Modern Sandface Completion Practices H A N D B O O K First Edition William K. Ott, P.E. and Joe D. Woods A Supplement to World Oil Publication of the World Oil Modern Sandface Completion Practices Handbook was made possible by the support of the following sponsors: Premier Sponsors: Baker Oil Tools BJ Services Company Core Laboratories Halliburton Energy Services Reslink Schlumberger Weatherford International Ltd. Sponsors: Borden Chemical, Inc., Oilfield Products Division Cabot Specialty Fluids, Inc. Carbo Ceramics Inc. Champion Technologies, Special Products Division con-slot Screens International GMBH Greig Filters, Inc. Grupo Royso, C.A. M-I L.L.C. Norton Proppants, Inc. Red Wing Perforating Services L.L.C. Smith Services, a Business Unit of Smith Interna- tional, Inc. STREN Company TBC-Brinadd Thru-Tubing Systems, Inc. Tucan Petroleum Services, C.A. Well Flow International About the cover: Various methods for controlling sand production in open- and cased- hole completions are shown. Illustration was adapted from one appearing in BP’s Frontiers magazine, December 2001. World Oil ® Modern Sandface Completion Practices HANDBOOK A treatise on reliable techniques to complete unconsolidated sandstone reservoirs at the sandface (the physical interface between the formation and the wellbore), using sand management and sand control methods. William K. Ott, P.E., and Joe D. Woods Published by World Oil magazine Gulf Publishing Company Houston, Texas WILLIAM K. (BILL) OTT, P.E., is an independent petroleum consultant based in Houston, Texas, and founder of Well Completion Technology, an international engineering consulting and petroleum industry training firm that was established in 1986. Before consulting and teaching, Mr. Ott was division engineer for Halliburton’s Far East region based in Singapore. Previously he was a research field coordinator for Halliburton in Duncan, Oklahoma. Mr. Ott received his BS Degree in chemical engineering from the University of Missouri (1972). He is a registered pro- fessional engineer in Texas, and a 25-year member of SPE. He works regularly with and on wells requiring sand control, principally in East Asia and South America. He has conducted technical petroleum industry courses worldwide and written numerous technical papers relating to well completion and workover operations. Mr. Ott teaches a Sand Control Technology course several times each year in the U.S., Canada, Southeast Asia and South America. He can be reached via e-mail at:
[email protected]. JOE D. WOODS is a Houston-based freelance writer and marketing consultant. He is founder of International Pinpoint, a marketing and advertising consulting firm specializing in the petroleum industry. For twelve years, Mr. Woods was director of marketing for Gulf Publishing Company. Mr. Woods has over 28 years of diversified experience in the oil and gas industry. Previously he was vice president of marketing for GEO International Corp., a multi-division NYSE-listed oil field services firm, which grew rapidly in the late 1970s and early 1980s. He also held key marketing-related positions with Halliburton Company in Duncan, Oklahoma, and Houston, Texas. In the mid-1970s, he was instrumental in developing curriculum for the Modern Well Completion Practices School at the Halliburton Energy Institute. Prior to that he was a marketing specialist with Texas Instruments. He has written and produced hundreds of hours of employee and customer training materials in the petroleum and electronic indus- tries. Mr. Woods has held memberships in AMA, BMA and PRSA, and has been an associate member of SPE and a corporate representative member of SEG. A Distinguished Student at Texas A&M University, he received his Bachelor's degree from the University of North Texas (1972). Mr. Woods can be reached via e-mail at:
[email protected]. ABOUT THE AUTHORS ii Acknowledgments More than 20 companies sponsored the preparation of this handbook. The authors greatly appreciate this sponsorship, and the technical and editorial assistance of these companies and numerous individuals. Without their cooperation and the release of their data, the publication of this handbook would not have been possible. In part, this work is a summary of technology already published by hundreds of others. That collective effort is greatly respected, and it is hoped that the references cited are some measure of permanent recognition. World Oil ® Modern Sandface Completion Practices Handbook First Edition US$95.00 per single copy To order additional copies of this handbook or for educational and volume discounts, contact the publisher at the address below. Copyright © 2003 by Gulf Publishing Company, Houston, Texas. All rights reserved. Printed in the United States of America. This handbook, or parts thereof, may not be reproduced in any form without permission of the publisher. Gulf Publishing Company P.O. Box 2608 Houston, Texas 77252 Phone: 713.529.4301 www.gulfpub.com Gulf Publishing Company and the authors have used their best efforts in collecting and preparing material for inclusion in this handbook, but do not warrant that the information herein is complete or accurate. Errors and omissions, typographical, clerical and otherwise, can occur and this possibility exists in respect to any- thing contained in this work. Gulf Publishing Company and the authors do not assume, and hereby disclaim, any liability to any person for any loss or damage caused by errors or omissions related to this handbook whether such errors or omissions result from negligence, accident or any other cause. This applies to product and service information, trademark information, directory listings, as well as all other matter contained herein. iii The business of completing oil and gas wells in unconsolidated sandstone reservoirs is continually changing with new challenges, new methods and new technologies. Sand, when produced with hydrocarbons and water from many wells, represents a costly problem for operators. Cost effective solutions for controlling sand production are many, ranging from stand-alone screens to conventional gravel packs to high rate water packs to frac packs and more. Most often operators elect to employ various sand exclusion techniques when completing a well. In some areas, it may be more economical to employ sand manage- ment techniques in an effort to minimize or delay expected problems such as formation erosion, sand fill, production interruptions or even eventual wellbore collapse. The true success or failure of a sand control application must always be measured against three related criteria: • Stopping the movement and production of sand • Maintaining maximum well productivity • Paying for treatment costs and realizing a satisfactory return on investment within a reasonable period of time. This handbook provides reliable techniques, updates industry methods and presents valuable new technologies used to complete unconsolidated sandstone reservoirs. Numerous illustrations complement the text, and there is an extensive list of references. The techniques and equipment described have been field-proven in thousands of oil and gas wells around the world. Operators must know when to apply the different solutions. This book has been prepared in an effort to provide the knowledge required for choosing the optimum solution. PREFACE iv Chapter One 1 Controlling Sand-Related Production Problems 1 Causes and Effects of Sand Production 3 Understanding the Reservoir 5 Productivity, Formation Damage and Flow Efficiency 7 Sand Management Techniques 9 Justification for Sand Control 10 Types of Sand Control 10 Drilling, Cementing and Completion Considerations Chapter Two 13 Open-Hole Sandface Completions 13 Drill-In Fluids Fluid Loss Completion Considerations Filter-Cake Removal 18 Stand-Alone Screens Slotted Liners Conventional, Prepacked and Premium Screens Stand-Alone Completion Assemblies 24 Gravel Packing Gravel-Pack Sand Sizing and Substitutes Slotted Liner and Screen Design Gravel-Pack Methods Alternate Pathway Screen Option 38 Open-Hole Frac Packing Chapter Three 43 Cased-Hole Sandface Completions 43 Completion Fluids Use of Completion Fluids Selection Criteria Fluid Loss Control 49 Debris Removal and Mysteries Displacement Procedures Pump Rates and Pressure Calculations 51 Fluid Filtration Filtration Guidelines Relationship between Completion and Filtration Filter Level Quality Completion Fluid Filter Types Filtration Quality Control 59 Perforating Gun Design and Deployment Techniques Detonation Methods Well/Reservoir Characteristics Perforation Clean Out Special Perforating Techniques Perforating Summary 70 Stand-Alone Screens CONTENTS v 71 Gravel Packing Perforation Prepacking Water Packs Slurry Packs Well Productivity Carrier Fluid Selection Field Evaluation Gravel-Pack Methods One-Trip Perforate and Pack System 81 Frac Packing Comparison of Frac Packs and Gravel Packs Comparison of Frac Packs and HRWPs Hydraulic Fracturing Concepts, Geometry and Rock Mechanics Frac Fluids and Proppants Pretreatment Testing Frac-Pack Methods/Applications 97 Gravel-Packing Method Selection Chapter Four 103 Surface Operations and Equipment 103 Surface Equipment and Techniques Mixing and Blending Equipment Pumping Equipment Proppant Handling Offshore Equipment 105 Monitoring and Control Monitoring and Control Equipment Design and Simulation 109 Evaluation Techniques Gravel-Pack Evaluation HRWP and Frac-Pack Evaluation Chapter Five 113 Alternative Practices and Special Techniques 113 Rigless Sand Control Techniques Chemical Methods Mechanical Methods 118 Specialty Tools and Techniques Wireline Gravel Pack VibraPak Multilaterals Rod Pump and ESP Sand Control Techniques Chapter Six 125 Next Generation Completion Technologies Appendix One 127 Gravel/Proppant Appendix Two 129 Graphic and Illustration Credits/Sources Appendix Three 131 Contributor Profiles and Acknowledgments 133 Service/Supplier Directory 139 Index vi Controlling Sand-Related Production Problems Causes and Effects of Sand Production • Understanding the Reservoir Productivity, Formation Damage and Flow Efficiency • Sand Management Techniques Justification for Sand Control • Types of Sand Control • Drilling, Cementing and Completion Considerations CHAPTER ONE 1 As the value of non-renewablehydrocarbon reserves and thecosts of remedial work increase, a renewed emphasis is being placed on proper well completion techniques. Maximum reliability and productivity are essential. These objectives are diffi- cult to attain in unconsolidated sand for- mations, which are always subject to structural failure. The sand production mechanism is exceedingly complex and is influenced by every completion oper- ation. This handbook will summarize the major problems encountered in unconsolidated sands, as well as current techniques and technologies employed in sandface completions. The techniques and equipment described have been field-proven in thousands of oil and gas wells. Sand flow—and the multitude of inconveniences, production losses, and serious well damage it can cause—is discussed with a view toward under- standing fundamental causes and imple- menting early preventive measures. Causes and Effects of Sand Production In highly unconsolidated formations, the production of formation fluids will probably be associated with the produc- tion of formation sand. In some situa- tions, small quantities of formation sand can be produced with no signifi- cant adverse effects; however, in most cases, sand production leads to reduced productivity and/or excessive mainte- nance to both downhole and surface equipment. Sufficient sand production may also cause premature failure of the wellbore and well equipment. Nature of Sand Production Conditions that can cause sand produc- tion and the probable condition of the formation outside of the casing after sand is produced can be determined by the factors that affect the beginning of sand production. These factors must describe both the nature of the forma- tion material and also the forces that cause the formation structure to fail. Strength of sandstone is controlled by: • Amount and type of cementation material holding the individual grains together • Frictional forces between grains • Fluid pressure within the pores of the rock • Capillary pressure forces Several researchers have investigated the type of failure that is likely to occur in sandstone. Work at Exxon1 indicates that the nature of a failed perforation tunnel is indicative of a shear failure that will occur when the compressive strength of the rock is exceeded. In addition, the Exxon work indicates that in weakly consolidated sandstones, a void is frequently created behind the casing. Exxon concluded that the for- mation’s compressive strength should be a good indicator of sand production potential, and that sand production will probably cause a void behind the casing that can be filled with gravel pack sand during a gravel packing operation. The mechanical failure of unconsoli- dated rock surrounding a perforation is analogous to the failure of a loose mate- rial surrounding a tunnel in soft earth. Terzaghi described the mechanism for load transfer surrounding a tunnel in such a situation2 in 1943. As the mate- rial over the tunnel yields, the stress originally held in the yielded material is relieved and transferred to the more rigid material surrounding the tunnel. However, a portion of the original stresses is supported by intergranular friction above the tunnel. To a certain extent, the arching con- cepts used in tunneling apply to the unconsolidated rock surrounding a per- foration. After some sand is produced from around a perforation tunnel, an arch is formed that has sufficient strength to support the weight of the surrounding material. Under certain conditions, the production of a limited amount of formation sand can be toler- ated to allow an arch to develop, after which the production of formation sand ceases.3 Figure 1.1 illustrates the con- cept of a stable arch around a perfora- tion; however, the stability of the arch is complicated by the fact that the state of stress surrounding the perforation is constantly changing due to changes in flow rate, reservoir pressure, producing water cut, etc. Effects of Sand Production The effects of sand production are nearly always detrimental to the short and/or long-term productivity of a well. Although some wells routinely experi- ence manageable sand production, these wells are the exception, not the rule. In most cases, attempting to man- age the effects of severe sand produc- Fluid inflow Fluid inflow Perforation tunnel Cement Sand grains under triaxial loading Fig. 1.1. Geometry of stable arch surrounding a perforation tion over the life of the well is not an economically attractive or a prudent operating alternative. Accumulation in surface squipment. If the production velocity is great enough to carry sand up the tubing, the sand may become trapped in the sepa- rator, heater treater, or production pipeline. If a large enough volume of sand becomes trapped in one of these areas, cleaning will be required to allow for efficient production of the well. To restore production, the well must be shut-in, the surface equipment opened, and the sand manually removed. In addition to the clean out cost, the cost of the deferred produc- tion must be considered. If a separator is partially filled with sand, the capacity of the separator to handle oil, gas and water is reduced. For example, one cubic foot of sand in an oil/water separator with a two-minute residence time will cause the separator to handle 128 fewer barrels of liquid per day. If the ratio of oil to water entering the separator is one to one (i.e., 50% water cut), the separator will deliver 64 fewer barrels of salable oil per day. At US$18/bbl, this adds up to US$420,480 worth of oil per year that is not moving through the separator. Accumulation downhole. If the pro- duction velocity is not great enough to carry sand to the surface, the sand may bridge-off in the tubing or fall and begin to fill the inside of the wellbore or casing. Eventually, the producing interval may be completely covered with sand. In either case, the production rate will decline until the well becomes sanded-up and production ceases. In sit- uations like this, remedial operations are required to clean out the well and restore production. One clean-out tech- nique is to run a bailer on the end of slick line to remove the sand from the wellbore. Since the bailer removes only a small volume of sand at a time, multi- ple slick line runs are necessary to clean out the well. Another clean-out operation involves running a smaller diameter tubing string or coiled tubing down into the production tubing to agitate the sand and lift it out of the well by circulating fluid. The inner string is lowered while circulating the sand out of the well. This operation must be performed cautiously to avoid the possibility of sticking the inner string inside the production tub- ing. If the production of sand is continu- ous, the clean-out operations may be required on a routine basis, as often as monthly or even weekly. This will result in lost production and increased well maintenance cost. Erosion of downhole and surface equipment. In highly productive wells, fluids flowing at high velocity and car- rying sand can produce excessive ero- sion of both downhole and surface equipment leading to frequent mainte- nance to replace the damaged equip- ment. If the erosion is severe or occurs over a sufficient length of time, com- plete failure of surface and/or down- hole equipment may occur, resulting in critical safety and environmental prob- lems as well as deferred production. For some equipment failures, a rig- assisted workover may be required to repair the damage. Collapse of the formation. Large volumes of sand may be carried out of the formation with produced fluid. If the rate of sand production is great enough and continues for a sufficient period of time, an empty area or void can develop behind the casing and can continue to grow larger as more sand is produced. When the void becomes large enough, the overlying shale or formation sand above the void may collapse into the void due to a lack of material to provide support. When this collapse occurs, the sand grains rearrange themselves to cre- ate a lower permeability than originally existed. This will be especially true for formation sand with a high clay content or wide range of grain sizes. For formation sand with a narrow grain-size distribution and/or very little clay, the rearrangement of formation sand will cause a change in permeabil- ity that may be less obvious. In the case of overlying shale collapsing, complete loss of productivity is probable. In most cases, continued long-term production of formation sand will usually decrease the well’s productivity and ultimate recovery. The collapse of the formation is par- ticularly important if the formation material fills or partially fills the perfo- ration tunnels. Even a small amount of formation material filling the perfora- tion tunnels will lead to a significant increase in pressure drop across the for- mation near the wellbore for a given flow rate. Causes of Sand Production The solid material produced from a well can consist of both formation fines (usually not considered part of the formation’s mechanical framework) and load bearing solids. The production of fines cannot normally be prevented and is actually beneficial. Fines moving freely through the formation or an installed gravel pack are preferable to plugging of the formation or gravel pack. The critical factor to assessing the risk of sand production is whether or not the production of load-bearing particles can be maintained below an acceptable level at anticipated flow rates and producing conditions. The factors that influence the ten- dency of a well to produce sand are the: • Degree of formation consolidation • Reduction in pore pressure through- out the life of the well • Production rate • Reservoir fluid viscosity • Increase of water production through- out the life of the well These factors can be categorized into rock strength effects and fluid flow effects. Each of these factors and their role in the prevention or initiation of sand production is discussed in the remainder of this chapter. Degree of consolidation. The ability to maintain open perforation tunnels is closely tied to the cementation of the sand grains around the tunnels. The cementation of sandstone is typically a secondary geological process and, as a general rule, older sediments tend to be more consolidated than newer sedi- ments. This indicates that sand produc- tion is normally a problem when pro- ducing from shallow, geologically younger Tertiary sedimentary forma- tions. Such formations are typically located in the Gulf of Mexico, Califor- nia, Nigeria, French West Africa, Venezuela, Trinidad, Egypt, Italy, China, Malaysia, Brunei and Indonesia, among others. Young Tertiary formations often have little matrix material (cementation 2 Modern Sandface Completion Practices 3 material) bonding the sand grains together. These formations are gener- ally referred to as being poorly consoli- dated or unconsolidated. A mechanical characteristic of rock that is related to the degree of consolidation is called compressive strength. Poorly consoli- dated sandstone formations usually have a compressive strength that is less than 1,000 psi. Additionally, degrading the matrix material, which would allow sand production, may change even well consolidated sandstone formations. This can be the result of acidizing treatments or high temperature, steam flood techniques. Reduction of pore pressure. As men- tioned previously, the pressure in the reservoir supports some of the weight of the overlying rock. As the reservoir pressure is depleted throughout the pro- ducing life of a well, some of the sup- port for the overlying rock is removed. Lowering the reservoir pressure creates an increasing amount of stress on the formation sand itself. At some point, the formation sand grains may break loose from the matrix, or may be crushed, cre- ating fines that are produced along with the well fluids. Compaction of the reser- voir rock due to a reduction in pore pressure can result in surface subsi- dence. For example, the Ekofisk central platform in the North Sea is reported to have sunk 10 ft in its first 10 years of existence due to subsidence. Production rate. The production of reservoir fluids creates pressure differ- ential and frictional drag forces that can combine to exceed the formation com- pressive strength. This indicates that there is a critical flow rate for most wells below which pressure differential and frictional drag forces are not great enough to exceed the formation com- pressive strength and cause sand pro- duction. The critical flow rate of a well may be determined by slowly increas- ing the production rate until sand pro- duction is detected. One technique used to minimize the production of sand is to choke the flow rate down to the critical flow rate where sand production does not occur or occurs at an acceptable level. In many cases, this flow rate is significantly below the acceptable pro- duction rate for the well. Reservoir fluid viscosity. The fric- tional drag force exerted on the forma- tion sand grains is created by the flow of reservoir fluid. This frictional drag force is directly related to the velocity of fluid flow and the viscosity of the reservoir fluid being produced. High reservoir fluid viscosity will apply a greater frictional drag force to the for- mation sand grains than will a reservoir fluid with a low viscosity. The influence of viscous drag causes sand to be pro- duced from heavy oil reservoirs that contain low-gravity, high-viscosity oils even at low-flow velocities. Increasing water production. Sand production may increase or begin as water begins to be produced or as water cut increases. Two possibilities may explain many of these occurrences. First, for a typical water-wet sandstone formation, some grain-to-grain cohe- siveness is provided by the surface ten- sion of the connate water surrounding each sand grain. At the onset of water production, the connate water tends to cohere to the produced water, resulting in a reduction of the surface tension forces and subsequent reduction in the grain-to-grain cohesiveness. Water pro- duction has been shown to severely limit the stability of the sand arch around a perforation resulting in the initiation of sand production.4 A second mechanism, by which water production affects sand produc- tion, is related to the effects of relative permeability. As the water cut increases, the relative permeability to oil decreases. This results in an increas- ing pressure differential being required to produce oil at the same rate. An increase in pressure differential near the wellbore creates a greater shear force across the formation sand grains. Once again, the higher stresses can lead to instability of the sand arch around each perforation (Fig. 1.1) yielding subse- quent sand production. Understanding the Reservoir By understanding the reservoir, it may be possible to predict whether a well will produce fluids without producing sand or predicting that some type of sand control will be required. In spite of the fact that there are a number of ana- lytical techniques and guidelines devel- oped to assist in determining if sand control is necessary, no technique has proven to be universally acceptable or completely accurate. In some geo- graphic regions, guidelines and rules- of-thumb apply that have little validity in other areas of the world. At the cur- rent time, predicting whether a forma- tion will or will not produce sand is not an exact science and more refinement is needed. Until better prediction tech- niques are available, the best way of determining the need for sand control in a particular well is to perform an extended production test with a con- ventional completion and observe if sand production occurs. Of course, any reservoir data should be correlated with available open-hole logs and for- mation core sample data as they form the foundation for understanding any reservoir. Formation Strength The general procedure followed by most operators considering whether or not sand control is required, is to deter- mine the hardness of the formation rock (i.e., the rock’s compressive strength). Since the rock’s compressive strength has the same units as the pressure draw- down in the reservoir, the two parame- ters can be compared on a one-to-one basis and drawdown limits for specific wells can be determined. Research per- formed at Exxon5 in the early 1970s shows that there is a relationship between the compressive strength and the incidence of rock failure. These studies show that the rock failed and began to produce sand when the draw- down pressure is 1.7 times the compres- sive strength. As an example, formation sand with a compressive strength of 1,000 psi would not fail or begin to produce sand until the drawdown was about 1,700 psi. The testing described was performed in the equipment illustrated in Figure 1.2 and an example of rock sample failure is shown in Figure 1.3. The correlation of the data from the research is shown in Figure 1.4. Other operators use Brinnell hard- ness of the rock as an indicator of whether to apply sand control. Actually, the Brinnell hardness of the rock is related to the compressive strength but is not as convenient to use since the Chapter One Controlling Sand-Related Production Problems units of hardness are dimensionless and cannot be related to drawdown as easily as compressive strength. Sonic Log The sonic log can be used as a way to determine the sand production poten- tial of wells. The sonic log records the time required for sound waves to travel through the formation in microseconds. The porosity is related to the sonic travel time. Short travel times, (for example, 50 microseconds) are indica- tive of low porosity and hard, dense rock; while long travel times (for example, 95 microseconds or higher) are associated with softer, lower den- sity, higher porosity rock. A common technique used for determining if sand control is required in a given geologic area is to correlate incidences of sand production with sonic log readings. This establishes a quick and basic approach to the need for sand control. However, the technique can be unreli- able and is not strictly applicable in geologic areas other than the one in which it was developed. Formation Properties Log Certain well logs, in addition to the sonic log, are indicators of porosity and formation hardness. For a particular formation, a low-density reading from a density log is indicative of a high porosity. Also, neutron logs are primar- ily an indicator of porosity. Addition- ally, several wireline-logging compa- nies offer a formation properties log.6 This log performs a calculation using the results of the sonic, density, and neutron logs to determine the likelihood of whether a formation will or will not produce formation material at certain levels of pressure drawdown. The cal- culation identifies which intervals are stronger and which are weaker and more prone to produce formation mate- rial. While the formation properties log has been used by some companies for over 25 years, the consensus is that it is usually conservative in its predictions on the need for sand control. Porosity The porosity of a formation can be used as a guideline for the need for sand con- trol. If the formation porosity is higher than 30%, the probability of a require- ment for sand control is higher. Con- versely, if the porosity is less than 20%, the need for sand control will probably be less. The porosity range between 20% to 30% is where uncertainty usu- ally exists. Intuitively, porosity is related to the degree of cementation present in a formation; thus, the basis for this tech- nique is understandable. Porosity infor- mation can be derived from well logs and/or laboratory core analysis. 4 Modern Sandface Completion Practices Oil reservoir Hand pump Confining pressure Ring nut End plug Piston Frac sand Unconsolidated sample Consolidated sample Perforation Pump Drain pan Fluid reservoir Pressure gauge Fig. 1.2. Rock failure test equipment with pressure drawdown Fig. 1.3. Cavity formation in rock during drawdown failure testing Early results Completion of test 0 0 2,000 4,000 6,000 Co m pr es si ve s tr en gt h, p si Pressure drop at failure, psi 500 1,000 1,500 Slope = 0.6 2,000 2,500 3,000 3,500 Fig. 1.4. Correlation from sand production initiation testing 5 Chapter One Controlling Sand-Related Production Problems Drawdown The pressure drawdown associated with production may be an indicator of potential formation sand production. No sand production may occur with low-pressure drawdown around the well, whereas excessive drawdown can cause formation material to be produced at unacceptable levels. The amount of pressure drawdown is normally associ- ated with the formation permeability and the viscosity of the produced fluids. Low-viscosity fluids, such as gas, expe- rience small drawdown pressures as opposed to the drawdown that would be associated with a 1,000 cp fluid pro- duced from the same interval. Hence, higher sand production is usually asso- ciated with viscous fluids. Finite Element Analysis Probably the most sophisticated approach to understanding the reservoir and predicting sand production is the use of geomechanical numerical models developed to analyze fluid flow through the reservoir in relation to the forma- tion strength. The effects of formation stress associated with fluid flow in the immediate region around the wellbore are simultaneously computed with finite element analysis. While this approach is by far the most rigorous, it requires an accurate knowledge of the formation’s strength both in the elastic and plastic regions where the formation begins to fail. Both of these input data are difficult to determine with a high degree of accuracy under actual down- hole conditions and that is the major difficulty with this approach. The finite element analysis method is good from the viewpoint of comparing one interval with another. However, the absolute val- ues calculated may not represent actual formation behavior. Time Dependence Whether time has an effect on the pro- duction of formation sand is sometimes considered to be an issue. However, there is no data that suggests that time alone is a factor. There have been undocumented claims that produced fluids could possibly dissolve the for- mation’s natural cementing materials, but no data is available to substantiate these claims. Multiphase Flow The initiation of multiphase fluid flow, primarily water and oil, can also cause sand production. Many cases can be cited where wells produced sand free until water production began, but pro- duced unacceptable amounts of forma- tion material subsequent to the onset of produced water. The reasons for the increased sand production are caused by two primary phenomena: the move- ment of water-wet fines and relative permeability effects. Most formation fines are water wet and, as a conse- quence, are immobile when a hydrocar- bon phase is the sole produced fluid because hydrocarbons occupy the majority of the pore space. However, when the water saturation is increased to the point that it also becomes mobile, the formation fines begin the move with the wetting phase (water) which creates localized plugging in the pore throats of the porous media. Additionally, when two-phase flow occurs, increased pres- sure drawdown is experienced as a con- sequence of relative permeability and increases the pressure drop around the well by as much as a factor of four to five. The result of fines migration, plugging, and reduced relative perme- ability around the well increases the drawdown to the point that it may exceed the strength of the formation. The consequences may be excessive sand production. Productivity, Formation Damage Damage and Flow Efficiency The issue of productivity is especially important in wells requiring sand con- trol. Gravel-packed wells are particu- larly sensitive to problems of extremely poor productivity if improper comple- tion techniques are used. On the other hand, the implementation of recognized best practices can result in very accept- able productivity from gravel-packed and nongravel-packed wells. Radial Flow The flow of fluids toward a well is governed by the principles of fluid flow through porous media. Darcy’s Law states that the flow of fluids through porous material is controlled by the pressure gradient from the virgin forma- tion to the wellbore, the viscosity of the flowing fluid and the area available for flow in the formation. The constant of proportionality between pressure drop and flow rate is called permeability. The permeability of a formation is a measure of the available flow area within a given cross-sectional area of porous material. In a linear flow situation, the flow area is constant, and therefore the pressure drop required to induce a given flow rate is constant. However, flu- ids flowing toward a well do not represent a linear flow situation and are usually modeled more accurately as radial flow. Under radial flow conditions, the area available for flow continuously decreases as the fluid gets nearer to the wellbore, as illustrated in Figure 1.5. As the flowing fluid approaches the wellbore, the decreasing area available for flow causes an increasing velocity of flow, with a cor- responding increase in pressure drop. The equation below is Darcy’s Law for radial flow expressed in oil field units. This equation can be used to examine the pressure changes surround- ing a flowing well. Where: pi = pressure at point of interest (psi) pe = pressure at drainage radius of well (psi) q = production rate (STB/d) Bo = formation volume factor of produced oil (reservoir bbl/STB) µ = viscosity of produced fluids (cp) k = formation permeability (md) h = thickness of the reser- voir (ft) re = drainage radius of well (ft) ri = radial distance from wellbore to the point of interest (ft) p p qB r ri e o e i = − 141 2. ln µ kh Reservoir thickness Fig. 1.5. Radial flow geometry The results of using this formula are illustrated in the graphs of Figure 1.6 for an oil well with a 200 md formation permeability that is flowing at 5,000 STB/d. The graph on the bottom is a detail plot of the top graph. It shows that the total pressure drop is equal to the reservoir pressure (approximately 2,700 psi), minus the pressure at the wellbore (approximately 2,070 psi), giving a total pressure loss across the area near the wellbore of 630 psi. Notice that almost half of the 630 psi of total pressure drop occurs within the 10 ft nearest the wellbore, and that more than 100 psi of pressure drop occurs within a 1-ft radius of the wellbore. Near Wellbore Flow Restrictions Because most of the pressure drop takes place in the area very near the wellbore, this same area is where any additional restrictions to flow have the most detri- mental effect. Two factors that affect the increase of this pressure drop are the amount of the permeability impairment, which is measured as a permeability reduction, and the radial thickness of the impaired or damaged area. Using the equation7 below to calcu- late the additional pressure drop associ- ated with a near wellbore flow restric- tion, Figure 1.7 illustrates the additional pressure drop that is created by reducing the permeability surrounding a wellbore from 1,000 md to 100 md. The different curves on this figure represent increas- ing radial distances of permeability damage ranging from 6 in. to 5 ft. Where: ∆pskin = pressure drop through damaged zone (psi) q = production rate (STB/d) Bo = formation volume factor of produced oil (reservoir bbl/STB) µ = viscosity of produced fluids (cp) k = formation perme- ability (md) ks = damaged zone permeability (md) h = thickness of the reservoir (ft) rs = radius of damage (ft) rw = radius of wellbore (ft) This plot indicates that, as expected, the total system pressure drop increases with increasing depth of damage. How- ever, the plot also illustrates that the majority of the increase in pressure drop is within a foot or so of the wellbore. The other factor that determines the magnitude of damage is the permeabil- ity of the damaged zone. Figure 1.8 indicates the pressure drop increase associated with a damaged zone which has a radial depth of 2 ft. The damaged zone consists of material with a perme- ability of 100 md, 50 md and 25 md, which is equivalent to 10%, 5% and 2.5% of the permeability of the virgin formation. Comparison of Figure 1.7 and Figure 1.8 indicates that severe per- meability impairment near the wellbore is much more detrimental than is mod- erate damage deep into the formation. The importance of severe permeabil- ity impairment can be shown by a cal- culation of the damaged productivity of a well expressed as a ratio of the undamaged productivity. This ratio is calculated as a function of the radial thickness of the damaged zone and the degree of permeability reduction by the following equation:8 Where: Js = productivity index of damaged well (BOPD/psi drawdown) Jo = productivity index of undamaged well (BOPD/psi drawdown) ks = permeability of dam- aged zone (md) ko = permeability of undam- aged zone (md) re = drainage radius of well (ft) rw = wellbore radius (ft) rs = damaged zone radius (md) Figure 1.9 shows the results when this equation is plotted against the dam- aged zone radius for different degrees of damage. This figure further supports the critical influence of permeability reductions very close to the wellbore. The permeability impairment sur- rounding a well is called skin factor, which is a dimensionless representation of the additional pressure drop across the near wellbore formation associated with the flowing of fluids through a near wellbore damaged zone. J J k k r r r r k k r r s o s o e w s w s o e s = + log log log ∆p qB kh k k r rskin o s s w = − 141 2 1 . ln µ 6 Modern Sandface Completion Practices 2,000 2,100 2,200 2,300 2,400 2,500 2,600 2,700 0 200 400 600 800 1,000 Pr es su re , p si Radial distance, ft Reservoir pressure = 2,700 psi Formation permeability - 200 md Production rate = 5,000 STB/d Oil viscosity - 1.02 2,000 2,100 2,200 2,300 2,400 2,500 2,600 2,700 2,800 2,900 3,000 0 200 400 600 800 1,000 Pr es su re , p si Radial distance, ft Formation permeability - 200 md Production rate = 5,000 STB/d Oil viscosity - 1.02 Fig.1.6. Calculated pressure distribution around a 200-md oil well Formation permeability - 1,000 md Production rate = 10,000 STB/d Damaged zone permeability - 100md Damage zone thickness No damage 6 inches 1 foot 2 feet 5 feet 0 500 1,000 1,500 2,000 2,500 3,000 0 2 4 6 8 1091 3 5 7 Pr es su re , p si Radial distance, ft Fig. 1.7. Additional pressure with increasing depth of damage Formation permeability - 1,000 md Production rate = 10,000 STB/d Damaged zone thickness - 2 ft Damage zone Permeability 100 md 50 md 25 md 0 500 1,000 1,500 2,000 2,500 3,000 0 2 4 6 8 1091 3 5 7 Pr es su re , p si Radial distance, ft Fig. 1.8. Effect of damage severity on magnitude of pressure drop increase The following equation9 illustrates how the dimensionless skin factor relates to this increased pressure drop. Where: s =productivity skin factor k =formation permea- bility (md) h =interval thickness (ft) ∆pskin=pressure drop through damaged zone (psi) q =production rate (STB/d) µ =viscosity of produced fluids (cp) Bo =formation volume factor of produced oil (reservoir bbl/STB) If the calculated skin number is posi- tive, there is an increased pressure drop around the well and the well is consid- ered to be damaged. On the other hand, if a negative skin is calculated, there is a zone of increased permeability pre- sent, typical of a stimulated well. Skin factors can range from about -6 to any positive number. Skin factors from +25 to +50 in high permeability formations are not uncommon. The effect of for- mation damage can be approximated through the concept of flow efficiency. This is a measure of the relative per- centage of the theoretical flow rate that can actually flow through a formation. The following equation presents an approximate method for calculating flow efficiency. Where: FE = flow efficiency (%) qs = flow rate from damaged well (STB/d) qo = hypothetical flow rate from undamaged well (STB/d) re = drainage radius of well (ft) rw = wellbore radius (ft) s = productivity skin factor The approximation of 8 for the term ln(re/rw) results from the fact that the natural log of a large number divided by a small number is approximately 8. Based on this equation, a well with a skin of +20 will have a flow efficiency of only about 28%. Skin factor is only a relative measure of an additional pressure drop in the flowing system. Skin factor does not distinguish between a near-wellbore, severely damaged zone and a deeper, moderately damaged zone. Formation Damage Mechanisms Skin is strictly a measure of an excess pressure drop in the producing forma- tion as fluids flow into a well. This excess pressure drop can occur from any one or several of a wide variety of causes. Various damage mechanisms can be classified into the following general categories: • drilling mud, cement and completion fluid filtrate invasion • solids invasion • perforating damage • fines migration • formation compaction • swelling clays • asphaltene/paraffin deposition • scale precipitation • emulsions • reservoir compaction • relative permeability effects • effects of stimulation treatments The critical factor from a well com- pletion standpoint is to limit, where possible, the creation of damage (espe- cially severe plugging in the near well- bore area). This means avoiding plug- ging of the perforations in a cased-hole completion and avoiding plugging of the formation face in an open-hole completion. Methods to avoid plugging will be described later. Beyond taking steps to eliminate severe permeability reduction in the near wellbore area, the next step in a completion is to obtain the best possible communication of the wellbore with the virgin formation. Sand Management Techniques Sand Management is an operating con- cept where traditional sand control means are not normally applied and production is managed through moni- toring and control of well pressures, fluid rates and sand influx. In the recent past, Sand Management in conventional oil and gas production has been imple- mented on a large number of wells in the North Sea and elsewhere. In almost all cases it has proven to be workable, and has led to the generation of highly favorable well skins because of self- cleanup associated with the episodic sand bursts that take place. These low skins have, in turn, led to higher pro- ductivity indexes (PIs), and each of the wells where sand management has been successful has displayed increased oil or gas production rates. Furthermore, expensive sand control devices are avoided and the feasibility of possible future well interventions is guaranteed. However, there is also risk that sand production might exceed expectations at a less than favorable production rate. In such cases, a perhaps costly work- over would be necessary to install some type of sand control method (Table 1.2). Historical Steps in Preventing Sand Production Risk Classical sand control techniques (such as gravel packing, wire-wrapped screens, frac pack, chemical consolida- tion, expandable screens, etc.) are based on a sand exclusion philosophy: abso- lutely no sand in the production facili- ties can be tolerated. Alternatively, in the absence of means of totally exclud- ing sand influx, the traditional approach is to reduce the production rate to mini- mize the amount of entering sand. The decision to exclude or control sand is based on a sand prediction anal- ysis. This has led to development of various techniques to predict the onset of sand production. As a result, sand influx is usually viewed as a factor that limits the production rate (and thereby FE q q r r s r r s s o e w e w = = + ≈ + 100 100 100 8 8 ln ln s kh P q B skin o = 0 00708. ∆ µ 7 Chapter One Controlling Sand-Related Production Problems 0.3 0.4 0.5 0.6 0.7 0.8 0.9 1.0 0 4 8 122 6 Damaged zone ks ko rw = 0.33 ft re = 660 ft 0.5 Productivity after damage/ undamagedproductivity 0.2 0.1 0.050.02 10 Pr od uc tiv ity a fte r d am ag e/ un da m ag ed p ro du ct iv ity Depth of damaged zone, (rS-rW) inches Fig. 1.9. Productivity loss caused by formation damage the cash-flow) through the induced pro- duction limitations set by installed sand control methods, production losses due to failures and workovers, and induced production restrictions arising from low maximum sand-free rate limits. However, sand influx is related to the mechanical failure and dilation of the formation rock and the removal of failed or damaged material. Clearly, the permeability in the wellbore vicinity is increased with respect to the intact for- mation. This has been verified in a case where well test data show that negative skin values often develop as a result of a cleaning of the near-wellbore forma- tion of sand.10 Sand Management Philosophy Table 1.1 is a critique of different meth- ods used for dealing with sand produc- tion: generally, sand control represents high-cost, low-risk solutions. Sand Management leads to low-cost solu- tions, but it also involves active risk management.11 Risk management requires reliable analysis of the Sand Life Cycle, starting with predicting formation conditions conducive to sanding, and ending with ultimate disposal of the produced material at the surface. These techniques are based on: • An extensive field data acquisition campaign • Theoretical modeling of the involved physical processes • Active monitoring and follow-up on production data • Well testing to optimize production rates Also, the techniques will help the production engineer in: • Completion design optimization • Risk assessment throughout the well’s production life. Phases in the Sand Life Cycle include sand detachment, sand trans- port, sand erosion and surface sand deposition. Quantification of Sand Production Risk Traditionally, sanding risk is perceived as the risk of reaching the operative conditions at which sand begins to enter into the wellbore. It is implicitly assumed that sand will eventually cause unbearable problems and that no effec- tive action can be taken to cope with it except to avoid the sand inflow. Sand Management extends this con- cept by assuming that sand production is not always unacceptable, economi- cally or for safety. Table 1.2 lists dif- ferent cases and suggests a classifica- tion with respect to the risks, and also to the benefits.12 Well Monitoring for Reliable Sand Management Sand monitoring. Sand monitoring is a critical aspect of Sand Management. Current sand monitoring methods may be classified as: • Volumetric methods: • Sand traps may be installed, usually Sand Control Method Major Short-Comings Chemical consolidation • Some permeability reduction • Placement and reliability issues • Short intervals only Screens, slotted liners, special filters • Lack of zonal isolation (including expandable screens) • High placement & workover costs • Longevity of devices • Plugging and screen collapse • Screen erosion • Potential damage during installation Inside-casing gravel packing • PIs reduction • Placement and workovers difficult • High cost of installation • Positive skin development Open-hole gravel packing • PIs reduction • Complexity of operation • Necessity for extensive under-reaming in most cases • Costs of installation Propped fracturing, including frac • Permeability recovery packing, gas propellant fracturing, • Risks of tip-screenout during installation and use of resin coated sand • Directional control and tortuosity issues (in inclined wells) • Fracture containment control • Proppant flow-back on production Selective perforating • Problematic in relatively homogneous formations • Need for formation strength data • Reduces inflow area Oriented perforating • Necessity for full stress mapping • Theoretical analysis required • Perforation tool orientation needed • Limited field validation available Production rate control • Erosion of facilities • Sand monitoring required • Separation and disposal required • Potential for lost production Table 1.1. Critique of different sand prevention methods Environment Bad ??? Good Gas or condensate ��� HP/HT � Sub-surface wellhead !!!! Depletion drive reservoir !!! Horizontal well !! Injection wells !! Separator functioning ! Low PIs $ Asphalt/scale precipitation $$ Heavy oil $$$$ �=hazardous !=of concern $=profitable Table 1.2. Sanding impact in various well environments 8 Modern Sandface Completion Practices 9 at tees or bends, to capture sand. Sand is measured by disassembling the sand trap, thus it is not a real-time method. Such techniques have not proven effective, because the major- ity of the produced sand is normally not captured (North Sea experience indicates a recovery of 1% to 10%). • Fluid sampling after the primary sep- arator represents an alternative, including centrifugation for water and sand cuts. This is the so-called Bottom Sediment and Water mea- surement (BS&W) done during appraisal well testing or during nor- mal production. However, much sand usually remains in the primary sepa- rator and the method sensitivity can not be guaranteed. • Another idea consists in dismounting the sand separator, jetting it clean from all sand, and quantifying all produced solids. This has been used quite extensively in the Adriatic Sea on gas wells.13 However, it is limited in terms of accuracy (see point above) and practicality (i.e., the time and manpower required to dismount, jet, and remount the separator). • A new method used on some North Sea platforms applies an in-line sand cyclone. Sand is effectively sepa- rated from produced fluids and stored in a tank. Load cells or other devices on the tank allow a measure of sand accumulation in real time. • Acoustic transducers installed in the flow system include: • An impact probe installed in the flow line to detect sand grain impacts. • An acoustic collar that captures information about the impact of the sand grains against the wall of the pipe or the choke throat. • Erosion monitoring on steel goods or special tab erosion: • Ultrasonic gauges are clamped to the external surface of the pipe. They send out an ultrasonic pulse to mea- sure thickness. The method is sensi- tive to noise from other sources. • Weight-loss coupons made of the same or similar material as the pipe being monitored are installed and periodically retrieved and weighed. They provide only discrete monitor- ing and are unsuitable for subsea installations. • Electrical resistance probes which measure accumulated erosion as an increase of electrical resistance (Ohm’s law) on a known cross sec- tion. Calibration and temperature changes are of concern. • Electrochemical probes that deter- mine erosion rate through measure- ment of the linear polarization resis- tance between electrodes through a conductive electrolyte flowing inside the pipe may be used. The method is suitable only for conductive liquids such as water or oil systems with high water cuts. Sand detector data interpretation. Sand detector technology has improved greatly in the recent past, in particular, in improved signal-filtering techniques, rapid acquisition and better analysis. However, the lack of downhole sand monitoring systems introduces errors in terms of the time lag between downhole and surface (or subsea) sand production. Well Management Optimization with Sanding Risks With a reliable Sand Management anal- ysis it is possible to define safe limits within which production rates should be kept. This information allows designing and managing the well so as to extend these limits and even to increase well productivity. Some exam- ples are given below. Rate exclusion. Reduction in produc- tion rate will reduce drag forces and drawdown to provide reduced risk of sand production. The procedure is to slowly increase rate until sand produc- tion begins to increase, and then, sequentially reduce flow rate until the sand production declines to an accept- able level. The object is to establish a maximum flow rate in conjunction with the stable-arch concept, which was described previously in this Chapter. Selective perforating practices. In het- erogeneous formations, strength varia- tions among different lithologies may be substantial; avoiding perforating the weakest intervals may lead to higher critical drawdown values. Once forma- tion characteristics are known, perforat- ing strategies can be evaluated. If possi- ble, only high strength intervals can be perforated. For high rate wells this will require a high shot density to prevent additional pressure drop and associated sand production. However, high shot density can lead to perforation interac- tion, which also promotes sand produc- tion. Selecting the appropriate compro- mise is the key to success. Perforating for sand prevention. It has been suggested that the best tech- nique to limit sand production is to minimize entry hole diameter, and space the perforations far enough apart to prevent failed-zone interactions. With standard phasing this leads to low shot density, which tends to promote failure through higher flow velocities. Phasing can be optimized to provide the least amount of interaction with great- est shot density. If stress state is known, orienting shots within about 25° of the optimum direction can provide improved stability. Also, perforating into breakouts should be avoided. Orientated perforating. Laboratory tests in the past have indicated that the mechanical stability of perforation cavi- ties depends on perforation direction relative to the in situ stress field.14 This led to the idea of oriented perforating to minimize the shear stresses acting at the wall of the perforation cavities. The method uses 180° phasing, which may affect the perforation density. This is, however, seldom a problem, as weak sandstone formations are normally quite permeable and do not require large drawdown. Some uncertainty must be accounted for in gun orienta- tion, but computations demonstrate that the sensitivity to this is not very high. Figure 1.10 shows the large gain, in terms of increased critical drawdown, of proper perforation orientation and the sensitivity of gun orientation. Even at great uncertainties on the order of 20°, benefits are still pronounced. Another argument for 180° phased, orientated perforating is the reduced probability of the perforations being oriented in the worst direction, which by itself reduces the sand production risk.11 Justification for Sand Control Operational problems related to sand production vary from expensive sand- handling problems to complete loss of a productive zone or the possibility of Chapter One Controlling Sand-Related Production Problems loss of well control due to an eroded surface production control equipment. Sand Disposal Sand disposal is a common problem in fields producing from unconsolidated sands. Even wells with successful sand control measures will produce small quantities of sand. While an acceptable rate of sand production may be as high as 0.1% by volume, this is a consider- able amount of sand. For example, at 0.1%, one well producing at the rate of 750 BOPD will produce 0.75 b/d of sand. When there are several wells pro- ducing into a common platform, the vol- ume of sand can be quite large. In off- shore locations, the sand must first be separated from the produced fluids and all oil removed prior to disposal. One processing system that satisfies anti- pollution laws utilizes cyclone separa- tors and oil cleaning chemicals. In this system, the sand is completely cleaned and discharged into the Gulf of Mexico. In other systems, sand is transported to shore where it is then disposed. Sand Erosion Sand production can cause erosion in both surface and downhole equipment. Downhole erosion is most likely to occur in blast joints or tubing opposite perforations or in screens or slotted lin- ers that were not packed in the gravel pack installation procedure. Erosion is more severe where the sand is produced in gas or where the produced fluids are in turbulent flow. High-pressure gas, containing sand particles, expanding through a surface choke is the most haz- ardous situation. While it is impossible to completely stop sand production, high-pressure gas production cannot tol- erate even smaller quantities of sand because of potential loss of well control. Types of Sand Control Sand control methods have become more varied in recent years. Since the early application of gravel packing, there have been several new processes introduced with varying results. Many of these innovations were introduced in the U.S. Gulf Coast area because, his- torically, gravel packing provided poor results in formation sands there. Results from these new techniques varied widely, so the industry moved rapidly from one process to another, but most often returned to gravel pack- ing. In the 1980s and 1990s, researchers and engineers found some of the keys to improved productivity in gravel pack completions. Therefore, gravel packing has maintained industry domi- nance and many alternative methods have been abandoned or their use diminished greatly. Factors normally considered in selection and design in a particular field or well are listed below:15 • Initial sand control cost • Expected reliability • Effect on productivity • Completion repair cost • Formation sand quality • Presence of multiple, thin productive sections • Exclusion of inter-bedded water or gas • Presence of undesirable shale streaks • Level of reservoir pressure depletion • History of sand production Sand-control methods can be grouped as follows: • Production rate control • Selective and oriented perforating • Mechanical stressing of the formation • Sand packing to restore formation stresses • In situ sand consolidation • Resin coated gravel packing without a screen • Mechanical control (prepacked, stand-alone, expandable screen, etc.) • Gravel packing, open hole and inside casing • Propped fracturing, including frac packing, propellant gas fracturing, and use of resin-coated sand Details about all of the above are discussed in later sections. Drilling, Cementing and Completion Considerations Successful sand control applications require that each step of the well com- pletion be designed and executed prop- erly. Such steps include drilling, cementing, perforating and use of drill- in fluids or completion and workover fluids. Of course, the sand control com- pletion stage must be suitably designed and installed as well. As Bruist16 cor- rectly emphasized back in 1974, there 10 Modern Sandface Completion Practices 0 50 100 150 200 250 350 400 450 300 0 10 50 70 9040 60 8020 30 Cr iti ca l d ra w d ow n, b ar Perforation direction, degrees relative to maximum horizontal stress direction Norwegian sector HPHT well vertical well case No depletion 200 bar depletion 400 bar depletion 600 bar depletion 50 bar drawdown line Fig. 1.10. Effect of oriented perforations on critical drawdown 11 are distinct and important mutual dependencies between various comple- tion operations when sand control is installed. Failure at any step may adversely affect well reliability and/or productivity. Higher-permeability sandstone for- mations, which more likely would pro- duce sand, are often subject to severe near wellbore damage caused by drilling fluids, cement filtrate, and completion fluids. Some of this damage is not easy to remove with acids and solvents, and diversion of treating fluids throughout the damaged interval is difficult. Drilling Related Issues Formation damage that can occur dur- ing the drilling of the productive inter- val should be avoided. Such impairment can be difficult or impossible to remove and may cause serious difficulties, such as non-uniform placement of gravel or consolidation chemicals, or unnecessar- ily high, localized produced fluid veloc- ities. In the latter case, with a portion of the pay zone blocked or restricted, the increased flow rate per unit area of for- mation open for production may be just high enough to cause sand production. In addition, high velocities can also increase downhole equipment erosion. During drilling, productivity can be damaged by washouts through the pay zone and reduction of permeability by low salinity mud filtrate, which dis- perses or swells water-sensitive clays. Washouts can reduce cementing effec- tiveness, commonly causing communi- cation between oil, gas and water zones that require remedial repair work to pre- vent unnecessary water production or even premature abandonment. Also, the extra-long perforation tunnel through cement in a washed-out section can substantially reduce productivity from a gravel pack due to high-pressure drop across gravel-filled perforations. Effective Cementing Proper cement is imperative to obtain a good well completion, but is one of the most difficult completion phases. Cementing problems still exist that were first discussed in 1941 by Jones and Berdine.17 The goal is and has always been to maximize mud displace- ment efficiency. Conditions are particu- larly severe in deviated and horizontal holes because of the casing being off- center. This phenomenon is illustrated in Figure 1.11. For such cases, accepted practices are: • Drill gage hole • Centralize pipe • Reciprocate or rotate pipe during placement of cement • Place cement slurry in turbulent flow during displacement if possible; otherwise, maximize the pump rate • Place an adequate, compatible spacer between the mud and cement slurry • Control properties of the mud and cement slurry In practice, some of the above requirements may not be attainable because high pump rates may cause lost circulation and reciprocation or rotation of the pipe may not be possible in highly deviated holes. In addition, spacer fluids should be properly designed to avoid well control problems and hole instabil- ity, which can stick the pipe and prevent its further movement. Other Completion Concerns Perforating debris and mud pockets at the cement formation interface can pre- vent uniform sand placement when gravel packing. This impairment can be locked in place by the sand control pro- cedure. Moreover, having clean perfora- tions is a must. Completion fluids can cause impair- ment due to deep formation invasion by entrained solids, or dispersion of forma- tion water-sensitive clays, as with mud filtrates. Therefore, the completion fluid must be formation compatible and ade- quately filtered. Damage can also occur if the completion fluid is not properly designed and large quantities of bridg- ing material are lost to the formation. The above points are mentioned to emphasize that proper sand control installations depend on almost all aspects of the drilling, cementing and completion operations. Best possible procedures should be followed during a sand control operation. Otherwise, a short-lived, ineffective installation may result if the well is not properly handled before, and after the application. References 1. Penberthy, W. and Shaughnessy, C., Sand Control, SPE Series on Special Topics, Volume 1, 1992. 2. Roberts, A., Geotechnology: An Introductory Text for Students and Engineers, Pergamon Press, New York, New York, 1977. Chapter One Controlling Sand-Related Production Problems Cement Mud Casing Cross section Top view Fig. 1.11. Cement channeling caused by off-centered pipe 3. Suman, G., Jr., Ellis, R., and Snyder, R., Sand Control Handbook, Second Edition, Gulf Publishing Company, Houston, Texas, 1991. 4. Ibid 5. Penberthy, W. and Shaughnessy, C., Sand Control, SPE Series on Special Topics, Volume 1, 1992. 6. Tixier, M., Loveless, G., Anderson, R., “Estimation of Formation Strength From the Mechanical-Proper- ties Log,” Journal of Petroleum Technology, March 1975, 283-293. 7. Earlougher, R. Jr., Advances in Well Test Analysis, SPE Monograph Series, Volume 5, 1977. 8. Williams, B., Gidley, J. and Schechter, R., Acidizing Fundamentals, SPE Monograph Series, Volume 6, 1979. 9. Lee, W., Well Testing, SPE Textbook Series, Volume 1, 1982. 10. Santarelli, F., Tronvoll, J., Skomedal, E. and Bratli, R., “The Skin Factor as a Rock Mechanics Diagnostic Tool.” SPE 37381, presented at the SPE/ISRM Eurock ‘98 Conference, Balkema, 1998. 11. Tronvoll, J., Dusseault, M., Sanfilippo,F., and Santarelli, F., “The Tools of Sand Management.” SPE 71673, presented at the SPE Annual Technical Con- ference and Exhibition, New Orleans, Louisiana, 2001. 12. Ibid. 13. Sanfilippo F., Brignoli M., Giacca D. and Santarelli F. “Sand Production: From Prediction to Manage- ment.” SPE 38185, presented at the European Forma- tion Damage Conf. Proc., The Hague, 1997. 14. Tronvoll, J., Kessler, N., Morita, N., Fjær, E., Santarelli, F., 1993: The Effect of Anisotropic Stress State on the Stability of Perforation Cavities, Int. J. Rock Mech. Min. Sci. & Geomech. Abstr. 30, 1085- 1090. 15. Suman, G., Jr., Ellis, R., and Snyder, R., Sand Control Handbook, Second Edition, Gulf Publishing Company, Houston, Texas, 1991. 16. Bruist, E., “Better Performance of Gulf Coast Wells.” SPE 4777, presented at the SPE Symposium on Formation Damage, New Orleans, Lousiana, 1974. 17. Jones, P., and Berdine, D., “Oilwell Cementing Factors Influencing Bond between Cement and Forma- tion,” API Drilling and Production Practice, 1941. 12 Modern Sandface Completion Practices CHAPTER TWO Open-Hole Sandface Completions Drill-In Fluids • Stand-Alone Screens • Gravel Packing • Open-Hole Frac Packing 13 Maintaining borehole stability dur-ing the drilling and completionphase of well construction is an essential requirement for open-hole sandface completions. Concern over the lack of borehole stability is a primary reason why open-hole completions are not used more often in unconsolidated formations. Unstable boreholes make running of tubulars and other downhole tools difficult. Fortunately, state-of-the art drill-in fluids are effective in main- taining borehole stability and preventing formation damage, which makes verti- cal, deviated and horizontal completions possible in dilatant sand formations known to have presented problems in the past. Open-hole sandface completions are usually avoided in formations with several sand and shale sequences, if the shales are prone to eroding and/or sloughing. During an open-hole gravel pack completion (described later in this chapter), the shale can intermix with the gravel-pack sand resulting in reduced gravel permeability and impaired well performance. Proper drill-in fluid selec- tion can alleviate some of the problems associated with laminated sand and shale formations. Drill-In Fluids A drill-in fluid (DIF) is a special fluid designed exclusively for drilling through the payzone or productive reservoir section of a wellbore. The reasons for using this specially designed DIF are to: • Drill the reservoir zone successfully, often a long, horizontal drain hole • Minimize damage and maximize production of exposed zones • Facilitate the well completion needed, which can be simply a stand-alone screen or a complicated procedure, such as a gravel pack. A drill-in fluid should resemble a completion fluid brine (a whole series of which are discussed in Chapter Three). It may be brine containing only selected solids of appropriate particle size ranges (salt crystals or calcium carbonate) and polymers. Only additives essential for filtration control and cuttings carrying are present in a drill-in fluid. A DIF can also be an all-oil system. Unlike con- ventional water-based systems, oil- based systems have an inherent advan- tage of being used without the risks in strata containing shales. Mixed metal silicate (MMS) systems are another alternative DIF.1 However, the focus of this section will be confined to water- based DIF systems most commonly used in sandface completions. Fluid design. Payzone drill-in fluid design should be based on a complete study of the reservoir rock characteris- tics at downhole conditions. The rock minerals and the chemical composition of the reservoir fluids should be deter- mined and evaluated for compatibility. To maximize well productivity and ensure proper reservoir protection, the casing should be set prior to drilling the payzone section. Conventional mud is then displaced by a displacement fluid, which is specially designed to minimize damage and yet maintain the necessary drilling fluid properties. This fluid must be tested in a laboratory to verify fluid/rock and fluid/fluid interaction, as well as possible residual damage. Based on the test results, the best treatment to remove such damage is devised. Field problems such as scale precipitation while completing wells with high den- sity brines, damage caused by oil-based mud when followed by brine comple- tion fluid, and fluid loss in the payzone can be eliminated by the timely use of available techniques.2 Fluid selection. The evaluation and selection of drilling and drill-in fluids for long, open-hole completions have been the subjects of numerous studies. In addition to the standard drilling fluid tests (rheology and fluid loss), forma- tion and completion-damage tests must be included to ensure the desired pro- ductivity level is achieved. Because the damaged zone created by conventional drilling fluids will not be bypassed in the open-hole completion, more atten- tion has been directed to developing less damaging DIFs. However, to con- firm formation compatibility and iden- tify the best DIF, specialized laboratory testing that simulates the anticipated drilling, completion and producing con- ditions is required.3 Formates. In recent years sodium and potassium formates have been used suc- cessfully for drill-in fluid applications. One application was a low permeability reservoir where solids-free formates were applied with polymers specifically for fluid loss. Formate brine systems tend to stabilize polymers at high tem- peratures. The polymers can be readily removed with enzymes.4 Additionally, Cabot Specialty Fluids recently reported that cesium formate (another formate based brine) was used in several field operations where wellbore temperatures reached 401ºF (205ºC) and bottomhole pressures exceeded 16,000 psi. Two popular DIFs are Thixsal- Ultra (a NaCl solids system from TBC- Brinadd) and PerfFlow (a CaCO3 solids from Baker Inteq). Thixsal-Ultra is an ideal fluid system for drilling the payzone in highly devi- ated and horizontal wells. Use of improved bridging particle distribution in Thixsal-Ultra reduces filtration con- trol polymer requirements while provid- ing more dense, ultra-low permeability filter cakes. PerfFlow DIF seals pore openings exposed to the wellbore and remains intact during completion operations. The thin (less than 1 mm) PerfFlow filter cake (Fig. 2.1) is easily removed with low production pressures. Other proven DIFs include: FloPro NT (from M-I) and Baradril N (from Halliburton). ActiSystems has a DIF that is being used to drill horizontal and high-angle wells through damage-prone reservoirs. This fluid combines certain surfactants and polymers to create a system of “micro-bubbles” known as gas aphrons encapsulated in a uniquely viscosified system. (Aphrons are micro-bubbles smaller than 200 micron. Their stability increases as their size decreases and they decrease the density of the base fluid.) These aphrons (Fig. 2.2) are non- coalescing and can be recirculated so that density reduction is accomplished without expensive air or gas injection. A unique feature of the micro-bubble network is stopping or slowing the entry of fluids into the formation by creating downhole bridging.6 Fluid Loss Fluid invasion into productive zones is recognized as detrimental to well pro- ductivity. Filtrate and solids invasion can cause irreversible formation dam- age and permeability reduction. Non- damaging, water-soluble or acid-soluble solids are added to drill-in fluids to pro- mote pore plugging and minimize fluid penetration. Development of less inva- sive, non-damaging fluid formulations requires knowledge of filtration mecha- nisms of solids-containing polymeric solutions in porous media. The application of a specialty DIF for an open-hole completion, particu- larly in horizontal wells, offers distinct advantages for maximizing production. DIF systems are designed to prevent liquid and solids invasion into a perme- able formation by bridging and sealing with a readily removable ultra-low per- meability filter cake. These characteristics are achieved by selecting a suitable size range and parti- cle distribution of soluble solids for bridging the pore openings between for- mation sand grains. Four types of solu- ble solids are available: • Water soluble such as sized NaCl in saturated brine • Acid soluble such as CaCO3 • Oil soluble specialty products • Breakable polymers such as HEC and Xanvis. An optimum concentration of these solids must be determined and properly balanced with sufficient sub-colloidal- sized components. The result of this optimized compo- sition is a stable filter cake with low fil- trate under specific conditions of tem- perature and pressure, Figure 2.3.7 The low permeability cake is deposited quickly and prevents excessive filtrate from entering the formation. Also, this film of polymer and NaCl allows the column of fluid to transmit the neces- sary hydrostatic pressure to keep the wellbore open, stable and in-gauge. In addition, the correct design and maintenance of a DIF is critical where open-hole completions are planned. The particle-size distribution of solids in the open hole must be carefully cho- sen, not only to bridge across the exposed formation, but also to permit flow back through the openings in the completion slotted liner or screen. Ini- tial fluid design and testing must be done in the laboratory. Once drilling has started in the reservoir, any flow back testing on field samples usually requires urgent shipping to a laboratory, resulting in costly delays. Figure 2.4, the Production Screen Tester (PST) (from M-I) can be used to perform testing of fluid flow back at the rig site. It can be used effectively with all screen types, from simple single- wrap designs to the more exotic pre- mium screens. (These sand exclusion devices will be discussed in the next section of this Chapter.) The PST unit is equipped with a portable CO2 cartridge holder and regu- lator to simulate drawdown pressure. In the laboratory, it can be attached to a compressed-air source. Removing fluid loss materials from the filter cake involves first getting the breaking fluid to interact with the bridging material and flushing whatever residual material is present. Washing a formation that has been plugged is dif- ficult. The more powerful acids will eat their way into the formation, but will also disturb the formation matrix and can cause problems greater than those caused by the bridging agents. The best alternative is a material where the breaker (enzyme, oxidizer or acid) trav- els with the polymer and waits for the proper conditions to go to work. Completion Considerations Maintaining formation compatibility and switching out the drilling fluid into a completion system requires knowl- edge of possible hole problems and the use of a staged wellbore cleaning pro- cedure. Maximum reduction of solids in the casing and open hole, as well as removal of filter cake, will minimize particle intrusion into the completion assembly during placement or when the 14 Modern Sandface Completion Practices Fig. 2.1. Micrograph of PerfFlow DIF system filter cake Gas Gas Gas Gas Gas Gas Gas Gas Meniscus: Source of laplace pressure Continuous film Plateau borderSoap film Gas Gas Gas Gas Gas Fig. 2.2. Structure of gas aphron5 0 2 4 6 8 10 12 14 0 4321 5 876 Test conditions: Media = 1,500 md sand Temperature = 150°F Pressure = 250 psi Fi ltr at io n vo lu m e, m l Filtration time, min Fig. 2.3. Fluid loss of a 10.5 ppg NaCl suspension 15 well is produced. Five major categories are addressed as completion considera- tions: • Formation compatibility • Drilling fluid transition to completion system • Completion assembly design • Displacement and clean-up procedure • Post-completion application. Formation compatibility. In situations where troublesome shale sections are anticipated, additions of potassium chloride or various polyglycols can be incorporated into the base fluid system. Shale Stability Index (SSI) values define the surface conditions of shale specimens before and after exposure to test fluids. The lower the SSI value, the higher the water uptake into the shale.8 Relatively high values are displayed in Table 2.1 for the standard polymer/salt system. However, improved values may be obtained through proper