling unit and associated coiled tubing handling equipments ii. 306 .000 ft [9. Downhole Equipments 1. Coiled tubing is spooled onto a reel for storage and transport. Surface Equipments Coiled tubing drilling surface equipments are as follows: i. Coring can be done with coiled tubing using small diameter. riser and blowout preventer (BOP) stack on top of the wellhead. This process is reversed to retrieve and spool coiled tubing back onto the reel. COILED TUBING DRILLING EQUIPMENTS Coiled tubing drilling equipments are widely divided into two categories: 1. These strings can be 31. A hydraulic power pack. The large storage reel also applies back-tension on the tubing. Well control system iii. single. expedited operations with no need to stop and connect tubing joints. The flexibility of working under pressure in “live” wells without killing a well and the unique capability to pump fluids at any time regardless of position in a well or direction of travel are also advantages. Surface Equipments 2. These include quick mobilization and lower cost. related surface equipment and associated workover. Circulating fluid and system.Drilling Operation Practices Manual 20. hydraulically powered service system designed to run and retrieve a continuous coiled tubing string. The predominant design of coiled tubing unit uses the vertical. which are powered by contra-rotating hydraulic motors. • Control the rate of tubing entry into the well under various well conditions. Several hydraulic systems are used to enable the CT unit (CTU) operator to exercise a high degree of control over any CT string movement – an important feature in delicate CTD operations where WOB must be carefully controlled. The saddle blocks within the chain are forced onto the pipe by a series of hydraulically attached compression rollers that impact the force required to establish the friction drive system. which is mounted directly above the drive sprockets and used to receive Coiled Tubing from the reel and 307 . Coiled tubing drilling unit and associated coiled tubing handling equipments The coiled tubing unit is a portable. Tubing injector heads are designed to perform three basic functions: • Provide the thrust to snub tubing into the well against pressure as to overcome well bore friction. contra-rotating chain-drive injector head. Tubing injector head b. The tubing injector head manipulates the continuous tubing string utilizing two opposed sprocket-drive traction chains. The injector head is also equipped with an arch roller system. Coiled tubing reel c. or can be used to convey downhole tools and devices attached to end of tubing. called a tubing guide. • Support the full suspended tubing weight and accelerate it to operating sped when extracting it from the well. The tubing can be snubbed or run open ended.Emerging Technologies i. The basic coiled tubing drilling unit components are as follows: a. These chains are fabricated with inter-locking saddle blocks mounted between the chain links and machined to fit the Coiled Tubing string circumference. Control console a) Tubing Injector Head The CT injector head provides the power and traction necessary to run and retrieve the CT string into and out of the wellbore. Hydraulic power unit d. operated stuffing box is positioned along the coiled tubing centerline and is secured in the chain drive assembly. The rotating joint is secured to a stationary piping section connected to fluid pumping system to circulate fluid. Standard prime movers packages on most coiled tubing units are equipped with diesel engines and hydraulic pumps. The innermost tubing end is connected through the hollow end of the reel shaft to a high pressurerotating joint. This isolates annular well bore pressure from the atmosphere. Motor is mounted for direct drive on the reel shaft or operated by a chain-sprocket drive assembly. The prime mover for a specific coiled tubing unit may range from a power take-off assembly (Bobtail land unit design) to a selfcontained offshore skid package. The primary function of the reel brake is to stop drum rotation if the tubing accidentally parts between the reel and the injector head. slight back-pressure is always maintained on the reel motor to allow the injector head to pull the tubing off the reel and keep tension between the injector and the reel.00" OD tubing or 22. Well control system/ Blow Out Preventer Stacks Coiled tubing drilling requires two sets of different blow out preventer stacks assemblies: 308 . The injector head is supported above the well head in one of the two ways. Either telescopic legs or a hydraulically elevated steel frame commonly called a “jack stand” are used. During lowering of the tubing. The minimum stuffing box working pressure rating is 5000 psig.25" OD tubing. It may be skid-mounted for offshore use or permanently mounted on land units. On the other hand. b.000 feet of 1. New reel units have a back-pressure device braking system to slow the reel and also a friction pad braking system for extra control. At the injector head base. The basic spool can store up to 26.000 psig shut-off valve is provided between the tubing and reel shaft to isolate the tubing from the surface pump lines. The stuffing box or “stripper rubber” contains a split elastomer element that is compressed against the tubing. Coiled Tubing Reel It consists of a fabricated steel spool drum with a core diameter of 60"-72" and a 9’ flange diameter side. The reel rotation is controlled by a hydraulic motor that is used for constant. c. tubing retrieval pressure increases on the reel motor allowing reel rotation to keep up with the tubing extraction rate out of the well. The prime mover assembly size will depend on hydraulic-drive unit needs.000 feet of 1. The braking system is not intended to halt uncontrolled tubing dispensing but only to offer resistance and slow down reel motion. The console includes all of the controls and gauges required to operate and monitor the coiled tubing drilling unit components. ii.Drilling Operation Practices Manual guide it into the chain blocks. but it is generally designed for working success upto 10. One 10. The friction pad is applied hydraulically to the outer reel flange diameter to slow reel motion. Control Console Normally all controls are positioned on one remote console. d. a hydraulically. stripper rubber and blow out preventor stacks are also located on the control console. steady pull and making sure that the coil is being tightly spooled onto the drum. Tubing spooling capacity is dependent on the core diameter. Control systems to regulate the drive chain. Reel and injector head motors are activated from the control panel through valves that determine the tubing motion direction and operating speed. Hydraulic Power Drive Units Hydraulic Power Drive Units are sized to operate all of the coiled tubing unit components.000 psig. Drilling fluid design must give due consideration to the following three points: • Minimizing the frictional pressure losses • Producing more HHP to run the mud motors • Have sufficient density to maintain bore hole pressure and ability to sweep hole clean of cuttings. Low solids mud system is better suited for this. Coiled tubing drilling circulating system is identical to conventional drilling circulation system. Tubing Shear rams. In addition. Slip Rams and Pipe Rams. shale shakers. mechanical forces yield the tube body to failure.Emerging Technologies a. they isolate well bore annulus pressure below the rams. iii.000 psig. • Blind Rams Blind rams are used to seal the well at the surface when well control is lost. These rams are also outfitted with guide sleeves to center the tubing as the rams are closed. Slip Rams are fitted with guide sleeves that properly center the tubing in the ram body‘s grooved recess as slips are closed. blind rams. • Tubing Shear Rams Tubing Shear rams are used to mechanically break the coiled tubing in the event coiled tubing becomes stuck or when it is necessary to cut the tubing and remove surface equipments from the well. For coiled tubing a) Bottom Hole Assemblies Blow Out Preventer Stacks This consists of annular preventer. Blind rams seal when elastomer elements are compressed against each other. The four BOP compartments are equipped from top down with Blind Rams. Circulating Fluid and System The bore of coiled tubing drilling equipments is very less as compared to conventional drilling and it results in high frictional pressure losses. But the mud system capacity requirement is less in comparison as smaller sizes of holes are drilled. As shear plates close on the tube. Triplex Pumps (500 HHP) are suitable to meet this requirement. 309 . The return line is used to circulate out the kick or for taking returns out in drilling an under balanced well. desilters and centrifuges.000-5. It is composed of four hydraulically-operated rams. When closed against the tubing. b) Coiled Tubing Blow Out Preventer Stacks The BOP system is a critical part of coiled tubing drilling units. • Pipe Rams or Stripping Rams Pipe Rams or Stripping Rams are fitted with preformed elastomer seals that fit the specific OD of the tubing in use. slip rams can be used to secure the pipe by closing on the tube to prevent the movement in the case of high pressure that may blow the tubing out of the well. pipe rams suitable for bottom hole assemblies and drilling spool with isolation valves. It also requires mud tanks. For Bottom Hole Assemblies b. desanders. generally rated for a minimum working pressure of 10. • Slip Rams Slip Rams are equipped with uni-directional teeth that move against the tubing when activated to support the pipe weight. Typical pressure and capacity requirements for circulation are in the range of 4.000 psi and 170 gpm. Positive Displacement Motors Positive Displacement Motors are used to turn the bit.Drilling Operation Practices Manual iv. High-speed. It must be able to resist the torque developed by the mud motor. Drill collars should have large enough ID to allow the insertion of the steering tools or MWD system and minimize the pressure drop through the drill collar string adjacent to the survey tool. Coiled Tubing Adapter Coiled tubing adapter is required to connect the coiled tubing to the BHA. Medium speed. c. d. re-entries and horizontal wells. Disconnect tools f. Non-standard size drill collars may be used. Drill bits b. a. low torque motors are suitable for those with TSD or natural diamond bits. Mud motors in the sizes suitable for coiled tubing drilling can develop torque in excess of 1. high-torque Motors should be matched to the bits they will be used with. Positive displacement motors (PDM) c. PDM are available for coiled tubing drilling in diameters ranging from 2. b. Disconnect tools have to resist the torque developed by the mud 310 .375" to 6. Downhole Tools Coiled tubing drilling gained momentum and acceptance with the innovative work done on downhole tools and bottom hole assemblies to meet the needs of deepening. Orienting tools Drill bits. Coiled tubing adapters. These specialized tools have been designed of necessity. When MWD or steering tools are used. Drill Bits Bits used for coiled tubing drilling should be able to attain adequate penetration rates with relatively less weight on bit and high rotational speeds. disconnect tools and orienting tools are unique to coiled tubing drilling.000 ft-lbs in a stall situation. Drill collars d. Coiled tubing adapters e. medium torque • Low speed. Disconnect mechanisms are of two typespressure release or shear release. e. Drill Collars Drill collars provide sufficient weight to the bit to achieve acceptable rates of penetration and also provide adequate strength to enable the BHA to be run in compression. bits with low torque requirements should be selected to minimize the complications of reactive torque while maintaining the desired well trajectory. Disconnect Tool Disconnect Tool provides a means of disconnecting the coiled tubing from the bottom hole assembly in case the bit or drill collars become stuck. low torque • Medium speed. non-magnetic drill collars are used to prevent magnetic interference with these devices. drill collars and survey tools are borrowed from conventional drilling operations. Coiled tubing drilling downhole tools are as follows: a. For directional applications.5" OD as follows: • High-speed. medium torque motors are suitable for PDC bits. PDM motors. The small amount of equipment placed to risk. supports the use of CTD. a whipstock is set at the kick-off depth. For horizontal sidetracks the drain hole length is limited by the required WOB. This quick rig up is especially attractive in offshore and artic locations. Orientation tools are actuated by mechanical reciprocation. The tool is run above the mule shoe sub in the BHA. CTD is also useful for offshore where UBD is required due to depleted reservoir pressures. Pressure release disconnects are actuated by pumping a soft ball through the coiled tubing. f. the most technically and economically successful applications of CT are in through-tubing reentries. In some softer operations the hole size may reach 12-1/4" however. where drilling and workover rigs have higher day rates. and begin drilling within hours. After the coiled tubing is released. are not especially suited to CTD. CTU can move in. fishing tools can be run to recover the BHA. Orienting Tools A downhole rotator or orienting tool is required to alter the tool face orientation to control the direction of the hole in directional and horizontal drilling. pressure cycling. Here too there are limitations 311 . typically 1500-1800 metres deep. and a window is milled in the casing. In these areas. and CTD is suited to a portion of these operations. Here too CTD units have to compete with depreciated drilling rigs with low day rate. the relatively new CTD unit and its bulk of required ancillary equipment must compete against a depreciated drilling rig. with hole diameters up to 8 ½”. In many regions of the world. mainly because of current market economics. the disconnect mechanism must be designed to accommodate the wire line without interfering with the releasing operation of the tool.Emerging Technologies motors. Conventional Re-entry Deepening and sidetracking wells cover the bulk of the conventional re-entry market. In such types of wells CTD has limitations of maximum hole size (6") and build up rates (>30 degree/100 ft). These projects are suited to CT because no additional equipment is needed to pull the tubing. For sidetracks. the CTD unit is not an economic alternative to the conventional rig. Orientation tools either allow for continuous adjustment or tool face orientation over a fixed range of rotation or for indexed tool face rotation with no limit on the total range of adjustment available. rig up. downhole electric motors or a combination of these actions. If the electric line is used. CTD is effective for new shallow gas relief wells being drilled in Indonesia and Venezuela. CTD however provides environmental advantages like small footprint. Here too CTD has the same environmental advantages as for new wells. Through-tubing reentries are typically drilled to deepen or sidetrack a well and are performed without removing the well’s production tubing. however. Through-tubing Re-entry Other than UBD applications of CTD. the casing size will be limited to a final production casing of 3-1/2". Recent technical advances continue to push these limits. location remoteness and limited space on offshore platforms. Many of today’s new well projects. reduced environmental impact. CTD Applications New Wells CTD units can handle small and shallow new wells. as well as the advantages of personal safety. Shear release tools are actuated by pulling on the coiled tubing until sufficient tension is applied to shear out pins holding the tool together and disconnect the BHA from the coiled tubing. torque from the drilling motor. The motivation driving through-tubing drilling is low cost rigless re-entry when overbalanced and safe drilling with Christmas tree and tubing in place when under balanced (for reduced formation damage). conventional or through-tubing reentries). the cement kickoff plug may be effectively free.Drilling Operation Practices Manual in production tubing and hole sizes. 