treatment. Drilling fluid transition to completion system. After insuring formation com- patibility of all fluids that contact the open hole, the next stage in the comple- tion is conducted with the drill pipe in the wellbore after reaching the total depth of the well. The drilling fluid is displaced from the open hole and 500 ft (152.4 m) into the last casing string with a new mixture of properly sheared polymer and suspended NaCl or CaCO3. It should have a maximum par- ticle size that is determined by one of the “rules of thumb” (see the Fluid Fil- tration section in Chapter Three). Assuming the well is a stand-alone completion, correct particle sizing will help prevent plugging of the slotted liner or screen. (Stand-alone comple- tions are covered in the next section of this Chapter.) When the relationship between pore size or slot width/screen spacing and particle size of the solids in a fluid is: Then, bridging occurs. Where: Dp = diameter of particle d = average pore diameter or slot width/screen spacing Since the completion pill mixture will not have been sheared through the nozzles of a drill bit, the use of a unit providing mechanical or hydraulic shear will prevent large “fish eyes” (clumps of partially hydrated polymer), and per- haps, “angel hair” (strands of partially hydrated polymer) that could infiltrate and bridge inside the sand exclusion device. Figure 2.5 shows a hydraulic shearing device that can effectively and efficiently mix dry materials with liq- uids, as well as blend, emulsify and sta- bilize liquid/liquid phases. A clean displacement mixture is important for several reasons: • It provides a fluid, which does not contain insoluble drill solids. • The soluble solids suspended in the open-hole annulus will ensure ade- quate secondary bridging particles for fluid loss control if the filter cake is damaged while placing the comple- tion assembly. • If an adequate displacement of the open-hole annulus is not achieved after placing the completion assem- bly, the smaller micron size of the suspended solids can more readily pass through the pores of a resin coated sand in a prepacked screen. D d p > 3 Chapter Two Open-Hole Sandface Completions Fig. 2.4. Production screen tester Drilling Fluid SSI Oil mud 100 Xanthan gum/hydropropylated starch derivative fluid treated with polyglycols 95 KCI/polysaccharide mud 90 Xanthan gum/hydroxypropylated starch derivative fluid 85 Lime/starch mud 74 Lignosulfonate mud 64 Table 2.1. Shale stability index (SSI) of various fluids Fig. 2.5. Hydraulic shearing device (Jet Shear) with a chemical hopper and eductor (venturi) After displacing the open hole with the polymer/superfine soluble-solids mixture and prior to running the com- pletion assembly, the polymer, sized- solids drilling fluid in the casing should be replaced with filtered completion brine. This provides a solids-free envi- ronment through which the completion assembly may pass. Using clean brine in the upper well- bore will allow the liquid to penetrate and fill the slotted liner or screen. This displacement to filtered brine reduces the risk of solids infiltrating into the sand exclusion device during its placement. Completion assembly design. As pre- viously discussed, wells that produce formation sand can create problems with formation erosion and can damage surface production equipment. There- fore, sand exclusion techniques are incorporated to limit or stop movement of sand while continuing to allow high production rates. The most common alternatives for sand exclusion include: • Slotted liners • Conventional wire-wrapped screens • Prepacked, premium and expandable screens • Gravel packing. Regardless of the slotted liner or type of screen run for sand exclusion, restric- tions to flow could develop wherever particles begin to collect and bridge. Therefore, before producing the well, an appropriate displacement and disassoci- ation of the filter cake into its individual components will limit the number of particles which could become plugged in the slotted liner or screen. Successful fluid displacement through the completion assembly can only be accomplished if the openings through which the solids must pass are sized large enough or the particles in the fluid are small enough to prevent bridg- ing. Typical openings for screens and the particle size required to initiate a primary bridge are shown in Table 2.2. Solids in the fluid system must be smaller than 1/3 of the opening size of the selected exclusion device in order not to bridge. Common features of assemblies that address removal of sized solids from the open hole during completion incorporate various options for fluid displacement and subsequent clean-up (Fig. 2.6). Common techniques used to remove solids include: Washing – Offers a method for wash- ing out low side cuttings, sand, bridges and excess fill by circulating fluid through the tubing and annulus during screen placement. It is also effective for spotting or removing pill material prior to setting the packer. Circulating bridging solids – Pro- vides the capacity of removing solids- laden pill material in the open-hole annulus to above packer depth, and out of the wellbore by circulating through tubing to the outside of the screen. The circulating direction is reversed with different options, but each method works equally well if the openings through which fluid must pass are large enough to prevent particle bridging. The fluid path into the annulus can be through: (1) a shoe assembly located near total depth and returned through a closing sleeve port, or (2) out a crossover assembly port near the casing shoe with returns through a slotted sub- assembly into the base of the washpipe. Isolating open hole – Utilizes seal assemblies or a reverse circulating posi- tion to control losses and to provide soak time for clean-up solutions. When using a crossover assembly, the com- pleting brine in the casing can easily be changed without disturbing the clean- up solution in the open hole. Screen cleaning – Provides a tech- nique to remove particulate from the slotted liner or screen with brine jetted from a cup wash tool, while taking returns through a closing sleeve. Diverting fluid flow – Prevent fluid from re-entering the screen during jet- ting operations with the addition of baffle cups on the washpipe. Post-completion isolation – Isolates the open hole by incorporating a mechanical, knock-out flapper valve for closure into the screen when the washpipe is removed. Displacement and clean-up proce- dure. The selection of a mechanical configuration, which permits circula- tion of a solids-laden fluid from a well- bore, is only one of the design parame- ters that must be considered. The method of displacement is influenced by well geometry, screen standoff, flow rate, fluid density and rheology.9 Com- bining this with the subsequent uniform removal of the filter cake after position- ing the screen is necessary for a suc- cessful open-hole completion. Major considerations associated with displace- ment operations are: Uniform clean-up – Probably the most widely known guideline to achieve a uniform annular displacement is to pump completion brine in turbulent flow. However, mechanical erosion or quick dissolution of very fine NaCl bridging solids with less dense, lower salinity brines (not a problem with sized CaCO3) can result in premature loss of clean-up solutions, thereby, reducing cake removal over the entire interval length. Channeling – Displacement involv- ing fluids of dissimilar density and vis- cosity will channel in a horizontal well- bore. The effects of gravity and density, especially in an eccentric annulus where a displacement brine will favor the widest side and bypass slower-mov- ing fluid in the narrowest side,10 can result in an ineffective removal of solids in the annulus and subsequently the fil- ter cake. It could potentially restrict production through a prepacked screen. Filter cake composition – The wall cake deposited by a non-damaging fluid system during drilling contains: • Soluble bridging solids • Polymer • Insoluble drill solids. Successful cake removal must recog- nize the method required to remove or dissolve each of these distinct compo- nents. Salt particles, which are inert in a saturated environment, can be dissolved with brine that is not saturated with respect to NaCl. However, sized CaCO3, suspension and filtration polymers in the system overlay and fill in between the 16 Modern Sandface Completion Practices Particle Size Opening Size Opening Size Required to Bridge (in.) (micron) (micron) 0.020 508.0 169.3 0.012 304.8 101.6 0.008 203.2 67.7 Table 2.2. Opening sizes and bridging particle requirements for slotted liners and screens 17 particles, which develop an ultra-low permeability membrane, must be treated with an enzyme, acid or oxidizer. Surface, solids-control equipment should remove the majority of the coarse formation sand grains incorporated into the fluid system while drilling. However, fine insoluble drill solids, which are the same size as the soluble particle distribu- tion and are not removed from the sys- tem, may ultimately become part of the filter cake, which cannot be dissolved. To maintain fluid rheology and filtration control and to provide a more soluble or compressible filter cake, these fine insolubles must be kept to a minimum with adequate dilution or larger initial drilling system volumes. Post-completion application. The final phase of the completion procedure is conducted after the wellbore clean-up operations. Should the isolation valve fail to close after removing the washpipe while tripping for the production tubing, a sized-NaCl or CaCO3 bridging pill with increased particle sizing may be placed inside the slotted liner or screen to prevent the loss of brine through the screen and into the formation. This pill may either be produced from the well- bore or removed with coiled tubing. Alternatively, solids-free, fluid loss pills (such as a high polymer loading of HEC or a crosslinked pill) can be used. The crosslinked pills are generally preferred because they will minimize the amount of gel leaked off to the formation, resulting in less formation damage. Filter-Cake Removal After placement of the completion assem- bly, removal of the polymer/ superfine NaCl or CaCO3 in the annulus and the fil- ter cake on the formation is accomplished with a sequence of sweeps and soaks varying in viscosity, density and salinity. Reduced flow rates, which prevent turbu- lence for specific wellbore geometry, are incrementally increased as the completion stages progress. This method helps reduce channeling and mechanical erosion. It also makes, in a separate step, each component of the filter cake soluble and provides a more uniform wellbore clean-up. The three stages for optimum removal are: • Viscosified push pill • Breaker soak • Wash solution. Viscosified push pill. Displacement flow pattern in cementing, where different fluid/slurry densities and gel strengths occur, may be directly related and provide guidance for displacing a drilling/completion system. McLean suggests that piston-like displacement of mud by an equal density cement slurry is possible through proper bal- ance of the flow properties of the mud and cement slurries to the eccentricity of the annulus. The more eccentric the annulus, the thicker the cement must be relative to the mud. If proper balance is not achieved, bypassing of mud by cement cannot be prevented without assistance from motion of the casing or buoyant forces. Increasing the flow rate can help start all mud flowing but can- not prevent channeling of cement through slower moving mud in an eccentric annulus.11 Gravity forces will affect the removal of narrow-side annular fluid between the screen and open hole. If the fluid in the annulus is lighter than the displacement slurry, buoyancy of the displaced fluid contributes to its removal. The movement of a more dense fluid, under a lighter one, helps push gelled fluid upward into a wider section of the annulus where it is more easily removed. Therefore, a properly designed dis- placement push pill for a polymer fluid system containing sized bridging solids should be a weighted, viscosified slurry. The density should be 0.2 to 0.5 ppg higher, and it should have at least three times the low shear rate viscosity at shear rate of 0.06 sec -1 of the fluid being displaced. Upward buoyancy forces and increased yield strengths are generated, which overcome the yield stress of the displaced fluid, thereby creating fluid movement on the narrow side of the annulus. Breaker soak. Laboratory tests and field applications of various breakers have verified the necessity of applying proper techniques to expedite efficient filter cake removal. A soak and subse- quent wash procedure has proven to be a preferable technique. Since these filter cakes primarily consist of polymers and NaCl or CaCO3 particles, suitable soak solutions contain enzymes, oxidizers or acids, that will degrade the polymers in the filter cake, yet will allow the bridg- ing solids to remain more or less intact. In the case of NaCl, each chemical soak is mixed in saturated sodium chloride brine and applied to the filter cake to break down the polymer film that coats the bridging salt. This film of polymer is very tenacious and difficult to pene- trate without the application of a proper soak solution, adequate tangential forces or mechanical erosion. Hydraulics provide a method of inducing water losses through the filter cake, especially with low salinity brine or weak acid. However, this complicates uniform removal over long, varied per- meability intervals where clean-up solutions can break through the higher permeabilities first, leaving little brine or acid available to remove filter cake from the lower permeabilities. By first degrading the polymer with a chemical breaker, fine NaCl or CaCO3 will remain intact over the formation pores, held in place by hydrostatic pressure. The low permeability between these soluble par- ticles continues to restrict outward flow, allowing brine leakoff into the formation Chapter Two Open-Hole Sandface Completions Fig. 2.6. Open-hole completion assembly OMNI valve• Hydraulic setting tool Secondary ball seat Running position Versa-Trieve packer Sealbore Ported closing valve Sealbore Inner string swivel Ceramic flapper w/internal prop sleeve • • • • • • to be equalized over the entire interval. Also, the breakdown of polymer sepa- rates the water or acid soluble particles and allows easier mechanical removal and particle dissolution during the sub- sequent displacement stages. Wash solution. Selection of a suitable wash solution is based on the density requirement and compatibility with the soak solution. Wash solutions should be unsaturated at circulating temperature. Suitable wash solutions include potas- sium or ammonium chloride, sodium chloride, calcium chloride and sodium bromide brines, and weak acid. During the circulating wash phase, pump rates should be increased and decreased in order to reach maximum interval length as the soluble particles are dissolved and probable losses occur. Stand-Alone Screens In some cases, slotted liners or screens are used alone to control the formation sand in open-hole completions as illus- trated in Figure 2.7. These sand exclu- sion devices actually function as a fil- ter. Unless the formation is well-sorted, clean sand with a large grain size, a stand-alone completion may have an unacceptably short producing life before the slotted liner or screen plugs. Subsequently, a “hot spot” may develop at some point in the formation interface causing potential erosion and screen failure (Fig. 2.8). Various measures for slot width or screen spacing have been offered in industry literature from results of sieve analysis done with formation sand; the accumulated weight percentage of par- ticles larger than a certain diameter to obtain a size distribution that is plotted on a semi-logarithmic scale. Figure 2.9 illustrates an example plot, using laser particle size analysis (LPSA). If the analysis data is expected to provide accurate gravel-packing information, the samples used for sieve analysis must be representative of the formation. If possible, a sample should be taken every 2 to 3 ft (0.6 to 0.9 m) within the formation or at every lithology change. The minimum size of the formation sample required for a conventional sieve analysis is about 6 g. The typical amount of material used for LPSA varies from about 1 g to 10 g, depend- ing on the amount of silt and clay-sized particles. The typical distribution range for laser-light defraction technology is approximately 3 mm to 0.001 mm. More on formation sand sampling is covered in the next section. These criteria range from those based on a single diameter in the for- mation sand size distribution (either D10 as suggested by Rogers12 or 2 x D10 as recommended by Coberly13) to attempts to better characterize the distribution through a uniformity coefficient (D40/D90).14 Recently, Tiffin et al.15 provided guidelines based on further experimental results, where they intro- duced two new parameters: sorting coefficient D10/D95 and mass fraction of fines (particles smaller than 44 micron). Their recommendations can be summarized as follows. Stand-alone screens can be used if: D10 /D95 < 10 And wire-wrapped screens should be used if: D40/D90 < 3 and fines < 2% by weight 18 Modern Sandface Completion Practices Open hole with slotted liner Packer Packer Open hole with screen Fig. 2.7. Stand-alone slotted liners and screens in an open hole 10 0 5 10 15 Fr eq ue nc y, % Cu m ul at iv e, % 20 25 0 20 40 60 80 100 1 0.1 Particle diameter, mm 0.01 0.001 ClaySilt Gravel Vcg sd Cg sd Mg sd Fg sd Vfg sd Fig. 2.9. Extended range particle size sand distribution plot from sieve analysis Fig. 2.8. Screen failure/damage from plugging of progressive screen plugging Prepacked or premium screens should be used if: 3 < D40/D90 < 5 and 2% < fines < 5% by weight A later section in this Chapter (“Gravel Packing”) contains details on determining formation grain size and what is meant by Dx. Stand-alone screen selection consid- erations should include the following: • Screen characteristics – Strength and damage resistance – Mud or DIF flow back – Sand control – Plugging resistance – Erosion resistance • Screen opening size • Laboratory testing with formation sand – Realistic test criteria – Transfer of laboratory results downhole • Prior industry experience. Increasing the area open to flow and decreasing annular flow outside the screen enhances stand-alone screen longevity. Slotted Liners Slotted liners are manufactured by machining slot openings through oil- field tubulars with small rotary saws. Slotted liners are fabricated in a variety of patterns as illustrated in Figure 2.10. While slotted liners are usually less costly than wire-wrapped screens, they have a smaller inflow area and experi- ence higher-pressure drops during pro- duction. Slotted liners also plug more readily than screens and are used where well productivity is low and economics cannot support the use of screens. The single-slotted, staggered-row pattern is generally preferred because a greater portion of the original strength of the pipe is preserved. The staggered pattern also gives a more uniform dis- tribution of slots over the surface area of the pipe. The single slotted staggered pattern is machine-grooved with an even number of rows around the pipe. There is typically a 6 in. (15.2 cm) longitudinal spacing of slot rows. The slots can be straight or keystone shaped. The keystone slot is narrower on the outside surface of the pipe than on the inside. Slots formed in this way have an inverted “V” cross-sectional area and are less prone to plugging since any particle passing through the slot at the outside diameter (OD) of the pipe will continue to flow through rather than lodging within the slot. When used alone as sand exclusion devices, slotted liners (Fig. 2.11) or screens are placed across the productive interval and the formation sand mechanically bridges on the slots or openings in the wire-wrapped screen. Slot widths usually range from 0.012 in. (0.031 cm) to 0.250 in. (0.64 cm). Screen performance is usually judged based on the open area presented to the formation. However, the flow loss through an open slot is much less than that caused by flow convergence in the permeable media near the wellbore. Consequently, slot spacing is even more important, because this feature controls the extent of flow convergence away from the liner and into the formation. Consider the two cases illustrated in Figure 2.12.16 Case 1 illustrates the flow convergence associated with a wider slot over the zone covered by that slot. Case 2 shows two slots half as wide covering the same zone. The open area is the same in both cases, but the wider slot forces flow convergence to begin further away from the liner. The relationship between the extent of con- vergence and the slot spacing is nearly linear. So, Case 1 generates about twice as much flow loss for the same open- area as does Case 2. This illustrates why wire-wrapped screens perform so well. In addition to a large open area, the slots are very close together thereby minimizing the extent of flow conver- gence and its associated flow loss. Numerical analysis results demon- strate the slot factor sensitivity to slot- ting parameters. Figure 2.13 illustrates a comparison of slot factors for three slot widths in terms of open area. The analysis demonstrates that flow loss is 19 Chapter Two Open-Hole Sandface Completions Horizontal slotted Single slotted non-staggered rows Single slotted staggered rows Gang slotted staggered rows 6 in Fig. 2.10. Slotted-liner geometry Fig. 2.11. Slotted liners with single-slotted, staggered rows Case 1: Slot width = W Slot width = N Case 2: Slot density = W/2 Slot density = 2N Formation Zone of flow convergence Inside of liner Fig. 2.12. Slot induced flow convergence 0.01 0.1 1 10 0.0 1.0 2.0 3.0 Slot width, in. 0.012 0.018 0.025 4.03.50.5 1.5 2.5 Sl ot fa ct or Open area, % Fig. 2.13. Slot factor comparison for 5-1/2 in. liner with respect to open area nearly proportional to slot size for a given open area (i.e., smaller slots give smaller flow loss). Bridging theory shows that particles will bridge on a slot provided the width of the slot does not exceed two particle diameters. Likewise, particles will bridge against a slot or hole if its diam- eter does not exceed about three parti- cle diameters. Plugging in slots (or screens) can be attributed to two main types of mechanisms: • Pore-throat plugging (in which the pore throats become filled with fines that migrate with the produced fluid or with precipitates produced by pres- sure reduction) • Slot plugging (in which sand parti- cles bridge in the slot, causing it to become an extension of the reservoir material. The flow through the slot then becomes Darcy flow instead of open-channel flow, substantially increasing the pressure). If both mechanisms come into being, the pressure-loss problem is obviously compounded. Figure 2.14 illustrates the slot-factor distribution for open and plugged slots, with a curve showing the ratio between flow performance for the two cases.17 Over the range of practical slot densities, the plugging ratio is between 12 and 24, demonstrating dra- matically reduced performance for a plugged slot. Furthermore, this resis- tance can be multiplied by pore throat plugging to effectively block inflow through the liner. The formation sand bridges formed will not be stable, regardless of the cri- teria used to determine slot width or screen spacing, and may break down from time to time when producing rate is changed or the well is shut-in. Because the bridges can break down, resorting of the formation sand can occur which over time tends to result in plugging of the slotted liner or screen. When this technique is used to control formation sand, the slotted liner or screen diameter should be as large as possible to minimize the amount of resorting that can occur. Another poten- tial disadvantage of both slotted liners and screens in high-rate wells is the pos- sibility of erosion failure of the exclu- sion device before a bridge can form. Stand-alone screen applications are used extensively in horizontal wells and will be discussed in this Chapter. Conventional, Prepacked and Premium Screens As previously stated, there are various types of sand screens used for sand exclusion: • Conventional wire-wrapped screens • Prepacked screens • Premium screens. Wire-wrapped screen. Wire-wrapped screens offer an alternative for retaining the gravel in an annular ring between the screen and the formation. The advantage of a wire-wrapped screen over a slotted liner is substantially more inflow area (Fig. 2.15). The screen con- sists of an outer jacket, which is fabri- cated on special wrapping machines that resemble a lathe. The wire wrap is simultaneously wrapped and welded to longitudinal rods to form a single heli- cal slot. The jacket is subsequently placed over and welded at each end to a supporting pipe base (containing drilled holes) to provide structural support. This standard design is generic and is manufactured by several companies. A schematic of the screen construction is illustrated in Figure 2.16. The term “gauge” is potentially con- fusing. Gauge refers to the slot width or wire spacing measured in thousandths of an inch. For example, a 20-gauge screen has a space between the wires of 0.020 in. (0.051 cm), and a 20-gauge slotted liner has a slot of 0.020 in. (0.051 cm) width. The best way to avoid confusion is to always specify the slot widths or wire spacing in inches (or mil- limeters or microns) rather than gauge. The main advantage of all-welded or wire-wrapped screens (Fig. 2.17), which typically employ grade 316L stainless steel wire, is the screens are more erosion and corrosion resistant than slotted pipe. The slotting process used to manufacture slotted liners changes the metal characteristics around the machined slots. This pro- motes corrosion problems. There are many cases where slotted liners have been delivered to a well site with cor- roded and plugged slots, rendering them useless as sand exclusion devices. This problem cannot be properly han- dled at the well site. However, there are areas and specific well conditions where slotted liners may be the only economical means of sand exclusion. If this is the case, proper care should 0.01 0 6 12 18 24 0.1 1 10 100 0 200 400 600 700500100 300 Plugging ratio Open slot Plugged slot Sl ot fa ct or Pl ug gi ng ra tio Slot density, slots/m Fig. 2.14. Slotted open and plugged-slot performance for 5-1/2 in. liner 0 4 6 12 16 20 24 28 32 1 5411/2 27/8 65/8 85/8 Ef fe ct iv e in le t a re a, s q. -in ./f t Pipe size, in. Slotted liner Machine grooved screen (channels) Wire wrapped ribbed (channels) all welded screen Fig. 2.15. Comparison of effective inlet areas (20 gauge) Fluid flow Wire wrap Ribs Pipe base Fig. 2.16. Costruction schematic of wire wrapped screen Fig. 2.17. All-welded, wire-wrapped screen on base pipe 20 Modern Sandface Completion Practices be taken to maintain the condition and quality of the slotted pipe. A field quality check that should always be made on a screen or liner after it reaches the field is to measure the wire spacing or slot width. A screen or liner should be rejected if the spac- ing varies more than 0.002 in. (0.005 cm) larger or 0.003 in. (0.008 cm) smaller than what was specified for the well. A screen that has a wire spacing that is too large will not control forma- tion sand. Conversely, screens with openings that are too small are subject to plugging with dirty fluid, drilling fluid solids and formation sand. Prepacked screens. Prepacked screens are a modification of existing wire- wrapped screens and represent a modular gravel pack. They consist of a standard screen assembly with a layer of resin coated gravel (consolidated) placed around it which is contained in an annular ring supported by a second screen (dual-screen prepack) or outer shroud (single-screen prepack). The thickness of the gravel layer can be varied to meet special needs. The screens with the lowest profiles are those which contain an annular pack between the jacket and the pipe base. The drilled-pipe base has a thin lattice screen wrapped around it to prevent gravel from flowing through its holes prior to consolidation (SLIM-PAK). Examples of various prepacked screens are shown in Figure 2.18. If they are not protected by a coat- ing, plugging of prepacked screens with formation fines can be a serious prob- lem. Proponents of prepacked screens claim that they are not as subject to plugging as previously thought because modern completion practices demand clean wellbore and filtered fluids. Nev- ertheless, a very small volume of solids will totally plug a prepacked screen. Some companies have run downhole filters in tubing strings to provide a final filter stage for fluids. However, they are often unable to complete a job without breaking the downhole filter, regardless of how clean the fluids and wellbore are. Prepacked screens are simply another design of a downhole filter. They will plug much more easily than a wire-wrapped screen. Premium screens. Slotted liners, wire- wrapped screens and prepacked screens were the initial completion method used to restrict the entry of formation sand into horizontal wells. Within the past ten years or so, several new screens designed to be used in stand-alone applications have become available. This new generation of screens was developed to address perceived prob- lems with stand-alone completions; namely, plugging and erosion before the wells were depleted. Some of the new- generation, premium screens include: • ResScreen Sand screen • con-slot screen • Baker Excluder2000 screen • Weatherford Stratapac screen • Halliburton PoroMax screen • Stren SC2000 screen • Schlumberger MeshRite screen • Weatherford Expandable Sand screen (ESS). ResScreen sand screen – This sand exclusion device (Fig. 2.19) is a robust single wire-wrapped sand screen that was recently introduced especially for open-hole, stand-alone completions in the North Sea. The base pipe deter- mines its overall mechanical strength. Its design allows for Inflow Control Devices (ICD) (Fig. 2.20) which may mitigate the need for gravel packing and extend the application of stand- alone completions.18 Reslink uses SAND software19 from PETEC Software & Services, a member of the Rogaland Research Group in Norway, to determine the wire spacing for their screens. Results from the cal- culations are four, critical slot-wire spacings that define a safe design inter- val for screen slot width: • Largest wire spacing where severe plug- ging is expected to be frequent (d--) • Smallest wire spacing where no plugging is expected to occur (d-) • Largest wire spacing where sand pro- duction is not expected to occur (d+) • Smallest wire spacing where contin- uous sand production is expected to occur (d++). For instance, these critical wire spac- ings are plotted for all the samples taken from the well. Screen wire-spacing design is then a matter of drawing a straight, hori- zontal line through the graph that inter- sects the critical wire-spacing curves as seldom as possible. A possible solution is illustrated in Figure 2.21. Using this method to determine screen wire spacing identifies: • Optimal screen wire spacing for a reservoir or part of a reservoir • Sand types that are well suited to stand-alone screen completions • Sand types that may cause problems for the chosen screen size. con-slot Formation Link screen – This is a heavy-duty, rod-based, wire- wrapped screen (RBWWS) that is suitable for controlling formation sand in open-hole horizontal completions. It was introduced in the early 1980s and is promoted in preference to all pipe-base screens, citing that pipe-base screens create a restriction to flow that are not observed with rod-based screens. An important factor in providing for high- flow capacity in the con-slot screen Fig. 2.18. Three types of prepacked screens 21 Chapter Two Open-Hole Sandface Completions Fig. 2.22. con-slot RBWWS screen cutaway Fig. 2.23. Baker Excluder2000 screen 0 200 400 600 800 1,000 d-- d- d+ d++ A2 A4 A6 A8 A10 A12 A14 Sl ot s pa ci ng , m ic ro n Sand type Suggested slot width: 250 micron Fig. 2.21. Suggested wire-spacing design using SAND software output for an example well Typical formation types Large grain Medium grain Small grain 0 10 20 30 40 50 60 70 80 90 100 1,000 100 10 Formation particle diameter, micron D10 C o a r s e w e a v e M e d i u m w e a v e F i n e w e a v e Fig. 2.24. Baker Excluder2000 selection guide chart Fig. 2.19. ResScreen sand screen Fig. 2.20. ResChoke inflow control device. Produced fluid enters the wire-wrapped, base-pipe annulus through nozzles 22 Modern Sandface Completion Practices design is the venturi-shape of the wire spacing and sharp corner radii of the wire (Fig. 2.22) which has a self- cleaning effect. However, should the screen still become plugged, surging or jetting from the inside can clean it. Hydraulics of the screen increases the permeability/transmissibility around it due to allowing not only a 100% cleanup of the mud or DIF sys- tem, but also a bridging of the coarser sand particles around the screen. This stabilizes the formation and allows for a sand-free production. To determine wire spacing, con-slot applies interpretation of a sorting fac- tor, uniformity coefficient (Cµ) from the formation sand distribution plot of the sieve analysis:20 Cµ = D40/D90 When: Cµ < 2.00 Then, very uniform unconsolidated sand is denoted and dictates a slot size at D50 or 50% retention. When: Cµ ≅ 2.00 Then, uniform unconsolidated sand is denoted and dictates a slot size at D40 or 40% retention. When: Cµ > 2.00 Then, non-uniform unconsolidated sand is denoted and dictates a slot size at D30 or 30% retention. Baker Excluder2000 screen – This premium screen design consists of three layers of media placed concentrically around a drilled-pipe base to form the jacket. The base wrap for the jacket consists of a strength-enhancing Baker- weld Inner Jacket for the overlying Vec- tor Weave Membrane medium. The pro- tective Vector Shroud is then placed concentrically over the Vector Weave Membrane (Fig. 2.23). The Excluder2000 screen is avail- able in three micron ratings (Fig. 2.24): • Fine: 100-200 D10 micron range (uni- form pore openings promote high retention efficiency and large inflow areas to control sand without high differential pressures) • Medium: 200-300 D10 micron range (optimized membrane allows flow- back of mud solids while maintaining sand retention) • Coarse: >300 D10 micron range (pore size allows the very fine particles that would ordinarily plug the screen to be produced). Weatherford Stratapac screen – The screen design of this downhole exclu- sion device consists of multiple filtra- tion layers of porous metal membrane (PMM) or porous metal fiber (PMF II). It contains about 30% open area through variable sized pore openings, between underlying drainage and over- lying protecting mesh screens that are placed concentrically between a drilled- pipe base and a perforated outer shroud. A schematic of the screen construction is illustrated in Figure 2.25. The filter medium for the screen is sintered metal powder that is pressed against a stainless steel lattice screen, which provides structural support for the filtration medium. The sand reten- tion characteristics of the PMM and PMF II are illustrated in Table 2.3. Halliburton PoroMax screen – This screen (Fig. 2.26) is engineered for opti- mum inflow area in a shrouded, sin- tered-laminate screen from the Purolator Products Company. It retains the tough- ness of the highly successful, original Poroplus screen design. It is suitable for installations with an extended reach, long open-hole and multilateral comple- tions, with or without centralization. It can function as a stand-alone or back-up means of sand control in horizontal open-hole completions, which is its most common application. Stren SC2000 screen – This sand exclusion device combines sintered metal mesh layers and metal fiber com- posite matrix for accurate pore sizing, yielding rugged, accurate sand particle control and flow erosion resistance. Rugged and crush resistant, Stren SC2000 (Fig. 2.27) screens have body diameters typically only 0.25 in. (0.64 cm) larger than tubing upset diameter. Schlumberger MeshRite screen – This screen technology claims to have 100 times the permeability of typical reservoir formations. Perforated base pipe is wrapped with special stainless steel mesh fiber. The fibers are compressed to form angular, three- dimensional pore spaces that range in Fig. 2.25. Weatherford Stratapac screen Media Equivalent Media Rating* Gravel Size PMM 60 micron 40/60 US Mesh PMF II 20/40 125 micron 20/40 US Mesh PMF II 12/20 200 micron 12/20 US Mesh * Defined at 90% retention efficiency. Table 2.3. Sand retention characteristics of Stratapac filtration layers Fig. 2.26. Halliburton PoroMax screens Fig. 2.27. Stren SC2000 screen 23 Chapter Two Open-Hole Sandface Completions size from 15 to 600 microns. This mesh structure maximizes the porosity within the filter. A perforated jacket protects the filter element and provides structural strength in both vertical and horizontal well applications. MeshRite screens reli- ably control a wide range of particle sizes and eliminate the need for screen sizing. The two profiles of a MeshRite screen are shown in Figure 2.28. Weatherford Expandable Sand Screen (ESS) – This sand control device was the first commercially available expandable sand screen design.21 The slim nature of the design facilitates deployment of the screens in various open-hole applications, including high dogleg severity and horizontal wells. After deployment, the ESS can be expanded by a solid expansion cone and/or an Axial Compliant Expansion System. Once expanded it virtually eliminates the annulus, making gravel packing operations unnecessary in reservoirs that carry risks such as reac- tive shale, low fracture gradient, frac- tures or faults. A partially expanded ESS is illustrated in Figure 2.29. An ESS consists of three layers: (1) a slotted base pipe, (2) a filtration medium (Petroweave) and (3) an outer protective shroud (Fig. 2.30).22 Petroweave is a wirecloth woven in a Dutch Twill and is available in a range of selected micron ratings from 150 to 270 microns. This ESS design offers a number of unique advantages. It offers a large inflow area that minimizes screen plug- ging and erosion. It is operationally simple to install. It offers a larger inter- nal diameter than any other type of sand control screen, optimizing inflow performance and facilitating installa- tion of equipment for zonal isolation. In open-hole applications, an ESS eliminates the annulus between the screen and the sandface. It therefore stabilizes the sandface and minimizes sand movement, reducing the risk of sand failure and screen erosion caused by sand production. Other sand exclusion techniques may be more appropriate in some reser- voir applications but, by nature, they will involve the loss of wellbore diame- ter, lower well productivity, and reduced well intervention and workover flexibil- ity when compared to expandable screen technology. Stand-Alone Completion Assemblies A typical stand-alone completion assembly with