312 . the option of through-tubing drilling has become a reality and the following through-tubing sidetracking techniques are available for circumventing a production problem. With the advent of CT drilling. Through-tubing whipstock (TTW) a. In addition the case of drilling 4-3/4" and smaller boreholes with the CT is an advantage in a region that does not have an established practice of slim hole drilling. This underbalanced condition prevents drilling fluid from entering and damaging the producing formation. It consists of placing a specially designed cement plug in the casing and drilling with a bent housing motor to cut the window and lateral. Sidetracking Technology for Coiled Tubing Drilling. Because the whipstock is cement. the well flows while the hole is drilled. This technique has been successfully used for 3-¾” and 4-½” hole sidetracks in both 7" and 9-5/8" casing at deviations from 110 to 900. If the pilot hole is on one side of the casing and the BHA is then oriented to drill toward the opposite side of the casing. Cement Sidetracking (CS) This technique is the most straight forward. The well is not killed while pipe is tripped. the technique is called CSO (cement sidetrack opposite sides). The CSO technique has the advantage that the mill hits the casing with an angle of attack. the bottom hole tools limit the applications. and the relatively fragile cement ramp. The key enabling technology for viable through-tubing drilling is the ability to sidetrack in casing below the tubing tail. Two techniques have been used to initiate cement sidetracks. and hence is required to cut less casing (for the same dogleg severity). If the pilot hole and the exit are on the same side of the casing. such as with snubbing units. Whipstock in cement (WIC) c. Cementing sidetracking (CS) b. making this the most economical technique. The disadvantages of this technique are the short windows. CTD has been used increasingly in recent years for extending existing wells (re-entries and multi-laterals). The CSS technique has the advantage of direct application of full BHA elastic load at a known depth. and also the cement is much thicker at the top of the window. For directional drilling. all subsequent operations through the window must be made carefully and preferably without rotation. The advantages of this technique include that no iron is left in the well (the cement can easily be drilled out if necessary at a later date) and there are few opportunities for something mechanical to malfunction. Through-tubing drilling is a major application for CT drilling. a. Underbalanced Drilling (UBD) In true UBD. Combined with UBD. Underbalance drilling can be applied in combination with any other application (shallow wells. If the existing wellbore must be plugged and abandoned. the technique is referred to as a CSS (cement sidetrack same side). but it has proven safer and more efficient with CT where the sealing is provided in the injector. This drilling technique is possible with jointed pipe. technique sensitivity. through-tubing reentry drilling projects provide for the highest potential cost savings for the operator. The only limitations are those associated with one of these three applications. The procedure described above can be used if the well is theoretically deviated more than 30 at the point where the whipstock is to be set. weight on bit (WOB) Measurement. a hole deviation of more than 100 may be required for stable tool face readings while drilling (this applies to the CS technique also). • Coil Coil manufacturers have been able to meet the demands of the industry to develop tubing specifically designed for drilling. Whipstock in Cement (WIC) This technique is slightly more complicated than the CS technique. CT c. The main draw back to these units was the size and length of coil they could facilitate.9 mm in order to gain minimum bulking/reduced annular space advantage. Additional instrumentation such as internal /external pressure and temperature. Enough straight hole is drilled adjacent to the casing to make a straight rathole for the whipstock. 82.3 mm and 73. steering tool d. Due to the inability to rotate the tubing in the hole. trouble free operation but this can usually be attributed to their small size and extreme conditions that they are exposed to while drilling under balanced. coil wall thickness has increased dramatically along with yield strengths to try and extract as much fatigue life as possible out of each string of 313 .0 mm. Coil Tubing Under balanced Drilling – Challenges • Rigs In the early 1990’s when directional Coiled Tubing Under balanced Drilling first entered the market.Emerging Technologies b. a. All TTW are normally used for a near high side exit. A bottom trip whipstock is run in with a bottom hole assembly (BHA) of. The typical diameters are concentrated around 60. Through-Tubing whipstock TTW). Motor life is a key issue with Coiled Tubing Under balanced Drilling. With larger Coiled Tubing Drilling rigs for Under balanced drilling available in the market. • Tools Coiled Tubing Under balanced Drilling tools have always offered a challenge to provide reliable. conventional Coiled Tubing units were utilized with modified substructures and cranes supporting the injector over the well head. All consist of an anchor that reacts torsional and axial loads and are designed to allow the small through-tubing diameter to span from the high side to the low side of the much larger casing inside diameter. starter mill c. decreasing the torque out put to the bit and resulting in excessive motor trips. Major improvement to bottom hole assembly (BHA) and motor design has generated tools that rarely malfunction in their basic componentry. so did the Coiled Tubing drilling rigs. drilling of the formation relies on bit rotation alone. whipstock b. From a practical stand point. gama ray and resistivity readouts have been introduced to the BHA through real time signals that only CTUD can supply. The casing is filled with cement (preferably to the tailpipe) and a through-tubing directional assembly is used to drill a hole to the inside of the casing at the proper tool face angle.6 mm and 88. Some contractors have opted to utilize pipe size like 66. Several versions of through-tubing whipstock exist. When high volumes of gas are pumped through these motors the gas impregnates and swells the stator rubber. This is to allow gravity to force the upper whipstock taper to lay against the low side of the casing.7 mm. As the benefits and rewards of Coiled Tubing Under balanced Drilling grew. the equipment and tools have been proven and the well bore configuration is conducive to utilizing coil. By combining all related services into one. then the final step towards creating an economically effective operations is to integrate the services involved. circulation analysis. especially when daily costs of a multitude of services are already quite high. rather than incorporating the necessary services available through one company. Jointed drill pipe is available in various diameters and weights and has a distinct advantage over coil by replacing any section of the string when required. • Engineering One of the most critical aspects involved with Coiled Tubing Under balanced Drilling operations is the preplanning of the job by all parties involved. Reservoir fluids/gasses. Many of these issues are common to both jointed pipe and joint less pipe (i. Since Coiled Tubing has typically been implemented as a live well intervention tool. Contingency plans are always necessary while drilling under balanced with Coiled Tubing. jointed pipe operations utilize 314 .Drilling Operation Practices Manual tubing. • Standby Time One of the largest contributors to high Coiled Tubing Under balanced Drilling prices is “stand by time”. If one of the services has problems the rest continue to keep charging. There are numerous issues to consider when contemplating an under balanced drilling project. It is important to keep in mind that Coiled Tubing is plastically stressed and due to absence of connection. Proper candidate selection and job planning is critical to the success of under balanced drilling jobs. One of the major issues associated with under balanced drilling is that of borehole stability. Many of the growing number of candidates for under balanced drilling exist in depleted. and boundary restrictions are planned by directional services. technique and material. These include massive losses of circulation and differential sticking. tool sizing. it can safely be used in compression. Butt-welding of the coil through experience. Drag and buckling analysis. hole sizing depths fluids and BOP are typically referred to by Coil Company. Well bore trajectory reservoir lithology. By comparison.e. the experiences level will increase. or under pressured reservoirs where under balanced drilling serves to alleviate many of the drilling problems associated with overbalanced drilling. • Rate of Penetration Optimizing rate of penetration with Coiled Tubing must be achieved with limited weight on bit. risk will decrease and cost will be predictable. Coiled Tubing) drilling operations. this technology has always been linked with under balanced drilling. Coiled Tubing Under balanced Drilling can usually be split up into three main services: • Coiled Tubing and pumping • Production testing equipment • Directional services This separation can prove to be costly. • Integration of Coiled Tubing Under Balanced Drilling If Coiled Tubing Under Balanced Drilling is thought to be advantageous. pressures and flow rates are analyzed by the production testing company. has seen vast improvements but still creates a high fatigue area in the drill string. typically has higher friction and this can limit the ability to reduce bottom hole pressure.Emerging Technologies drill collars further down in the string (usually near the bottom of the vertical section) to provide weight and maintain the drill pipe in tension. Bent sub 3. Foam. b. reduction in bottom hole pressure below reservoir pressure can sometimes stimulate influx of reservoir fluids. In general. However. resultant increased penetration rates or improved hole cleaning leads to reduced risk of stuck pipe and reduced wiper trips. Rotators which give one option of rotating the BHA to overcome drag friction which has limited the length of horizontal wells achievable with cost. • Cost Cost. c. For example while increasing nitrogen rates may result in higher nitrogen cost per unit time. 315 . A downhole orientating sub-assembly which allows proper tool face orientation during directional drilling. • Bottom Hole Pressure Bottom hole pressure is a function of nitrogen to liquid ratio in either case. Coiled Tubing Horizontal Drilling Coiled tubing drilling for horizontal wells requires the following special purpose tools: 1. The weight of the Coiled Tubing or combination of the Coiled Tubing weight with injector force wills more than make up for the lack of drill collars. 4. As a general rule of thumbs foam qualities around 80% are preferred to minimize cuttings beds in the horizontal well bore and build section. under balanced drilling) • Hole Cleaning Optimizing hole cleaning parameters with Coiled Tubing and multi-phase flow is not a well understood science especially in highly deviated or horizontal wells. rate of penetration with Coiled Tubing is controlled by motor/bit selection and the reduction of hydrostatic pressure on the formation (i. of course. is the driving parameter behind most oilfield operations. The additional weight of Coiled Tubing due to increasing depth is taken up in friction due to helical buckling in the vertical well bore. Where effective hole cleaning can be achieved with non-foamed or nitrified fluids. Torque reactors which compensate for the reactive torque from the drilling process. The available weight on bit also does not increase with increased depth. this system is usually simpler to manage. This influx will affect the bottom hole pressure depending upon the nature of the influx (gas. oil or water) and the rate of influx. Research and developments which have specifically led to the coil being successful for horizontal drilling are:a. due to the helical nature of Coiled Tubing and the inability to rotate friction is increased resulting in the reduction of the effective transfer of weight to bit. A downhole surveying tool 2. An adjustable bent housing on PDM. Typically. Thrusters which allow higher weight to be placed on the bit in the horizontal section. it is more prudent to consider value than to focus strictly on costs of individual items in a reservoir management scheme. stable foam will be more homogeneous and make cuttings transport more predictable. By comparison experience with non-foamed multi-phase flow has experienced success with qualities around 60% or less. However.e. however good. it is felt that foam is superior to nitrified fluid (more susceptible to slugging) for cuttings removal. Liquid in flux will tend to be self-regulating in under pressure formations while gas influx can often result in significant unloading of the well bore. Drilling Operation Practices Manual Coiled Tubing Life Failure of coil tubing is mainly due to the repeated bending and plastic deformation of coil tubing on and off the reel and gooseneck during Coiled Tubing drilling operations. CT Failure Causes Statistical analysis of CT failure causes are as follows: 1. Corrosion 51% 2. Overload 21% 3. Mechanical damage 12% 4. Manufacturing defects 07% Though the mechanism for predicting Coiled Tubing life is not fully understood, still it has been possible to predict very closely actual life performance. Coiled tube working life is affected by Coiled Tubing size and thickness, internal pressure, yield strength, reel diameter, gooseneck radius, operating conditions (corrosion etc.). Based on scientific studies carried out, it shows that Coiled Tubing life can be greatly increased by increasing Coiled Tubing wall thickness and Coiled Tubing strength, while the Coiled Tubing working life decreases under high internal pressure, corrosion, butt weld conditions etc. It can be seen that; 1. 2. 3. 4. 5. 6. CT life increases with smaller OD of CT CT life increases with higher wall thickness CT life increases with higher yield strength. CT life increases with increase in reel diameter and gooseneck radius. CT life reduces with increase in internal pressure. CT life reduces with corrosion and after operating conditions. CT Metallurgy Precision Tube Technology, Quality Tubing Incorporation and South Western Pipe Inc. are the major manufacturers of these coils. The steel used for making coils is mainly High Strength Low Alloy Steel (HSLA). A typical steel composition of A606 alloy type 4 modified is as follows: Composition Carbon 0.1-0.15 Manganese-0.6-0.9 Phosphorus-0.030 max. Sulphur- 0.005 max Silicone 0.3-0.5 Chromium-0.55-0.70 Copper-0.2-0.4 Nickel-0.25 max Physical Properties Minimum yield strength 70 ksi Minimum tensile strength 80 ksi Minimum Elongation 30 % Maximum Hardness 22C Rockwell Capabilities (Advantages) Of CTD a) Fast trips A primary consideration of CTD is that the pipe is continuous, and does not require the makeup of connections during operations. This feature allows for faster handling and tripping speeds that can contribute to reduced costs. 316 Emerging Technologies b) Drill and trip underbalance Coiled tubing systems have been designed to operate under live-well conditions and have a commendable safety record in performing this type of work. Traditional drilling practices include using the drilling fluid as a pressure control system (first line of defense). Coiled tubing systems, alternatively, have first and second lines of defense in their stripper rubbers and BOP systems that render the need to have weighted drilling fluids redundant. Both drilling and tripping can occur while the well is under pressure. c) Small footprint The coiled tubing drilling unit is significantly smaller than a conventional drilling unit requiring less wellsite preparation and is very suitable for urban areas, remote offshore/land locations and other locations where land availability and environmental impact is of great importance. d) Direct control and Monitoring The continuity of coiled tubing merits use of electric wire line in the tubing that facilitates continuous, high quality two-way telemetry between surface and downhole for real time data and control. e) Considerable safety advantages • Closed system permits continuous well control even when tripping. • Quicker shut-in in emergency situation. • Easier to handle a kick. • Wellbore isolated from atmosphere any time that is desirable. • No personnel needed near the wellhead during most operations, including trips. f) Reduced environmental impact CTD operations generate less noise and fewer emissions. Smaller diameter wells generate smaller volumes of cuttings. g) Portability As coiled tubing drilling does not require a mast, rotary table etc., the equipment required for CTD is much smaller than for a conventional rig. Hence mobilization, rig up and rig down are faster. h) Continuous circulation The circulation system in CTD operations is so complete such that circulation can continue even while the trip is taking place. i) Slim hole capabilities With larger diameters coiled tubing now available, coiled tubing can be used to drill or core slim holes. Further the operator can opt to complete the well with coiled tubing in place, thus eliminating the casing. Slim hole technology can further be applied to; • Vertical deepening • Small cased, wellbore re-entries • Short radius re-entries. • Horizontal drilling with coiled tubing. Limitations Of CTD a) Annular Velocity for cuttings removal Sufficient annular velocity is required for removal of drilled cuttings. However, it is limited by three factors: • Coiled tubing pressure losses. 317 Drilling Operation Practices Manual • • Flow rate for downhole motor. Flow rate for MWD. b) Downhole weight on Bit (DWOB) WOB is critical at the end of the build section and at TD. The bending friction force in the curved section affects the DWOB and consequently the maximum reach. Coiled tubing OD and wall thickness have significant effect on reach. WOB of 100 lbs per square inch of bit diameter is required to achieve practical ROP. Helical buckling of coiled tubing in the 9 5/8" casing will increase the friction forces and thus reduce the weight that can be applied on the bit. If coiled tubing is run inside 7" casing or smaller, relatively more DOWB can be supplied to the bit. c) High Circulating Pressures Friction losses in the coiled tubing results in higher circulating Pressure and tend to limit the flow rate and hence effects the selection of mud motor. Well-designed drilling fluid properties should help in decreasing friction losses without sacrificing carrying capacity. d) Tension The maximum allowable tension depends on the pipe OD, ID and the fluid strength of the pipe. e) Torque The maximum stall torque of the drilling motor will impact the selection of coiled tubing pipe. The stall torque depends on the flow rate th rough the motor. If the pump rate is reduced, the stall torque is also reduced. f) Short Coiled tubing Life One to two wells can be drilled with the same reel, depending on the drilling depth and problems encountered while drilling. Number of cycles over the gooseneck, in addition to depth and pressure should be closely monitored to determine if the CT reel can drill a second well. Heavy wall pipe and high yield strength improve the CT life. g) Weight and size limits. In order to do larger jobs, it may be required to take multi reels to location, weld or connect the coiled tubing on site and spool it on a larger work reel. However, the cost will be considerably high. h) Limited Reach The amount of the reservoir drained is generally a function of the length of the horizontal section. The reach of the coiled tubing is limited by the limitations in the amount of weight transmitted to the bit. i) No rotation from surface The inability to rotate the coiled tubing from the surface makes directional drilling more difficult, increase the possibility of sticking, inhibits cutting removal and increases pipe drag. Frequent wiper trips are required to compensate for this absence of pipe rotation. j) Limited fishing capabilities Due to the very small clearance especially in slimholes and re-entry drilling, availability of reliable fishing tools is a major concern.Thus in many cases stuck ups requiring fishing cannot be liquidated and often results in repeat sidetracking or abandonment. 318 Emerging Technologies k) High cost of operations CTD operations for normal wells are costlier than conventional rig operations. Techno-Economic Feasibility There are many factors that go into determining both the technical and economical feasibility of CTD candidates. Of these factors which influence the economic feasibility, some tend to increase the competitiveness of CTD while some tend to reduce it relative to other possible solutions. These economic parameters include; the number of wells to be taken up, production benefits from drilling underbalance and possible reduced cost of through-tubing operations. Technical feasibility While advances in CT services have tremendously increased its usage, limitations still exist. This is especially true for drilling projects, where the CT equipment is very small when compared with a conventional drilling rig. A thorough review is required to ensure that the CT is capable of performing the tasks that are required of it to drill. To optimize drilling, the operator must optimize the rate of penetration, trip time and hole cleaning. However, the size of the pipe introduces a number of constraints on the operator when drilling with CT. To achieve the best rate of penetration, the operator must optimize the hydraulic and mechanical power at the bit. Yet, the small CT limits the flow rate that can be achieved through the pipe. The depth of the hole is also limited by the tension that can be put on the CT while the diameter is limited by the annular velocities that can be achieved outside the CT. Therefore, to determine the technical feasibility of any CT drilling project, each of these items must be evaluated. The following table elaborates the above; Information Hole, casing and tubing sizes Hole, casing and tubing depths. Motor Size Well trajectory and Total depth CT Size and wall thickness Injector capacity Influenced parameter Annular velocity, CT Reach/ WOB CT reach/WOB Flow rate, annular velocity CT reach, WOB, Coil Tubing tension Flow rate, CT reach/ WOB, CT tension Depth, CT size Coil Tubing drilling has limitations, depending on the desired application in drilling. Considering the limitations, coil tubing drilling is specially suited for certain applications. Economical Feasibility Generally, the economic feasibility of a coiled tubing drilling job depends on the location and scope of the project. Evaluating Coil Tubing differs a bit from evaluating a conventional drilling job. With a conventional rotary rig; the required equipment typically arrives on location with the drilling rig. These rigs are built to be mobilized and demobilized many times. In contrast, with a Coil Tubing drilling unit, ancillary equipment is not typically part of the basic rig package and must be rented separately. The pipe, injector head, power pack (for CTU only), Coil Tubing blow out prevents (BOPs) and control cabin can be expected with the Coil Tubing unit. 319 Drilling Operation Practices Manual The mud equipment, fuel tanks and pump, generator, electrical equipment, and accommodations are some of the additional surface equipment that may be required. If a job requires pulling or running a jointed completion, a jack-up frame and power tongs will be needed, in addition to the normal completion hardware. Conventional drilling equipment will be required for the bottom hole assembly. For vertical holes, this equipment should minimally include bits, drill collars, mud motor and drilling jars. For deviated /sidetrack holes, other equipment, such as steering and orientation tools, monel drill collars, whipstock, casing collar locator, cement bond tools and mills for window milling, may be required. Acquiring all this additional equipment can be costly and time consuming. For this reason alone, some Coil Tubing drilling jobs may not be feasible and multiwell projects may be required to justify the cost associated with the mobilizing this equipment. The future of Coil Tubing drilling as a commercially viable alternative in the coming days will depend on developments such as the price of oil and the rig day rate charges and other developments such as Coil Tubing drilling specific technology. Some areas for improvement, which will directly impact the economic viability of Coil Tubing drilling, are: Shorter more flexible BHA, which will allow higher build rates. More reliable and sensitive orienting tool which will allow wells to be steered with more precision and faster. More sensors including for WOB, resistivity etc. Better understanding of Under Balanced drilling (UBD) which will allow us to better optimize potential benefits of UBD for different reservoirs. Improved casing exiting techniques will allow wells to be drilled more economically and in a more wide variety of conditions (casing size, inclination). Hybrid Coil Tubing drilling equipment will bring more versatility and efficiency by allowing operations such as running jointed tubulars in addition to drilling in a single unit. Conclusions Unless there are specific advantages to be gained from using coiled tubing it is difficult to be commercially competitive. The are however, specific types of drilling operations in which Coil Tubing has a technical advantage and in these situations the economic case is much more easy to justify. The areas in which there are distinct advantages to using coil tubing are: Through-tubing drilling where the cost of pulling the completion string can be avoided and re-entry is done through the existing completion tubing. Coil Tubing is a safer and more reliable way of drilling wells in an underbalance state with numerous production benefits. For pilot or relief wells; Coil Tubing with its pressure seal at surface is ideally suited to these types of wells which are difficult to control by the drilling fluid alone and thus tend to be quite dangerous. Offshore platforms or remote locations where the cost of rig is often prohibitive. Location of candidate wells – whether the well is drilled in a remote location or an urban area, offshore or on land, the amount of site preparation needed etc, will have an impact on the commercial viability of Coil Tubing drilling. In areas with environmental requirements, Coil Tubing drilling is often advantageous because fewer rig loads are required and resulting location is smaller than that of a conventional drilling rig. In jungles, mountainous regions, national parks, and urban areas, a small wellsite footprint is desirable to reduce environment impact. In offshore the smaller location need of Coil Tubing drilling unit becomes especially attractive because many platforms have limited deck space. 320 Emerging Technologies One of the major factors in the analysis of the economic viability of Coil Tubing drilling is the number of wells to be done in a campaign. There are significant start up costs associated with this service. Increasing the number of wells to be drilled or going to continuous operations would reduce these costs. Continuity of personnel and hence improved efficiency through experience, reduced mobilization costs etc. can be realized in continuous operations. IV. Slant Drilling Slant Drilling is the technique of drilling from a slant angle at the surface (45° max. in 1.5° increments), and zeroing in on shallow-depth targets. Slant drilling is an ideal option for reaching target zones that are relatively shallow and may sometimes be necessary to negotiate difficult terrain conditions, such as drilling under bodies of water, population centers or environmentally protected areas. A conventionally drilled directional well is typically started with a vertical section from surface. Specially designed bottom hole assemblies or mud motors are then used to deviate the well at an appropriate angle to reach the target. In contrast, slant hole drilling attains the shortest drilling distance by allowing the well to be spudded at an angle aimed directly at the target. With the proper drilling rig, the well can be drilled straight to the target. The slant hole path can be deviated additionally with the use of conventions directional tools, including into a horizontal direction. The major applications for this technology have occurred in the shallow depth, heavy oil areas. The multi-well pad approach of slant technology is conducive to the drilling of the numerous wells required in these areas. Other applications include wells that require considerable horizontal displacement, especially at shallow depths. Since the 1960fs, the drilling industry has experimented with the concept of automated drilling rigs. In Canada during the 1970’s, small hydraulic rigs were developed for shallow drilling. These rigs featured hydraulic power swivels and partially automated pipe-handling systems that improved 321 Drilling Operation Practices Manual both drilling performance and rig move times. An offshoot of this technology was the development of the first slant-drilling rigs which could spud from vertical to 45°. The 1990s saw the revival of slant technology, which was used most successfully in heavy-oil drilling at shallow depths. This differed from directional drilling in several ways: • It followed a shorter, more direct route. Wells could be spudded at an angle—usually 30[degrees] to 45[degrees]—and then aimed straight at the target. • It was less expensive, faster and more productive than directional horizontal drilling. • Slant drilling allowed shallow heavy-oil deposits to be developed from one or several pad locations, which vary in number of wells. Pad drilling also emerged as a way to minimize environmental impact because it allows multiple-well access to larger areas and targets beneath sensitive areas, such as lakes and towns. Precision Drilling Precision Drilling, Canada is the worldwide leader in slant rig technology. Precision Drilling, a division of Precision Drilling Ltd., is Canada’s leading drilling contractor with a well maintained fleet of more than 229 rigs including singles, doubles, light triples, heavy triples, coiled tubing rigs, a surface hole rig along with the skilled personnel to drill at any depth. Their fleet consists of 15 singles, 95 doubles, 45 light triples, 41 heavy triples, 11 coiled tubing rigs, 16 singles and 21 Super Singles. The Super Single rig is ideal for drilling multiple wells from a single location (pad drilling) including drilling in environmentally sensitive areas. For well drilling up to 3000 metres in depth, Precision Drilling manufactures and operates Super Single rigs which feature top drive units, longer range III drill pipe, and automated pipe handling capabilities. These rigs are capable of slant drilling, which is done by tilting the rig mast from vertical. Slant drilling is used to drill several wells from one location, saving the time and avoiding the environmental 322 remote control features that minimize manual labour.Emerging Technologies impact associated with setting up a rig in a number of different locations.): 40’ (12m) (PIN-TO-PIN) STATIONARY CENTRAL COMPLEX 323 . control processes that alleviate safety concerns. has evolved over several generations to offer such benefits as fast and simple movement between sites. developed in the early 1990s. MULTI-WELL PAD CONFIGURATION `ALL PDI DRILLING UNITS SHOWN IN THE `MULTI-WELL PAD RIG CONFIGURATION’ ALSO CAN BE ARRANGED TO ACCOMMODATEA `SINGLE-WELL PAD’. and the ability to drill a number of different kinds of wells. Weatherford International has in September 2005 completed its acquisition of Precision Drilling Corporation’s Energy Services Division and International Contract Drilling Division. A NUMBER OF `SUITCASES’ CARRY POWER AND DRILLING FLUIDS BETWEEN THE TWO COMPLEXES. Slant drilling is also being used by Precision Drilling with increasing frequency in support of the steam-assisted gravity drainage method of recovering bitumen from oil sands. Once merely identified as a slant drilling rig. the Super Single rig has evolved to become a known versatile drilling rig that is competitive in many drilling operations within a 3000m depth range and is unmatched by any land rig today. Hence now Precision Drilling International is a division of Weatherford and is totally independent from Precision Drilling Corporation. Precision’s Super Single rig. TYPICAL SUITCASE LENGTH (EA. LEASE DIMENSIONS DICTATE THE NUMBER OF SUITCASES REQUIRED. This versatility makes the Super Single rig ideally suited to shallow land operations throughout the world. which were adequate for the shallow gas wells drilled. Top Drive. Fluid Handling On present pads. Advances in slant-drilling technology and experi-ence have expanded the slant-drilling role. The entire pipe-handling as-sembly on the top drive also can rotate 360°. Casing: Up to 18 5/8" (473 mm) 11.Drilling Operation Practices Manual A new generation slant rig’s main rating are as below. It now can be considered an economic alternative to vertical development in many cases. When running casing. Top Drive Speed: 150 RPM 13. Tubular Handling On most slant rigs.2 mm) (RII) 9. Hole Size: Up to 26" (660 mm) 10. The initial top drives used on slant rigs were modified power swivels. Depth Rating: Up to 9. a wrench was built to spin and torque drillpipe. Pipe Handling The latest generation of top drives used on slant rigs now have hydraulic elevators. this feature acts as an infinite-position stabbing board and provides accurate thread alignment. and casing in a single opera-tion.800’ (3. Slant Rig Mast Adjustable Vertical To 45º 4. The advantages of sumpless drilling include the following. collars.000 ft-lbs 12. Top Drive Torque: 30. Mast Capacity: Up to 150 tons (133. The mud is reused up to 16 times. Drill Pipe: Range III – 13Mtrs Rig-Design The initial concept for slant drilling was to develop shallow reserves that could not be reached economically with conventional direc-tional drilling. only one makeup/breakout is required for each joint. Pull Down: 100. Hook Load: 125-150 Tons (111. these top drives have makeup/breakout wrenches allowing connections to be made up/out in the mast as required.500 daN) 7. 