an RBWWS in a hori- zontal open-hole is shown in Figure 2.31. Note the end of the coil tubing where there is a jet that can be used to wash inside of the screen. This diagram is representative of hundreds of downhole assemblies which can be designed using stand- alone liners or screens as the primary method for controlling sand. Summary. Many more types of screens are available. The screen examples and designs discussed in this Chapter are representative of the wide variety of sand exclusion devices offered by numerous manufacturers. In some cases, there are more or less equivalent screen designs available from other commercial sources. For detailed speci- fications on these and other screens, contact the various screen manufactur- ing companies. Gravel Packing A gravel pack is simply a downhole fil- ter designed to prevent the production of unwanted formation sand. The formation sand is held in place by properly sized gravel-pack sand. The gravel-pack sand is held in place with a properly sized screen. Open-hole gravel packing is a common completion technique in many areas of the world, such as California, Canada, Bolivia, Venezuela, Brunei, China, Indonesia, Nigeria; and in some wells in the Gulf of Mexico and the North Sea. However, there are advan- tages and disadvantages of open-hole gravel packing, and an understanding of these factors will assist in selecting the completion technique to use where a choice is possible. Advantages of open-hole gravel packing include: • Easiest type of gravel pack to place because of the large annular space between the screen and the forma- tion. Since gravel does not have to be carried through perforations, this technique presents minimal gravel transport problems. • Highest theoretical productivity because there are no perforation tun- nels filled with gravel, sand or dirt to restrict flow. • Lowest possible velocity for pro- duced fluids flowing through the gravel pack. • Usually less expensive because it eliminates some casing and cement- ing costs. Disadvantages of open-hole gravel packing include: • More difficult to control unwanted water or gas production, or injection into thief zones, within the comple- tion interval. • Hole stability during placement of the gravel is often a problem, which Fig. 2.29. Weatherford Expandable Sand Screen (ESS) partially expanded Fig. 2.28. Schlumberger MeshRite screens 24 Modern Sandface Completion Practices may result in sand filling the annulus around the screen before the gravel is placed. • Screen is more easily plugged with formation sand during gravel place- ment than in cased-hole completions. • The underreaming process may cause additional formation damage. • Generally limited to a bottom interval in multiple zone completions. • Sloughing problems may occur at the casing to open-hole interface. Most open-hole completions are underreamed before they are gravel packed. The underreaming usually increases the diameter of the borehole to approximately twice the casing inside diameter (ID). Usually casing is set above the productive zone, but sometimes casing is set through all pro- ductive intervals. Then, a window or windows are milled out through the zones to be gravel packed. Underreaming (Fig. 2.32) is defined as enlarging a wellbore past its original drilled size. It serves two purposes: (1) provides a larger wellbore diameter for slightly increased theoretical productiv- ity and (2) removes mud cake and mud invasion damage. Unfortunately, the underreaming process, as it is commonly practiced, may cause as much formation damage as it removes due to the combi- nation of fluid loss additives, dirt in the fluid and formation fines that are recir- culated with the underreaming fluid. To prevent a weak formation from collapsing during underreaming opera- tions, a formation compatible DIF or underreaming fluid must be properly employed to control fluid loss. Discard- ing the fluid returns is usually not con- sidered due to cost. Consequently, the underreaming DIFs continuously become dirtier and cause more forma- tion damage as underreaming operations advance through the formation. This formation damage cannot be removed prior to the gravel packing because the hole might collapse. So, it is frequently gravel packed in place. The result may be more restrictive than if underreaming were not done, or if casing were set to provide some stability to the formation. These concerns can be addressed with current filtering (see the “Fluid Filtra- tion” section of Chapter Three) and polymer shearing (see the “Drill-In Fluids” section of this Chapter) devices. As gravel is being circulated into an open hole, the formation sand is dis- turbed much more easily than in a cased-hole completion. This can cause formation sand to be fluidized and plug the slotted liner or screen, usually toward the lower part of the screen. Slurry packing, using a high-viscosity high-density slurry, can help alleviate this problem (see the “Gravel Packing” section of Chapter Three). Underreaming can cause formation damage toward the lower part of a zone. Additionally, the lower part of the slotted liner or screen can be plugged by circu- lating fluid and gravel. The overall result of these problems is that the highest leak-off rate, highest production rate and worst thief zones tend to be toward the top of the open-hole completion. Any subsequent stimulation treatment Fig. 2.31. Stand-alone completion assembly with RBWWS Fig. 2.30. Weatherford ESS construction. Slotted base pipe, a metal weave filtration layer and outer protective shrouded Fig. 2.32. Underreaming operation 25 Chapter Two Open-Hole Sandface Completions (i.e., steam injection, solvent treatment or acidizing) will preferentially flow into the upper part of the gravel pack. Once the pack is damaged, diversion of fluids from entering the upper part is difficult. Gravel-Pack Sand Sizing and Substitutes To determine what size gravel pack sand is required, samples of the forma- tion sand must be evaluated to deter- mine the median grain size diameter and grain size distribution. With this information, gravel pack sand can be selected using the technique outlined by Saucier.23 The quality of the sand used is as important as the proper sizing. API Recommended Practice 58 has set forth the minimum specifications desir- able for a gravel pack sand.24 Formation sand sampling. Improper formation sand sampling techniques can lead to gravel packs which fail due to the production of sand or plugging of the gravel pack. The importance of a truly representative sample of the for- mation sand cannot be overstated in determining proper sand control design. Without a representative sample, the following items cannot be determined and are at best a guess: • Proper size gravel, slot or screen spacing to stop formation sand while maintaining productivity • Degree and type of clay stabilization required • Benefits or hazards of acidizing • Fluid filtration requirements to avoid damaging the formation (see “Fluid Filtration” section in Chapter Three). Samples must be at least 15 cc each. They should be taken every two to three feet or at each lithology change. Most pay zones have varying permeabilities, porosities, average grain sizes and strengths. These parameters may change very quickly within an interval. Sandstone formations also vary across the reservoir; thus, representative samples should be taken from each well in a field. Unless a considerable history is available on a producing formation or reservoir, samples from only one well in a field should not be considered ade- quate. Continuous coring technology has been developed and may prove valuable for coring horizontal and long, high-angle wells. Today, depending on the type of for- mation being drilled, the best samples of formation sands are obtained by cor- ing operations. The formation type will usually dictate the coring procedure (e.g., either double-tube, which have effectively replaced rubber sleeve, or conventional core barrels).25 The classi- fication of formation sands include: • Quicksand (completely unconsoli- dated formation sand) • Partially consolidated sand (has some cement agents present, but is only weakly consolidated) • Friable sands (semi-competent, well cemented and potentially troublesome). The use of double-tube core barrels, enhanced by a full-closure core catcher system (Fig. 2.33) is the only technique currently available to obtain good sam- ples of quicksand. This type of forma- tion sand tends to fall out of conven- tional core barrels and limits core recoveries. The rubber or plastic sleeve core barrel holds the core together dur- ing the coring and retrieving operation and often results in better core recovery. A conventional core barrel can be used to recover samples of friable and partially consolidated formations. How- ever, low recovery efficiencies would indicate alternating intervals of consoli- dated and unconsolidated formations, and consideration should be given to using double-tube core barrels for total recovery. Experience in a formation will dictate the best coring system. If full cores of the formation are not available, the next best samples are sidewall cores. Partially because they are less expensive than full cores, side- wall cores are frequently the only types of cores available from most sandstone formations (especially in workover operations). Sidewall core samples are Outer core barrel Steel sleeve Split spring Full closure core catcher Core bit Coring mode Retrieval mode Fig. 2.33. Hydro-Lift full closure core catcher 26 Modern Sandface Completion Practices small and often contain mud cake or invaded mud particles. However, they are more representative of the forma- tion sand than either produced or bailed sand samples. Samples of the formation sand obtained at the surface in vessels or flow lines will usually contain only the smaller sand grains, which were easily transported out of the wellbore. Sam- ples taken at different points on the sur- face (wellhead, sand trap, heater treater, etc.) will indicate a variation in sand grain size distribution. This variation makes it difficult to know which sam- ple to use. Samples obtained from bail- ing operations or from circulation of fill off bottom will generally include the larger sand grains from some of the interval(s) opened to production. In summary, if full-sized cores are not available, the next best samples are sidewall cores. Sidewall cores are small and generally will contain some mud, but they are more representative of the formation sands than either produced or bailed samples of sand. Produced samples of formation sand tend to be skewed toward the small grain sizes and bailed sand samples tend toward the larger grain sizes. Surface or bailed samples of formation sand should never be used for designing sand con- trol treatments.26 Conventional core, unconsolidated core and sieve analyses. Numerous laboratory tests, which can be per- formed on core samples and other types of formation samples, aid in the proper design of (1) drilling mud, (2) DIFs, (3) completion fluids, (4) stimulation treat- ments and (5) sand control installations. For example, Core Lab was the first company to introduce laser-optics, par- ticle-size analysis as a routine service. With a range of measurements that cover sand, silt and clay size particles, the applications of the data have grown to include enhanced sidewall core per- meability determination, stand-alone slotted liner or screen selection and gravel-pack design. The analysis of data obtained from formation cores and samples have become very sophisticated, and an in- depth discussion of modern data analy- sis and data management techniques is well beyond the limitations of the scope of this presentation. However, for dis- cussions related to unconsolidated sands, three basic types of laboratory analysis should be reviewed. Conventional core analysis – A set of measurements normally carried out on core plugs or whole cores. These gener- ally include porosity, grain density, hori- zontal permeability, fluid saturation and a lithologic description. Routine core analyses often include a core gamma log and measurements of vertical perme- ability. Measurements are made at room temperature and at atmospheric confin- ing pressure, formation confining pres- sure or both. It should be understood that conventional core analysis is dis- tinct from special core analysis (SCAL). Recommended practices for routine core analysis, which are routinely per- formed in oil field laboratories, are available in Core Analysis, 2nd Edition, API Recommended Practices 40, February 1998.27 Unconsolidated core analysis – It must be understood that unconsolidated formation samples can be easily dam- aged and require special equipment and techniques for safe, reliable acquisition and transportation. Labs located in key producing regions around the world offer various tests, which can be per- formed on these samples and include: • Sample selection and preparation using spectral core gamma, CT scan- ning and mineralogy screening. • Poro-Perm to determine porosity, gas permeability, and Klinkenberg cor- rected permeability. • Resination to preserve core integrity after slabbing. • Sw/Sor determined directly from core. • Unsteady-State Profile Permeametry to provide rapid, quantitative deter- mination of detailed permeability variations. • Profile Acoustic to evaluate sanding potential and borehole stability models. • Photography to reveal fluorescing hydrocarbons and minerals. • High Resolution Digital Core Imag- ing to provide detailed sedimentary information by acquiring continuous images of the entire core at resolu- tions up to 300 dots per inch (dpi) at the core surface. At selected posi- tions, an area over 10 mm by 7 mm and up to 5,000 dpi can be produced to provide highly detailed textural information (Fig. 2.34). Sieve analysis – A typical laboratory routine performed on a formation sand Fig. 2.35. Sieves and shaker apparatus Fig. 2.36. Various sieves containing formation samples after sieving process Fig. 2.34. High-resoolution digital core imaging 27 Chapter Two Open-Hole Sandface Completions sample for the selection of the proper size gravel-pack sand according to ASTM E-11. Figure 2.35 shows a typi- cal sieves and shaker apparatus. Sieve analysis consists of placing a formation sample at the top of a series of screens, which have progressively smaller mesh sizes. The sand grains in the original well sample will fall through the screens until encountering a screen through which grains size cannot pass because the openings in the screen are too small. By weighing the screens before and after sieving (Fig. 2.36) the weight of formation sample retained by each size screen can be determined. The cumulative weight percent of each sample retained can be plotted as a comparison of screen mesh size on semi-log coordinates to obtain a sand size distribution plot (Fig. 2.37). Read- ing the graph at the 50% cumulative weight gives the median formation grain size diameter. This grain size, often referred to as D50, is the basis of gravel-pack sand-size selection proce- dures. Table 2.4 provides a reference for mesh size versus sieve opening. Gravel size determination. There have been several published techniques for selecting a gravel-pack sand size to 0 10 20 30 40 50 60 70 80 90 100 0.1000 0.100 0.0010 0.0001 Cu m ul at iv e w ei gh t, % Grain diameter, in. D50 Poorly sorted sand Well sorted sand Fig. 2.37. Sieve analysis of uniform and non-uniform formation sands Gravel Sand Fluid flow Fig. 2.38. Saucier’s experimental core US Series Sieve Opening Sieve Opening Mesh (in.) (mm) 2.5 0.3150 8.000 3 0.2650 6.730 3.5 0.2230 5.660 4 0.1870 4.760 5 0.1570 4.000 6 0.1320 3.360 7 0.1110 2.830 8 0.0937 2.380 10 0.0787 2.000 12 0.0661 1.680 14 0.0555 1.410 16 0.0469 1.190 18 0.0394 1.000 20 0.0331 0.840 25 0.0280 0.710 30 0.0232 0.589 35 0.0197 0.500 40 0.0165 0.420 45 0.0138 0.351 50 0.0117 0.297 60 0.0098 0.250 70 0.0083 0.210 80 0.0070 0.177 100 0.0059 0.149 120 0.0049 0.124 140 0.0041 0.104 170 0.0035 0.088 200 0.0029 0.074 230 0.0024 0.062 270 0.0021 0.053 325 0.0017 0.044 400 0.0015 0.037 Table 2.4. Standard sieve openings 0.0 0.2 0.4 0.6 0.8 10 12 0 4 8 12 16 202 6 10 14 18 Ra tio o f f in al p er m ea bi lit y to in iti al p er m ea bi lit y, k f/k i Ratio of median gravel pack sand diameter to median formation sand dia., D50/d50 Fig. 2.39. Results of Saucier’s gravel size experiments29 No sand control Optimum sand control 0 2 1484 6 10 12 In cr ea se d gr av el p ac k sa nd pe rm ea bi lit y as a fu nc tio n of D 50 a nd D 50 /d 50 Ratio of median gravel-pack sand diameter to median formation sand dia., D50/d50 Fig. 2.40. Gravel-pack sand size optimization 28 Modern Sandface Completion Practices control the production of formation sand. The technique most widely used today was developed by Saucier.28 The basic premise of Saucier’s work is that optimum sand control is achieved when the median grain size of the gravel-pack sand is no more than six times larger than the median grain size of the forma- tion sand. Saucier determined this rela- tionship in a series of core flow experi- ments where half the core consisted of gravel-pack sand and the other half was formation sand (Fig. 2.38). The ratio of median grain size of the gravel pack sand and median grain size of the for- mation sand was changed over a range from two to ten to determine when opti- mum sand control was achieved. The experimental procedure con- sisted of establishing an initial stabi- lized flow rate and pressure drop through the core and calculating an effective initial permeability (ki ). The flow rate was increased and maintained until the pressure drop stabilized fol- lowed by a decrease in flow rate back to the initial value. Once again, pres- sure drop was allowed to stabilize and an effective final permeability (kf ) of the core was calculated. If the final per- meability was the same as the initial permeability, a conclusion was made that effective sand control was achieved with no adverse productivity effects. If the final permeability was less than the initial permeability, the conclusion was made that the formation sand was invading and plugging the gravel-pack sand. In this situation sand control may be achieved, but at the expense of well productivity. Figure 2.39 illustrates the results of the core flow experiments and can be summarized as follows: When: D50/d50 ≥ 6 Then, there is good sand control and no formation sand invasion of gravel pack sand. When: 6 < D50/d50 ≥ 13 Then, there is good sand control but restricted flow due to formation sand invasion of gravel-pack sand. When: D50/d50 < 13 Then, there is no sand control and the formation sand passes through the gravel-pack sand. In practice, the proper gravel-pack sand size is selected by multiplying the median grain size of the formation sand by four and eight to achieve a gravel- pack sand size range whose average is six times larger than the median grain size of the formation sand. This calcu- lated gravel-pack sand size range is compared to the available commercial grades of gravel-pack sand. The avail- able gravel-pack sand that matches the calculated gravel-pack size range is selected. In the event that the calculated sand-size range falls between the size ranges of commercially available gravel- pack sand, the smaller gravel-pack sand is normally selected. Table 2.5 contains information on commercially available gravel pack-sand sizes from Unimin. Note that Saucier’s technique is based solely on the median grain size of the formation sand with no consider- ation given to the range of sand grain diameters or degree of sorting present in the formation. The sieve analysis plot discussed earlier can be used to estab- lish an indication of the degree of sort- ing in a particular formation sample. A near vertical sieve analysis plot repre- sents a high degree of sorting (most of the formation sand is in a very narrow size range) versus a more horizontal plot which indicates poorer sorting. Again, refer to the plots shown in Figure 2.37. A sorting factor, or uniformity coeffi- cient, can be calculated as follows: Cµ = D40/D90 Where: Cµ = sorting factor or uni- formity coefficient D40 = grain size at the 40% cumulative level from sieve analysis plot D90 = grain size at the 90% cumulative level from sieve analysis plot If Cµ is greater than five, the sand is considered to be poorly sorted. In such case, the next smaller size gravel-pack sand than the size calculated using Saucier’s technique may be justified. Another method, which can be applied when poorly sorted sand is encountered, is to use the D75 grain size instead of D50 to calculate the appropriate gravel- pack sand size. Using the results of Saucier’s experi- ments, optimization of gravel-pack sand size (Fig. 2.40) can be accomplished using the following guidelines.30 When: D50/d50 < 5 Then, there is good sand control but restricted flow due to low gravel perme- ability. When: 5 < D50/d50 < 7 Then, there is good sand control and maximum pack permeability. When: 7 < D50/d50 < 9 Then, there is good sand control but restricted flow due to formation sand invasion of gravel- pack sand. US Series Mesh Typical Mean % Retained on Individual Sieves (ASTM E-11) 12/20 16/30 20/30 20/40 30/40 40/60 12 – – – – – – 16 22.7 trace – – – – 18 59.4 6.9 – – – – 20 17.1 54.4 0.4 0.4 – – 25 0.8 36.7 72.1 14.1 – – 30 – 1.8 26.7 29.3 0.5 – 35 – 0.1 0.8 47.3 74.0 – 40 – – – 8.1 24.7 0.6 45 – – – 0.8 0.8 40.9 50 – – – – – 48.3 60 – – – – – 9.3 70 – – – – – 0.9 PAN – – – – – – Table 2.5. Gravel sizes distribution of Accupack 29 Chapter Two Open-Hole Sandface Completions When: D50/d50 > 9 Then, there is no sand control and the formation sand passes through the gravel-pack sand. Gravel-pack sand. Gravel pack well productivity is sensitive to the perme- ability of the gravel-pack sand. To ensure maximum well productivity only high-quality, gravel-pack sand should be used. The API Recommended Prac- tices 5831 establishes rigid specifica- tions for acceptable properties of sands used for gravel packing. These specifi- cations focus on ensuring the maximum permeability and longevity of the sand under typical well production and treat- ment conditions. The specifications define minimum acceptable standards for the size and shape of the grains, the amount of fines and impurities, acid solubility and crush resistance. Only a few naturally occurring sands are capable of meeting the API specifi- cations without excessive processing. The high quartz content and consis- tency in grain size characterize these sands. A majority of the gravel-pack sand used in the world is mined from the Ottawa formation in the Northern United States. Table 2.6 documents the permeability from three separate inves- tigations of common gravel-pack sand sizes that conform to the API Recom- mended Practices 58 specifications. Gravel-pack sand substitutes. Although naturally occurring quartz sand is the most common gravel-pack material used, a number of alternative materials for gravel-pack applications exist. These alternative materials include resin-coated sand, garnet, glass beads and aluminum oxides. Although two to three times more costly, each of these materials offers specific properties that are beneficial for given applications. Resin-coated gravel – A thin layer of resin coating on standard gravel-pack sand may provide some protection against quartz dissolution due to high pH steam,35 but not by HCl-HF acid. It is primarily used in the manufacture of prepacked screens (discussed earlier in this Chapter), and has gained some renewed interest for screenless frac packing (see Chapter Three). Aluminum oxide (Sintered Bauxite, CarboLite, etc.) – This is a processed product with extremely high permeabil- ity. It resists dissolution due to high pH steam and is moderately to highly solu- ble in HCl-HF acid. The primary appli- cations of these products are for frac packing and for fracturing thermal wells. Garnet – This mineral is a brittle and more-or-less a transparent, usually red, complex silicate with a high specific gravity (3.4 to 4.3). Its primary applica- tion is in thermal wells due to its resis- tance to dissolution by high pH steam. Garnets are also resistant to HCl-HF acid. Glass beads – This silica material is a processed product that is extremely round and highly soluble in HCl-HF acid. It is a predecessor to aluminum oxide. Slotted Liner and Screen Design These two general types of sand exclu- sion devices perform the same function in gravel packs, so the discussion in this section will use the term “screen” to include both slotted liners and screens. Screens must be designed to allow gravel to be packed completely around them and then hold the gravel in place during production, just as the gravel holds the formation sand in place. Pro- duction of a substantial quantity of gravel will jeopardize the success of a gravel pack by uncovering the upper portion of the completion or creating a hole in the pack. Wedging of out-of- size gravel into the openings of the screen will restrict fluid production. Therefore, proper screen designs for gravel packs are very important. Screen openings (slot widths or wire spacing) should be smaller than the smallest gravel grains at downhole con- ditions. There is little difference between screen openings at the surface and downhole, but gravel sizes do change. Gravel is eroded as it is pumped through triplex pumps, down a work string and through crossover tools; and the effect of erosion depends on the gravel size and quality, the pump rate and the fluid that is used. A weak, non-spherical, poorly rounded gravel (less than API standard gravel), high pump rate and low-viscosity brine will cause the greatest amount of erosion, as well as considerable screen plugging. Screen openings are usually referred to by the term “gauge,” which means one thousandth of an inch (e.g., 0.012 in. is 12 gauge). The most common screen opening designs are listed in Table 2.7, which indicates that a 12- gauge screen is normally used with 20/40 U.S. Mesh gravel. These recom- mended screen openings provide the best results with good quality gravel, low pump rates and gelled or viscous Permeability32 Permeability33 Permeability34 US Mesh Range (Darcy) (Darcy) (Darcy) 6/10 2703 - - 8/12 1969 - - 10/20 652 500 - 12/20 - - 668 16/30 - 250 415 20/40 171 119 225 40/60 69 40 69 50/70 - - 45 Table 2.6. Permeabilities of gravel-pack sands Gravel Size Gravel Size Screen Gauge Screen Gauge (US Mesh) (in.) (in.) (in.) 40/60 0.0165-0.0098 0.008 8 30/50 0.0230-0.0120 0.010 10 20/40 0.0330-0.0165 0.012 12 16/30 0.0470-0.0230 0.016 16 12/20 0.0660-0.0330 0.020 20 8/12 0.0940-0.0470 0.028 28 Table 2.7. Screen gauge used with various gravel sizes 30 Modern Sandface Completion Practices fluids. Smaller screen openings should be used for poor quality gravel, water packing and high rate water packing. Screen diameters should allow at least a two-inch radial clearance in open-hole completions. The reasons for this recommendation are: • A large annulus reduces the chance of gravel bridges forming as the well is being packed, which could leave cavities in the gravel pack. • Gravel can shift more easily in a larger annulus, which makes it easier to tightly pack the well. • Two inches or more reduces the risk of fluidizing the formation sand in an open hole when gravel is being circu- lated around the screen. Screens have such high flow capaci- ties that there is no reason for the diam- eter of a screen to be larger than the production tubing unless multiple gravel packs are performed in one well- bore or a logging tool or pump needs to be positioned inside the screen. Centralizers should be placed below and above the screen and/or at mini- mum spacing of 15 ft (4.57 m) so that the gravel can be packed uniformly around the screen. Bow-spring type centralizers are used in open holes. A tell-tale screen is usually a short section of screen placed above or below the production screen. Lower tell-tale screens, used when open-hole gravel packing, are usually no longer than 5 ft (1.52 m) and have a seal bore between the lower tell-tale screen and the main screen. Lower tell-tale screens are used in open-hole gravel packing with high- viscosity, high-density gravel slurry. Upper tell-tale screens are usually used with conventional low-viscosity, low- density, gravel-packing fluids. The top of the screen in an open hole should be designed to provide reserve gravel in the underreamed open-hole section. Gravel Packing Methods Based on experiences of major service companies, the following are absolute requirements for open-hole gravel-pack tool systems: • Must be capable of maintaining overbalance pressure at all times. • All operations must be performed with- out swabbing or surging the formation. • Must provide ability for positive tool positioning. Three basic tools are used in gravel packing operations: • Packer/crossover tool assembly • Over-the-top tool assembly • Port collars. Some are completion tools that remain in the well after the gravel pack is complete. On the other hand, service tools are used while placing the gravel pack but then are removed. Vertical wells. Reverse circulation gravel packing (Fig. 2.41)36 was one of the early techniques used before the development of the crossover tool. It was frequently used in relatively short, open-hole intervals where there was minimum deviation and separation of zones was not necessary. It is not as popular today because of the following problems: • Requires large volumes of fluid • Potential pack damage due to casing debris during annular gravel placement • Potential pack damage due to mixing gravel with filter cake and formation sand. For low-pressure, shallow wells, one popular version of the crossover method, which has been around for decades, is the “over-the-top” system. It uses a downward cup-type pack above the crossover tool. Gravel is placed below a cup-type service packer (Fig. 2.42). For reversing, clean fluids are pumped past the cup packer and back up the tubing. The cup packer is then pulled, and an inexpensive O-ring or Chevron seal overshot is landed into the top of the screen (Fig. 2.43). For higher-pressure wells where greater control is needed, “one-trip” tools are used. These tools are described more fully in Chapter Three. Briefly, the advantage is that a high- quality production packer can be run Casing Cement Slotted-liner or wire wrapped screen Wash pipe (tail pipe) Underreamed open hole Fig. 2.41. Reverse circulation, open-hole gravel pack method Fig. 2.42. Mechanical set cup-type packer 31 Chapter Two Open-Hole Sandface Completions and tested. In many cases the produc- tion packer is required as an integral part of a high-pressure well completion. Figure 2.44 illustrates a modern gravel- pack tool being used to circulate a pack into place in an underreamed hole, with fill-up to be indicated with an upper, tell-tale screen.37 Special equipment that may be used in open-hole gravel packing includes port collars, inflatable packers and combination tools. In a vertical open-hole well, the gravel-packing screen and tool hookup should typically be as follows (starting from the bull plug on the bottom): 1. Approximately 5 to 10 ft (1.52 to 3.05 m) of blank liner will allow for some sloughing of formation sand between the time the screen is on bot- tom and the time the gravel is placed. A 5 ft (1.52 m) blank is probably enough for relatively strong (friable) formations and 10 ft (3.05 m) should be used for weaker formations. 2. Approximately 5 ft (1.52 m) lower tell-tale screen and seal bore above it will indicate sand fill, screen plugging and when gravel reaches the bottom of the well. 3. Slotted liner or screen from the lower blank liner to within 10 ft (3.05 m) below the top of the underreamed hole section. 4. At least 10 ft (3.05 m) of blank liner, or 10% of the total open-hole length if the total open-hole length is more than 100 ft (30.48 m). This allows reserve gravel to be placed inside the underreamed hole so that the gravel may settle without exposing the screen or slotted liner to direct contact with the formation. 5. About 20 to 30 ft (6.10 to 9.14 m) of blank liner up in the casing. 6. Approximately 5 ft (1.52 m) upper tell-tale screen, only if conven- tional gravel packing placement tech- nique is used. 7. Approximately 5 to 10 ft (1.52 to 3.05 m) of blank liner. 8. Crossover tool assembly and packer. 9. Washpipe or stinger hanging from the crossover tool with its bottom in the seal assembly, if a lower tell-tale screen is used (otherwise hanging just to near the bottom of the main screen). 10. Bow-spring centralizers spaced out every 15 ft (4.57 m) in the open hole, starting with one on the lower blank liner. 11. Steel-wing centralizers should be used on the upper blank liner in the casing. A simplified illustration of this assembly, but without the lower tell-tale screen, is illustrated in Figure 2.45. The following recommendations have been successful for obtaining good results in open-hole gravel packs: Placement technique – Use the one- trip tools (described in the “Gravel Packing” section of Chapter Three) with lower tell-tale screen and seal bore with the high-density, slurry-pack tech- nique. After fluid returns are lost by covering the lower tell-tale screen with gravel, the tools can then be shifted to the upper circulating position to finish packing the annulus while back pres- sure is held on fluid returns to help pack gravel against the formation. Alternate technique – Some opera- tors keep the tools in the lower circulat- ing position or shift to the squeeze posi- tion until a sandout is observed. Some claim that this actually balloons the open hole to achieve a better pack. High gravel concentration (15 to 20 lb/gal), large screen/hole annulus and down- ward momentum of the slurry in verti- cal wellbores allow packing of the entire open-hole section. This is not advisable in long open holes (>100 ft [>30.48 m]) and high-angle open holes (>60° from vertical). Lower tell-tale screen – A lower tell- tale screen and seal bore should be used for high-viscosity, high-density gravel packing on every well. The reason for this is that a lower tell-tale and seal bore will indicate if the screen is being covered with sand or plugged with sand or dirt before you start pumping gravel. The pressure drop across a 5 ft (1.52 m) Casing Packer Cement Upper tell-tale Screen Underreamed open hole Fig. 2.44. Open-hole, low-viscosity, low- density, crossover gravel-pack method Fig. 2.43. Liner sealed to casing with O-ring or Chevron seal overshot 32 Modern Sandface Completion Practices screen should be approximately the same as the pressure drop circulating through the main screen while circulat- ing ungelled brine at 1 or 2 bpm. If the pressure to circulate in the lower circu- lating position is much higher than in the upper circulating position, the entire assembly should be pulled and wellbore and screen cleaned. Caliper logs – The hole should be callipered after underreaming to ensure it is open to the desired diameter and depth, and to determine the quantity of gravel needed to fully pack the hole. Underreaming fluids – These fluids must be clean and formation compati- ble. They should provide low-fluid-loss rate and enough viscosity to carry cut- tings to the surface. All of these proper- ties are necessary to maintain hole sta- bility, minimize formation skin damage, maximize well productivity and reduce thief zone problems. In quicksand and many partially consolidated formations, this is virtually impossible to achieve without adding an oil-soluble, water- soluble or acid-soluble fluid loss addi- tive to a viscous fluid and discarding the fluid returns. Naturally, these addi- tives will add considerable cost to the operation and must be removed before maximum well productivity is obtained. Drill-in fluid – Initially drilling the payzone with a DIF (discussed previ- ously in this chapter) may eliminate the need for an underreaming step. Removal of formation damage after the pack – Serious efforts should be made to prevent formation damage during drilling and underreaming an open hole, but there will always be some damage present. No attempt should be made to remove this damage before gravel is packed in the well, because of the risk that the formation sand will slough into the hole and interfere with gravel placement. Removal of formation damage after the pack must be done very carefully to prevent pushing gravel away from the slotted liner or screen, mixing of gravel with the formation sand or adding more damage to the pack and forma- tion. Spotting solvent on bottom and soaking it into the gravel and formation or slowly injecting solvent via coil tub- ing are the preferred methods. How- ever, neither of these techniques is really very effective because they do not force solvent into the most dam- aged sections of the completion. Wash tools with opposing cups (Fig. 2.46) have been used with some success to focus the injected solvent, but these tools have proven to be extremely dam- aging to a gravel pack when they are used to circulate fluid through the pack. If short blank sections of screen or liner have been made-up between sections of the gravel-pack screen or slotted liner, and if spaced out so that the tool cups will match blank sections and isolate each section of screen or slotted liner; injecting solvents slowly through a wash tool could be effective. Gravel packing low-pressure wells – Foam has been successfully used to cir- culate gravel into shallow, low-pressure open holes. Low-liquid-volume fraction foam helps stabilize the hole because it does not easily leak-off to the forma- tion, but it can flow through the screen as gravel is being packed. Forty pounds of gravel per minute can be added to the foam via a downstream sand injec- tor, and standard crossover circulation tool systems can be used. Foam is also a good diverting system for after gravel-pack acid treatments, especially if HEC gelled brines and acid-soluble or water-soluble additives have been used for fluid loss control while drilling or underreaming. Washing the pack – Do not wash a pack after it is in place. This procedure is sometimes undertaken in an attempt to eliminate voids and place additional gravel across the screen. Studies have shown that this damages the pack and promotes mixing of gravel with forma- tion sand. It should never be attempted. Correct placement techniques and flu- ids should completely pack the interval; but if much less than 100% fill is obtained or logs indicate there are cavi- ties in the pack, the screen and gravel should be removed and the gravel pack should be redone. Horizontal/deviated wells. An exact definition of a horizontal well is a drilled hole achieving a deviation angle of 90° from vertical. In applica- tion, the technology is much broader than this, and well profiles with devia- tion angles exceeding ±70° (highly deviated) are often referred to as “hori- Fig. 2.45. Typical vertical open-hole assembly Fig. 2.46. Wash tool 33 Chapter Two Open-Hole Sandface Completions zontal” if the length of the wellbore within the producing formation is many times greater than the thickness of the producing formation. Gravel packing is the option to stand- alone screens, discussed previously, for completing horizontal wells in uncon- solidated formations. While this tech- nology is more complicated and sophis- ticated than slotted liners, wire-wrapped screens, prepacked screens or premium screens, it is a more general-purpose completion for horizontal wells where sand control presents a problem. While using slotted liners, wire-wrapped screens, prepacked screens or premium screens may be applicable only for cer- tain wells; a gravel pack can be used on almost any horizontal completion pro- vided that sound gravel placement guidelines are followed. Additionally, this technique is believed to meet the challenge of completing high volume producers (>15,000 bbl/d in oil wells or >70 mmcf/d in gas wells) in high per- meability formations with well lives of up to 15 years.38 Note the time line of significant horizontal gravel-packing events (Fig. 2.47). Some believe that gravel packing long, horizontal wellbores should only be considered if it will improve well pro- ductivity or stability. The combination of high angle and long interval is very dif- ficult to gravel pack successfully without trapping a lot of formation damage in place. The effect of gravel packing around a prepacked screen on well pro- ductivity can be seen in Table 2.8.39 If gravel packing is not done, the for- mation sand may eventually fill the screen/hole annulus when the well is on production. This will not significantly reduce the well productivity, if the per- meability of the sand remains nearly equal to that of the undamaged forma- tion sand. However, if mud cake and for- mation mix reduces the permeability of the sand in the annulus from 1,000 to 100 md, the well productivity may be reduced by approximately 24%. Because it is highly unlikely that it will occur in a horizontal wellbore, sand and shale mix- ing will not reduce gravel permeability. Theoretically, the impairment of well productivity will be less if gravel pre- vents the screen/casing annulus from filling with low permeability. However, more damage to the formation may be done by fluid-loss-control solids and First horizontal, offshore California (1988) 1988 1990 1992 1994 1996 1998 2000 First Gulf of Mexico horizontal gravel pack (1993) First deepwater Gulf of Mexico horizontal openhole gravel pack (Aug. 1997) First horizontal OHGP (openhole gravel pack) Congo (1990) First horizontal openhole gravel pack from Floater Brazil (Oct. 1998) Fig. 2.47. Horizontal gravel-packing time line Directional wells Frac-pack wells Horz gravel packs Horz slotted lines 0 21 3 4 5 6 Months 7 8 9 10 11 12 200 400 600 800 bo pd 1,000 1,200 1,400 1,600 Fig. 2.48. Comparison of average initial 12 month oil production in Venezuela wells 45° Upper tell tale Upper tell tale Crossover packer Wash pipe Wash pipe Wire-wrap screen Screen Fig. 2.49. Low-viscosity circulation gravel packs 34 Modern Sandface Completion Practices polymer during the gravel pack, which will result in severe impairment. Gravel packing has not been widely used in horizontal wells until the last decade or so, but results since then have been promising. Consider the compari- son of production from directional, frac-pack, horizontal gravel pack and horizontal slotted-liner completed wells in Venezuela (Fig. 2.48).40 The reason for the initial lack of use appears to have been reluctance on the part of operating companies to try a long, horizontal gravel pack because of the perception that the technology is not available to place gravel over an interval of several thousand feet with success. The industry has long recog- nized the difficulties of successfully gravel packing long, highly deviated conventional wells using viscous gravel carrier fluids.41 Since horizontal wells represent the ultimate long, highly deviated well, a reluctance to gravel pack is well founded. At the time horizontal wells were beginning to be drilled in unconsoli- dated formations, viscous gel carrier fluids represented the state-of-the-art in gravel-packing technology. Research and studies in physical models confirm that performing a successful gravel pack in a horizontal well using viscous gravel carrier fluids is extremely diffi- cult. Today, brine is the state-of-the-art gravel carrier fluid. Research and stud- ies in physical models confirm that per- forming a successful gravel pack in a horizontal well using brine is possible. It is widely believed that by stabiliz- ing the formation sand, gravel packing increases the reliability and longevity of sand control completions in highly devi- ated and horizontal wells. An additional driver for open-hole gravel packing is the productivity limitations of the cased- hole frac-packing technique in high- transmissibility formations. Although open-hole gravel packing of horizontal wells extends well life, achieving a high-productivity, sand-free completion involves a number of considerations in the design and execution stages. Field-scale testing – The feasibility of gravel packing a long, horizontal well (which includes the completion equip- ment design, pumping schedules and other related procedures) has been deter- mined using scaled physical models.42 Up to well deviations of about 60º, grav- ity tends to initially assist in transporting the gravel to the bottom of the comple- tion interval (Fig. 2.49). However, at well deviations exceeding 60º, the angle of repose of the gravel is exceeded (Fig. 2.50). As a result, dimensional changes must be made to the gravel-pack equip- ment and higher pump rates are required to completely gravel pack the entire interval. The main requirement is that the ratio of the OD of the wash pipe to the ID of the screen must be at least 0.75, and returns through the wash pipe must be sufficient to transport the gravel to the toe of the well. The gravel placement at deviations exceeding 60° is initiated at the top of the completion interval rather than at the bottom of the well, as is the case when well deviations are less than 60°. The subsequent gravel placement extends downwards until the gravel dune, commonly referred to as the alpha wave, reaches the bottom of the well. At that point, secondary place- ment, or beta wave deposition, packs the volume above the alpha wave (Fig- ure 2.51). However, if the gravel con- centration is too high, the flow rate is too low, or the wash pipe permits exces- sive flow in the annulus between it and the screen, the alpha wave will prema- Dry sand Container 28° 62° Inverted cone of dry sand Fig. 2.50. Gravel angle of repose ∼ 60° Effective Permeability Productivity Rate Ratio of Sand/Mud Fill in for Horizontal Hole Screen/Drilled Hole Annulus (md) Q Collapsed/Q Undamaged 500 0.96 250 0.90 100 0.76 50 0.61 10 0.23 Drill hole radius (rw) = 0.33 ft, Screen radius (rs) = 0.250 ft, Formation permeability (Ke) = 1,000 md, Reservoir radius (re) = 2,106 ft, Completion zone length (L) = 1,000 ft Table 2.8. Effect of a wellbore collapse around a screen in a horizontal completion Screen Wash pipe After settling 80° 80° Crossover packer Fig. 2.51. Packing sequence with brine in high-angle well with high rate and large diameter washpipe 35 Chapter Two Open-Hole Sandface Completions turely stall. Increasing the diameter ratio to 0.75 and maintaining a return flow superficial velocity of 1 ft/sec (the ratio of the flow rate to the cross-sec- tional area of the annulus) promotes the stable alpha-beta wave packing sequence (Fig. 2.52).43 Later studies44 in a 7 in. OD by 25-ft long (7.62 m) scaled gravel-pack simu- lator have confirmed the findings por- trayed in Figures 2.49 and 2.51. How- ever, because the model was short, there was concern that horizontal gravel-pack tests would not be representative for actual conditions since tests could be dominated by end effects. Consequently, a longer field-scale model was designed and constructed. The model consisted of 1,500 ft (457.2 m) of 4-1/2 in. casing equipped with a 2-1/16 in. screen and is illustrated in Figure 2.52. Using foot- long pipe filled with resin-coated gravel simulated fluid loss. The difference in the flow into the model and the returns through the wash pipe was the fluid loss to the formation. The model was equipped with high-strength plastic windows that allowed the visualization of the gravel packing process as it pro- gressed down the model. Figure 2.53 shows the alpha wave traversing a window and Figure 2.5445 perhaps illustrates more clearly the alpha beta wave principle. A typical plot of the location of the alpha and beta waves as a function of time for a horizontal gravel pack is illustrated in Figure 2.55 and demon- strates that the entire 1,500-ft (457.2 m) model was packed with gravel. Pro- vided that the design of the gravel pack is dimensionally correct and a superfi- cial velocity of 1.0 ft/sec (30.48 cm/sec) is maintained, gravel packing a long horizontal gravel pack can be per- formed with routine procedures. How- ever, for open-hole completions, a clean, stable wellbore is an additional requirement for a quality gravel pack to avoid contamination with formation material. Displacing the hole to brine prior to running the screen and gravel packing the well is preferred. Typical installation method – The following steps are performed in a typi- cal open-hole, horizontal gravel pack:46 1. Drill open hole with formation- compatible fluid designed to be non- damaging to the payzone and establish a nearly impermeable filter cake that allows fluid returns to almost equal the pumping rate. (Low leak-off rate must be established and maintained to stabi- lize the hole and maintain a high enough fluid velocity to push gravel dunes to the toe of the screen and finish packing the annulus.) 2. Circulate the hole clean and dis- place open hole with solids-free DIF. 3. Run in hole with bottom gravel- pack assembly. (Figure 2.56 illustrates a simplified hook-up). 4. Flush-joint wash pipe is run in the screen assembly till it engages to the receptacle of the isolation plug. 5. The retrievable packer, closing sleeve with upper and lower extensions threaded to the gravel pack service tool is picked up and made up to the wash pipe as well as screens. 6. The entire packer assembly is run in the well on drill pipe until the packer reaches setting depth inside the liner and screens are in open hole. 7. After reaching target depth, per- form a circulation test to make sure the open-hole is in stable condition, and the tool is clear to pump through it. This is a critical step in the success of the over- all completion. If there were problems circulating at this point, it would be best to attempt to retrieve the downhole screen assembly. 8. Set the gravel-pack packer. 9. Test the packer by pressuring the annulus, then apply an upward pull and slack off. 10. Mark positions and pump the gravel slurry at a concentration of no more than 1.5 ppg. Care should be taken to stay below frac pressure. (The slurry should form a dune of sand beginning at the heel of the well and progress to the toe of the well until the end of the screen is reached. The returning fluid enters through the tell- tale screen into the wash pipe and flows back to the surface via the crossover tool from the annulus side.) 11. Continue the process until the beta wave is fully formed and screen- out occurs. 12. Reverse out the slurry in the workstring. 13. Acidize screens with wash tool or foamed acid using coiled tubing. The above horizontal, gravel-pack- ing method can be done by using the BJ HST System or equivalent. It allows the washdown, gravel pack and stimulation of a horizontal well in a single trip that has the benefit of reducing the potential for fluid loss to the formation. The vari- ous positions of this type service tool are shown in Figure 2.57. Fig. 2.53. Results from 1,500-ft horizontal gravel-pack model: alpha wave propagating in model 1 P1 P2 P3 P4 P5 3 2 543 6 65421 Windows Thief zone Perforation ScreenThief zone QtFlow in Qi Return flow, Qr Fluid loss 1,500 ft Fig. 2.52. 1,500 ft horizontal, gravel-pack model 36 Modern Sandface Completion Practices Field result – Several hundred hori- zontal wells around the world have now been completed with gravel packs. The vast majority being open-hole installa- tions. Typical gravel mix ratios pumped have been about 1 ppa (pound per gal- lon added); however, pack times have been reasonably short except for large diameter holes. Typical gravel pack times are in the 4 to 6 hour range. Wells that have been gravel packed many times do not experience the productiv- ity declines observed with stand-alone screens provided that the completion process described above is followed. Summary – Achieving a successful horizontal gravel pack requires: • Washpipe screen OD-ID ratio of at least 0.75 • Running the washpipe to the end of the screen • Maintaining a superficial velocity of at least 1.0 ft/sec (30.48 cm/sec) based on return flow • Ensuring that the formation is not fractured • Pumping at gravel concentrations that are typically 1.0 lb/gal (119.8 kg/cu m) Alternate Path Screen Options Alternate Path Technology. This tech- nology (developed by Mobil Oil) (also see the “Frac-Pack Methods/Applica- tions” section of Chapter Three) com- bined with Schlumberger AllPAC screens, is an advanced gravel place- ment technique, which ensures 100% annular pack even in the most adverse hole conditions. The technique utilizes viscous fluids with high gravel concen- trations (4–8 ppa) and involves the use of shunt tubes attached to the screen Fig. 2.54. Alpha-beta wave principle Alpha wave (velocity 9.9 fpm) Beta wave (velocity 33.5 fpm) Pump rate - 1.5 bpm mix ratio - 0.75 ppga Elapse time, hr Thief zone End of model 0 200 400 600 800 1,000 1,200 1,400 1,600 1,800 2,000 0 1 2 3 Du ne lo ca tio n, ft Fig. 2.55. Results from 1,500-ft horizontal gravel-pack model; gravel dune location vs. elapsed time Gravel-pack paker Gravel-pack extension Blank pipe Production screen Seal bore Bull plug Fig. 2.56. Typical horizontal open-hole hookup 37 Chapter Two Open-Hole Sandface Completions (Figs. 2.58 and 2.59), which allow bypass of annular bridges that may form as a result of high leak-off. Gravel packing with shunt tubes does not rely on the existence of a tight filter cake, as is required in conventional horizontal, open-hole gravel packing. The AllPAC screen is used in gravel- packed completions with Alternate Path technology. The screen design features one or more 1.0 in. x 0.50 in. shunt tubes that are attached either concentri- cally or eccentrically to the screen joint with 1/4 in. exit nozzles at 6.0 ft (1.83 m) intervals on each shunt tube. Gravel packing rate can be up to 2.0 bpm per shunt tube, depending on the screen type, blank pipe length, and type of gravel-pack fluid. The horizontal AllPAC screen design features one or more 1.50-in. x 0.75-in. tubes attached eccentrically to the screen joint. Each transport tube, which runs the length of the screen and connections joint-to-joint, feeds one or more 1.0-in. x 0.50-in. docking shunt tubes. The docking tubes have nozzles sized at either 1/4 in. or 3/8 in., depend- ing on the application requirements. Horizontal AllPAC screens also include an outer shroud. The shroud not only protects the gravel-pack screen’s wire wrapping and shunts during run in, but it also centralizes the assembly, making the use of open-hole centraliz- ers redundant. This type screen is nor- mally applied in horizontal or highly deviated wells with intervals more than 250 ft (76.2 m). In cases where synthetic oil-based DIFs are used, low flow initiation pres- sures typically observed with these flu- ids can result in cake liftoff with slight underbalances. These underbalances may occur during tool manipulations, causing high leak-off and jeopardizing the completion of the gravel packing operation. The association of low liftoff pressures and low yield stresses with oil based filter cakes as observed in field applications indicates these cakes are prone to erosion. Field experience shows that gravel packing open-hole horizontal wells with long shale sections can be problematic. Because the shunt technique is indepen- dent of the state of the filter cake, it allows the use of breakers in the carrier fluid to gravel pack and simultaneously to aid in cleanup of the filter cake.47 Alternate-Path screens have been successfully run in several horizontal wells (Fig. 2.60) offshore Trinidad, Venezuela and several other worldwide locations.48,49 This technology may increase the length of formations that can be gravel packed and will especially address the issue of fluid loss during gravel packing long horizontal intervals. Concentric Annular Packing Service (CAPS). Halliburton has introduced CAPS, an alternate-path screen system. It too provides multiple paths so that gravel-pack slurry can bypass any pre- mature annulus bridges that formed during gravel placement, ensuring a complete annular pack. Annular clear- ance is particularly important in the design of the system. For normal verti- cal open-hole wells, the normal annular clearance is typically 1.5 to 2 in. (3.81 to 5.08 cm). Figure 2.61 illustrates the possible bridging problem in an open hole and how it can be bypassed with CAPS to obtain a complete pack. Open-Hole Frac Packing Frac packing has been a popular sand- control technique since the early 1990s and provides highly reliable comple- tions aimed at enhancing the productiv- ity of gravel-packed wells. The tech- nique consists of incorporating a ‘‘tip-screenout’’50 hydraulic fracturing treatment (see “Frac-Pack Methods/ Applications” section of Chapter Three) as part of the gravel-packing procedure, thus stimulating the well. The tip- screenout method provides a high con- trast between fracture permeability and formation permeability and is essential to ensure that fracture width and prop- pant concentrations are adequate to efficiently connect the reservoir to the wellbore. Since the beginning of its increased attractiveness, almost all frac-pack treatments have been performed in cased holes. This stimulation tech- nique, including frac fluids and prop- pants (sized particles mixed with frac- turing fluid to hold fractures open after a hydraulic fracturing treatment), are discussed thoroughly in Chapter Three as noted. In high-performance wells, perforations are the dominant restric- tion to flow. In these high-transmissiv- ity wells requiring sand control, an open-hole completion is preferred because perforations, and thus flow restrictions, are eliminated. As mentioned in Chapter One, poorly consolidated, usually moderate- to high-permeability sandstone, reser- voirs are susceptible to sand production. Screen shunt ring AllPAC 93 Joint connector OD Pipe OD 0.5 in. 1 in. Fishing OD Screen OD Fig. 2.58. AllPAC screen cross section Fig. 2.57. BJ HST System horizontal, gravel-packing method 38 Modern Sandface Completion Practices Sometimes, traditional techniques (described earlier in this handbook) to control the sand influx typically result in decreased well productivity. To possibly solve this decreased pro- duction problem, operators have discov- ered that performing a fracturing treat- ment combined with a sand control gravel pack can enhance well produc- tivity and mitigates the tendency of a stand-alone screen or gravel pack to decrease production. The success of this frac-pack technique is due in part to the larger proppant sizes used in frac- turing than those sizes commonly used in gravel packing (Fig. 2.62). Non-Darcy effects are primarily due to the acceleration and deceleration of the fluid as it travels through the tortu- ous flow path of porous media (in this instance, the propped fracture). The oil, water or gas in the fracture must contin- ually change direction, accelerating through pore throats and decelerating in the larger pore spaces.51 Excessive velocities in the created fractures of high-transmissivity wells may make for significant non-Darcy effects and some resulting skin.52 Frac packing an open-hole of a highly permeable, unconsolidated for- mation combines fracturing and gravel packing as a single operation with a screen or sand exclusion device (dis- cussed previously in this Chapter). The fracture provides stimulation and enhances the effectiveness of the gravel-pack operation in eliminating sand production. Candidate Selection Proper candidate selection, treatment design and execution can increase pro- duction and alleviate fines migration by reducing pressure losses and flow velocities. Figure 2.63 illustrates an ideal fracture system in a high-perfor- mance well that can accomplish the treatment design objectives. Good candidates for open-hole frac packing include wells with the follow- ing characteristics: • High permeability, easily damaged reservoirs • Near-wellbore damage • Low permeability reservoirs and for- mations with fines migration problems • Formation sanding potential • Productive layers not connected to the wellbore • Laminated sand/shale sequences • Poor productivity expected after a gravel-pack installation. Therefore, an alternative approach to gravel packing high-performance wells is open-hole frac packing, which combines the benefits of an open hole and fracturing and eliminates perfora- tions, as well as provides a highly conductive flow path that bypasses near-wellbore damage. However, one problem encountered in frac packing or gravel packing long intervals is annular bridging that results in incomplete pack- ing of the sections below a sand bridge. Special Products and Tools The Alternate Path screen option using Schlumberger AllFRAC Screens (described in the previous section of this Chapter) has proved successful in bypassing bridges and yields higher productivity through complete packing of long intervals. This technique also has been proposed for frac packing hor- izontal wells53 as well as gravel packing open-holes above fracturing pressure without pads.54 In addition, unlike a conventional frac-pack treatment, this approach does not use pads and is intended to simply bypass the filter- cake damage. By employing larger shunts than on the Alternate Path screens used for con- ventional gravel packing, increased pump rates can be applied to perform frac-pack operations. Fractures propa- gate throughout the interval, not just 93 Cover OD Packing tubes with nozzles Transport tube Screen OD Pipe size Fig. 2.59. Horizontal AllPAC screen cross sections Transport tubes 9393 Cover OD Screen OD Pipe size Packing tubes with nozzles Transport tube Nozzles Packing tube 9393 ShroudScreens QUANTUM gravel-pack packer Oil-bearing layer AllPAC screens Fig. 2.60. QUANTUM packer and AllPAC screens used in a horizontal, open-hole gravel pack 39 Chapter Two Open-Hole Sandface Completions above a premature bridge, and proppant is placed along the entire interval. In addition, the fractures as well as the screen/open-hole annulus can be tightly packed for maximum conductivity. (Also see Figure 2.61, which illustrates a simi- lar proceedure using the CAPS horizon- tal, open-hole, gravel-pack technique.) A typical open-hole, frac-pack tool assembly is illustrated in Figure 2.64. The Baker Model CS-300 crossover tool in this string is designed to maintain hydrostatic overbalance across the for- mation during all phases of the open- hole, gravel-pack completion. If the hydrostatic pressure is allowed to decrease to the static bottomhole pres- sure, the risk of filter cake removal or hole sloughing increases dramatically. Specialized components in the assembly permit hydrostatic, overbalance-pressure transmission to the borehole at all phases of completion. The system is designed to provide positive tool locating and elimi- nation of surge and swab pressures. Another completion tool string that was used in the open-hole, frac-pack case history, described below, is illus- trated in Figure 2.65.55 Run as part of the completion assembly, a Multi-Zone (MZ) isolation packer was located below the QUAN- TUM gravel-pack packer inside 7-in. casing. Two large shunt tubes extending through the packer bypassed the reac- tive shale section. A protective shroud covered the AllFRAC screens and shunt tubes to prevent mechanical damage from hole instability or assembly rota- tion to reach total depth. The shroud also centralized the screens for a more complete annular pack. Case History A 70° deviated offshore well in the Java Sea had a 110 ft (33.53 m) section to frac pack. Packing efficiency was a concern based on previous completion failures where incomplete packing of the deviated wellbore was suspected. To address these two considerations, a combination of screen with shunt tubes and an MZ packer was selected for the job. The MZ packer has cup-type ele- ments that prevent flow across it, which is illustrated in Figure 2.65. Frac-pack execution went smoothly despite concerns about the high-angle wellbore, multiple competing fractures and excessive fluid leak-off through 225 ft (68.58 m) of open-hole interval with 47 ft (14.33 m) of high-permeabil- ity net sand. Treatment simulation indi- cated a final fracture half-length of 18 ft (5.49m) with a propped fracture width of 1.0 in. Initial production of 2,000 bpd total fluid with 500 bopd from an electrical submersible pump exceeded expectations. Post-treatment skin was not measured by pressure- buildup analysis, but a sensor on the electrical submersible pump monitored downhole flowing pressures, which indicated a small pressure drop at the completion sandface. Fig. 2.63. Ideal fracture system in a high productivity well Fig. 2.61. Conventional screen with gravel bridge and incomplete pack (top). CAPS screen bypasses bridge (middle). Completed open-hole gravel pack via CAPS (bottom). Fig. 2.62. High concentrations of large, spherical proppant offset embedment and non-Darcy flow effects 40 Modern Sandface Completion Practices References 1. Davidson, E. and Stewart, S., “Open Hole Comple- tions: Drilling Fluid Selection,” SPE/IADC 39284, Mid- dle East Drilling Technology Conference, Bahrain, November 23-25, 1997. 2. Ezzat, A., “Completion Fluids Design Criteria and Current Technology Weaknesses,” SPE 19434, Forma- tion Damage Control Symposium, Lafayette, Louisiana, February 22-23, 1990. 3. Hodge, R., Augustine, B., Burton, R., and Sanders, W., “Evaluation and Selection of Drill-In Fluid Candi- dates to Minimize Formation Damage,” SPE Drilling and Completion, September 1997, 174. 4. Saasen, A., Jordal, O., Durkhead, D., Berg, P., Løk- lingholm, G., Pedersen, E., Turner, J., and Harris, M., “Drilling HT/HP Wells Using a Cesium Formate Based Drilling Fluid,” IADC/SPE 74541, Drilling Conference in Dallas, Texas, February 26-28, 2002. 5. Scbba, F., Foams and Biliquid Foams-Aphrons, John Wiley and Sons, New York, 1987, 46-61. 6. Brookey, T., “’Micro-Bubbles’: New Aphron Drill-in Fluid Technique Reduces Formation Damage in Hori- zontal Wells, SPE 39589, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 13-15, 1998. 7. Dobson, J. and Kayga, D., “Soluble Bridging Parti- cle Drilling System Generates Successful Completions in Unconsolidated Sand Reservoirs,” 5th International Conference on Horizontal Well Technology, Amster- dam, The Netherlands, July 14-16, 1993. 8. Mondshine, T., "Tests Show Potassium-Mud Versa- tility," Oil & Gas Journal, April 1974. 9. Ryan, D., Kellingray, D., and Lockyear, C., "Improved Cement Placement on North Sea Wells Using a Cement Placement Simulator," SPE 24977 presented at the European Petroleum Conference, Cannes, France, November 16-18, 1992. 10. McLean, R., Manry, C., and Whitaker, W., "Displacement Mechanics in Primary Cementing," Journal of Petroleum Technology, February 1967. 11. Ibid. 12. Rogers, E., “Sand Control in Oil and Gas Wells,” Oil & Gas Journal, November 1, 8, 15 and 22, 1971, 54-68 13. Coberly, C., “Selection of Screen Openings for Unconsolidated Sands,” Drilling & Production Prac- tices, API, 1937, 189-201. 14. Schwartz, D., “Successful Sand Control Design for High Rate Oil and Water Wells,” Journal of Petroleum Technology, September 1969, 1193-98. 15. Tiffin, D., King, G., Larese, and Britt, L., “New Cri- teria for Gravel and Screen Selection for Sand Con- trol,” SPE 39437. Formation Damage Control Sympo- sium, Lafayette, Louisiana, February 18-19, 1998. 16. Kaiser, T., Wilson, S., and Venning, L., “Inflow Analysis and Optimization of Slotted Liners,” SPE Drilling and Completion, December 2002, 201-202. 17. Ibid 18. Moen, T., Gunneroed, T., and Kvernstuen, O., “A New Sand Screen Concept: No Longer the Weakest Link of the Completion String,” SPE 68937, European Forma- tion Damage Conference, The Hague, May 21-22, 2001. 19. Markestad, P., Christie, O., and Espedal, A., “Selection of Screen Slot Width to Prevent Plugging and Sand Production,” SPE 31087, Formation Damage Control Symposium, Lafayette, Louisiana, February 14-15, 1996. 20. Gillespie, G., Deem, C., and Malbrel, C., “Screen Selection for Sand Control Based on Laboratory Tests,” SPE 64398, Asia Pacific Oil and Gas Confer- ence, Brisbane, Australia, October 16-18, 2000. 21. Metcalfe, P. and Whitelaw, C., “The Development of the First Expandable Sand Screen,” OTC 11032, Offshore Technology Conference, Houston, Texas, May 3-6, 1999. 22. van Buren, M., van den Broek, L., and Whitelaw, C., “Trial of an Expandable Sand Screen to Replace Internal Gravel Packing,” SPE/IADC 57565, Middle East Drilling Technology Conference, Abu Dhabi, UAE, November 8-10, 1999. 23. Saucier, R., “Considerations in Gravel Pack Design,” SPE 4030, Journal of Petroleum Technology, February 1974, 205-212 24. “Recommended Practices for Testing Sand Used in Gravel Packing Operations,” API Recommended Practices 58, 2nd Ed., December 1986. 25. Skopec, R., “Proper Coring and Wellsite Core Han- dling Procedures: The First Step Toward Reliable Core Analysis,” Journal of Petroleum Technology, April 1994, 280. Seting tool SC-R type packer GP sliding sleeve CS crossover port Seal bore sub FASTool S-1 shifting tool Indicating coupling SMART collet Fig. 2.64. Open-hole, frac-pack tool assembly with Model CS-300 crossover tool Drilling bit Drilling motor AllFRAC screens with nozzles AllFRAC blank pipe without nozzles Reactive shale MZ isolation packer with bypass shunts Shunt tubes QUANTUM gravel-pack packer QUANTUM service tool Washpipe Fig. 2.65. Offshore Java Sea completion 41 Chapter Two Open-Hole Sandface Completions 26. Gurley, D., Copeland, C., and Hendrick Jr., J., “Design, Plan, and Execution of Gravel-Pack Opera- tions for Maximum Productivity,” Journal of Petroleum Technology, October 1977, 1259-1266. 27. “Core Analysis,” API Recommended Practices 40, 2nd Ed., February 1998. 28. Saucier, R., “Considerations in Gravel Pack Design,” SPE 4030, Journal of Petroleum Technology, February 1974, 205-212. 29. Ibid. 30. Cocales, B., “Optimizing Materials for Better Gravel Packs,” World Oil, December 1992, 73-77. 31. “Recommended Practices for Testing Sand Used in Gravel Packing Operations,” API Recommended Practice 58, 2nd Ed., December 1986. 32. Sparlin, D., “Sand and Gravel – A Study of Their Per- meabilities,” SPE 4772, “Symposium on Formation Dam- age Control, New Orleans, Louisiana, February 7-8,1974. 33. Gurley, D., Copeland, C., and Hendrick Jr., J., “Design, Plan, and Execution of Gravel-Pack Opera- tions for Maximum Productivity,” Journal of Petroleum Technology, October 1977, 1259-1266. 34. Cocales, B., “Optimizing Materials for Better Gravel Packs,” World Oil, December 1992, 73-77. 35. Diallo, M., Jenkins-Smith, N., and Bunge, A., “Dis- solution Rates for Quartz, Aluminum-Bearing Minerals, and Their Mixtures in Sodium and Potassium Hydrox- ide,” SPE 16276, International Symposium on Oilfield Chemistry, San Antonio, Texas, February 4-5, 1987 36. Suman, G. Jr., Ellis, R., and Snyder, R., Sand Con- trol Handbook, Gulf Publishing Company, Houston, Texas, 1991. 37. Ibid. 38. Foster, J., Grigsby, T., and LaFontaine, J., “The Evolution of Horizontal Completion Techniques for the Gulf of Mexico. Where Have We Been and Where Are We Going!” SPE 53926, Latin American and Caribbean Petroleum Engineering Conference, Cara- cas, Venezuela, April 21-23,1999. 39. Karcher, B., Giger, F., and Combe, J., Some Practi- cal Formulas to Predict Horizontal Well Behavior,” SPE15430, Annual Technical Conference, New Orleans, Louisiana, October 5-8, 1986. 40. Benavides, S. and McKee, J., Using Horizontal Gravel Packing Technology to Optimize Well Produc- tivity and Field Economics: Case History, Uracoa Field, Venezuela,” SPE 65468, International Conference on Horizontal Well Technology, Calgary, Alberta, Canada, November 6-8, 2000. 41. Forrest, J., “Horizontal Gravel Packing Studies in a Full Scale Model Wellbore,” SPE 20681, Annual Technical Conference, New Orleans, Louisiana, September 23-26, 1990. 42. Penberthy, W. and Echols, E., “Gravel Placement in Wells,” SPE 22793, Annual Technical Conference, Dallas, Texas, October 6-9, 1991. 43. Ibid. 44. Penberthy, W., Bickham, K., and Nguyen, H., “Gravel Placement in Horizontal Wells,” SPE Drilling and Completion, June 1997, 85-92. 45. Ibid. 46. Walvekar, S. and Ross, C., “Production Enhance- ment Through Horizontal Gravel Pack,” SPE 73777, International Symposium on Formation Damage Con- trol, Lafayette, Louisiana, February 20-21, 2003. 47. Price-Smith, C., Parlar, M., Kelkar, S. Brady, M., Hoxha, B., Tibbles, R., Green, T., and Foxenberg. B. “Laboratory Development of a Novel, Synthetic Oil- Based Reservoir Drilling and Gravel Pack Fluid System That Allows Simultaneous Gravel Packing and Cake Cleanup in Open-Hole Completions,” SPE 64399, Asia Pacific Oil and Gas Conference, Brisbane, Australia, October 16-18, 2000. 48. Foster, J., Grigsby, T., and LaFonntaine, J., “The Evolution of Horizontal Completion Techniques for the Gulf of Mexico. Where Have We Been and Where Are We Going!” SPE 53926, Latin American and Caribbean Petroleum Engineering Conference, Cara- cas, Venezuela, April 21-23,1999. 49. Romero, J., Pizzarelli, S. and Mancini, J., “Simul- taneous Stimulations and/or Packing in Multiple Zones. Effective Solutions,” SPE 77437, Annual Tech- nical Conference, San Antonio, Texas, September 29- October 2, 2002. 50. Smith, M. and Haga, J., “Tip Screenout Fractur- ing: A Technique for Soft Unstable Formations,” SPEPE, May 1987, 95 Transcript, AIME, 203. 51. Vincent, M., Pearson, M. and Kullman, J., “Non- Darcy and Multiphase Flow in Propped Fractures: Case Studies Illustrate the Dramatic Effect on Well Productivity,” SPE 54630, Western Regional Meeting, Anchorage, Alaska, May 26-28, 1999. 52. Ayoub, J., Barree, R. and Chu, W., “Evaluation of Frac and Pack Completions and Future Outlook,” SPE Production & Facilities, Vol. 15, No. 3, August 2000, 137-143. 53. Jones, L., “Frac-packing Horizontal Wells Allows Ultra-High Rates from Mediocre Formations,” Petroleum Engineer International, July 1999, 37-40. 54. Parlar, M., Bennett, C., Gilchrist, J., Elliott, F., Price- Smith, C., Brady, M., Tibbles, R., Kelkar, S. and Fox- engerg, B., “Emerging Techniques in Gravel Packing Open-Hole Horizontal Completions in High Perfor- mance Wells,” SPE 64412, Asia Pacific Oil and Gas Conference, Brisbane, Australia, October 16-18, 2000. 55. Saldungaray, P., Troncoso, J., Sofyan, M., San- toso, B., Parlar, M., Price-Smith, C., Hurst, G. and Bai- ley, W., “Frac-Packing Open-hole Completions: An Industry Milestone,” SPE 73757, International Sympo- sium on Formation Damage Control, Lafayette, Louisiana, February 20-21, 2002. 