324 . This is accomplished with a hydraulic pipe boom that raises pipe from horizontal to the well bore inclina-tion. The top drives used on the newer slant rigs are 450 kW units capable of 20 000 N-m drilling torque and 320 rev/min. Torques up to 100 000 N-m can be generated with these wrenches. Overall Height: 75’ (23m) 6. Travelling Equipment Guides 5. 1. Drill Collars: Up to 8" (203. The main factors that have contributed to improved rig performance during the past decade include the following.000# (44. sumpless drilling is used. Drill pipe and casing are made up by the top drive. thus. In addition.500 daN) 8. all tubulars are laid down when tripped. a power tong can be added with minor rig modifications. When ac-curate casing torqueing is required.000m) 2.500 daN) 3.300 -133. Ex-perience with the latest generation slant rig has shown sufficient improvements in performance to reduce drilling costs below those experienced on equivalent vertical wells. Using con-cepts adapted from large power casing tongs. The catwalk end of the rig is mounted on a small skid plate. 2. Each eight-wheel bogie on the suspension is mounted on a turntable allowing rig movement in any direction. Agitators on each compartment to improve solids removal and prevent solids loading during extended pad operations. 2. Sever-al safety benefits can be attributed to slant drilling. By reusing the drill fluids. and BOP hy-draulic lines run in a heated enclosure with the electrical lines strung above the transfer cases. These rigs are capable of rig release to spud times of <5 hours. This reduces the environmental effects of the drilling operation significantly. 2. Linear motion shakers at the flow line virtually eliminate solids-generation problems during fluid transfer. cleanups are simplified. As pad drilling progressed. Because they are light. Remote Tank Design To allow for sumpless drilling. water tank. Rig Mobility The first slant rigs were designed for single-well ap-plications. Adjustable skimmers between tank compartments to allow for either top or bottom equalization.Emerging Technologies 1. Pad rigs now are designed with heavy-duty 16-wheeI suspensions beneath the substructure. This sys-tem was adequate but caused freezeup problems during winter op-erations. Safety The development of slant-drilling rigs has resulted in op-erations that are safer than those of conventional vertical rigs. degasser. Once the rig load has been placed on the sus-pension. the transfer of fluid and power between the main and remote rig sys-tems for pad drilling became more complex. Each injector should be equipped with an agitated mixing tank. A separate suction manifold between the first two compartments to allow flexibility for the cen-trifuge suction. The drilling-fluid. umbilicals on mechanical rigs used cable stands and flexible hose. steam. 1. All plumbing for the rig’s well control remains fixed. Today’s electric rig umbilicals typically consist of 10-m enclosed sections. and trip tank are incorporated into this tank. Fluid Transfer In the latest generation of slant rigs. the remote mud tank was designed with the following features. Only a small remote sump is required. the shaker tank. Initially. Rig placement on the pad is simplified because individual sumps do not have to be worked around. 325 . 1. water. these rigs are moved with two bed trucks by use of winch lines on either end of the rig. the ability to move the en-tire drilling module in a single load was necessary. Transfer Umbilical With the advent of electric slant rigs. The following items are designed into the tank. The entire rig can be jacked up on hydraulic rams allowing the suspension to be positioned as required. They were moved in a manner similar to conventional trailer rigs. The choke manifold. Variable-rate chemical injectors for injecting flocculent directly into centrifuges while clearwater drilling on top hole. and doghouse are skidded to the next well slot. 3. This allows for the same well-control hookup regardless of well bore inclination. a small tank is situated at the rig flow line. 4. rig move accidents that occur during this phase of the-rig move are eliminated. Programmable Logic Control (PLC) Most functions for the latest generation of slant rigs are controlled with a PLC. the ability to program safety interlocks is very easy. the main rig module requires very lit-tle rig up or rig out on an inter-well move because the entire unit is moved as one piece. As a result. Rig crews are never in direct contact with tubulars on the drill floor. accidents while running casing are virtually eliminated. Blow Out Preventer (BOP) The BOP is nippled up in a slant mode which aligns with the tubular running path. a derrickman is never required to be in the mast because all pipe is laid down on every trip. The topmost pipe is in tension and will be rubbing on the wear bushing in the wellhead. In addition to efficiency gains. These features include: Hydraulic tubular handling arm Hydraulic power wrenches for make-up and break-out of tubulars Hydraulic power wrench carrier Hydraulic top drive Hydraulic BOP handler and hydraulic pulldown Pneumatic tubular slips Hydraulic pipe tables for gravity indexing of tubulars and casings to and from the catwalk Hydraulic tubular kickers and indexer systems that index tubulars from the catwalk individually into the tubular handling boom. including the power tong operation. Picker Crane Slant rigs do not have V-door ramps. and mud pumps are never moved on inter-well moves. The hydraulic pipe tables lift joints of drill pipe to the catwalk. Because all these functions are programmed. The PLCs program can be updated continually as new safety and equipment concerns are identified. this high level of equipment control has the specific benefit of drastically reducing connection times. the rig’s remotecontrol features reduce the crew’s exposure to harsh weather. or kick tubulars out of the handling boom and onto storage racks or tables. Remote Control Features Fully mechanized. where the hydraulic pipe arm is located. a hydraulic picker is used. Again. In addition. using state-of-the-art technologies to minimize manual labor. thus minimizing the wear and tear.Drilling Operation Practices Manual Pipe Handling All pipe handling is performed from remote lo-cations. the main power generation. The indexers then roll the joints onto the catwalk and into 326 . the rig crew is removed from directly handling heavy equipment. thus. In addition. mud system. The string is further supported by an hydraulic arm below the drill floor which moves the tubular path to minimize contact with BOP. Slant rigs are not equipped with catheads or spinning chains. Rig Moves During pad drilling. Running Casing The entire opera-tion is hands off. The rig crew cannot perform a sequence of steps that may lead to an accident or equipment damage. To allow equipment to be transported to the drill floor. run the equipment. The BOP Handler accommodates a 540mm annular BOP Personnel are required to operate the controls. disassemble the rig and rig up at the next drill site. reducing the employees’ exposure to lifting related injuries. The rams are fully retracted through all stages and are pinned hydraulically in place. eliminating the labor-intensive and dangerous component of tubular handling. a fraction of the usual three to five minutes required by conventional single and double rigs. The application of a power wrench mounted in a hydraulically positioned cradle reduces the need for manual tongs. Safety Benefits Special consideration to areas of exposure of personnel to hazardous operations is given during the application and control of the equipment throughout the drilling rig. the Super Single rig does not require personnel to be in the mast for anything besides servicing or visual inspections. The mast is hydraulically pinned into position by a remotely operated pinning system. but also improves safety considerably. The slip table is designed to accommodate most tubular slip sizes into the power link mechanism. perform basic maintenance.Emerging Technologies the pipe arm. 327 . A top drive screws directly into each joint. No pins other than safety pins have to be installed or removed manually while the mast is at height. eliminating the need for an awkward and heavy kelly. The entire connection process takes less than a minute. Being a single style of rig and using equipment to lay down and pickup pipe in all tripping operations. This not only makes the entire process more efficient. Mast-raising rams are required to be laid down during drilling operations. The chief difference is that the equipment does most of the work. which lifts the joints individually to the derrick. Range III tubulars reduce the number of times and operations required to run tubulars. Extended-reach development of reservoirs below lakes and rivers now is more feasible. catwalk and racking areas. Slant Drilling Applications 1. which can affect the safety of rig operations. 10.a all high exposure operations on conventional drilling rigs.and fatigue-related labor issues. 45°. 4. Maximization of hydraulic and pneumatic control for as many functions as possible can reduce manual. Be-cause these reservoirs were shallow. The tubular indexing system eliminates the need for personnel to be working on the catwalk during drilling. Slant drilling beneath city and town boundaries where it is unfeasible to obtain surface leases above the target horizon 5. highways. Precision Drilling has experienced a 58% reduction in drill floor recordable incidents on Super Single rigs relative to the remainder of the fleet. Surface sites for shallow wells frequently are set too far back from the downhole targets to be reached economically with convention-al directional-drilling techniques. The true vertical depths (TVD’s) of these wells typically were 500 to 800 m. 8. The tubular handling arm eliminates several tubular operations from the drill floor. Plans are in progress for 2000 to 3000 M lateral displacements under lakes in southern Alberta. conventional directional drilling could not provide sufficient lateral displacement to penetrate the targets.Drilling Operation Practices Manual Opportunities are constantly being evaluated to reduce further exposure. lease. Slant drilling was mainly done for exploiting primarily shallow gas reservoirs under bodies of water. Horizontal drilling in reservoirs that require large lateral dis-placements before turning horizontal now can be achieved. The IADC (International Association of Drilling Contractors). a 300-m displace-ment requires only a 31° well bore path from surface. The two operator controls are located beside one another in a way that maximizes operator view for all operations in the well line. 3. This greatly minimizes the environmental effects of road. 6. Using slant techniques. Future applications envisage up to 3000 m of lateral displace-ment in a well of TVD . Slant drilling for installation of pipeline crossings beneath rivers. and tie-in construction.e. CAODC (Canadian Association of Oilwell Drilling Contractors) and Precision Drilling note that the highest percentages of safety-related incidents occur on the drill floor.3000 m (i. Slant drilling extended-reach wells beneath rivers and lakes. A full section of land (four wells per section) can be drilled from a common surface location. Pad drilling for shallow wells in environmentally sensitive regions. reducing staff turnover. 328 . 9.and beach-front approaches 7. These reser-voirs lie at approximately 1000 M TVD. tripping or while running casing.. a 1:1 TVD/lateral displacement ratio). v-door and catwalk . The simple design of the top-drive and the inherent features of top-drive drilling also provide a safer work environment. The application of true proportional control on hydraulic functions improves operational control. Environmentally sensitive regions are excellent candidates for slant drilling. Up to 500 m of lateral displacement could be achieved with the maximum al-lowable spud angle found on slant rigs. The latest generation of Slant rigs enable drilling of wells requiring large lateral displacements with minimal directional costs. 