42 Modern Sandface Completion Practices CHAPTER THREE Cased-Hole Sandface Completions Completion Fluids • Debris Removal and Mysteries • Fluid Filtration • Perforating Stand-Alone Screens • Gravel Packing • Frac Packing • Gravel Packing Method Selection 43 Careful planning, well preparationand completion execution are allrequired for the success of a cased-hole sandface completion. The omission of any of these steps may account for a completion that falls short of its objectives since many of the com- pletion operations are interdependent. To achieve the completion goals of sand control, productivity and longevity, attention must be given to completion fluids, debris management, fluid filtra- tion and perforating. Proper preparation of a well for stand-alone completions, gravel packing and frac packing can be the key to a successful completion. Cleanliness may be one of the most important considerations when prepar- ing a well for a stand-alone completion, gravel pack or frac pack. Since all of these operations represent the installa- tion of a downhole filter, any action that promotes plugging the filter (i.e., the screen, gravel pack sand or frac pack proppant) is detrimental to the success of the completion and well productivity. Many advances have been made in improving the cleanliness of these com- pletion operations, particularly comple- tion fluids. However, in spite of the fact that clean completion fluids are used, the lack of cleanliness in the casing, work string, lines, pits and other equip- ment is a source of potential formation damage and lost productivity.1,2 While cleaning the well and rig equipment can be expensive, it is not as expensive as lost productivity or having to rework the entire completion because proper clean- ing was neglected in the beginning. Completions Fluids It is useful to think of completion fluids as tools that aid in performing a down- hole operation on, or in contact with, a producing formation, after the well has been drilled, cased and cemented. As tools, these fluids are (1) introduced for a particular function, (2) removed after the job and (3) not intended to leave the wellbore and penetrate the formation. However, it is impossible to prevent some loss. The proper selection and use of flu- ids in completing and/or working-over a well can significantly affect both for- mation productivity and mechanical performance. Generally, a completion fluid is any fluid used to conduct down- hole operations subsequent to drilling the wellbore. The completion fluid is important because of its role in well control and perforation clean-up or “washing.” A dirty or contaminated completion fluid can plug perforations with solids, hence creating a barrier for the proper and consistent placement of gravel during gravel pack operations. Additionally, fines from an improperly filtered fluid can mix with the gravel- pack gravel, thereby reducing gravel pack permeability. A poor gravel pack can result in sand-control failures and/or low production rates. Mechanical plugging is the most important cause of formation perme- ability damage. Formation fines, added solids, cement or other debris sus- pended in the completion fluid, can cause plugging. For this reason, typical or even modified drilling mud with their high solids content should not be placed against a producing formation. Accordingly, every attempt must be made to use only clean, particle free, completion and workover fluids. A pro- gram of clean well site handling prac- tices and proper completion fluid filtra- tion is necessary to obtain the desired level of clarity. Since a density of approximately 8.6 ppg (1,030.5 Kg/m3) is as light as prac- tical for conventional completion fluids, a wellbore that is overbalanced is a par- ticular problem when working in a low- pressure or pressure-depleted forma- tion. The potential for fluid loss can lead to difficulties with well control and/or obtaining clean perforations. Clean perforations are considered crucial to the completion process. Gen- erally, perforating a formation with an overbalanced, solids-laden fluid (mud) yields the least efficient perforation. Perforating a formation with an over- balanced, solids-free, non-damaging fluid (brine) yields a more efficient per- foration. Perforating with an underbal- ance into the wellbore yields a still more efficient perforation, with the least formation damage.3 Use of Completion Fluids Completion fluids are required down- hole to conduct operations such as: • Well killing and well control • Perforating • Perforation washing • Gravel packing • Under reaming • Sand fill cleanout • Spotting or displacing treating fluids • Drilling or milling • Leaving behind a packer. They are used to enhance the safety and efficiency of each operation. Solids-free brines are selected for use whenever the producing formation is exposed during completion and workover operations. They serve pri- marily to control downhole formation pressures, while reducing the risk of formation damage resulting from inva- sion of either solids or liquids. These brines accomplish this task by utilizing highly water-soluble salts, which do not react with the formation minerals or water to obstruct the effective perme- ability. Otherwise, formation perme- ability can be plugged by precipitates formed when incompatible waters are intermingled.4 Most damage mecha- nisms, such as emulsifying or scale- forming potential, can be anticipated and avoided through proper testing and design. The primary water-soluble salts, which make up the commercially avail- able, solids-free completion brines, are listed in Table 3.1. All of these salts are highly soluble and stable, and economical to use. (Consider the economic consequences of lost production due to formation damage caused by barite, bentonite or other drilling mud plugging solids.) These brines are generally safe to han- dle and can be easily disposed, with several notable exceptions. Opera- tionally, they are adaptable to rig site procedures, and require only simple safety considerations and equipment during use. This provides the operator a fluid that (1) minimizes fluid loss by hydrostatic balance, (2) is compatible with the producing formation, and (3) offers ease of handling and perfor- mance at the rig site. Selection Criteria Most operators will order brine based on three principal criteria. These are (1) density for proper well control, (2) compatibility with the formation rock matrix and fluids, and (3) true crystallization temperature (TCT) for maximum storage and optimum operating conditions. Density. The primary performance requirement for completion brine is to maintain hydrostatic pressure. The den- sity specified must be sufficient to hold back the formation pressure and prevent influx of produced fluids. Typically, an overbalance of 200 psi to 300 psi over reservoir pressure is used to maintain well control. Table 3.2 displays brine density ranges for the common salt brine completion fluids at 60ºF (15.6ºC). Unlike drilling muds that depend on solids to maintain density, completion fluids must be blended in anticipation of a lower effective-fluid-density downhole due to increased temperature at depth. Completion brines exhibit a volumetric response to temperature and pressure (i.e., they expand with increasing tem- perature and compress with increasing pressure). Under downhole conditions, the temperature effect (expansion) is more pronounced than the pressure effect (compression) on a completion fluid. The increase in volume results in a decrease in fluid density. This can cause well control problems due to reduced hydrostatic pressures. Formate brines were introduced as a completion fluid in the 1990s. Cabot Specialty Fluids reports that these fluids have all the advantages of more conven- tional solids-free brines, yet none of the disadvantages of the halide brines. The formate brines, which are shown in Table 3.2, consist of sodium (11.0 ppg), potassium (13.1 ppg) and cesium for- mates (20.0 ppg). Formate brines can be blended to achieve any density between 8.4 ppg and 20.0 ppg. Bromide brines can be used at similar, higher densities, but these have additional limitations, particularly regarding HSE (health, safety and environment), corrosivity, formation damage and polymer compat- ibility. Bromide brines above 14.3 ppg are normally considered impractical as a completion fluid because they are toxic, corrosive and incompatible with most oil field elastomers and polymers.5 The Dow Chemical Company, in connection with OSCA (now BJ Ser- vices), investigated the expansion/com- pression properties of completion fluids under typical oil field conditions and derived a mathematical model that cal- culates the surface density needed to achieve the required hydrostatic pres- sures. This model is being used world- wide to predict the effects of tempera- ture and pressure on a column of com- pletion fluid in a wellbore. Expansion and compression factors for various clear brine fluids are shown in Table 3.3.6 Note that expansion and compres- sion effects on density are greater in the higher density ranges, and, when com- pared on a percent change, the effects are greater on sodium-based brines than on calcium-based brines. Many suppliers of solids-free brines have software to calculate the optimal surface density for a given bottomhole temperature (BHT) and desired hydro- static pressure. The program accounts for the effects of both temperature and pressure, and with it considerably Chloride Salts Bromide Salts Formate Salts NaCl NaBr NaHCO2 KCI CaBr2 KHCO2 NH4CI ZnBr2 CsHCO2 CaCI2 Table 3.1. Water-soluble salts Brine Type Density Range (ppg) Typical Dencity (ppg) NaCl 8.4 - 10.0 8.5 - 10.0 KCI 8.4 - 9.7 8.5 - 9.0 NH4CI 8.4 - 8.9 8.5 - 8.7 NaBr 8.4 - 12.7 10.0 - 12.5 NaCl/NaBr 8.4 - 12.5 10.0 - 12.5 NaHCO2 8.4 - 11.1 9.0 - 11.0 KHCO2 8.4 - 13.3 11.0 - 13.1 CsHCO2 13.0 - 20.0 17.5 - 20.0 KHCO2/CsHCO2 13.0 - 20.0 13.0 - 17.5 NaHCO2/KHCO2 8.4 - 13.1 11.0 - 13.1 CaCI2 8.4 - 11.8 9.0 - 11.6 CaBr2 8.4 - 15.3 12.0 - 14.2 CaCI2/CaBr2 8.4 - 15.1 11.7 - 15.1 ZnBr2 12.0 - 21.0 19.2 - 21.0 ZnBr2/CaBr2 12.0 - 19.2 14.0 - 19.2 ZnBr2/CaBr2/CaCl2 12.0 - 19.1 14.2 - 19.1 Table 3.2. Brine selection density range 44 Modern Sandface Completion Practices improved estimates of effective down- hole pressures are achieved resulting in lower fluid losses and better clean up under production conditions. The pro- gram has been in field use for several years. The densities calculated by this method have been found to control for- mation pressures with less fluid loss to the formation than by correction algo- rithms previously used. The program can be used to perform four important functions: • Calculate a required surface density to achieve a specified bottomhole pressure • Calculate the downhole effects of a specified surface density completion fluid • Calculate surface temperature effects only on the fluid density • Calculate average density for the well. Formation damage. Formation dam- age is described as the reduction of per- meability to a producing formation by any means at all. The most common causes of formation damage, when using completion brines, typically is either the plugging via solids invasion or possible incompatibility within the formation or hydrocarbons. Clay problems can be created by water-based completion fluids that are lost to the formation during the well completion or a workover. Whether these fluids cause clays to swell or to become mobilized, formation damage will result. Not all formations are sensi- tive to this problem, but it is most com- mon in sandstones. The magnitude of clay problems is related to the: • Amount and type of water-based fluid and additives that enter the formation • Types and amounts of clays present • Condition and arrangement of the clays in their native state. Therefore, Baroid Drilling Fluids (now Halliburton Energy Services) sug- gests that completion fluid design should be based on a detailed study of reservoir characteristics at downhole conditions, and that fluid sensitivity studies should be conducted to ensure fluid/fluid and fluid/formation compatibility.7 Solids-free completion fluids have found widespread application because they are considered far less damaging to the productive zone than solids-laden fluids. Particulate matter can be filtered out of clear brine fluids down to a size of 2 microns to reduce formation dam- age caused by solids. The high salinity attainable with brine completion fluids helps assure that clay swelling and/or migration are also minimized. Since these solutions are also relatively non- reactive with most oilfield waters, their interaction with formation fluids is gen- erally considered to be minimal. For these reasons, clear brines have been particularly useful in frac/gravel pack- ing operations where the gravel carrying fluid may leak off into the formation dur- ing the transport of gravel into perfora- tion tunnels or open-hole type operations. Clear brine fluids versus seawater. The use of seawater as a completion fluid should be avoided whenever pos- sible. Seawater contains many contami- nants such as carbonate, bicarbonate, and sulfate which all can precipitate within a producing formation. This pre- cipitation reaction can produce insolu- ble solids in what is supposed to be solids-free brine especially if interacted with other types of completion brines or even some formation waters. While cal- cium carbonate generally precipitates at a higher pH and at higher temperatures, calcium sulfate precipitates under most conditions. Even if the calcium brine is prepared and filtered on the surface, a positive carbonate-scaling tendency may occur downhole. Seawater also contains many types of microorganisms that cause a variety of problems. Common bacterial prob- lems include slime formation or plug- ging solids. The worst of the bacteria are the sulfate-reducers, which generate H2S gas under downhole conditions and are usually the source for the formation of iron sulfide scale. Typically, all low- density brine systems (low total salt content) are susceptible to bacterial contamination. In order to minimize formation dam- age associated with seawater-based completion fluids: • Add a scale inhibitor • Treat with a biocide • Saturate the brine with the appropri- ate salt and filter fluid to 2 micron absolute • Dilute to working density (if possible, with fresh water), and then filter again. Crystallization temperature. The crystallization temperature of brines is defined as the temperature at which solid crystals will form in the solution. Another way to consider the crystalliza- tion temperature is the temperature below which a component of the brine exceeds its maximum solubility. Please Expandibility At 12,000 psi from 76°F to 345°F Coefficient Brine System Density lb/gal α Vol/vol/°F x 104 A lb/gal/100°F NaCI 9.49 2.54 0.24 CaCI2 11.45 2.39 0.27 NaBr 12.48 2.67 0.33 CaBr2 14.30 2.33 0.33 ZnBr2/CaBr2/CaCl2 16.01 2.27 0.36 ZnBr2/CaBr2 19.27 2.54 0.48 Compressibility At 198°F from 2,000 psi to 12,000 psi Coefficient Brine System Density lb/gal β Vol/vol/psi x 106 B lb/gal/1,000 psi NaCI 9.49 1.98 0.019 CaCI2 11.45 1.50 0.017 NaBr 12.48 1.67 0.021 CaBr2 14.30 1.53 0.022 ZnBr2/CaBr2/CaCl2 16.01 1.39 0.022 ZnBr2/CaBr2 19.27 1.64 0.031 A = Density correction factor for temperature B = Density correction factor for pressure Table 3.3. Expandability and compressibility of brine systems 45 Chapter Three Cased-Hole Sandface Completions note, however, that there are various methods for determining this property of brines: • First crystal to appear (FCTA) • True crystallization temperature (TCT) • Last crystal to dissolve (LCTD). Figure 3.1 is a plot of the above tem- perature points for an example 19.2 ppg ZnBr2/CaBr2 brine. When salt is added to fresh water, the freezing point of the water is depressed. In dilute solutions, the freez- ing point depression is directly propor- tional to the amount of salt; that is, 10 lb (4.5 kg) of salt will lower the freez- ing point of a barrel of water by twice that of 5 lb (2.25 kg). As the solution becomes more con- centrated, this simple relationship no longer holds true. At high salt concen- trations, the maximum solubility becomes a more complex function of water temperature. When completion brine is cooled below its crystallization temperature, the least soluble compo- nent in the solution will crystallize. This solid can be ice, salt or salt hydrates, depending on the solubility limits of that salt in water. Operations utilizing completion fluids must account for the crystallization tempera- ture by recognizing the coolest temper- ature to which the bulk of the brine will be exposed for any significant period of time. For example, a completion fluid standing static in the riser of a well drilled in 2,000 ft (609.6 m) of water may be exposed to very low tempera- tures near the mudline. This should be taken into account to avoid forming a plug in the riser due to crystallized fluid, even though the surface condi- tions may be sunny and warm. Since the cost of brine increases with decreasing crystallization tempera- ture, it is worthwhile to select the brine with the maximum crystallization tem- perature possible for the operating con- ditions. Except for single salt brines, adjusting the concentration and compo- sition of salts in solution can cause a variance of the crystallization tempera- ture of a brine. For example, 13.0 ppg calcium chloride-calcium bromide brine can be formulated to have crystal- lization temperatures from less than -35ºF (-37.3ºC) to 70ºF (21.1ºC) by adjusting the ratio of calcium bromide to calcium chloride. Surfactants. Surfactants are often added to completion fluids to minimize potential formation damage problems associated with water blocking, oil wet- ting and emulsions. Surfactants are sur- face active agents that reduce the sur- face tension and interfacial tension of fluids and control the wettability of the matrix to help prevent these problems. They must not be used indiscriminately, however, as they can cause more dam- age than they are supposed to prevent. Many different types of surfactants are used in the oil field for such pur- poses as to disperse solids, emulsify water in oil (invert emulsion mud), sep- arate oil and water, etc. The four gen- eral types of surfactants used in the oil field are (1) Cationic, (2) Anionic, (3) Nonionic, and (4) Amphoteric. There are many different chemicals and brand names for each of these types of surfac- tants, but we can generalize the proper- ties of the first two types, as shown in Table 3.4, and as follows: • Anionic surfactants tend to water-wet sand • Cationic surfactants tend to oil-wet sand • Anionic surfactants tend to oil-wet carbonates • Cationic surfactants tend to water-wet carbonates • Anionic surfactants tend to emulsify oil-in-water and break water-in-oil emulsions • Cationic surfactants tend to emulsify water-in-oil and break oil-in-water emulsions • Anionic surfactants tend to disperse clays in water • Cationic surfactants tend to floccu- late clays in water • Anionic and cationic surfactants are not compatible with each other. We cannot generalize on the other two types of surfactants, because they have a wide variety of properties. These surfactants have many useful proper- ties, but they should be tested if there is any question about what effect they will have. The wrong type of surfactant, or the wrong concentration of surfactant, may cause formation damage. Service companies often use surfac- tants which are selected by experience in a given formation or area. Normally these have been checked thoroughly and will aid in preventing formation damage; but when a new formation is being treated or completed, samples of the formation crude oil, brine, and core should be tested to be certain that these surfactants are compatible. The concentrations of surfactants in fluids are normally very small; usually only 1% or 2% is adequate, and often much less than this will do a job. It is dangerous to add too much surfactant as this may cause the opposite effect of what is desired. Always be certain that tests have been performed to indicate what type and concentration of surfac- tant are required for a particular effect. Do not change or modify this recom- mendation without good reason. Cationic Surfactants Anionic Surfactants Oil wets sands Water wet sands Water wets carbonates Oil wets carbonates Emulsifies water in oil Emulsifies oil in water Breaks oil-in-water emulsions Breaks oil-in-water emulsions Biocculate clays in water Floculates clays in water Disperses clays in oil Disperses clays in water Note: The function of surfactants also depends on pH, other chemicals present, formation properties, and crude oil properties. Table 3.4. Functional tendencies of surfactants 0 10 20 30 40 0 10 20 30 40 50 Te m pe ra tu re , ° F Time, min Cooling Heating LCTD 24°FTCT 16.5°F FCTA 15°F 19.2 ppg ZnBr2/CaBr2 brine Fig. 3.1. Crystallization curve for one example brine illustrates three possible “crystallization points.” (data from The Dow Chemical Company) 46 Modern Sandface Completion Practices Often two or more surfactants are required to have the desired total effect. For instance, some completion or workover fluids (acid treatment, heav- ier weight completion fluids, etc.) will contain both a corrosion inhibitor and surfactant. The corrosion inhibitors are commonly cationic in nature. If an anionic surface tension reducing sur- factant is added to these cationic corro- sion inhibitors, it will interfere with the corrosion inhibitor and neither additive will function properly. Normally, a nonionic surfactant must be selected when cationic corrosion inhibitors are required.8,9 Fluid Loss Control Fluid loss should be controlled or managed but not necessarily stopped. The amount of fluid loss that can be tol- erated during the completion is site spe- cific. Ideally, nothing would be done to stop fluid loss, but when expensive high density brine is being lost, completion fluid reserves are low or the loss rate makes operations unsafe, some type of loss control system must be employed. Also, the formation damage potential of continued fluid loss (even though the fluid is filtered) should be considered in light of the potential damage from employing a fluid loss control system. The normal methods for controlling fluid loss are: • Reduced hydrostatic pressure • Viscous polymer gels • Graded solid particles • Mechanical means. Reduced hydrostatic pressure. Fluid loss is a direct result of differential pres- sure into the formation due to the over- balanced condition created by the hydrostatic pressure of the completion fluid. A reduction in the rate of fluid loss can be accomplished by simply lowering the density of the completion fluid. Some operators have even allowed the hydrostatic pressure exerted by the completion fluid to equalize with the formation pressure by letting the com- pletion fluid seek its own level in the wellbore. Working with a low fluid level in the well would only be acceptable in wells that are not capable of flowing to surface. Regulatory authorities and/or operator imposed safety regulations may dictate the minimum hydrostatic over- balance allowed which could limit the effectiveness of this technique. The rate of fluid loss associated with a given overbalance pressure is con- trolled by several factors. To estimate the fluid loss rate for a given differen- tial pressure, Darcy’s Law for radial flow can be examined. Where: Q = loss rate (bph) k = permeability (md) ∆P = pressure differential (psi) µ = viscosity of completion fluid (cp) S = skin h = net sand thickness (ft) Bo = formation vol. factor of comp. fluid ln(re/rw) = Assume = 8 This equation indicates that the flow of fluids from the wellbore for a given differential pressure is controlled by the formation’s permeability, the interval thickness, the viscosity of the flowing fluid, the compressibility of the reser- voir fluids, as well as the degree of for- mation damage surrounding the well- bore. Figure 3.2 illustrates the level of fluid loss rates associated with a 1 cp fluid leaking off to formations of differ- ent permeabilities with overbalance pressures ranging from 0 psi to 500 psi. This plot makes it clear that while a reduction of overbalance pressure may successfully control fluid loss for mod- erate to low permeability formations, for high permeability formations exces- sive loss rates may still occur even for overbalance pressures down to 100 psi to 200 psi. Overbalance pressures much below this level will impose additional well control concerns on the operation. Viscous polymer gels. The viscosity of the fluid that is lost to the formation directly affects fluid loss rate. This rela- tionship between loss rate and viscosity has led to the common use of viscous polymer gels to control fluid loss. Vis- cous gels are very effective at control- ling losses provided the permeability of the formation and the overbalance are not too great. In general, it becomes impractical to control fluid loss if the wellbore pressure exceeds the reservoir pressure by more than approximately 500 psi. In addition, elevated tempera- tures are detrimental to the ability of gels to control fluid loss. The gels will degrade at high temperatures and often additional gel pills will be required throughout the course of the completion or workover to keep the loss rate at an acceptable level. The total volume of pills likely to be needed can be calcu- lated based upon Darcy’s Law calcula- tions. Combined calculations of viscos- ity increase as the velocity decreases with radial distance into the formation. Figure 3.3 illustrates the results of such a calculation. The least damaging means of con- trolling fluid losses may be to increase the viscosity of the fluid with a viscous polymer gel. There are many different types of polymers that are used for this purpose, but the polymer that is gener- Q kh P B r r So e w = × × × × − + ∆ 24 141 2 0 75. ln .µ 0 20 40 60 80 100 120 140 160 0 100 200 300 400 50050 150 250 350 450 Lo ss ra te , b ph Differential pressure, psi Interval length = 25 ft Fluid viscosity = 1 cp Skin = 5 500 md 250 md 100 md 50 md Fig. 3.2. Effect of differential pressure on fluid loss rate for 1 cp fluid 0 10 20 30 40 50 60 70 80 90 Pi ll vo lu m e, b bl Differential pressure, psi 1,000 md 500 md 250 md 100 md Formation permeability 7501,000 250500 80 lb/1,000 gal HEC 30 ft interval length Desired fluid loss rate = 4 bph Fig. 3.3. Volumes of HEC pills required to control fluid losses . 47 Chapter Three Cased-Hole Sandface Completions ally accepted as being least damaging to formations is HEC (Hydroxyethyl Cellulose). Chemical breakers, that cause the viscosity of the HEC gelled brine to break after it is downhole, are acids, oxidizing agents and enzymes. Hydro- chloric acid and ammonium hypochlo- rite have been commonly used, but enzymes are now becoming more com- mon. Enzymes used to have a tempera- ture limitation of only 130°F (54.5ºC), but now the temperature limitation has been increased to 200°F (93.4ºC) by specifically designed cellulose-poly- mer-specific enzymes. These recently developed enzymes offer significantly better chemical degradation of the poly- mer and are considered to be the best breakers within their temperature and pH limits. Limitations and potential problems with HEC are: • Contain microgels if not sheared and filtered • Cause formation damage if its viscos- ity is not broken • Contain fish eyes if not properly mixed • Maximum thermal stability of 210°F (99ºC) without special additives • Relatively low shear strength. Microgels in HEC gelled pills are beneficial because they serve as a fluid loss control agent; thus HEC gelled pills should never be sheared and fil- tered after they are prepared. Table 3.510 compares some properties of HEC, before and after shearing the gelled brine. This data appears to indi- cate that HEC will cause a lot of forma- tion damage if it is not sheared, but notice the “Initial” data was obtained by using HEC without a chemical breaker. Since HCl acid is a common chemical breaker, the data in the “After HCl” col- umn shows that there is no difference between the sheared and unsheared HEC solutions, as 5% and 3% perme- ability reduction data are within normal laboratory core test scatter. The API fluid loss data in Table 3.5 shows clearly why it is important that HEC should not be sheared when it is used for gelled pills to control fluid loss rate. More, recent studies have shown that fluids viscosified with dry HEC are not as thermally stable as fluids viscosi- fied with liquid products. HEC pre- hydrated in an activating polyol solvent system easily disperses into all brine systems and hydrates rapidly to produce a more effective viscosifier and ther- mally stable fluids than dry HEC.11 If dry HEC is used, care must always be taken while preparing HEC pills to prevent fish eyes. These are clumps or clusters of partially hydrated HEC poly- mer that will not dissolve, and can plug the formation and perforations. This problem can easily be prevented by fol- lowing proper guidelines for preparing the pills (i.e., adequate stirring while adding the HEC, low pH conditions until the polymer particles are totally dis- persed, pre-wetting of the polymer with isopropanol or kerosene, and not adding polymer after gelation has begun). Tests by Shell Development Com- pany describe many useful parameters of HEC for perforating and fluid loss con- trol. They recommend that an HEC con- centration of 4.2 ppb of brine be used as a minimum for fluid loss control pills. At this concentration, the viscosity will slowly break and reach approximately 10% of its initial viscosity after about 24 hours at 200°F (93.4ºC).12 Some opera- tors are using 5 ppb HEC in brines as a fluid loss control pill. This has an extremely high viscosity and will remain stable for approximately three days at 200°F (93.4ºC). However, a special additive can be used that will stabilize HEC to temperatures as high as 270°F (132.3ºC). Other water soluble poly- mers such as Xanthan Gums, HPG (hydroxypropyl guar) or CMHPG (car- boxymethyl hydroxypropyl guar) may be used for high temperature applications. Kelco XC (Xanthan Gum) type poly- mers are also used for gelling brines and some laboratory reports indicate that there is less potential formation damage with this gelling agent than with HEC. The most common problems with this type of polymer are that it is difficult to prepare a good solution in the field because of the high shear rate required and its sensitivity to heavy brines. If XC polymer is properly pre- pared (without fish eyes), it will have better gel strength and can suspend more solids at lower shear rates than an HEC polymer solution. The high viscosity (23,500 cp) at a low shear rate of 0.1 sec-1, Table 3.6, indicates the relatively high shear strength of XC gelled water. Although HEC gelled water has a higher viscosity (100 cp) at a high shear rate (511 sec-1) than XC gel, the viscosity of HEC is much less (5,900 cp) at a low shear rate (0.1 sec-1), which allows sand particles to fall much faster in HEC gel at static conditions. These data favor the use of XC gelled pills to control fluid loss rate, but also indicate a much greater potential for formation damage by any XC gel that does enter the formation. The viscosities of Shellflo-S, a biopoly- mer viscosifier, fall between the Xanvis and HEC.13 All of the above products can be used to viscosify solids-free completions. They are also compatible with a wide range of completion fluids and Xanvis and HEC may be broken with a wide range of breakers. Viscosity breaking of Shellflo-S Biopolymer can be achieved without a conventional breaker by using API Fluid Loss Average Permeability (400 psi/36 min) Reduction cc Initial (%) After HCI (%) Unfiltered HEC 80 71 5 Sheared/Filtered HEC 190 20 3 Test Conditions: 24 md Berea cores, 120°F, 40 pore volumes 7.5% HCI, 80 lb/1,000 gal HEC, no chemical breakers Table 3.5. HEC performance: sheared vs. unsheared Viscosity, cp Product Name 511 sec-1 170 sec-1 1 sec-1 0.1 sec-1 Xanvis 20 42 4,650 23,500 Shellflo-S Biopolymer 16 35 2,600 10,200 HEC 100 200 3,500 5,900 Table 3.6. Comparision of polymer viscosities 48 Modern Sandface Completion Practices its unique viscosity-temperature profile, which is brine dependent.14 If required to be stored for more than a few days after hydrating, biocide must be added to any viscous polymer gels because bacteria present in the brine, tanks or lines will cause the polymer to break prematurely. Each product has been used for fluid loss control, but none of them are effective in extremely high permeability formations. Generally, HEC gelled pills are preferred over XC gelled pills where wellbore conditions do not exceed the HEC gel limitations and when the HEC gelled pills are pre- pared properly and contain the proper viscosity breakers.15 It is also important to note here that HEC is being challenged as the “poly- mer of choice.” OSCA (now BJ Ser- vices) reported on a New Polymer (NP) that is slightly less formation damaging than HEC when tested as a solids-free pill. In brines where HEC shows pre- cipitation, NP will not precipitate and no NP precipitation was seen in the brines tested. HEC generally shows greater viscosity at low temperatures than NP, but NP shows greater viscosity at high temperatures.16 Debris Removal and Mysteries The productivity of a well can be dam- aged by drilling and cementing long before a completion fluid is introduced into the wellbore. These operations can force particles as incidental bridging agents into the formation. Therefore, to help prevent further damage, it is impor- tant to make an extra effort to take steps to remove as much debris as possible when switching from the drilling mud to completion fluid. In addition, comple- tion fluid related mysteries should be avoided, if possible. For example: • The completion ran perfectly, but the packers will not set. • The completion ran perfectly, but the mechanical or hydraulic valves will not operate. • The brine cleaned the casing to a “spotless” condition, but the comple- tion got stuck running in. • The casing was cleaned perfectly and perforating and the completion went without a hitch, but the well does not produce at all or below par. The cause of the above problems can almost always be tracked back to poor cased cleaning. Consider that 9,000 ft (2,743.2 m) of 7 in. chrome casing can contain up to 330.75 lb (150 kg) and up to 300 ft (91.4 m) of pipe extruded pipe dope inside of it. Further, 9,000 ft (2,743.2 m) of 9-5/8 in. casing contain- ing brine with only 500 ppm solids extrapolates into 150 ft (45.7 m) of solids fill. Pipe dope, which can be easily over- looked as a damaging material, can be a difficult problem to remedy. A recent study done by Saudi Aramco, whereby they examined sam- ples of pipe dope used during placing well casing and the drill pipe, docu- ments this. Table 3.717 summarizes the results obtained with the two types of pipe dope. The pipe dope that was used for the casing contained nearly 26 wt% of organic material, whereas that used in drill pipe had 39 wt% organic materi- als. This data verifies that pipe dope is indeed, wherever found in a well, not an easy material to remove. Note the extruded pipe dope shown in Figure 3.4. If not properly removed, this material can negatively effect the completion. Pipe dope removal from the wellbore is critical because it: • Weighs two times more than water • Consists of metal solids as well as heavy oils • Accumulates on tubing and casing, and unless removed settles in the wellbore • Clogs perforations, pore throats • Agglomerates other solids remaining to form large masses, which can cause tool and packer sticking or failure. Super Pickle products (solvent and surfactant blends from Well Flow Inter- national) are excellent oil, ester and pipe dope removers. All Super Pickle products are designed for minimum 95% to 100% combined pipe dope and oil-based mud (OBM) removal in 180 seconds at laminar flow rates. Field exposures vary from 3 to 12 minutes at the same rates. All possible debris needs to be removed from the well in the course of displacement procedures. Proper proce- dures include the following steps: • Displace drilling fluid • Pump base fluid spacer, followed by a: • Surfactant spacer (Rinse Aid, a non-ionic water soluble surfactant system, or equivalent) • Solvent wash (Super Pickle or equivalent) • Water wetting wash (Rinse Aid or equivalent). An efficient wellbore cleanup can (1) eliminate risk of completion tools, packers and strings from sticking or becoming inoperable, (2) eliminate par- ticle invasion to the formation, (3) enhance productive capability of the well, and (4) extend the working life of the completion. Displacement Procedures The objectives of a drilling mud to completion fluid displacement are to remove the mud and mud filter cake, maintain control of the wellbore and minimize overall rig operation time. To effectively remove the drilling mud, it must be conditioned prior to its displacement. The rheology should be adjusted to minimum plastic viscosity Fig. 3.4. Internal photo of extruded pipe dope Variable Tubing & Casing Drill Pipe Color Brown Gray Organic material a 26.4 wt%b 39.4 wt%b Inorganic material 73.6 wt% 60.6 wt% Average densityc 4.44 g/cm3 4.23 g/cm3 Acid solubilityd 25 wt% 75 wt% a. Solubility in xylene, b. Average of three measurements, c. Density of inorganic material, d. Solubility of the inorganic portion in 20 wt% HCI Table 3.7. Characteristics of pipe dope 49 Chapter Three Cased-Hole Sandface Completions (PV) and yield point (YP) values to ensure that circulation can be estab- lished. To remove solids from the cas- ing walls, the work string should be run into the well with two casing scrapers for each casing size. It is commonly recommended to run in with a bottom scraper to the plug back depth or liner top and an upper scraper spaced mid- way in the casing section. Circulation should be established to condition the mud, to disperse mud cakes from tanks and drill pipe, and to remove solids through all available solids control equipment. Rotation and reciprocation of the drill pipe is also recommended if possible. Once completed, a short trip with the drill pipe should be made. In addition to conditioning the mud, the surface pits containing drilling mud should be pumped empty, and the tanks that will contain completion fluid should be pressure washed. All surface equipment should be cleaned with a volume of surfactant-treated drill-water (or seawater), and then flushed again. Tanks and surface equipment should be allowed to drain and dry prior to receiv- ing clean completion fluid. To accomplish efficient mud dis- placement, the following wellbore cleanup design steps are recommended: • Verify cleanup procedures with labo- ratory testing. • Design surfactant spacer and wash train based on cased well design and mud type/characteristics. • Program tool usage based on casing design. • Detail surface cleaning procedures to avoid contamination. • Implement clean-up procedures. Chevron applied a successful dis- placement procedure offshore Califor- nia. They reported the suspended solids content of circulated well returns during a typical changeover, Figure 3.5.18 After running a scraper and flushing with seawater, the solids load normally stabilizes at a level below 100 mg/l indicating that most of the easily removable solids in the wellbore have been removed. When the surfactant sweep is circulated, solids content often rises over 1,000 mg/l as the surfactant frees up particulate attached to the cas- ing by reducing interfacial tension. Another flush of seawater is circulated to pick up any solids loosened by the surfactant that may have strung out through the well. Finally, when the completion fluid is circulated through the well, it picks up only a minor amount of additional solids. Pump Rates and Pressure Calculations Hydrostatic differences between the spacer pills and drilling mud can have a major impact during direct displace- ment, where pump rates and pressure calculations are critical. Knowledge of casing and work string size is essential to these calculations, and for a determi- nation of friction loss estimates calcu- lated for both the forward and reverse circulating directions. The pumping direction chosen is often based on lower pump pressure and hydraulic horse- power requirements. Generally, however, the forward cir- culating direction is preferred in order to facilitate rotation and reciprocation of the work string, which helps reduce residual mud pockets in the annulus. A good guideline is to pump at rates based on a minimum flow rate of 3 ft/sec (91.44 cm/sec) in the largest annulus. This velocity is sufficient to put non-viscous pills in turbulent flow, which ensures good contact of chemical cleaners with the surface of pipe, casing and mud cake, and provides efficient mud removal and pipe-wall cleaning. Displacements are categorized as direct, indirect, balanced or staged. All can be pumped in either the forward or the reverse pumping direction. The for- ward, conventional displacement pumps fluid down the work string, taking returns up the annulus. A reverse circu- lating displacement pumps fluid down the annulus, taking returns up the work string. There are advantages and limita- tions to both. A standard displacement replaces the drilling mud that is heavy enough to control the well with a completion fluid that also controls the well pressures. However, prior to placing a full-hole vol- ume of completion fluid in the wellbore, a series of low-density spacers is circu- lated. This situation requires well control considerations when open or squeezed perforations are exposed, liner tops have not been negatively tested, or other pres- sure sensitive situations are evident. Bal- anced displacements are the exceptions. Conventional circulation allows easy rotation and reciprocation of the work string when the annular blowout pre- venter and pipe rams remain open. Pipe movement is especially important in deviated wellbores. Forward circulation usually permits higher pump rates and less frictional pressure loss over the course of the displacement, where much of the pump pressure is contained within the work string rather than trans- mitted to the annulus. Conventional dis- placements also allow greater control over differential pressure across liner tops, squeezed perforations and other pressure sensitive areas. When well control does require back pressure, rotation and reciprocation of the work string is less likely. Reverse circulation limits contami- nation of the interface between high- density mud and lower-density spacer pills or completion fluid. It is often used as the first stage of an indirect dis- placement in which the mud is reversed out of the hole with water and then the annulus and work string cleanup is pumped conventionally. Because reverse circulation is carried out with the annular pressure control equipment closed, the possibility of pipe move- ment is limited or eliminated. While pressure calculations are less signifi- cant when indirect displacements are possible, high flow rates should still be maintained to facilitate mud removal and wellbore cleanup. Additionally, brine cleaning can be enhanced with the use of products such as Dirt Magnet (from Well Flow Inter- national). Dirt Magnet uses a system 0 100 1,000 2,000 3,000 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 To ta l s us pe nd ed s ol id s co nt en t, m g/ l Time, hrs Sea water Sea water Surfactant 8.7 lb/ gal KCI Fig. 3.5. Suspended solids content of circulated returns 50 Modern Sandface Completion