2. and ocean. Above average usage rates and consistent operator use provide a stable working environment for employees. The application of improved control of equipment ensures that these percentages are on the decline. The hydraulic pipe tables and casing racks greatly reduce personnel exposure to the hazards of rolling tubulars. which are the highest incident percentage in drilling operations. Slant wells to avoid irrigation systems. In PetroZuata’s case.. the rig can be prepared to move in two hours and rigged up in the same amount of time. The top-drive capabilities also reduce the risk of experiencing stuck pipe. attributes that are essential for the Surat Block. Part of the rig’s efficiency also has to do with the top-drive design. Petro-Canada etc. super single slant rig “PD 709SLE”. Hence the rest of the locations were drilled in the vertical mode. The rig was chosen as it was particularly suited for drilling applications in environmentally sensitive and limited size locations. The small size may pose problems for some of the larger projects. Once logging is completed. it is easier to orient downhole motors and back-ream with the rig. Rather than manually racking the drill pipe on the rig floor before logging. have used the rig for well depths of 1. Normally. Indian Scenario Precision Drilling had been awarded a drilling contract by Niko Resources Ltd. Overall. Drilling was to have been carried out for reservoirs below the city. 329 .500 ft (500 m to 2.193 ft in one day. In a eight month period. The rig is much faster because you’re operating at a higher range of rpms and you can have much quicker connection times. as the drill pipe is 45 ft (13 m) long—that’s 50% more than conventional single rigs. the casing can be run immediately because the pipe has already been laid down. it prospects in the inaccessible areas were down-graded. PD 735 Super Single rig broke a world record in drilling time.000-ft measured-depth horizontal wells at a true vertical depth of 2. Perhaps one of the biggest time savers. the rig’s mobility was a significant factor in improving the efficiency of PetroCanada’s drilling program. The approximate contracted operating cost per day in 2002 was US$ 13. the rig had no significant limitations with the exception of its drawworks and pulling capacity. and after re-evaluating the seismic data. Petro-Canada has been able to move the rig and spud the next well in less than two hours from the time it’s released from the previous well.500 ft to 7. many companies like EOG Resources Canada. Niko utilized a semi-automated. Later. Also observed are quicker connection times. With four pads and 50 wells. Penetration rates of 500 ft/hr (150 m/hr) have been experienced almost doubling the drilling efficiencies.. Continuous back-reaming was also listed as an advantage of the rig because each joint is handled by making up the top drive into the pipe. The rig was to have drilled an estimated 15 wells on the Surat appraisal program in both vertical and slant modes. which use the standard 30-ft (9-in) drill pipe.Emerging Technologies World Scenario & Advantages Over the past many years.000 in slant mode. The rig routinely drills 8. The necessary torque for the casing can be applied by the rig’s top drive system. achieving 5.100 ft without any issues. is the Super Single’s design of the remote-controlled tubular handling equipment and the top drive. to conduct work on its onshore Surat Block in the Gujurat state of India. The rig can pick up casing joints as regular joints and run casing without needing a power tong. Multi well pad drilling was carried out for the development wells.000 in vertical mode and US$ 18. The rig (PD 735) used by PetroZuata took only 15 hours to move to another pad. Due to its size and compact design.300 in). However after drilling the first appraisal well in slant mode. a hydraulic arm operated remotely by the rig crew lays the drill pipe on the pipe racks. conventional rigs take at least 30 hours to move from pad to pad. because of greater flexibility and savings in rig time and operating costs due to the rig design’s efficiencies and ruggedness. more wells were drilled by Cairn Energy in Rajasthan using this rig in vertical mode. PetroZuata also experienced faster rig moves compared to conventional drilling rigs. In addition to the same 50% reduction in connection time. Inc. or kick tubulars out of it onto the racks or tables for storage. The rig has reduced connection times. 4. horizontal well sections and a single or dual-speed. to 30-45 sec for this slant rig compared with 3-5 min for conventional. These designs incorporate the latest drilling technology to accomplish a variety of drilling tasks. into the tubular-handling boom. the latest generation of slant rig designs. The rigs have remotely controlled tubular-handling systems. known as “Super Single” enables newer rigs to do more than drill at an angle. without any manual intervention. 330 . 2. Casing in conventional lengths (API Range III) with diameters up to 133/8 in. pull-down system for inducing artificial gravity on long-reach. and the carrier for positioning it. Heavy-weight drill pipe in conventional lengths (API Range II). He also operates the hydraulically powered. masts that can tilt from vertical to 45 degrees in 1. he places all tubulars in the hydraulically activated tables and racks. The rig’s control processes help to alleviate this problem. telescoping double. use remote controls to accomplish the handling of all tubulars. and the fluid containment system keeps to a minimum any fluid loss due to the angle of the BOP while maximizing fluid head for fluid transfer to the shale shakers Safety Benefits. 3. On these rigs. along with swift rig up. The drilling system is designed around the use of: 1. He also controls a tubular kicker and indexer system that can index tubulars from the catwalk. The phrase ‘super singles’ when the rigs were extended from Range II drillpipe that’s 9 m long to Range III drill pipe that’s 13 m long. generating minimum disturbance to the wellsite environment. Once the tubular is on the rig floor. two operators. Similarly. When he moves the desired tubular to the catwalk. The derrickman operates a hydraulic power wrench for tubulars makeup and breakout. the derrickman remotely operates the power wrench for makeup. directional. Most injuries to drilling crews occur while they are handling tubulars. The driller remotely operates air-powered tubular slips for drill tubulars and hydraulic catheads for use with manual tongs when a power wrench is not applicable. One key advantage to starting a well at a sharp incline is the reduction of wellbore build rate from vertical to horizontal . rig down. and incorporate safety and control features. the driller and the derrickman. Removing personnel from hazardous environments and heavy. 45-ft lengths of drill pipe (API Range III) with diameters up to 51/2 in. vertical.5 degrees increments. repetitive work typically involved in tubular handling has resulted in a significant improvement in rig floor and catwalk safety statistics associated with these rigs. individually. and reversible single or dual-speed top drives. and moving capabilities as priorities. reversible top drive with integral traveling block and orientation lock. The driller uses a remotely controlled hydraulic system to set the blowout preventer (BOP) at the correct angle for the wellhead. the hydraulic tubular-handling boom lifts it to the rig floor. when coming out of the hole. with most of those injuries occurring on the rig floor and catwalk.Drilling Operation Practices Manual Summary Although slant drilling is a technology that has been in use for many years. and horizontal drilling. These rigs are designed for slant. The new rig also could drill multiple shallow wells from a single pad. Using the automatic controls. Drill collars in conventional lengths with diameters up to 8 in. The system requires no roustabouts or roughnecks to physically move tubulars from racks to the catwalk or to manipulate them on the rig floor. The rig handles casing and drillstring tubulars without exposing employees to the heavy labor normally required on conventional drilling rigs. The remote-controlled hydraulic tubular handling boom enables the derrick-men to safely remove and add tubulars and accessories to the drillstring mechanically rather than manually. or other single slant rigs. the tubulars are laid down and returned to the racks or tables via remote control.a reduction in dogleg severity-during the drilling of very shallow horizontal wells and reduced measured depth of a directional well. Emerging Technologies The boom also provides for the handling of casing. Pad drilling for conventional shallow depth reserves can be done economi-cally and with minimal environmental effect. 4. Well cost for shallow directional wells reduces since only holding assembly is used and well’s measured depth is reduced in slant drilling. Venezuela and Kazakhstan. requiring only eight loads for well-to-well movements on a pad (including boilers and tubulars). China. A tri-parameter auto-drilling system enables the controls to make adjustments on its own if drilling should deviate from safe operating parameters. Conclusions The use of slant drilling is a proven economic method of drilling in many countries worldwide especially in Canada. deviated wells. and under-balanced wells to 3. on which the signals for the various rig systems are multiplexed. thus reducing the potential for human error. The rig design is also simple and compact. The rig can also be moved one to two miles in four hours and is easily disassembled for highway transportation. By presetting safety limits on other operating parameters. 1. reduce the many control lines to one. can lower production operating costs for wells that will re-quire artificial lift. 7. Advances in drilling-crew safety can be achieved through de-sign improvements to drilling equipment and techniques. Slant drilling. The sixth-generation rig design uses “programmable logic controls” to monitor the position of traveling blocks and employ a fail-safe disc brake to control the block speed as it approaches the crown. movements on a pad can be completed within two hours. 331 . The result is a simpler system that can be rigged up and down more quickly The rig can be moved quickly. as compared with conventional directional drill-ing. The system also slows the block as it nears the rig floor. Brazil. The tubulars can be moved at any time without breaking down stands. the control system is programmed to sound alerts and keep the drilling system operating within safe limits while the driller analyzes any deviations and takes corrective action. hydraulic safety lockouts for mast position pinning and crown maintenance reduce the need for personnel to climb the mast. Drilling crews no longer must move tubulars from racks to the catwalk or position them on the rig floor. Recent advances in slant tech-nology have made it possible to exploit many fields up to 3000 m deep at costs below those for conventional vertical development. The latest generation of slant rigs have proved the following. The slant rig’s tubular handling system lays down each joint during every trip out. PLCs. PLC of medium-sized electric land rigs is very effective. Venezuela etc. Mexico. 5. China. 6. This level of PLC control enhances process efficiency and helps prevent potential damage to the rig floor and the crown. This is achieved through smoother well bore profiles that minimize rod and tubing wear. for shallow development wells mainly in the range of 400-800 M TVD.000 m (MD). Sump less drilling can be achieved economically on medium-depth land rigs and will reduce the environmental effect of drilling-fluid wastes significantly. 3. Drilling Efficiency and Versatility The rig can drill vertical. In some cases. 2. These rigs are presently used in Canada. though the average measured depth of wells drilled worldwide by slant rigs is around 950 M. Beyond that. Top-drive technology can achieve both economic and perform-ance advantages over rotarytable drives on medium-depth land rigs. The main disadvantage of this technology apart from the high cost is that since the wellhead is tilted work-over can be done only by Slant Rig and not by conventional rig. This concept leads to the possibility that a viable solution to the task of drilling increased diameter holes could be a bit that offers substantial expansion capabilities while still presenting full cutting structure to the formation. Besides the direct costs associated with reaming. To achieve this and to maximize drilling performance requires a device with a formation cutting structure indistinguishable from a standard PDC drill bit but capable of being withdrawn through a restriction significantly smaller than the borehole size just drilled. severely affected total well economics. With the development of rotary drilling and increase of borehole depths. Because of its unique geometry. which could be run down and pulled out of the bottom hole inside the casing or drill pipes by the wire line was the principal answer. a bi-center bit can freely move to one side of the hole during the trip through the casing and effectively drill a hole size larger 332 . One embodiment of the technique of drilling with casing requires a bit that can be retrieved through the existing casing string. In some cases. ideas were developed by engineers for decreasing drill string tripping time to change the worn bit.This kind of tool provides the possibility to realize the method of drilling without pulling out the pipes (DWPP). The development of a bit. Hole Enlarging & Under Reaming Introduction When using standard reaming techniques to enlarge open hole sections. operators have normally drilled a pilot hole to the next casing depth and afterwards run an expandable-arm under reamer. in particular the loss of under reamer arms and pins. Hence the term Retractable Bit (RB). Hence the concept of expandable bit was born. Furthermore. Initial efforts to circumvent the economic and technical drawbacks of standard under reaming techniques focused on bi-center PDC bits. which has substantial cost benefits in the process of construction of a borehole or one of its intervals. frequent downhole tool failures.Drilling Operation Practices Manual V. the historically low penetration rates (ROPs) prevented operators from optimizing drilling efficiency. reaming the hole to its targeted diameter was more time-consuming than drilling the pilot hole. abnormal tool wear. The accompanying box provides a list of strengths and limitations for retractable drill bits. the abnormal pressure characteristic of Venezuelan wells requires the setting of maximum-diameter liners throughout the well bore to minimize hole loss. In terms of product selection and application. including bi-center bits. In the majority of wells drilled onshore Venezuela. unlike traditional under reamers.-were created to aid in the analysis. This propensity places severe limitations on rotary speed. As such. in the hole. the shortcomings of bi-center bits in reaming operations were even more pronounced. reaming wing tools. depending on the formation composition. This design eliminates the risk of leaving metal parts. bi-center bits. bi-center bits are not without operational problems that can negatively affect drilling costs. Because of the technical differences between hole openers and under reamers. Contemporary exploration trends and the documented limitations of both bi-center and traditional hole opening technology spurred the development of the ream-while-drilling tool. The ream-while-drilling (RWD) tool is a two-piece system that. high temperature wells increases. Aside from low penetration rates. the variety of available options presents a dilemma to the drilling professional. deviation control is difficult. Two hole-size categories171/2 to 36 in. incorporates no moving parts. bi-center bits have not eliminated drill string failures. reaming wing tools. expandable bits and under reamers. the type and size of both the pilot assembly and bit depends only on the design of the specific tool. Furthermore. Thus. high pressure. The first section of the tool consists of the pilot bit. and 43/4 to 171/2 in. and instances where the reamed interval was not as large as that stipulated in the well plan. making it challenging to affect proper stabilization.This was also intended to identify any trends that may emerge as to product preference and hole size. particularly in the upper sections. Because of the extra casing strings and longer intervals often drilled through unstable or encroaching formations. Under reaming offers several product options.. perhaps best amplified the difficulties associated with the use of bi-center bits for opening holes. The cocking (walking) tendencies of bi-center bits generate unusual wear patterns. the second is essentially a tube incorporating either four or five fixed blades with PDC cutters. Although a step-change improvement over standard under reaming. thus lowering penetration rates. 333 . Under Reaming Technologies Under reaming is a complex market consisting of at least 22 drilling applications. The position of fluid jets on only one side of the tool enables eccentric rotary movement to widen the pilot hole. which are highly prone to bit balling. hole openers have been excluded from the market analysis. either a PDC or roller cone bit can be used. such as under reamer arms and pins. operators have recognized the enormous economic advantages of simultaneous drilling and reaming. The ability to drill and ream in a single pass has become even more advantageous as the global trend toward deeper. et al. This requirement and the wide variance of formation composition require flexibility in the size and type of pilot bits and bottom hole assemblies. Warren. Foremost among the problems are deviation tendencies that make these bits extremely weight sensitive when run on rotary drilling assemblies. Because only stabilizers matching the pass-through diameter can be used. Hole openers start to enlarge an existing pilot hole from the surface of the well bore and contain fixed cutters of a predetermined diameter. the shallower fluid courses of one-piece bi-center bits significantly restrict hole cleaning in those intervals. By virtue of the two-piece configuration. and under reamers. Standard bi-center bits do not afford this flexibility.Emerging Technologies than the inner diameter of the casing through which it passes. Drilling Operation Practices Manual Conversely. The cutters are kept closed during the pass-through and are activated once the tool reaches the point that requires under reaming. under reamers enlarge the hole below a restricted tubular bore. 334 . Turning the pumps off deactivates the cutters with this technology. Another problematic area includes mud packing. The tools also allowed full volume circulation at all times. It can also be used to under ream existing holes. Reportedly. typically selected according to formation type so as to optimize performance. Even today. these factors have swayed decision making in regards to its use. An example of the limitations associated with this type of technology can be seen in runs where traditional arm-type under reamers have led to failures. This has raised concerns regarding the effect of bending stresses on the body and connections. These cutters were stub-welded in place once fatigue became an issue. typical tool life was extended to 10 runs or more. under reamers have difficulty coping with deviated wells and hard chalk. involving complete section redrill. the development of polycrystalline diamond compact cutters eliminated problems associate with mud packing and arm breakage. replacing these with new cutters. Thus. Under reamers Originally. it can prevent them from closing in. To improve the mechanical integrity of traditional arm type under reamers. the Anderreamer uses a unique combination of mechanical and hydraulic mechanisms to extend the cutter blocks. Historically. several things happened. It is convenient to classify the various reamers as either drilling or reaming types. Conversely. involving an additional trip. often resulting in a sidetrack. under reamers still have a way to go in terms of improving mechanical integrity and shedding a poor image. First.Emerging Technologies 1. making it extremely difficult to pull out of hole. Its design allows mudflow to be diverted to the bit or can even be used with guidance system such as a bullnose for pilot-hole reentry. Three-cone under reamers have been capable of enlarging holes by as much as 50%. 335 . The reaming type serves only to enlargen an existing hole. the drilling type allows for the simultaneous reaming of a pilot hole as it is drilled. under reamers were only used to under ream previously drilled holes. Typical design features included flow or weight-activated arms that expanded on a pivot-bearing mechanism. For the purpose of drilling oversized hole sections. A further procedural innovation involved the removal of all cutters from worn roller cones. When this occurs below the arms. the quality of standard casing pipes and particularly types of thread connections did not allow using them for DWPP especially in hard formations. including retrievable BHA (RBHA) and connection to drillstring • latch and seal unit for RBHA The real advantage of the RB technology . using a wireline or drilling mud circulation was a logical solution. drilling. DWPP features are as follows: • continuous flushing of the borehole during the RB operational cycle: running in. 2) Super-long boreholes drilling – RB could provide drill string tripping timesaving. Retractable Bit (RB) derived of this application.for moving inside the pipe The bit name. coring. RB Technology Prospects 1) Drilling with casing – this is most promising trend in cost-effective technologies for 21st century. The attempts were made after the First World War of this method realization in Poland. The development of a bit that could be run in and pulled out of the bottomhole inside the casing or drillpipe. which affects substantially the process of construction of a borehole or one of its intervals. Drilling method with RB and DHM was proposed in 1902. The use of RB allows drilling without pulling out the pipe (DWPP) and substantially affects the process of construction of a borehole or one of its intervals. Unfortunately. These bits were used in two modes: (1) working . and a little bit later in France (1928). In 30s. depending on formation and other factors. better well control and borehole walls stability in 10-15 km long wells. This kind of tool provides the possibility to realize the method of drilling without pulling out the pipes (DWPP). 2. this trend of RB use could be one of the major tasks for future research.simultaneous borehole drilling and casing. Nevertheless. Over the same period (20s-30s) great interest to RB was displayed in the USA. Thus. and milling) without pulling out drillpipes • carrying out logging operations without pulling out drillpipes • relief of the workload on drilling rig crews This required among others: • more complicated bit design • special or larger ID flush joint drillpipe • special design BHA. First designs of cone rock RB were patented in the USA before the Second World War. The bit designs with retractable blades operated worse than standard two-blade drag drilling bits (“fish-tail” bits). Retractable Bits (RB) First projects of DWPP occurred at the beginning of 20th century.Drilling Operation Practices Manual The latter has been reported to give good hold or slight build tendencies. the concept of decreasing drillstring round-trip time to change the worn bit was devised. pulling out • replacement of the different purpose tools (drilling. its performance resembles a packed-hole assembly. because it brought revolutionary changes in the entire drilling process. Subsequent to the development of rotary drilling and the increase of borehole depths.for bottomhole destruction (2) transport . three-cone rock bits were introduced as the main type of rock destruction tool. 336 . Design Basis The original design premise was to build a drill bit with a variable diameter PDC cutting structure using a simple. The present design of the expandable bit was prepared after considering a number of options and alternatives and was seen to embody the features associated with best drilling practice. robust and reliable operating mechanism. 4) Geothermal drilling – drilling with retractable bits makes available cost effective deep geothermal drilling in hard crystalline hot formations. to 9 5/8-in. It was realized that this would not only make selection of the right drilling application much easier. One method of drilling a monobore well is to use a drilling device capable of passing through a restricted diameter. Expandable Bits Two techniques directly applicable to. when drilling with casing. This resulted in an expansion ratio of 20%. although very early on this was increased to 10 3/4-in. Similarly. Following assessment of a number of alternatives. with the ability to drill a larger diameter hole. a concept design with four moveable blades was selected. 3.. such as under-reamers and bi-center bits. This initially achieved an expansion from 8 ½-in. and positively impacted by utilization of an “Expandable Drill Bit” are the use of expandable casing and drilling with casing. It also quickly became apparent that the design allowed much larger expansion ratios to be achieved with minimal 337 .Emerging Technologies 3) Scientific drilling – RB provides unique opportunities for continuous coring and logging operations in all kind of geological conditions both onshore and offshore. one method is to drill the borehole and then recover the drilling device through the bore of the casing just installed. but also achieve a significant performance improvement over existing oversize hole drilling methods. The lower face of each blade was provided with a rubber plug. as much as possible. engaging with the return pins were replaced with grooves on the front and back faces and the pins were re-designed accordingly. with a blunted knife-edge.) In an attempt to provide a pressure sensitive open/closed indicator. retaining only sufficient material to ensure necessary structural integrity. Flushing ports were also introduced into the hydraulic cylinder to enable cleaning of the actuating chamber and spring chamber without necessitating stripdown during field operations. to displace any solids accumulating underneath them. that no entrapment could occur. It was recognised that preventing ingress and entrapment of debris to the working parts of the bit would be impossible. Also. Although the original design concept had attempted to keep the number of parts to an absolute minimum. alterations in the blade design. small by-pass ports were drilled into the head of the bit immediately below the lower face of each blade. An internal coil spring is incorporated to return the blades to the closed position. The ports would have the additional feature of washing out the lower face of each blade during drilling operations. 338 . (The slots in the blades. to prevent flow when the bit was closed. drilling debris was entrained within parts of the blade guide slots. Accordingly. Some damage was evident to the bore of the hydraulic cylinder. Operational Feedback and Product Development It was evident that debris contamination along the underside of the blades could prevent the bit from closing satisfactorily. it was decided to fit bronze wear rings between the piston/cylinder and cylinder/mandrel interfaces. caused by contact with the outer diameter of the piston. The lower faces of the blades were also re-profiled. to increase reliability. During field tests with Unocal in Indonesia.Drilling Operation Practices Manual The expandable drill bit’s closed configuration is shown on the left with the expanded mode on the right. the slots in the head were considerably relieved. so the alternative was to insure. weight on bit required to achieve a specificed controlled penetration rate was 30% lower than for offset tricone runs. These were retrofitted to the prototype and could easily be replaced in the field. The expansion mechanism is entirely hydraulically actuated by the pressure differential from fluid flowing through the bit. This would occur every time flow through the bit stopped. 4.Emerging Technologies Summary and Future Developments Developments of the expandable bit have proved the concept to be feasible and practical. 4. 339 . Supported by continuous development in association with Unocal. this project has provided performance improvement and addressed all necessary operational issues. Bi-center bits Fig. Drilling Operation Practices Manual In 1994. The results were fewer trips. The only major draw back to using bi-center bits has been that they could not be used to drill out cement. bi-center bits were introduced. drillers spent a lot of time slide drilling. It is also felt that they do not drill out shoes as efficiently as predicted. Directional control is conducted through a steerable motor. even in highly directional applications. allowing for greater flexibility in pilot bit selection. there was an understandable apprehension towards running bi-center bits. float equipment. This design eliminates the risk of leaving metal parts. which can be difficult at the best of times. Gradually. These companies realized that bi-center bits could to an extent be steered by weight alone. The first section of the tool consists of the pilot bit. incorporates no moving parts (fig. 1). in the hole. notably in shallow high angle wellbore field developments. which contained new technology. Reaming Wing Tool Another technology is the reaming wing tool. With all factors duly considered reaming wing tools may have some potential for use in deep open water applications. Finally recent calliper logs run in the GOM illustrated that large sections of the wellbore had not been enlarge “opened up” at all. the second is essentially a tube 340 . then a trip was needed to pick up the bi-center bit. Consequently. This tool differs from bi-center bits in that it features a two-piece design. there was a need to depend almost entirely on the bent motor housing to steer. to make changes in inclination. and casing guide shoes. bi-center bits are used in hard formations as they are perceived to be more robust than traditional arm under reamers. Design The ream-while-drilling (RWD) tool is a two-piece system that. advancements in bi-center technology have resulted in a bi-center bit that can be used to drill out and then continue to drill ahead. bi-center bit manufacturers have found ways to improve BHA behavior. The success of bi-center bits removed the need for hole openers in many applications. increased demand for these bits highlighted certain technological limitations. It was required that a conventional drill bit be used first to drill out into new formation. this was linked to the lack of a full-gauge stabilizer above the bi-center bit. unlike traditional under reamers. Essentially. including poor directional drilling performance. In 1999. This technology features a polycrystalline diamond compact bit with a ream while drilling capability. eliminating the need to drill the interval twice. BHAs using bi-center bits tended to have a problem with inclination control. On the other hand. resulting in bottomhole assembly (BHA) stabilization issues. Today. From the drilling engineers’ point of view. a single integral component reduced risk and cost as compared to two or three. They also found that longer bit profiles helped to stabilize BHA performance. all with no moving parts. 5. For the first time. such as under reamer arms and pins. All these factors came together to confirm the place of the bi-center bit in the industry. Without stabilization. From this perspective. let alone with the added complication of running a bit that is geometrically unstable. a single tool could reliably be used to simultaneously drill and under ream. and less “problem” time. As steerability issues continued to hinder directional performance. Bi-center bits often produce excitation force required to induce vibrations that are then detrimental to drillstring and BHA components. fewer rotating hours. under reamers tend to be preferred in softer formations as their application can lead to impressive gains in penetration rates while providing an increased time window to conduct operations in swelling formations. depending on the formation composition. The geometry of the RWD tool revolves around three interrelated diameters: pass through. The pass-through is the drift diameter of the casing or the liner through which the system must pass. The pilot bit stabilization pad offsets the net imbalance force of the reamer blades. By virtue of the two-piece configuration. Thus. 341 . drill size. Upon rotation. providing faster stabilization of the system. or hole opening. the tool is then able to widen the hole to its programmed final diameter.Emerging Technologies incorporating either four or five fixed blades with PDC cutters. the stabilization pads force rotation around the center of the pilot hole. ensuring the drilling of a full-size well bore. Both the pilot hole size and the extent of the imbalance force generated determine the size of the gauge pad. By spreading the cutter arrangement across the profile of the tool. 2. and pilot bit The geometry allows the tool to adapt easily to the maximum diameter of the liner or casing in which it must pass. either a PDC or roller cone bit can be used. The reamer wing has carbide-supported edge PDC cutters. in conjunction with the pass-through diameter stipulated in the well objectives. The drill size of the targeted section. Basically. blade creates a smooth transition from the pass-through size to the drill size. Fig. thus providing the additional stabilization not possible with bi-center bits. Fig. the RWD tool designers successfully facilitated even load distribution. 1. Drill size is the final drilled hole diameter. The shape of these new-generation cutters strengthens the diamond edge and delays the onset of fracture and cutter wear. the type and size of both the pilot assembly and bit depends only on the design of the specific tool. determines the pilot bit diameter. The position of fluid jets on only one side of the tool enables eccentric rotary movement to widen the pilot hole. The leading. the demand for remedial work such as drilling through failed screens will place additional demand on under reaming technologies. the need for enlarging holes to place new sand screens and gravel packs also arises. 