Practices of surfactants specially blended with a high boiling point alcohol carrier to remove mud, oil, sand, barite and other solids effectively from casing and pro- duction tubing. It is somewhat unique and effectively flocculates micro-emul- sified oil and fine solids, minimizes fluid filtration requirements and helps ensure a solids-free well completion. Fluid Filtration Contamination reduces production and shortens the productive life of the well. Contamination can occur during perfo- rating, fracturing, acidizing, workover or gravel packing a well. Any time a fluid is put into the wellbore with solid particle content, no matter how slight, the chance of damaging the well is pre- sent. Particle-induced impairment of this type is shown from lab test results performed on 450 md Cypress sand- stone cores to be severe and only partly removable with acid when caused by bay water solids (Fig. 3.6).19 In the field, fluids having 10 to 15 ppm solids appear “clean” in pits. How- ever, in Figure 3.5 note that 10 to 15 ppm solids caused a permeability reduction of 90%. Then, only 10% to 30% of the original permeability was restored by backflowing and acid restored just 50% of original permeabil- ity. The purpose of using clear brine as a completion fluid is to provide a solids-free environment that protects the producing formation from particle invasion damage. The single most important aspect of completion fluid maintenance is filtration. Filtration can be defined as the removal of solid particles from a fluid. This process is critical to keep all solids from the intended productive interval and to allow a well to produce at its full potential for the maximum period of time. Although filtering can be expen- sive and time consuming, it is quickly offset by the net increase in production. Filtration has evolved from the old surface sand bed systems with low vol- umes capabilities to highly sophisticated systems. Regardless of which system is used, a case for filtering fluid can be made for every well that has concerns for any type of particulate impairment. The following example illustrates the seriousness of formation damage: In 50 bbl of fluid containing one-half percent solids (1/2% = 0.005 = 5,000 ppm), there are approximately 2,426 cu in. of solids. Since the volume of a per- foration tunnel 1/2 in. in diameter and 10 in. long is 1.96 cu in., the volume of solids in those 50 bbl of fluid could totally plug 1,235 perforations. If a gravel pack is to be done and contaminated fluid is used as a carrying fluid, the small particles of solids mix- ing with the sand will take up the pore space between the sand grains reducing permeability. The permeability of this mixture is actually less than that of the gravel pack with only sand particles. A contaminant in completion fluid can come in many sizes and forms. Cut- tings from drilling operations, drilling mud, rust, scale, pipe dope, paraffin, undissolved polymer and any other material on the casing or pipe string contribute to solids in the fluid. At times it is virtually impossible, because of particle size, to remove all of the solids from the fluid, but by filtering, this suc- cess factor can be increased 100%. Filtration Guidelines How clean does the fluid need to be? What size particle needs to be removed? During the past 25 years, many studies have been done to assess the effects of particle invasion damage and the size cut and quality level of filtration neces- sary to prevent formation damage. The pore throat size of the produc- tive formation must first be determined or estimated. If core material is avail- able, the pore throat size distribution can be measured by mercury injection and capillary pressure relationships, or by directly measuring pore throat sizes 0 10 50 100 500 100 200 300 400 500 0 0.02 0.04 0.06 0.08 0.1 Location Treatment A 998-112 Sand pack filter B 1008-48 Ballast tank, 2µ cotton filter C Platform AA (Blk 27), untreated D 1008-77 5µ cotton filter E 998-112 5µ cotton filter F 1008-77 Untreated G Fed lease Produced water, untreated H 998-112 Untreated I 1008-48 Collapsed 2µ cotton filter Pe rm ea bi lit y, m d Volume injected, pore volumes Volume injected, gallons/perforation A (2 ppm) B (2.5 ppm) C (14 ppm) D (26 ppm) E (50 ppm) F (48 ppm) G (94 ppm) H (110 ppm) I (485 ppm) Fig. 3.6. Apparent permeability reduction due to injection of various treated and untreated bay waters 51 Chapter Three Cased-Hole Sandface Completions by a scanning electron microscope. Should sieve analyses of the formation be available, an estimation of the aver- age pore size of a formation sand can be determined by the Coberly equation: Where: d = average pore size D50 = diameter of median formation grain However, when core material is not available, a rough approximation of the average pore size of a formation sand can be determined by Kozeny’s method: Where: d = average pore size, microns D50 = diameter of median formation grain microns φ =porosity, fraction k =permeability, md Or, from an equation developed by Blick and Civan: Where: d = mean pore diameter, micron φ = porosity, percent k =permeability, md The relationship between pore size and particle size of the solids in a fluid are given by the following “rules of thumb.” If bridging occurs. If shallow invasion occurs (worst case). If deep invasion occurs (no problem). Where: Dp = diameter of particle d = average pore diameter In terms of minimum filtration crite- ria, the objective is for all particles to be small enough to freely flow through the formation without plugging the crit- ical near wellbore area. Thus, filtering should be done to achieve a maximum particle size in the completion fluid, which is less than d/7. For example, consider a formation with k = 2,000 md and φ= 22%, and use Kozeny’s method: Therefore, the minimum filtration requirement is 2 micron. In summary, the diameter of the grains of formation sand is 6.5 times the size of the pore throat (Coberly equation), assuming the sand is per- fectly round. Particles greater than 1/3 the diameter of the pore throat bridge instantly on the throat and do not pene- trate the formation. These particles pre- sent some problems, which usually can be remedied by removing the particles from the perforation tunnels with a per- foration wash tool. Particles less than 1/7 the pore diameter pass through the throat and through the formation with- out bridging or plugging. However, par- ticles between 1/3 and 1/7 the pore throat diameter invade the formation and bridge on the pore throat deeper in the formation. These particles are the ones that cause the serious problems. With the pore throats plugged causing significantly reduced permeability, flu- ids cannot be injected into the forma- tion to clean the pore throats. The concept described above is illus- trated in Table 3.8. Put another way, any particle that is 33% of the pore diame- ter will instantly bridge and block the pore. Any particle that is 14% to about 30% of the pore throat diameter will penetrate deeper into the formation and plug or bridge matrix permeability. Fil- tration levels are based on removing particles to the 14% throat diameter level to prevent particulate damage. Even 3 Darcy formations, often thought not to need filtration, are subject to particle damage from material too small to see. Figure 3.7, illustrates the particle size range that is damaging to formation matrices. Particles in the highlighted range can have a very large particle count without occupying large part per million levels. They may appear insignif- icant, but should be considered a poten- tial problem and filtered accordingly. Relationship between Completion and Filtration In the last stages of the well completion process, wellbores are exposed to fluids contaminated by a high concentration of particles over a wide range of sizes. To maintain production, the recom- mended filtering process should employ a number of steps to remove contami- nants, starting with the largest and working down to the smallest. This includes the use of (in order) a shale shaker, tank, desilter, centrifugal sepa- rator, cartridge filters, and Diatoma- ceous Earth (DE) filtration. However, there are several limitations. Consider Dp = = 12 2 7 1 7 . . micron d = =0 128 2 000 0 22 12 2. , . . micron d k= 32 φ d D k= −( ) = φ φ φ 50 3 1 0 128. d D= 50 6 5. 0.01 0.1 1.0 10 100 1,000 10,000 0.01 0.1 1.0 10 100 1,000 Solids concentration, ppm (by wt.) Virus Bacteria Fly ash Beach sand Particle size (micrometers) Fig. 3.7. Scope of filtration Particle size Affect >1/3 pore throat Bridge instantly on the throat and do not penetrate the formation. diameter Solution: Filter fluids to remove particles +/>1/3 the pore diameter. Remove particulates from the perforated tunnels by applying a perforation wash tool. 1/3 to 1/7 pore Invade the formation and bridge on the pore throat deeper in the throat diameter formation. Solution: Filter fluids to remove particles less than 14% of the pore diameter. the actual process of well completion and how it interacts with filtration in the following offshore well scenario. 1. Displacement of drilling mud with seawater. All drilling mud in the bore- hole is displaced with unfiltered sea or salt water while the work string is slowly rotated to ensure complete dis- placement of the mud. Unfiltered sea or salt water is used in an open-loop sys- tem. Both straight circulation and reverse circulation have been used dur- ing this stage of the process; this deci- sion is usually based on on-site judg- ment. The advantage of the reverse circulation technique is that it offers low viscosity, high turbulence flow through a smaller pipe diameter to carry particles to the surface. During this step, the bit and casing scraper runs are made through the wellbore to remove mud cake and rust. 2. Assurance of a clean wellbore. When water returns are of the same quality as the water pumped into the well, unfiltered sea or salt water is dis- placed with filtered sea or salt water, again while rotating the work string to assure complete displacement. Filtering down to 2 microns is desirable to remove plankton and bacteria, prevent- ing growth of microorganisms in the bore after the completion. An advantage of first flushing the wellbore with unfiltered water is that it reduces the filtering time by removing a great percentage of contaminant during this initial phase. At this point, the clean fluids are introduced into the wellbore. The most desirable method of operation is to switch to clean tanks, lines, troughs, pumps and traps, that are uncontami- nated by drilling mud. If this is not possible, the entire existing system should be cleaned of mud. A clean pro- duction or work string should be used for completions. When inserting a new string, dope should be applied to the pin end only in small amounts, rather than to the box end in large amounts, as excess dope can fall in the hole and plug formations. 3. Displacement of completion fluid. When recirculated sea or salt water is clean, indicating a clean wellbore, a completion fluid is pumped into the system. If possible, it is desirable to run a clean spacer system as an interface between water and comple- tion fluid. Maintenance of clean completion fluids starts at the dock by assuring that all equipment used to handle comple- tion fluids is clean. Field mixing of brines is not recommended. Delivery should be made in clean tanks. Final filtration when running them downhole is recommended. 4. Perforations. After perforating and washing perforations, if applicable, per- foration debris and formation sand must be filtered out of the completion fluid to prevent replugging of the open perfo- rations and formation. 5. Gravel packing. When perforating is complete and the completion fluid has been filtered to the desired level, the drill pipe is pulled, and the gravel pack- ing operation commences. Taking these precautions can generally help result in a stable pack with the desired produc- tivity, although there is no assurance that this will be the case. Experience has shown that success- ful completions depend primarily on following a set procedure without tak- ing shortcuts, and on detailed attention to good housekeeping practices. A key element in the entire process is using clean fluids, which is made possible in large part through filtration techniques. Filter Level Quality How effective a filter system is at removing particles became a concern in the early 1980s. Nominal cartridge fil- ters were the equipment of choice for many years. They were relatively inex- pensive and did not require much space. The standard used to measure the effi- ciency of the filter was solids removal by weight percent. The most common method of testing the size cut of a filter was the “Bubble Point” method. Laboratory testing with particle counters and particle size distribution graphs revealed that as much as 70% of the total particle count in a fluid was passing through the filter and that parti- cles much larger than the size rating of the filter were passing the media. Fig- ure 3.7 illustrates how fine particles take up small weight percentage, ppm. Nominal filters were found to have relatively poor construction integrity. The media was subject to deformation and shifting at the upper range of delta pressure. A more reliable media struc- ture and a more accurate efficiency standard were sought. The result was the absolute rated filter. A comparison of absolute rated and nominally rated filters is shown in Table 3.9.20 The method of rating a filter’s effi- ciency that was adopted was the Beta Ratio (βR). The beta ratio method com- pares the particle size distribution and particle counts before and after a filter Particle density in unfiltered fluids = 295 mg/l I. 1.0 and 2.0 micron nominal filters averaged 53% reduction of solids * Particle size % of total solids % of total solids (micron) in unfiltered fluids in filtered fluids 0.5 - 3 38 34 3 - 8 29 32 8 + 33 34 II. 2.5 micron absolute filters averaged 72% reduction of solids ** Particle size % of total solids % of total solids (micron) in unfiltered fluids in filtered fluids 1 - 5 64 100 5 - 15 28 0 15 - 25 6 0 25 - 50 1 0 50 + 1 0 * Analytical method: millipore testing ** Analytical method: particle counting and gravimetric analysis Table 3.9. Comparison of nominally and absolute-rated cartridge filters 53 Chapter Three Cased-Hole Sandface Completions medium and expresses the efficiency as a β coefficient. The following formula illustrates how the β coefficient is determined and Table 3.10 shows corre- sponding removal efficiencies for vari- ous β coefficients. A Beta coefficient of 5,000 (99.98%) was established as the preferred level of filter efficiency. Cartridge filters capable of this efficiency are referred to as Absolute (ABS) filters. They are usually composed of a shallow or multi-layered filter media. The media has strong bond- ing mechanisms that prevent the media from shifting or deforming, thus assur- ing high integrity throughout the delta range of the cartridge. Most ABS filters are configured as pleated cylinders to provide maximum surface area and therefore maximum flow rate per unit. The Beta ratio of a filter at the desired level of size cut is the basis for quality assurance in the field. Since actual particle size and count measure- ment is very difficult to impossible in the field, the Beta-rated cartridge is the determining factor. The Beta method used to test and verify a cartridge filter’s removal effi- ciency is referred to as the modified OSU (Oklahoma State University) F-2 standard. This testing procedure is described as follows: Particle removal efficiency testing: Procedure – OSU F-2 (Modified single – pass water) Test Particles – AC Test Dust Fluid – Water maintained at 1 cp kinematic viscosity Flow Rate – 1 gpm per 10 in. cartridge or as specified by user Sample Sequence – A minimum of five sample sets is taken upstream and downstream of the cartridge. The first sample set is taken at the start of the test, after the system has stabilized. The remaining sample sets are taken at 10%, 20%, 40% and 80% increase in the net pressure drop. Terminal pres- sure drop is 35 psi. The two methods used to verify fluid quality are Particle Size Distribution (PSD) and Total Suspended Solids (TSS). These tests require a laser parti- cle counter and a very sensitive lab scale. Both pieces of equipment are not accurate under field conditions and the time required to perform the testing pre- cludes a rapid test result. Samples of fil- tered fluid are usually collected and sub- mitted for testing on a 48-hr time scale. Completion Fluid Filter Types There are two basic types of completion fluid filters: cartridge filters and diatomaceous earth (DE) filters. Modern well completion technology has shown that filtration with DE systems followed by final polishing filtration with dispos- able cartridge filters is the recommended method of assuring the clean non-dam- aging character of completion fluids. Cartridge filters. There are various types of cartridge filters. The commonly used absolute Beta-rated fiber cartridges are relatively inexpensive, but they are not designed for backwashing and are normally discarded when they become plugged. In multi-cartridge filter hous- ings, adequate cleaning of all cartridges by backwashing the entire unit is nor- mally impossible because of flow chan- neling through a few cartridges. How- ever, if the cartridges are removed from the filter and washed individually, cleaning may be effective. ABS filter cartridges are several times more expensive than nominally rated car- tridges. Beta 5,000 cartridges are cost effective when used as a downstream polishing filter after a DE filter unit. Removal efficiency inlet concentration outlet concentration inlet concentration Rβ( ) = − ×100 Gauge connections Drain (dirty) Vent Drain (clean) Inlet Filter cartridge Outlet Fig. 3.9. Cartridge filter housing Fig. 3.10. DiatomsFig. 3.8. Pleated absolute cartridge 54 Modern Sandface Completion Practices Cartridge filtration alone is cost effective for low volume or low con- taminant level fluids. Filtering make-up water for chemicals and or filtering rel- atively clean seawater are examples. The demands of circulation and mainte- nance of a completion fluid system are better addressed by a staged filter sys- tem comprised of a DE unit followed by ABS cartridge filters. A common use for cartridge filters is polymer solution filtration. Beta 5,000 10-micron filters are used to remove contaminants from polymer pills. Com- bined with hydraulic shear devices and due to the low volumes and relatively low percentage of contaminants, these cartridges provide a cost effective means of formation protection with polymer pills. Figure 3.8 is a cut-away of a typical ABS filter cartridge, which is con- tained in multi-cartridge filter housing, Figure 3.9. Diatomaceous earth filters. DE is the fossilized skeletal remains of marine diatoms. There are two main types, salt and fresh water. These structures pro- vide a highly porous non-compressible cake ideal for the removal of solid con- taminants. Figure 3.10 are micropho- tographs of typical diatoms. DE is produced in a variety of size and treatment grades and is used in a broad range of industrial applications. Although a DE filter consistently produces a very high fluid quality (less than 50 ppm), it is not absolute Beta rated because the filter cake is suscepti- ble to shifting. Some DE particles and solids across a small range (relative to the DE type) can pass through the DE filter. The nominal median pore size in microns of DE provided by Celite Cor- poration are: • 10 micron Celite 503 • 5 micron Celite 512 • 2 micron Celite 505. For oil field applications, the most commonly used DE material is Celite 505 and in some applications 512. The 503 grade is used in high concentration contaminant situations when staging- down to a required level is the practical method. There are two main types of DE filters used in brine filtration: • Recessed Plate Press • Vertical Leaf Pressure Filter. Recessed Plate Press (Fig. 3.11) – The plate manifold is made up of a number of plates with recessed cham- bers on each side of the plate. At the head and tail of the manifold are special plates with only one recessed side. The plate recessions are covered with and appropriate filter septum material that promotes the formation of a DE cake but permits maximum flow through the septum. The plates with their cloths are closed and hydraulic pressure is applied to seal the individual plates. A pre-coat of clean DE is established by pumping slurry of clean brine and DE into the central port of the mani- fold. The slurry spreads radially through all the plate chambers. As the slurry passes through the filter septum, the DE is deposited on the septum as a Fig. 3.11. Combination filter unit including recessed plate press on bottom and cartridge filter housing on top Beta (β) Removal efficiency (%) 1 0 2 5O 4 75 5 80 10 90 20 95 50 98 75 98.67 100 99 1,000 99.9 5,000 99.98 10,000 99.99 ∞ 100 Table 3.10. Particle removal efficiency based on ß coefficients 55 Chapter Three Cased-Hole Sandface Completions uniform and clean coating. The fluid that passes through the septum travels via channels to the inside corners of each plate recess. Exit ports in the plate allow the fluid to enter the manifold discharge ports and then exit the press. Once a clear and air-free circulation is seen in the slurry skid pre-coat tank, the press is ready to begin filtering dirty fluid. Figure 3.12 is a diagram of a recessed plate press. The slurry skid has an additional tank that is used to prepare a body feed slurry of DE and fluid. This slurry is a concentrated suspension of DE. The slurry skid manifold is configured to allow dirty fluid to be brought from the rig return pit and body feed slurry is either injected or pulled into the dirty fluid stream. The mixture of DE and dirty fluid enters the press through the center port and makes a radial distribution through the plate stack. As the DE and dirty fluid pass through the pre-coat a contin- uous layer of DE and trapped solids is deposited building a porous cake. The clean fluid exits the press and is routed to the downstream guard filter with absolute cartridge filters and then to the rig clean pit. Filtration continues until the press reaches its maximum cake capacity or maximum pressure drop. Ideally maxi- mum cake and maximum pressure hap- pen simultaneously. The slurry skid is configured for re- circulation and pumping stops. The fluid in the press is evacuated by air pressure and the press is opened. The spent cake is removed from the plate recesses and the press is closed and sealed again ready for the next filter cycle. The length of a press cycle is gov- erned by the concentration of contami- nants and their type. Ridged particles are easily incorporated into the DE cake and do not create excessive pressure drop across the cake. Malleable solids such as clays and polymers deform readily and block a much higher portion of the DE cake permeability and cause more rapid delta pressure build across the cake. Sudden influxes of malleable particles can cause the press to “blind.” In other words, the press will reach its maximum pressure drop before reach- ing maximum capacity. DE presses can usually deal with solids concentrations of up to 1.0% or 1.5% and maintain a practical cycle length. Solids concentrations above this threshold can be impractical to process with a filter press. Some other method of solids concentration reduction must be used first. Vertical Leaf Pressure Filter (VLF) – These DE units approach pressure con- tainment in a different manner. Instead of plates, clothes and pressure sealing, the VLF encloses the filter areas in a pressure vessel (Fig. 3.13). A pressure leaf is composed of a ridged hollow frame enclosed in a filter septum of cloth or metal mesh. Fluid filtrate exits to the interior of the leaf then out a discharge port at the bottom of the leaf to the system manifold. The DE filter cycle is performed the same as with a press unit. The differ- ence begins at the cleaning point. Man- ual systems evacuate the pressure hous- ing with air. The vessel lid is opened and the vertical leaves are washed with water. The water and spent cake exit via a large diameter cleanout port. VLF units have some unique advan- tages as a result of design. The flow rate possible with a VLF is higher per unit area than a press unit. VLF units are usually set with 100 to 1,000 sq ft of leaf surface and achieve flow rates with light fluids in the 8 to 15 bpm range. The equipment foot print is smaller Fig. 3.13. Combination filter unit including VLF at right and cartridge filter housing at left Inlet Inlet Expansion plate assembly Hydraulic control unitFollower Top view Side view Left end view Right side end view Outlet port Outlet port Follower liner plate Intermediate plates Head liner plate Head Air blowdown manifold Fig. 3.12. Recessed plate press diagram 56 Modern Sandface Completion Practices than a press system and cycle cleaning is usually faster than a press unit. The disadvantages of the VLF are that it cannot deal with rapid changes in solids concentration or higher malleable particle loads. The VLF units also have a lower range of practical solids load- ing, on the order of less than a half per- cent by volume. Situations that have blinding particle loads and inconsistent solids loads are not practical use points for a VLF filter. Figure 3.14 illustrates fluid flow paths inside a VLF unit. Filter system selection is a critical component of the completion design process. Table 3.11 is a filter system selection guide. Filtration Quality Control 21 Since clean fluid is essential for maxi- mizing well potential, it is important to verify system efficiency during the filtra- tion process. Complete on-site analysis would include the following operations: • Fluid sampling • Centrifugal shakeouts • Turbidity testing • Gravimetric analysis • Determination of particle size distribution. Fluid sampling. Representative fluid samples should be taken from the fol- lowing locations: 1. Upstream of the DE unit – This sample gives an indication of the solids content of the dirty fluid and is useful in determining the proper DE add-mix ratio. 2. Downstream of the DE unit – This sample indicates the efficiency of the DE unit and will reveal any DE screen bypass problems. An efficiently oper- ated unit should reduce the solids con- tent to 20 to 30 mg/l. 3. Downstream of the polishing fil- ters – This sample indicates the overall efficiency of the system. A comparison of the DE downstream sample with this sample can reveal element bypass problems. 4. At the shale shakers – These sam- ples are used to monitor wellbore cleanup progress. Since filtration efficiency can vary with pressure changes, flow rate fluctu- ations and cycle lengths, fluid samples should be taken as follows: • At beginning of cycle • At end of cycle • Once per hour during cycle. It is important to ensure that each sample taken is representative of the overall fluid mix. Sample locations should ensure that fluid is drawn from a flowing stream, not from dead fluid traps. The following practices will assist in obtaining good samples: 1. Sample ports should be flushed for 30 seconds prior to drawing sample. 2. Flush sample bottles several times with fluid before catching the final sample. 3. If samples are not analyzed imme- diately, treat with a bactericide to pre- vent organic growth. 4. Label each sample with well information, sample port location, date, time, fluid type and weight. Centrifugal shakeouts. A centrifugal shakeout of suspended solids is a useful technique for obtaining a rough esti- mate of the percentage solids in a given fluid. Using this information, a proper DE add-mix ratio can be chosen to maximize flow rate and filtration cycle. The use of shakeouts to determine final wellbore cleanliness is not recom- mended because the most accurate devices will only read as low as 0.05% solids or 500 ppm. Turbidity testing. Turbidity is a mea- surement of fluid clarity and is recorded in Nephelometric Turbidity Units (NTU). A lower NTU reading corresponds to better clarity. Turbidity is one of the opti- System Type Best Usage Cartridge units Low volume or low contaminant levels. Use when space limitations are severe. Filter press Applicable in most filter situations. May experience size limitations in some circumstances. VLF filter Applicable with lighter fluids or fluids with low or consistent solids loads. Use when size limitations make press units less attractive. Table 3.11. Filter system selection guide Inlet Outlet Fig. 3.14. VLF interior diagram 57 Chapter Three Cased-Hole Sandface Completions cal properties of a liquid and is related to the presence, nature and concentration of discrete aggregations of material differ- ent from the pure liquid center. Since it is defined as an appearance parameter, it can be measured by optical techniques. Basic measuring systems of different brand turbidimeters are similar. A linear photo detector mounted in the detector section of the instrument senses a nar- row optical beam that is projected through fluid. This detector, mounted 90 degrees to the lamp source, mea- sures the intensity of the light scattered by the particles in the fluid. Electronic components amplify this signal and provide a meter reading that corre- sponds to the concentration of particles. See Figures 3.15 and 3.16. Although turbidity readings alone cannot determine solids content, they are very useful in monitoring filter per- formance and wellbore cleanup. Clarity differences between filter influent and effluent samples reflect filter efficiency. Plotting turbidity of well returns versus circulating time (Fig. 3.17) is helpful in determining when optimum wellbore cleanup is achieved. The accuracy of turbidity measure- ments is dependent upon instrument limitations and the use of proper field testing techniques. The following points should be considered while using a turbidimeter: 1. Each new instrument is supplied with its own unique turbidity “transfer standard” that has been calibrated to duplicate factory settings. Using an off-the-shelf replacement standard can affect the accuracy of a given turbidimeter by as much as 20%. 2. Since turbidity readings are optical measurements, any extraneous distor- tions caused by scratched or dirty glass- ware will affect the NTU reading. It is important to keep the “transfer standard” and sample vials free of finger prints, scratches and particle contamination. 3. Sample preparation is important for consistent and accurate turbidity readings. The collected sample should be passed through a 200 mesh screen, to remove particles larger than 74 microns, and then allowed to stand for a few minutes. The sample used for mea- surement should not contain any settled or floating solids. 4. Turbidity readings between differ- ent turbidimeters on the same sample will not produce the same results unless the units have identical optical systems. Gravimetric analysis. Gravimetric analysis is used to determine the total amount of total suspended solids (TSS) in a completion fluid sample. This tech- nique involves passing a specified amount of fluid through a 0.45 micron membrane, drying the membrane, and measuring its weight gain due to trapped solids. By convention, solids content is measured in number of mil- ligrams per liter of fluid (mg/l). Since there are 1,000 ml in one liter of fluid, the following calculation can be used to determine the solids content in a given fluid based on a gravimetric analysis: API RP 13J, “Testing Heavy Brines,” 2nd Edition, March 1996, provides a lab- oratory procedure for correlating turbid- ity readings to total suspended solids. This technique uses a calibration curve that is generated from gravimetric analy- sis. The procedure involves taking NTU measurements on five fluid samples that have increasing levels of suspended solids. Gravimetric analysis is then run on each sample. The data is plotted with NTU on one axis and total suspended solids on the other axis (Fig. 3.18).22 The resulting linear calibration curve can be used to estimate suspended solids at any given NTU reading. It is important to remember that accuracy of the correlation is dependent upon the analysis of the same fluid using the same turbidimeter throughout the filtration operation. If a different fluid or distribution is introduced into the system, a new calibration curve should be generated. Determination of particle size distribution. As previously discussed, it is generally accepted that particles 1/3 to 1/7 the diameter of the average pore throat cause the most significant wellbore damage. Actual determination of the particle size distribution can be accomplished by using particle counters or microscopic analysis. Onsite particle size distribution determination can be expensive and time consuming. Unless a trained technician is available, it can Practice for TSS mg l final mg weight original mg weight sample volume in ml ( ) = −( ) ×1 000, 0 100 200 300 400 500 600 700 0 40 80 14012020 60 100 To ta l s us pe nd ed s ol id s, m g/ l Turbidity, NTU Fig. 3.18. Typical calibration curves Lenses Spatial filters Detector Sample cell Light shield Lamp Fig. 3.15. Turbidimeter optical diagram Fig. 3.16. Turbidimeter 0 50 100 150 200 0 3 7 11106 9 128421 5 Tu rb id ity , N TU Circulation time, hr Fig. 3.17. Typical wellbore cleanup curve 58 Modern Sandface Completion Practices also be difficult to obtain reproducible data. For these reasons, field particle size distribution testing is not recom- mended at this time. Perforating The main purpose of perforating an oil or gas well is to establish good flow communication between the wellbore and the reservoir. Although in all cased- hole completions perforating is the pri- mary means for establishing reservoir connectivity, it is frequently taken for granted in the completion design pro- cess. In any completion, the primary objectives of perforation should be clearly defined and an appropriate design accordingly implemented. Both well productivity and injectiv- ity depend primarily on near-wellbore pressure drop (commonly referred to as skin) which is a function of completion type, formation damage and perforation parameters. Modern perforating is inseparable from other services that improve well productivity, such as frac- turing, acidizing and sand control or prevention.23 In addition to being con- duits for oil and gas inflow, perforations provide uniform points of injection for water, gas, acid, proppant-laden gels for hydraulic fracture stimulations and flu- ids that place gravel to control sand in weak or unconsolidated formations.24 In other sand-management applications, perforating provides the required num- ber, orientation and size of stable holes to prevent sand production.25 Jet perforating, using special shaped- charge explosives made specifically for oilfield perforators, has been commonly employed since the late 1940s. The shaped charge evolved from the WWII military bazooka and replaced less powerful bullet perforators and other technologies such as mechanical cutters and hydraulic jets. While jet perforating is the most common way to establish conductive tunnels that link oil and gas reservoirs to steel-cased wellbores that lead to the surface, the perforating event also damages formation perme- ability around each perforation tunnel. This damage and various perforation parameters—formation penetration, hole size, shot density and the angle between holes or phasing—have a sig- nificant impact on pressure drop and, therefore, on production. Optimizing these parameters and mitigating induced damage are important aspects of perforating. In the past, completion engineers often based the selection of perforating systems solely on charge performance data from API RP 43 Concrete and Berea Test criteria such as depth of pen- etration and/or casing-exit hole size. It was generally accepted that a good indi- cation of charge hole size could be obtained from the concrete target tests since in these the charges are fired through casing. Likewise, since the Berea sandstone target core is more uniform, results from it were thought to yield more reliable charge penetration performance. Much of the perforating charge data published by the service companies is still based on the API RP 43 evaluation tests. Today, optimizing the perforating process involves much more than the analysis of shaped-charge penetration and hole size. Most would agree that understanding and predicting perfora- tion inflow performance is critical for predicting well inflow performance in natural (cased and perforated) comple- tions. The same is true to a lesser degree in fractured or sand-control completions where additional operations are con- ducted to enhance or assure a reliable connection to the reservoir.26 In November 2000, the American Petroleum Institute published API RP 19B, First Edition, “Recommended Practices for Evaluation of Well Perfo- rators.” This Recommended Practice supersedes all previously issued edi- tions of API RP 43. Sections 1 through 4 of API 19B provide means for evalu- ating perforating systems (multiple shot) in four ways: 1. Performance under ambient tem- perature and atmospheric pressure test conditions. 2. Performance in stressed Berea sandstone targets (simulated wellbore pressure test conditions). 3. How performance may be changed after exposure to elevated temperature conditions. 