342 . such as those encountered in the upper hole of Venezuelan wells. Depleted reservoirs are also likely to result in transition from oil to gas production. The polishing process also removes any microscopic imperfections in the cutter. and technical innovation in well design show promise for the future. further heightening the likelihood of sand productivity. as certain technical restrictions can be associated with older platforms. As such. In these instances. medium. which is especially advantageous when sections prone to bit balling are drilled. increased production. or that of ice sliding on ice. Increased production Increased production is important for two major reasons. and long term will tend to encourage conditions apt for growth.Drilling Operation Practices Manual The cutter surfaces are highly polished. Polished PDC cutters have a friction coefficient of 0. These restrictions include the availability of conductor slots and the size of blowout preventers. Decommissioning has proved to be complicated. Eventually. The future of under-reaming technology The three main characteristics of the under reaming market. Moreover. to preserve or improve production rates. Finally. Both of these examples make under reaming an attractive option. time consuming. Consequently. under reaming technologies can be applied towards sidetracking and multilateral drilling applications where hole enlargement through existing casing strings provide an attractive option. Polished cutters reduce the shear forces that restrict cuttings removal and limit penetration rates. strong market drivers in the short. depleted reservoirs result in lower reservoir pressures and poorer rock mechanics. the use of under reaming technologies to configure larger bore casing strings can be viewed as a preferred method of improving productivity by maximizing the size of the borehole in the reservoir section of the well. First. provision must be made for sand exclusion through pre-wrapped screens or gravel packs. and expensive. This can also heighten demand.1. cost cutting. which restricts bit diameters and conductor placement. further enhancing cutter durability. Polished cutters reduce the penetration rate limitations posed by the built-up edge that forms when an amount of drilled formation is not removed and subsequently attaches itself to the leading edge of the cutter. enhancing the appeal for extending platform life. These costs tend to dissuade operators from such activities. as it overcomes such limitations while maximizing the configuration of casing strings. The bracket of increased production also covers older platforms. ) into photons (electromagnetic radiation) • The photons created through stimulated emission form a narrow beam of SPONTANEOUS EMISSION monochromatic. California. Albert Einstein. chemical. Maiman in 1960 at Hughes Research Laboratories in Malibu. Laser beam Application of Lasers • Medical: In surgery – as a scalpel. in 1917. in which all the waves reinforce one another) light” and also “to cut or treat with coherent light” • A laser is basically a device that converts EXCTTATION energy of some form (electrical. STIMULATED pulsed. etc. • Lasers can operate in continuous-wave (CW). External energy pump 3. heat. EMISSION Laser Construction 2 3 4 RETURN TO GROUND STATE 1 5 Principal components 1. fuse (melt) and/ METASTABLE STATE AND BUILD UP OF STIMULATED or vaporize} a target depending on the power EMISSION ALONG AXIS delivered. 343 . The term LASER is an acronym for Light Amplification by Stimulated Emission of Radiation. Laser Drilling Introduction Laser Drilling is a revolutionary method of using laser beams to drill oil and gas wells. The first working laser was made by Theodore H. • “To lase” means “to produce coherent ABSORPTION (consisting of waves of a single wavelength. and repetitively pulsed (RP) modes.Emerging Technologies VI. coherent light that when focused into an intense beam can be used to POPULATION OF ablate {spall (chip/ fragment). Active laser medium 2. Partial mirror 5. to reattach retinas and to stitch up incisions after surgery by fusing together skin • Entertainment & Advertising: These use lasers that are in the visible spectrum to paint images in the air. predicted the possibility of stimulated emission (generation of photons or discrete bundles of energy via transitions between atomic or molecular energy levels). Mirror 4. • small diameter exploratory wells. Oil & Gas Industry: Projects are being carried out to drill & complete oil and gas wells with lasers. • When the well bore reaches its target depth. drilling volcano artificial chimneys for pressure relief. General Purposes: Lasers are also used to align pipes and wheels. Types of lasers The laser medium can be a solid. excavation. • When desired. • primary perforation to create the path between the wellbore and reservoir • extend perforations to connect additional reservoir rock to the wellbore (fracturing) • Laser technology can also be applied to other arrears that require rock removal. tunneling. Metal working: Lasers allow better cuts on metals and the welding of dissimilar metals without the use of a flux. some or all of the excavated material is melted and forced into and against the wall rock to line well bores for well stabilization and abnormal pressure control. • Cutting windows for side tracking and laterals • cutting trenches for pipelines. • Excavated material is carried to the surface as solid particles / vapour. archeological investigation.Drilling Operation Practices Manual • • • • Computers and Music: One popular use of lasers is optical drives. • horizontal and slanted wells. • All this is done in one pass without removing the drill string from the hole. such as. fusion or vaporization. nuclear reactor decommissioning. liquid or semiconductor. the well is completed by using the same laser energy to perforate through the ceramic casing. • removal of objects lost downhole that would normally require drill out or fishing operations. measure speed and distances. read bar codes etc. Defence: Lasers track & destroy missiles etc. Given below are a few of the expected applications in oil & gas industry • vertical & directional (including extended reach) drilling. etc. all in real time. mining. gas. • The down hole assembly includes sensors that measure standard geophysical formation information. Lasers are commonly designated by the type of lasing material employed: • Solid-state lasers • Gas lasers • Excimer lasers • Dye lasers • Semiconductor lasers or diode lasers • Fiber lasers Laser Drilling Concept • Laser applies infrared energy to the working face of the borehole and ablates the rock by spallation. geothermal wells. as well as imaging of the borehole wall. Laser Drilling Action High power lasers can be used to destroy rock in two ways: • by weakening the rock prior to application of mechanical tools 344 . • seismic shot holes. Technologies. Basic benefits of laser drilling • Non-contact process (no tooling wear or breakage) • Highly accurate and precise control of heat input • Ability to produce small diameter holes with high aspect ratios • Ease of programming and ready adaptability to automation • No out-of-balance or out-of-axis turning is expected to occur with a laser drilled hole because photons travel in straight paths. Department of Defense’s Star Wars project to civilian applications.S. Air Force. the U. Argonne National Laboratories. Boeing Intellectual Property Business. In 1997. Each of the three methods of ablating rock (spalling. Reflection and scattering represent energy losses in the process of rock destruction. Benefits to Oil & Gas Drilling • Could significantly increase the rate of penetration (ROP) and thus reduces overall drilling costs • Since a sheath will be formed around the hole drilled. Halliburton. Geological Survey. are reduced. N. Likewise downhole problems like caving.S. • Provides perforating and side-tracking capabilities. They demonstrated the feasibility of using high power lasers for oil and gas applications. DOE/NGOTP (Natural Gas and Oil Technology Partnership). U. Research Objectives • To obtain much more precise measurements of the energy requirements needed to transmit light from surface lasers down a borehole with enough power to bore through rocks as much as 6000M or more below the surface. fuse or vaporize rock.S. casing & piping can be eliminated/ along with all equipment and operations (like tripping etc.Emerging Technologies • by direct rock destruction via ablation.S. 345 . IPG Photonics (IPG) and the Venezuelan National Oil Company (PDVSA). Also eliminates/reduces • Rig size • Power consumption • Mud/chemical requirement • Bit costs Laser Drilling Research Worldwide In 1994. fusing or vaporizing) may have specific applications for natural gas drilling and completion. the Gas Research Institute called for proposals to revolutionize drilling. Occidental Petroleum. Parker Geoscience. ‘Colorado School of Mines’ and ‘Solutions Engineering’ submitted proposals for applying star wars laser to drill and complete wells. There are three processes by which lasers might transfer energy into a rock target: • Absorption • Reflection • Scattering It is the absorbed energy that gives rise to rock heating and destruction. Gas Technology Institute. Congress issued a mandate to transfer the laser technology developed for the U.) associated with this. Consortium partners in this research with DOE were Colorado School of Mines. U. loss etc. The degree to which energy is lost dictates the effectiveness of the laser’s ability to spall.A. IL Native American Technologies.06 0.6 1.315 5 to 6 10. White Sands. To determine if lasers can be used in the presence of drilling fluids. Moscow. rather than as a continuous stream. The technical challenge will be to determine whether too much laser energy is expended to vaporize and clear away the fluid where the drilling is occurring. location. CO Figure above shows experimental set-up for Nd:YAG Laser interacting with rock 346 .6 to 4. could further increase the rate of rock penetration. Location Wave length (µm) 2. Golden.8 Power Used (kW) 900 8 6 6 8 10 6 4 LASER Mid-Infrared Advanced Chemical Laser (MIRACL) Chemical Oxygen Iodine Laser (COIL) Pulsed CO Laser Pulsed CO2 Laser CO2 Laser CO2 Laser Nd:YAG Direct Diode US Army. NM Kirtland Air Force Base.6 10. Moscow. A variety of lasers have been used in the research. and laser properties. OH Argonne National Labs. Pulsed lasers have been used for better performance in cutting rocks. NM Lebedev Institute. Russia Lebedev Institute. The following table shows the lasers.6 10.2 1. Albuquerque. IL Argonne National Labs. Chicago.Drilling Operation Practices Manual • • • To determine if sending the laser light in sharp pulses. Chicago. Russia Wright Patterson Air Force Base. Dayton. Limestone. It has been determined that power not wavelength controls rock removal rate. Even though CO2. However. downhole energy delivery and lower environmental impact. Low reflectance indicates that more energy is absorbed into the rock. The size of lasers varies from the US Army’s MIRACL which is the size of a small refinery to the Direct Diode laser which is about of the size of a shoe box. It is controlled by diverse mechanisms that are function of both the rock properties and the laser parameters. Granite. CO and MIRACL lasers have the greatest absorption. The Direct Diode. emitted. as part of the airborne laser defense system. Sandstone. In every rock type tested. In other words specific energy (SE) is the energy required to remove a unit volume of rock and hence it is a critical rock property data that can be used to determine both the technical and economic feasibility of laser oil and gas well drilling.Emerging Technologies A comparison of laser parameters for industrial lasers at 4KW power output is given in table below. the porosity and permeability were increased and the elastic moduli were altered to weaken the rock. ROP as a function of Specific Energy and Specific Power Specific energy (SE) is a measure of the efficiency of the rock destruction technique. Spectroscopy is used in determining the amount of energy reflected. The most efficient rock removal mechanism would be the one that requires the minimum energy to remove a unit volume of rock. portability. it can remove the rock by thermal-spallation. When a high power laser beam is applied on a rock. to operate inside a Boeing 747. Shale. melted or vaporized by a laser beam. melting or vaporization depending on the applied laser energy and the way the energy is applied. Nd:YAG and COIL have lower absorption but they have better prototype/field qualities such as durability. Even though the melted material in the wall of the hole is impermeable. Concrete and Salt were tested during the course of the research. the rock properties behind the melted sheath are improved. This process in primarily due to the creation of microfractures and dehydration of clays. The US Air Force COIL has been miniaturized. Rocks can be chipped. and scattered by the rock. they may not be the best candidates for prototype/field applications. The specific energy or the amount of energy required to remove a unit volume of rock and is mathematically defined as follows: 347 . (5) Flame jets. (2) Rotary drills. ROP is related to specific power and specific energy by Pc / SE (cm/s). (7) Future laser spallation. (4) Raise-and-tunnel-boring machines. (3) Drill-and-blast tunneling. etc. To increase ROP. Figure above reveals that to increase ROP of rock breaking. Also Specific power (Power Density) is the power per unit area. absorption of the laser energy by the plasma and the plume.Drilling Operation Practices Manual SE = Energy Input P = Volume Reoved dV / dt ⎡ kW ⎤ ⎢ cm2 ⎥ second kW kJ ⎦ =⎣ = = 3 cm cm /sec cm3 Where P = Power Input (Watts) DV/dt = Volume Time Derivative (cm3/sec) Hence Specific Energy varies inversely as the efficiency of the laser cutting process.. (6) Laser spallation. Above graph shows a comparison of various techniques for rock drilling and boring in terms of rate of penetration. (1) Percussive drills (small holes). With better laser head and assisting purging system designs. (kW/cm2). Secondary effects like melting. thermal 348 . Pc. reduce the efficiency of laser cutting and are dependant on mineralogy. specific power and specific energy. laser drilling would be the next generation drilling system. one should use techniques that have high specific power and low specific energy. The most efficient rock removal mechanism would be the one that requires the minimum energy to remove a unit volume of rock. techniques that have high specific power and low specific energy should be used. re-melting. 52 (spalling) 1.7 Average power W 2020 2210 2210 3000 Specific power W.54 (spalling) 3.5 (spalling + slight melting) 6.s Specific Energy.53 (spalling) 5.070 1. • Layer-2 is a continuous layer. The thickness of layer-2 depends upon the silica content of the lased area. the porosity. SE.5 330 262 202 534 4. One can see that rock removal mechanisms can be changed between spalling and melting through controlling either the specific power or exposure time.5 (spalling + medium melting) 30.5 Exposure times. 1.79 (spalling) 2. saturation (air. Some important laser drilling research results Many organizations and institutes are carrying out research in laser drilling The following conditions have been varied during the experiments: rock type.610 2.6 (medium melting) 2. This layer will not be formed if the laser melt is removed before solidification.5 0. 349 . m m 19 cw Berea grat sandstone CO2 19 12.217 3. A few relevant research results are summarized below.71 (spalling) 3.6 (Spalling) 3. methane. fresh and salt water).369 0.0 0.kJ/cm3 2. Shale samples recorded the lowest SE values as compared with limestone and sandstone samples. This underlines the need for an efficient debris and vapor removal system. lased through drilling mud and fresh water. It is seen that each rock type has a set of optimal laser parameters to minimize SE. kJ/cm3) for two typical reservoir rocks tested in the studies are listed in the Table.Emerging Technologies properties and rock properties. continuous and pulsed. stress orientation. Rock Type Laser used Beam spot size. This layer shows potential for possibly replacing conventional casing steel used in oil and gas wells. time on target (heat input).0 (heavy melting) 534 415 Shale Pulsed Nd: YAG 12. beam direction (horizontal or vertical).Cm2 712 780 1. sample shape and purge assist gas. The minimum specific energies (energy required to remove unit volume of rock. Study of samples from rock samples drilled with high-power lasers Figure of Petrographic thin section of Berea gray sandstone showing the lased hole and the four concentric alteration zones • Layer–1 is a discontinuous layer.745 2. the power of the laser.280 2. and the thermal conductivity of the rock.590 4.7 12.217 1. This layer forms a sheath of petrified silica around the lased hole. oil. Since some relaxation time is needed for avoiding melting of rock.Drilling Operation Practices Manual • • Layer-3 is wider than the other three layers. Layer-3 represents a mechanical support to layer-2. • • • Each laser beam can spall a shallow hole as big as the spot size usually 1. Overlapping multiple small laser beams method to drill large diameter and deep holes. • To cover large diameter area (8-1/2 or greater). Crystals are not transformed into other minerals but are instead mechanically deformed and slightly burnt. 350 .27 cm in diameter. The rock fragments from this layer will be instantaneously removed with the help of the purging and flushing system. Layer-4 represents the external limit of the laser thermal effect. the overlapped beams will fire on the rock sequentially or in groups to create a layer of nearly circular work face of a desired diameter. Fresh rock Layer-4 Layer-3 Layer-2 Layer-1 Lased-hole 3. either the small spot size beam has to be scanned or multiple such beams are overlapped. Both layers may indeed provide adequate support for oil and gas boreholes. Layer by layer. thermal properties and measured average power Tests on Nd:YAG laser shows that. melting or vaporization the rock.Emerging Technologies • • • • • • • • • Then laser beams will fire again to spall the second layer of rock. Limestone and Shale Identifying Laser-Rock Reaction Zones and Calculated Power Densities. 351 . the rock type. depending on the application required. Nd:YAG laser can perforate the rock as efficiently as the other types of high power lasers the permeability of the rock lased by pulsed Nd:Yag laser beam increases up to 566% compared to non-lased rocks due to clay dehydration and micro-fractures induced by the high temperature gradient. The phase change in the rock depends mainly on. Linear Nd:YAG Laser Track Test Samples with Constant Focal Position Change Rate for Sandstone. a deep hole will be drilled out until the desired depth reaches Laser parameters can be controlled very precisely to achieve spallation. • Temperature higher than 6500C (12000F) was recorded on the tested rock that was exposed to a kilowatt level laser beam.Drilling Operation Practices Manual Summary of Other Experimental Results • Measured SE increases very quickly with beam exposure time indicating the effects of energy consuming secondary processes. potentially. • High power laser-rock interaction tests have proven that lasers can penetrate all rock types including granite. and granites indicates this). • A higher percentage of quartz in the sample will result in higher melting point for the rock. • Sandstones saturated with water spall faster. quickly elevating SE values. wasting energy. etc. large diameter holes in petroleum rocks due to peak power 4 times higher than the average power. (Examination of more than 50 lased samples of different rocks . • The application of high power lasers can also enhances rock properties such as permeability and porosity.34 kW Ytterbium-doped multiclad fiber laser on multiple samples of granite. Multiple holes drilled side by side with 1-inch-diameter collimated beams for a drill hole diameter of 8 inches overcomes this problem. • As it drills. • Rock properties (type. while a CW laser. • Operating a high power laser in underbalanced conditions showed the laser’s ability to perform at downhole conditions without requiring a supplemental assist purge system Conclusions • Laser spallation shows 8 –100 times faster ROP than that of the conventional rock breaking techniques because it has specific power as high as that of flame jets which is the highest among the conventional methods and specific energy as low as that of most conventional methods. deep holes. temperatures rise to the minerals’ melting points and beyond. moisture content. As absorbed energy outpaces heat diffusion. • Super-pulsed (SP) CO2 laser beams were shown to efficiently drill deep. porosity. the laser exposure creates a glass or ceramic liner that. shales. cement and steel confirmed that the laser was capable of penetrating these materials under a variety of conditions.sandstones. • In narrow. causes it to melt and vaporize. fragments of rock can block the beam. • Pulsed lasers cut faster & with less energy than continuous wave lasers. much faster than conventional methods and other non-conventional methods. • Applying 5. could replace the steel casing now required in boreholes. • Rates of heat diffusion in rocks are easily and quickly overrun by absorbed energy transfer rates from the laser beam to the rock. More rock can be removed before melting commences. therefore requiring more energy to melt and more energy to vaporize. which dumps too much power into the rock. • A laser is able to spall and melt rock through water. • The most energy efficient drilling can be achieved by maintaining laser intensities below the threshold for rock melting and vaporization. They have better penetration and fracturing. and the beam’s pulse nature. limestones. Eliminating the need for casing & drill-pipe would be a big saving. the consequence of which is slower drilling. dolomites. although laser energy at these wavelengths is readily absorbed as it passes through the water to the sample.) effect laser drilling effectiveness and some rocks may have optimum (minimum) SEs higher than others. Laser can also induce fractures in the rocks by thermal expansion. 352 . The SP mode is more efficient than CW operation. • To confirm that the differential pressure between the reservoir pore pressure and the wellbore pressure would provide the means for ejecting the cuttings in under-balanced conditions downhole. For the initial application. when the specific energy increases substantially. The configuration of the surface and downhole equipment will have to be adapted to the application. This is not new technology.Emerging Technologies • • • • • • • Pulsed Nd:YAG laser with fiber optic cable delivery is a strong candidate for laser applications for oil and natural gas wells. multiclad fiber laser has raised hopes. Some of the challenges still being faced by the researchers are. It is envisioned that the laser system would have a smaller environmental footprint and the use of hazardous chemical would be greatly reduced. and one of the most promising is the Direct Diode Laser which is compact enough to put the entire laser mechanism downhole. since the petroleum industry has used compress gas as drilling fluid for many years. The recent evolution of a high-power 5. • To make available lasers which can produce more high power to cut different types of rock. The fundamental principles of laser rock destruction are independent of the application. The specific energy improves (decreases) with increasing laser intensity to an optimum just below the transition to a melting mechanism. Laser drilling is faster so the system is on location for a shorter period of time. 353 . The objective of laser drilling is to get the laser beam energy to the rock face. thus minimizing interruptions to the natural ecosystems and reducing drilling objections for local residents. They are currently looking at fiber optics. They have drilled 8 inches diameter hole in the laboratory with a megawatt laser and 0.5 inch diameter hole with a few kilowatts. It is just a function of the power available. fiber lasers. down to where formation fluids are present and mud is used as a fluid for cuttings evacuation. In the lab researchers have successfully drilled more than 18 inches which was limited by sample size available and laboratory capabilities. drilling must be done with a transparent fluid. Placing of laser energy downhole i. it is anticipated that pressure control and cutting removal would be accomplish using a highpressure inert gas such as N2 or CO2. is the current challenge of research teams. Characteristics of the laser system make it friendlier to the environment than current stateof-the-art drilling systems. • To apply the technology in actual downhole temperature and pressure conditions. Since traditional drilling fluids (mud) used for pressure control and cutting removal are not transparent to laser wavelength. beam deliverability. hollow fibers.e. Lasers can be used for perforating or extended reach drilling. There is no limit to the size and depth of the hole.3 kw ytterbium doped. The laser drilling prototype may provide answers to many of these challenges. • To design a laser head that could put the power directly into the well bore and could incorporate a sensor array for real-time monitoring down the hole. etc • And finally to incorporate the laser technology and fiber optics with coiled tubing. • To fabricate fibre optic cables for the depths required • To determine & address the power loss issues • To built a working laser drilling prototype. solids removal.) • To devise methods to cool the laser head under the downhole conditions and the expected working temperatures (~6000C or more). Researchers expect that would be ready by 2010. Currently options are being explored to develop a prototype drilling system using the Solid State Direct Diode Laser (DDL) and integrating the various components such as. 354 . • To deliver power from Nd:YAG and fiber lasers through fibre optics to depths of 2000 M and more. Beam deliverability.Drilling Operation Practices Manual Diagram of a high power fiber laser (Courtesy of IPG Photonics. pressure control. This type of precision and range could eliminate many of the side-tracking and directional (lateral) drilling problems. Inc. The Hoist.. The English Book Depot. Texas. BHEL Manufacturing Catalogue Trichi OISD Standard -187 “Care and Use of Wire rope”. Graham and Trotman London Moore L Preston. Lesson –IV. The Bit. ONGC. Rotary Drilling Series. New Delhi House. 24. PES. 27. 6.Texas. The University of Texas. Texas. Oil well Drilling Engineering. 14. The University of Texas. Prentice hall. Drilling Fluids Engineering Manual. Tulsa Oklahoma Rotary Drilling Series Unit . ONGC. IDT. Rotary Drilling Series. BIBLIOGRAPHY 1. 2. Lesson-IV. 18. 20. Petroleum Engineering Drilling & Well Completion. 2. IDT. Texas. The university of Texas. Oklahama Coring Manual Diamant Boart Petroleum Division Brussels ( Belgium) Composition and Properties of Drilling Fluids” Darley HCH and Gray G. IV Offshore Technology. Dehradun. Casing & Cementing PES. Houston. 11. PES.W. BHEL Oil Well Drilling Rig. Rotary Drilling Series. IDT. Dehradun. Pennwell Publishing Company. 19. 23. Houston. Drilling Operations Manual. ‘The Block and Drilling Line’ PES. Unit-I. New Jersey. Engineering Inc. MOPNG. Lesson –III. IADC. Lesson –II. Vol. Unit-I. 17. Govt. ONGC. Unit-II. Operations Manual Halliburton Services. Pennwell books. 3. Englewood Cliffs. Texas.W and Cole F. 7. 5.Principle & Practices. of India.References REFERENCES 1.-I Stuck pipe prevention by John Metchill Dulberg. Lesson –III. Dehradun. 12. Inc. 1994. 22. Unit –II. Randy Smith. Duncon.R. 10. The University of Texas. Stuck pipe prevention. 13. 3. Texas. USA. Gatlin Carl. Texas. Unit-V. 15. IDT. 9. 7th Floor. Tool Pushers Course Materials. The university of Texas Texas. New Delhi -110001. Drilling Operations Manual. The Drill Stem PES. Barakhamba Road. Well Control Manual. Stuck pipe prevention Prentice Training Company Inc. 355 . ONGC.. Drilling a Straight hole. lesson –V. Dehradun. 16. Rotary Drilling Series. Oil Well Drilling Technology.I. 1987 Operation and Maintenance Manual. 25. Rabia H. Magcobar division Oilfield Products Group Dresser Industries Inc. Fundamentals of Casing Design. 8. Dehradun. Do’s and Don’ts for Drilling Engineers. Dehradun. Drilling Practices Manual. Graham and Trot man London. IDT. McCray A. 21. Rabia H. 4. PES The University of Texas. 2003 API-RP 7G (Sixteenth Edition August 1998) Trouble free drilling Vol. P K DUBEY : He is B E (Mechanical Engineering) and joined ONGC in 1982. He has worked in R & D Drilling in directional drilling. He has worked on Jack up/Floater Rig as Driller / Tool Pusher for 10 years. A K JOSHI : He is M Sc (Chemistry) and joined ONGC in 1980. AJEETH X PARAPULLIL : He is BE (Mechanical Engineering) and has varied experience of 21years of working in the Oil Industry.ABOUT THE AUTHORS V CHAKRAVARTY : He is B E (Mechanical Engineering) and has 25 years field & R&D experience in ONGC. His present assignment is Drilling R &D and specializes in casing design. He has worked on Floater Rig as Driller / Tool Pusher for 10 years. R SHANKER : He is B E (Mechanical Engineering) and has wide experience in ONGC. He remained a regular faculty for Drilling Technology courses. Assam and Karaikal. Dehradun G. He is presently posted in Drilling Technology School and is a regular faculty for Drilling Technology courses. VINOD KUMAR : He is B E (Mechanical Engineering) and joined ONGC in 1988. He has many papers to his credit. He is working in R & D section in Drilling Fluid Engineering (DFE). He has working experience in drilling operations & directional drilling at various field of ONGC. Singapore. He has working experience as mud engineer on drilling rigs in Assam and Ankleshwer Assets. He is a regular faculty for Drilling Technology courses. D DASGUPTA : He is B E (Mechanical Engineering) and has 13 years of field experience in cementing operations in Agartalla. He is a regular faculty for the drilling fluid related topics. He has many papers to his credit. He remained a regular faculty for Drilling Technology courses. He has also authored many OISD standards. He has working experience in drilling operations in Assam and directional drilling in Ankleshwar. He has also worked as Drilling Superintendent on Deep Exploratory High Pressure Gas Well for 3 years on the Land Rig. He has also experience of working as Drilling Superintendent on deep wells of Assam Asset & as Fishing Engineer in Ankleshwar Asset. He has worked in HRD and QHSE audit in IDT and his present assignment is Drilling R & D in directional drilling.He has field experience in drilling operations in Eastern and Western Region. VENKATSEWARAN : He is BE (Mechanical Engineering) and has varied experience of 21 Years of working in the Oil Industry. T R K SHERWANI : He is BE (Mechanical Engineering) and has varied experience of 22 years of working in the Oil Industry. He has presented many technical papers in various workshops/seminars and also authored many OISD standards. He is a regular faculty for casing design. He has also worked as Safety Auditor.He remained a regular faculty for Drilling Technology courses and specializes in the latest advancements. . He is a faculty for Cementing Technology topics. He is presently Head of Cementing and Cementing Material (CCM). SANJAY KULKARNI : He is BE (Mechanical Engineering) and has varied experience of 24 years of working in the ONGC. He specializes in QHSE. He remained a regular faculty for Drilling Technology courses. He has also worked as Drilling Superintendent on Deep Exploratory High Pressure Gas Well for many years on the Land Rigs. He has vide field experience in drilling operations in Bombay Offshore and on the Land Rigs. He has working experience in drilling and cementing operations in Bombay Offshore and Assam assets. accredited to DNV. Working as Faculty in Well Control School and Stuck Pipe Prevention courses at IDT. Dehradun. He has worked on Land rigs as Driller / Tool Pusher for 15 years. Working as Faculty in Well Control School and other training courses at IDT. ATANU BHATTACHARJEE : He is B E (Mechanical Engineering) and has 18 years field experience in drilling operations in KG and Assam assets. He has worked on Jack up rigs as Driller / Tool Pusher at Bombay Offshore for 12 years. R P AGGRAWAL : He is B E (Mechanical Engineering) and joined ONGC in 1982. 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