4. Flow performance of a perforation under specific stressed test conditions. Service companies have started pro- viding performance information on new perforator systems based on the API RP 19B criteria. There is a multitude of perforating options varying in charge type, gun size, shot density, phasing, conveyance method (tubing versus wireline, etc.), wellbore fluids, and perforating shot conditions (under/over/extreme over balance). While many combinations of these options have been applied in field perforating systems, some debate still exists over the relative benefits (e.g., shooting under versus overbalance, tub- ing conveyed versus wireline, and charge selection). In addition, technical analyses have been developed to quantitatively address components of an optimized perforating system (e.g., optimum underbalance or charge performance) but, rarely, the entire system itself. This is in large part due to the magnitude of parameters and the difficulty in validat- ing the quantitative impact in the field. Many questions still exist concerning the entire range of perforating systems and their application: • How to predict their impact on inflow • When should a given perforating system be applied • Can different parts be interchanged (e.g., does each charge have the same optimum underbalance based on permeability) • What are the risk factors to achieve predicted performance.27 Although the development of a definitive strategy for the optimum per- forating system design is well beyond the scope of this discussion, it is impor- tant to understand the basic components of a perforating system and how each impacts the completion process. Hence, the balance of this section will concen- trate on the following: • Shaped-charge design and performance • Gun design and deployment techniques • Detonation methods • Well/reservoir characteristics • Perforation clean-up • Special perforating techniques. Shaped-charge design and perfor- mance. Perforations are created in less than a second by shaped charges that use an explosive cavity effect usually coupled with a metal liner to maximize penetration. Perforating charges consist of a primer, outer case, high explosive and conical liner connected to a detonat- ing cord (Fig. 3.19). The detonating cord initiates the primer and detonates the main explosive. The liner collapses to form the high-velocity jet of fluidized 59 Chapter Three Cased-Hole Sandface Completions metal particles that are propelled along the charge axis through the well casing and cement and into the formation. Each component of the shaped charge must be made to exact tolerances. The first requirement for predicting perforation inflow performance is an accurate description of the perforation geometry. The API RP-43 Section 1 test was designed to provide a simple means to assess charge penetration per- formance using standard field guns. Pratt and Carrera28 have raised some concerns that charges can be designed to optimize performance in any mate- rial, and hence, comparison in concrete targets may be misleading for selecting charges for rocks with different proper- ties. However, in a statistical analysis of the available Section 1 data, Bell et al29 demonstrate that while charge opti- mization is a real phenomenon, the data can still be analyzed within rea- sonable accuracy limits in a meaningful way to infer penetration performance in target rocks of different strengths. In this analysis, most of the data (includ- ing “hard” rocks, i.e., rocks with suffi- cient strength that natural completions would not normally be considered) falls within reasonable error bands of the predicted average performance. The API RP-43 Section 4 test arises from a set of recommended API proce- dures30-32 designed to assess perfor- mance of perforating gun systems. The purpose of the Section 4 test is to assess perforation inflow performance for a single shaped charge explosive under simulated in-situ stress and perforating conditions. Halleck and Dogulu33 review Section 4 test procedures along with different test experiences. Numerous papers34,35 have been written on pioneering work and results using Section 4 tests; in particular, inflow damage created during the per- forating operation and optimal perforat- ing conditions to remove the damage have been documented. However, the open literature has limited documenta- tion on the standardization or repeata- bility in conducting these tests, in part, because of test complexity, and per- haps, because there are limited test facilities with which to compare results. Furthermore, a large percentage of the published results are based on small charges (3.2 gm and 6.5 gm weight explosives) not typically used in well completions. Depending on whether inflow performance is unique to each charge, some questions remain regard- ing the universality of the results and how to implement these results to design and optimize perforating gun systems for field application.36 As previously mentioned, an undesir- able side effect of perforating is addi- tional damage in the form of a low-per- meability zone around perforations. The jet penetrating mechanism is one of “punching” rather than blasting, burning, drilling or abrasive wearing. This punch- ing effect is achieved by extremely high impact pressures—3 million psi (20 Gpa) on casing and 300,000 psi (2 Gpa) on formation stemming from impact of the initial portion of the jet traveling at approximately 30,000 ft/sec (914,000 cm/sec). These enormous jet impact pressures cause steel, cement, rock, and pore fluids to flow plastically outward. Elastic rebound leaves shock-damaged rock, pulverized formation grains and debris in the newly created perforation tunnels. Hence, perforating damage can consist of three elements—a crushed zone,37 migration of fine formation particles and debris inside perforation tunnels (Fig. 3.20). The crushed zone can limit both productivity and injectivity. Fines and debris restrict injectivity and increase pump pressure, which decreases injec- tion volumes and impairs placement or distribution of gravel and proppants for sand control or hydraulic fracture treatments.38 Erosion of the crushed Case Conical liner Detonating cord Shaped charge Explosive cavity effects Charge detonation Primer Main explosive Explosive Steel target Metallic liner Lined cavity effect Flat-end Unlined cavity effect 5 microseconds 25 microseconds 40 microseconds 50 microseconds 70 microseconds Fig. 3.19. Shaped charges, with a capability to instantaneously release energy in an explosive, use a cavity effect and metal liner to maximize penetration (lower left). Shaped charges consist of four basic components—primer, main explosive, conical liner and case (top left). An explosive wave travels down the detonating cord, initiating the primer and detonating the main explosive. A detonation advances spherically, reaching pressures of 7.5 million psi (50 Gpa) before arriving at the liner apex. The charge case expands and the liner collapses to form a high-velocity jet of fluidized metal particles that is propelled along the charge axis (right). 60 Modern Sandface Completion Practices zone as well as removal of debris from perforations by surge flow are essential to mitigate perforating damage and ensure well success in all but the most prolific reservoirs. Studies show that induced damage increases for larger explosive charges.39 The extent of perforation damage is a function of lithology, rock strength, porosity, pore fluid compressibility, clay content, formation grain size and shaped-charge designs.40 Research in conjunction with numerical modeling is providing a better understanding of per- meability damage in perforated wells that can be used to improve completion designs in the future.41 It is important to note that shaped charges have been designed to generate optimal combinations of hole size and penetration using minimum of explo- sive material. Among the many advances in perforating technology are new deep-penetrating charges that increase well productivity by shooting beyond drilling and completion fluid invasion, and big-hole charges for gravel packing or frac packing. Drilling and completion fluid inva- sion can range from several inches to a few feet. When formation damage is severe and perforations do not extend beyond the invaded zone, pressure drop, or skin, is high and productivity is reduced.42 Perforations that reach beyond the damage increase effective wellbore radius and intersect more natu- ral fractures if these are present. Deeper penetration also reduces the pressure drop across perforated intervals to pre- vent or reduce sand production. In general, hard, high-strength for- mations and reservoirs damaged by drilling fluids benefit the most from deep-penetrating perforations that extend beyond the formation damage and increase the effective wellbore radius. Low-permeability reservoirs that need hydraulic-fracture stimulation to produce economically require appro- priately spaced and oriented perfora- tions. Unconsolidated formations that may produce sand need high density, big-diameter holes which reduce pres- sure drop and can be packed with gravel to keep the formation particles out of the perforation and the wellbore. Perforations also can be designed to prevent tunnel and formation failure associated with sand production.43 Gun Design and Deployment Techniques Gun design. Shaped charges are placed in guns (Table 3.12) and conveyed downhole to the correct depth by wire- line, slickline, tubing or drill pipe, or via coiled tubing. There are two types of guns, capsule and carrier (Fig. 3.21). Capsule guns are used in electric wire- line and slickline perforating for through-tubing applications. Since the shaped charges in capsule guns are exposed to well conditions, they must be encapsulated in separate pressure-proof containers. Debris from these expend- able guns is left in a well after firing. Carrier guns (including those with threaded and sealed port plugs, machined scallops or non-scallops) are deployed on wireline or slickline, tub- ing or drill pipe run by drilling and workover rigs or snubbing units, and on coiled tubing with or without an electric line. In these guns, charges and most of the debris are contained in hollow steel carriers that are retrieved or released and dropped to the bottom of the well- bore after perforating. Casing and through-tubing guns, both capsule and carrier, were initially run on wireline; tubing-conveyed perforating (TCP) with high shot density (HSD) guns became popular in the late 1970s and early 1980s. Through-tubing guns are limited in gun size and length by well completion design and surface pressure control equipment. The use of under- balance is also limited when guns are run on electric line. Conversely, TCP guns offer a wide variety of choices and allow for simultaneous underbalance perforating of long intervals, which is often considered essential for gravel packing or frac packing. Shot density and phasing. Shot density (the number of holes specified in shots per foot) and phasing (perforation orien- tation or the angle between holes) play important roles in perforating technol- ogy. An adequate shot density can reduce perforation skin and produce wells at lower pressure differentials. Optimized phasing reduces pressure drop near the wellbore by providing flow conduits on all sides of the casing minimizing interference and interlinking of adjacent damaged zones and reducing the risk of formation failure without compromising flow rate per perforation. Deployment methods. Deployment of perforating guns has evolved from early electric line and tubing or drillstring- conveyed guns, and now includes coiled tubing with or without electric line, snubbing units, slickline and downhole tractors on wireline and coiled tubing. Each conveyance method has advan- tages and disadvantages related to per- 61 Chapter Three Cased-Hole Sandface Completions Fig. 3.20. Perforating damage. A zone of reduced permeability is created around perforation tunnels by shaped-charge jets. Shock-wave pressures pulverize adjacent rock, fracture matrix grains, break down intergranular cementation and debond clay particles. Shattering of the formation around perforations damages in-situ permeability primarily by reducing pore-throat size. Photomicrographs show undamaged rock (top insert) compared to microfracturing in a perforation crushed zone (bottom insert ). Gun Configuration Charge Performance Data Charge Information Carrier Gun Shot Entry Target Casing Expl. Min I.D. Pressure 1 hr Temp OD Density Phase Hole Dia. Penetration O.D. Data Expl. Load Charge Charge for Running Rating Rating (in.) (spf) (deg.) (in.) (in.) (in.) Source Type (gm) Type or Name Case (in.) (psi) (°F) BAKER ATLAS 3-3/8 6 60 0.70 6.50 5-1/2 API RP43 RDX 22.7 GP Perfform 3.75 20,000 330 3-3/8 6 60 0.76 6.40 4-1/2 API RP43 RDX 22 JJ Steel 3.8 20,000 330 3-3/8 6 60 0.77 8.50 4-1/2 API RP43 HMX 22 JJ Steel 3.8 20,000 400 3-3/8 12 150/30 0.64 5.60 5-1/2 API RP43 HMX 11 GP Steel 3.75 20,000 400 3-3/8 12 150/30 0.62 5.30 5-1/2 API RP43 HMX 11 GP Perfform 3.75 20,000 400 4-1/2 12 135/45 0.71 6.40 7 API RP43 RDX 22.7 GP Perfform 4.75 17,000 330 4-1/2 12 135/45 0.72 6.60 7 API RP43 RDX 22.7 GP Steel 4.75 17,000 330 4-1/2 12-Auger 135/45 0.71 6.90 7 API RP43 RDX 22.7 GP Perfform 4.75 17,000 330 4-1/2 18 140/20 0.71 6.90 7 API RP43 RDX 19 GP Perfform 4.75 17,000 330 4-1/2 18 140/20 0.79 6.50 7 API 19B HMX 19 GP Steel 4.75 17,000 400 4-5/8 12 135/45 0.92 5.80 7 API RP43 RDX 26 GP Perfform 5 17,000 330 4-5/8 16 135/45 0.98 4.80 7 API RP43 RDX 28 GP Steel 5 17,000 330 4-5/8 16 135/45 0.92 5.80 7 API RP43 RDX 26 GP Perfform 5 17,000 330 4-5/8 16 135/45 0.93 4.56 7 API 19B HMX 28 GP Steel 5 17,000 400 4-5/8 16 135/45 0.86 5.01 7 API 19B RDX 26 GP Perfform 5 17,000 400 5 18 140/20 0.70 6.40 7-5/8 API RP43 RDX 19 GP Perfform 5.38 17,500 330 5 18 140/20 0.72 6.60 7-5/8 API RP43 HMX 19 GP Steel 5.38 17,500 400 5-1/4 18 140/20 0.87 6.30 7-5/8 API RP43 RDX 26 GP Perfform 5.63 15,500 330 5-1/4 18 140/20 0.90 5.70 7-5/8 API RP43 HMX 26 GP Steel 5.63 15,500 400 6 12 135/45 0.78 6.40 9-5/8 API RP43 HMX 32 GP Perfform 6.75 14,500 400 6 16 135/45 0.78 6.40 9-5/8 API RP43 HMX 32 GP Perfform 6.75 14,500 400 7 12 135/45 0.99 7.10 9-5/8 API RP43 RDX 61 GP Perfform 7.38 12,000 330 7 18 140/20 0.95 6.50 9-5/8 API RP43 HMX 39 GP Perfform 7.38 12,000 400 7 18 140/20 1.07 7.20 9-5/8 API RP43 RDX 48 GP Steel 7.38 12,000 330 HALLIBURTON / JRC 3-3/8 12 150/30 0.62 5.33 5-1/2 API RP43 RDX 14 BH Steel 4.423 23,000 325 3-3/8 12 150/30 0.64 5.24 5-1/2 API RP43 HMX 14 BH Steel 4.423 23,000 400 4-5/8 12 150/30 0.93 6.30 7 API RP43 RDX 28 SH Steel 5.795 16,000 325 4-5/8 12 150/30 0.96 5.10 7 API RP43 HMX 28 SH Steel 5.795 16,000 400 4-5/8 12 150/30 0.81 5.40 7 API RP43 RDX 28 SH/ LD Zinc 5.795 16,000 325 4-5/8 12 150/30 0.85 5.30 7 API RP43 HMX 28 SH / LD Zinc 5.795 16,000 400 4-5/8 14 128.5/25.7 0.93 6.30 7 API RP43 RDX 28 SH Steel 5.795 20,000 325 4-5/8 14 128.5/25.7 0.96 5.10 7 API RP43 HMX 28 SH Steel 5.795 20,000 400 4-5/8 18 135/45 0.73 6.18 7 API RP43 RDX 20 BH Steel 5.666 18,000 325 5 21 120/60 0.72 5.40 7-5/8 API 19B RDX 21 BH Steel TBD 16,000 325 5-1/8 14 231.4 0.93 5.11 7-5/8 API RP43 RDX 32 SH Steel 5.969 17,000 325 5-1/8 14 231.4 0.94 5.83 7-5/8 API RP43 HMX 32 SH Steel 5.969 17,000 400 6-1/2 12/14 138 0.91 6.80 9-5/8 API 19B RDX 47 BH Mirage Zinc 7.600 20,000 325 7 12/14 135-138 1.03 4.70 9-5/8 API 19B RDX 39 SH Mirage Zinc 8.379 11,000 325 7 12/14 135-138 0.98 6.40 9-5/8 API 19B RDX 39 BH Mirage Zinc 8.379 11,000 325 7 12 32 1.16 5.00 9-5/8 API 19B RDX 56.5 SH LD Zinc 8.379 11,000 325 7 12/14 135-138 1.29 5.80 9-5/8 API 19B RDX 56.5 SH Steel 8.379 11,000 325 OWEN OIL TOOLS / A CORE LABORATORIES COMPANY 3-3/8 6 60 0.73 6.05 5 API RP43 RDX 20 BH Steel 3.75 20,000 330 3-3/8 12 135/45 0.63 4.87 5-1/2 API RP43 RDX 11 BH Steel 3.75 20,000 330 3-3/8 12 135/45 0.63 5.46 5-1/2 API RP43 RDX 11 BH / LD Zinc 3.75 20,000 330 4-1/2 12/16 135/45 0.72 6.32 7 API RP43 RDX 20 BH Steel 4.81 18,000 330 4-1/2 12/16 135/45 0.72 6.96 7 API RP43 RDX 29 BH / LD Zinc 4.81 18,000 330 4-1/2 12 135/45 0.94 6.15 7 API RP43 RDX 26 SH Steel 4.81 18,000 330 4-1/2 16 140/20 0.82 7.00 7 API RP43 RDX 23 SH / LD Zinc 4.81 18,000 330 4-1/2 18 140/20 0.82 6.67 7 API RP43 RDX 17 BH Steel 4.81 18,000 330 4-1/2 18 140/20 0.78 6.57 7 API RP43 RDX 17 BH / LD Zinc 4.81 18,000 330 5-1/8 12/16 135/45 0.72 6.87 7-5/8 API RP43 RDX 20 BH Steel 5.65 18,000 330 5-1/8 12/16 135/45 0.71 7.05 7-5/8 API RP43 RDX 19 BH / LD Zinc 5.65 18,000 330 5-1/8 16 140/20 0.80 6.51 7-5/8 API RP43 RDX 23 SH / LD Zinc 5.65 18,000 330 7 12/16 135/45 1.13 7.60 9-5/8 API RP43 RDX 39 BH Steel 7.63 13,000 330 7 12/16 135/45 1.06 7.43 9-5/8 API RP43 RDX 39 BH / LD Zinc 7.63 13,000 330 7 18 140/20 1.13 7.60 9-5/8 API RP43 RDX 39 BH Steel 7.63 13,000 330 7 18 140/20 1.06 7.43 9-5/8 API RP43 RDX 39 BH / LD Zinc 7.63 13,000 330 SCHLUMBERGER 3-3/8 6 60 0.44 31.40 4-1/2 API 19B HMX 22.7 UltraJet 3406 Steel 3.86 20,000 400 3-3/8 12 135/45 0.64 4.50 5 API 19B HMX 14.1 PowerFlow 3412 Steel 3.72 20,000 400 4-1/2 12 135/45 0.34 30.20 7 API 19B HMX 22.0 PowerJet 4512 Steel 5.11 12,000 400 4-1/2 12 135/45 0.39 17.90 7 API 43 RDX 20.5 34B HyperJet II Steel 4.97 12,000 340 4-1/2 12 135/45 0.34 28.60 7 API 43 HMX 22.7 34JL UltraJet Steel 4.97 12,000 400 4-5/8 21 120/60 0.83 5.90 7 API 43 RDX 19 PowerFlow 4621 Steel 5.02 15,000 340 4-5/8 21 120/60 0.83 6.10 7 API 19B HMX 19.4 PowerFlow 4621 Steel 5.02 15,000 400 5 8 135/45 0.54 20.20 7 API 43 RDX 24 UltraJet 5008 Steel 5.39 10,000 340 5 8 135/45 0.98 5.80 7 API 43 RDX 30 PowerFlow 5008 Steel 5.39 10,000 340 5 21 120/60 0.74 7.90 7-5/8 API 43 RDX 19 43 CleanJet UltraPack II Zinc 5.34 11,000 340 5-27/32 18 120/60 0.93 7.20 8-5/8 API 43 HMX 34 PowerFlow 5918 Steel 6.16 20,000 400 6-5/8 18 120/60 0.91 6.80 9-5/8 API 19B HMX 34 PowerFlow 6618 Steel 6.93 20,000 400 7 12 135/45 0.47 32.00 9-5/8 API 43 RDX 37 51B HyperJet II Steel 7.25 10,000 340 7 12 135/45 0.45 39.90 9-5/8 API 19B HMX 38.3 UltraJet 4505 Steel 7.25 10,000 400 7 14 140/20 0.95 12.20 9-5/8 API 43 RDX 61 58C UltraPack Steel 7.47 10,000 340 7 12 135/45 1.13 10.10 9-5/8 API 43 RDX 59 64C CleanPack Zinc 7.95 10,000 340 7 18 120/60 1.13 5.90 9-5/8 API 19B RDX 51.5 PowerFlow 7018 Steel 7.33 10,000 340 7 18 120/60 1.14 7.10 9-5/8 API 43 HMX 49.5 PowerFlow 7018 Steel 7.33 10,000 400 NOTES: BH = Big Hole, SH = Super Hole, LD = Low Debris, JJ = Jumbo Jet, GP = Gravel Pack, DP = Deep Penetrating, SDP = Super Deep Penetrating KISS = “Kiss the Face” designed to perforate the casing and cement sheath with minimal penetration of the formation Table 3.12. Several perforating systems commonly used in sandface completions (check with your service supplier for other available charges and systems.) 62 Modern Sandface Completion Practices forming downhole operations, gun length and pressure control, perforating without killing wells, mechanical strength and wellbore angle, depth cor- relation, rigless intervention and gun type. To optimize perforation designs, the pros and cons must be weighed for all gun systems being considered for a specific completion. Gun clearance/centralization. Exces- sive gun clearance with any perforating gun can result in inadequate penetration, inadequate hole size, and irregularly shaped or “keyed” perforations (Fig. 3.22). Conventional carrier guns nor- mally have adequate penetration in unconsolidated sands unless the cement sheath is unusually thick due to washed- out borehole. If necessary, clearance control can be achieved through spring- type deflectors, magnets and other methods. Depending on charge and gun design, 0 or 1/2 in. gun-to-casing clear- ance usually provides maximum perfo- ration penetration and hole size. In some carrier guns, significant changes in hole size result as gun clearance is increased for 0 to 2 in. In such cases, centraliza- tion may produce a satisfactory and more consistent hole size. With gun clearance above 2 in., it is usually desir- able to decentralize and to orient the direction of fire from the gun. Gun length and perforating without killing wells. Total weight of long gun strings and running or retrieving guns under pressure can restrict wireline, coiled tubing and even tubing-conveyed perforating. However, these limitations can be overcome by a technique referred to as permanent completion perforating (PCP) systems. This tech- nique allows downhole assembly of multiple gun sections to any length with or without a rig, and provides underbal- anced perforating of long intervals in one descent. The system can be deployed and retrieved by slickline, electric wireline or coiled tubing. When necessary, gun sections can be retrieved without killing the well. This system can be used to perforate wells without interrupting production. High-angle wells. In high-angle and horizontal wells, wireline may not allow guns to descend unless a tractor is used. Coiled tubing is the preferred con- veyance method, unless a horizontal section is so long that helical buckling occurs before the perforating interval is reached. Tractors have also been used successfully to extend the maximum reach of coiled tubing. In many of today’s high-angle and extended-reach wells, there may be no alternative to TCP or PCP. If mechanical pulling or pushing force must be exerted on a gun system, TCP, snubbing, coiled tubing and tractors offer more versatility than electric line and slickline. For long guns like those used in horizontal wells, gun- string design must consider tensile strength. High-strength adapters and tapered gun strings have been used suc- cessfully. Gun bending must also be modeled and addressed. Duration of operations. If intervals are vertical and short—less than 40 ft (12 m)—and perforated in balanced or over- balanced conditions, wireline perforat- ing usually can be performed in a few hours and may be the most efficient method. If the interval is longer or has multiple sections, wireline operations Retrievable Enerjet Standard Enerjet Expendable Enerjet Capsule guns Carrier guns 111/16 -in. OD running 3.79-in. OD deployed 1.56-in. HSD gun 4 spf zero phasing 2.0-in. HSD gun 6 spf, 60˚ spiral phasing 2.25-in. HSD gun 6 spf, 60˚ spiral phasing 5.85-in. Bigshot 18 spf, 120˚/60˚ phasing 6 5/8-in. Bigshot 18 spf, 120˚/60˚ phasing Pivot gun Tubing Casing Fig. 3.21. Gun types. Perforating guns are classified as capsule or carrier. A few examples are shown. Capsule guns are conveyed by wireline or slickline in through-tubing operations. Detonating cords are exposed to downhole conditions, so the charges are encapsulated in pressure-proof containers. Expendable through-tubing capsule guns generate debris, which remains in a well after perforating. Carrier, or casing, guns are conveyed by wireline, tubing and coiled tubing and can be designed to retain debris inside the carrier. Detonation occurs inside the carrier under atmospheric pressure. 63 Chapter Three Cased-Hole Sandface Completions require more than one trip, which pre- vents use of underbalance during subse- quent gun runs. As well deviation increases, operating time increases, especially if the gun-string weight is low and surface pressure-control equipment is used. When well deviation exceeds about 65°, other conveyance methods like TCP and PCP that require a longer running-in time must be used. If perfo- rating intervals become significantly longer, the overall duration of TCP can be significantly shorter than wireline operations. Additionally, the entire inter- val can be perforated with underbalance for optimal perforation cleanup. Run-time also has an effect on the explosives (most commonly RDX, HMX, HNS, and PYX) used in the per- forating system. Each charge or explo- sive type has a time/temperature range rating (Fig. 3.23). Since charges are exposed to downhole temperatures for extended periods of time, this rating should be considered when designing a perforating system for particular well conditions. Detonation Methods Two types of detonators are used in per- forating guns: electrical detonators or blasting caps, and percussion detona- tors. Conventional electrical detonators, most typically used with capsule guns, are susceptible to accidental application of power from electric potential differ- ences (EPD). This can constitute a safety hazard, hence appropriate safety precautions should be taken to prevent and control any stray currents that could trigger premature detonation. Percussion detonators that are typically used in TCP systems actuate mechani- cally when a firing pin strikes a pres- sure-sealed membrane and detonates a primary high explosive. Several tech- niques can be used to actuate the firing pin: impact from a drop bar, annular pressure, tubing pressure, etc. Well/Reservoir Characteristics Underbalanced, balanced, overbalanced and extreme overbalanced (EOB) describe the pressure differential between a wellbore and reservoir before perforating. At one time, perforating was performed with mud or high-den- sity fluids in wells—balanced or over- balanced conditions. Today, in order to minimize or remove perforation dam- age, underbalanced perforating is more common. An underbalance exists when pressure inside a well is less than the formation pressure. Balanced condi- tions occur when these pressures are equal. An overbalance occurs when well pressure is greater than reservoir pressure. Extreme overbalance means that well pressure greatly exceeds rock strength—fracture initiation, or break- down, pressure. Both EOB and fractur- ing attempt to bypass damage.44 Underbalanced or reverse-pressure. The potential of underbalanced perfo- rating was recognized in the 1960s. Wells perforated with underbalance tended to show production increases. In the 1970s and early 1980s, researchers recognized that the flow efficiency of perforated completions increased when higher underbalance pressures were used. They concluded that post-shot flow was responsible for perforation cleanup and recommended general underbalance criteria.45 Since then, var- ious aspects of perforating have been investigated using field and laboratory data. These studies consistently rein- force the advantages of an initial surge (a few hundred to thousands of psi depending on rock strength and perme- ability) to erode perforation crushed zones and flush out perforating debris.46 Magnitude and duration of an initial pressure surge are believed to dominate cleanup of crushed-zone damage. Instantaneous flow minimizes fluid invasion, loosens damaged rock and sweeps away rock debris in perforation tunnels (Fig. 3.24). The degree to which material is loosened is primarily a func- 1 11/16 in. - 90° phased gun 0.1 in. - entrance hole 2.5 in. - penetration 0.18 in. - entrance hole 3.7 in. - penetration 0.3 in. - entrance hole 6.0 in. - penetration 0.3 in. - entrance hole 6.0 in. - penetration Cement 7 in. casing Fig. 3.22. Decreased performance of poorly centered, small-diameter perforating guns in large casing is illustrated by test target results of 1-11/16-in., 90° phased gun fired in 7-in. casing in simulated Berea sandstone. Note extreme variation in hole size and penetration. Time, hrs Te m pe ra tu re , ° F RDX HMX HNS PYX 1 150 250 350 450 550 650 10 100 1,000 Contact charge manufacturer for recommendations and possible need for systems testing Fig. 3.23. Time vs. Temperature limits for common explosives used with carrier guns. This chart is valid for the explosive train inside hollow carrier guns only: non-electric boosters, detonating cord, and shaped charges. It is not valid for TCP firing systems, electric detonators, or capsule guns. For more specific information regarding these and other explosive components, contact your perforating service provider. 64 Modern Sandface Completion Practices tion of underbalance pressure differen- tial. The high-velocity surge is followed by pseudosteady-state flow, which is less effective because rates and associ- ated drag forces are less than those gen- erated during an initial transient surge. Fluid volume and flow that occur later are believed to be secondary. The underbalance pressures required to effectively clean perforations and reduce permeability damage have been measured in single-shot perforate and flow tests that provide a basic under- standing of damage mitigation.47 Immediately after perforating in under- balanced conditions, there is instant decompression of reservoir fluids around a perforation. The dynamic forces—pressure differential and drag—that mitigate permeability dam- age by eroding and removing fractured formation grains from tunnel walls are highest at this time.48 Underbalanced perforating requires that the well be under control when the gun is fired so that fluid inflow can be handled safely and perforating equip- ment can be removed if needed. Short intervals can be perforated underbal- anced using through-tubing guns run on wireline below a packer. When using these smaller strip or capsule guns, more than four to six shots per foot (SPF) can be obtained by reshooting the same interval. Small guns present cen- tering problems in the larger casing, and in strongly flowing wells they can be blown uphole if cable size and selected underbalance is not properly coordinated. After the first gun is fired, pressure differential can be assured only by flowing existing open holes to draw down internal pressure. In high- pressure wells, this requires careful planning and may not even be possible. TCP or PCP guns can be made up in very long lengths to underbalance per- forate an entire zone or multiple zones at once. These systems offer the most options for perforating configurations and completion optimization, and are considered the safest way to shoot large intervals underbalanced. Gun assem- blies as long as 8,000 ft have been deployed and intervals over 6,500 ft long in a single run have been success- fully perforated using TCP techniques. These systems can involve very sophis- ticated assemblies employing numerous (as many as 52 to date) firing heads. After firing, TCP or PCP guns can remain on the tubing to serve as a blast joint for inflowing fluids, or they can be dropped to bottom to allow future wire- line operations through the tubing. In some applications, the guns are retrieved to the surface. Because tubing above the guns can be run empty or contain any volume of buffer fluid to cushion the blast, various magnitudes of initial pres- sure differential can be obtained to surge the new perforations clean.49 Options for perforating with under- balance have reached a high degree of sophistication because of hardware for TCP and PCP. Whatever the conveyance method, it is usually possible to perfo- rate with sufficient underbalance (Table 3.13). Practical exceptions when opti- mal underbalance cannot be achieved are depleted reservoirs, shallow wells or wells with open perforations. For certain conditions, a high underbalance is needed to clean out perforations and generate post-shot flow. With wireline- conveyed guns, this is possible only if anchoring devices are used while shoot- ing to prevent guns from being blown up hole. Anchoring devices are also rec- ommended when the level of underbal- ance is unknown and guns are exposed to a sudden fluid influx, as for example, when perforating new intervals in for- mations with differentially depleted pro- ducing intervals.50 Underbalance Differential Permeability King* Hsia #1** Hsia #2*** (md) (psi) (psi) (psi) 1 2,900 50,600 17,000 10 1,266 6,182 3,392 100 553 755 677 500 310 174 219 1,000 241 92 135 2,000 188 49 83 5,000 135 21 44 10,000 105 11 27 *∆ P = 2,900 / k0.36(md) **∆ P = 5.06 x 104 / k0.913(md) ***∆ P = 1.7 x 104 / k0.7(md) Table 3.13. Underbalanced perforating guidelines related to underbalanced pressure differential Casing Undamaged formation Balanced perforating Formation damage Cement Perforation debris Crushed and compacted low-permeability zone Casing Undamaged formation 3,000-psi underbalance perforating Cement Low-permeability zone and perforation debris expelled by surge of formation fluid Formation damage Fig. 3.24. Underbalanced perforating. In an overbalanced or balanced perforation without cleanup and before flow, the tunnel is plugged by shattered rock and perforating debris (top). Production flow may remove some debris, but much of the low-permeability crushed zone remains. The initial surge flow generated by using an adequate underbalance during perforating helps remove debris and erode the crushed zone (bottom). 65 Chapter Three Cased-Hole Sandface Completions Overbalanced or positive-pressure. This perforating method simplifies well control because fluid inside the casing overbalances formation pressure and prevents inflow. However, this also holds all perforating charge debris and crushed rock in the perforation, neces- sitating an additional clean-out opera- tion. For sand control, further clean out is imperative prior to gravel packing, frac packing or injecting consolidating chemicals. Without tubing in the well, the larger more powerful carrier guns can be run on wireline. This may be an efficient and more cost-effective alter- native when perforating short intervals. Perforation Cleanout Underbalanced perforating. As previ- ously discussed, underbalanced perfo- rating has been successfully used for cleaning perforations in unconsolidated sands. The method may be most appli- cable where: • Adequate formation stability permits use of sufficient differential pressure and backflow volume to clean perfo- ration debris and mud from all perfo- rations without sand-up. • Reservoir pressure is near original hydrostatic so that underbalance can be obtained with fluid column. • Perforating is conducted through tub- ing, limited to one gun run, and fol- lowed by consolidation treatment. The rig may or may not remain on location. However, if the rig has been removed, there is a tendency to restrict differential pressure and backflow volume unduly to avoid risk of sand-up. Where reservoir pressure has been depleted, proper design may be difficult because of inaccuracies in estimating actual reservoir pressure at time of perforating.51 Perforation washing. This is a widely used method for removing perforation debris, mud, and formation sand from the perforation tunnel, and from behind the casing (Fig. 3.25). During perfora- tion washing, circulation must be main- tained to remove debris from the well. Returns at surface may contain up to 10% sand. Either a “clean” fluid system or fluids with surface filtration systems or a combination of both should be employed for the washing process. Truly clean salt water would normally be lost to the reservoir due to pressure overbalance. However, washed mud, per- foration debris, and formation sands and clays entrained by the wash salt water frequently bridge-off the permeable zone and prevent loss. These solids may cause deep permeability damage that is diffi- cult to remove. If bridging does not occur, there will be no support for the cavity formed by the washing operation and the cavity face may cave or slough back against the casing. Soluble bridging material (usually salt, calcium carbonate or oil-soluble resins) used with the brine will permit circulation of debris from the well and support cavity walls to prevent collapse prior to gravel placement. Bridging material will flow from the well during production if it is sized small with respect to gravel pores. Any remaining bridging material can be removed with the proper solvents—lower salinity brine for salt, acid for calcium carbonate, or produced oil for oil-soluble resins. Use of a non-penetrating fluid for washing may restrict the ability of sub- sequent fluids to force gravel through perforations and into all cavities behind the pipe, and make it more difficult to obtain a tight gravel pack outside the screen. Therefore, excess fluid may have to be washed from the cavities and/or bridging material solvent may have to be used in conjunction with gravel placement. Care should be taken to prevent swabbing when pulling wash tools. Swabbing action may cause caving of the washed interval. Additionally, pre- cautions should be taken to control the well while retrieving the wash tools to prevent the possibility of a blowout. Acid stimulation. Stimulation using hydrochloric (HCl) and/or hydrofluoric (HF) acids has been used to improve well productivity and injectivity where consolidation treatments or inside gravel packs are applied. Acid treat- ment is frequently required, particularly when previously mentioned clean-up methods and non-damaging techniques have not been used. Acids have been used effectively in skin removal and some operators believe that perforation debris can be removed or bypassed through acid treatments. Additionally, HCl is used to remove cal- cium carbonate bridging material. Impairment should be avoided through use of proper fluids and perfo- ration cleaning method. Acid should be applied only to remove unavoidable damage because of the possible disad- vantages, including: • Uncertainty that all perforations are open and treated prior to consolidation. • A possible region of reduced perme- ability in some unconsolidated sands resulting from migratory siliceous fines released as more reactive cemen- tation material is consumed. Produc- tion decline after acid treatment is frequently greater than normal. • Reduction in compressive strength of some rock formations in the wellbore vicinity. Use of oil-soluble resin bridging material in conjunction with mechanical perforation clean-up methods may eliminate need for acid, where incompatibilities between acid and formation exist. Circulating valve Tubing Formation sand Washed zone SWAB cups Casing Perforations Casing Swab cups Length of perf interval 1 foot +/- Fig. 3.25. Schematics of perforation wash tools 66 Modern Sandface Completion Practices Regular mud acid has been effective at volumes of about 50 to100 gal/ft. Spacers should be used (HCl is com- mon) to remove and separate mud acid from any calcium carbonate bridging materials to avoid precipitation of cal- cium fluoride and from sodium chlo- ride brine to avoid precipitation of sodium fluosilicates.52 Special Perforating Techniques Once thought as simply a means to create holes in steel casing and cement, perforating is a complex element of the well completion design. As wellbore construction and configurations have become more advanced, the design of perforating systems has been brought into better focus by contemporary research and an understanding of basic principles. Advanced perforating sys- tems and techniques have been designed for specialized applications. Three spe- cial perforating techniques—oriented perforating, single-trip perforating/ gravel packing, and propellant-assisted perforating—are discussed below. Oriented perforating. The first appli- cations of oriented perforating were in wells with dual or multiple tubing strings. Tools were developed to ensure that guns run in one string of tubing do not perforate other tubulars in a well- bore.53 Today, oriented or selective per- forating techniques are becoming more widely used in applications requiring fracturing deviated and horizontal wells, controlling sand production, and solving wellbore instability problems among others. Optimal phasing angles, hole spacing and orientation of perfora- tions facilitate hydraulic fracturing and eliminate the likelihood of sand influx from perforation-tunnel collapse. When perforations are not properly oriented, fractures normally reorient near the wellbore in order to propagate perpendicularly to the minimum hori- zontal stress, i.e., to align with the maximum horizontal stress. This reorientation near the wellbore creates a complex geometry that can introduce multiple problems: • Increased treating pressures • Increased risk of sudden, near-well- bore, screen outs • Increased risk of multiple fractures • Localized reduced fracture conduc- tivity near the wellbore • Potential for crushed proppant near the wellbore • Increased risk of proppant flowback • Increased risk of formation sand production. Guns can be oriented using a number of techniques such as: • Mechanical devices • Motors coupled with downhole sensors • Eccentric weights and swivels • Gyroscopes • Wireline orienting tools. Oriented perforating to prevent sand production – Sand prevention incorpo- rates techniques to minimize or elimi- nate the amount of sand produced and also to reduce the impact of produced sand without mechanical exclusion methods. Oriented perforations may be used to create stable tunnels in poorly consolidated formations thus avoiding sand failure and consequently prevent- ing sand production.54 Additionally, selective perforating can avoid weak zones or formations altogether. If sand production is the main issue to deal with for a given poorly consoli- dated reservoir, an innovative comple- tion technique using oriented perforat- ing coupled with hydraulic fracturing may be used to minimize or prevent sand production. This technique is based on the fact that a circular hole (i.e., perforating designed to enhance radial flow entry into the wellbore by the spiral phasing of charges in the gun) should not be introduced to a poorly consolidated formation. However, the hydrocarbon reserve can be reached via a hydraulic fracture. This can be achieved in vertical and horizontal wells, preferably a horizontal well. For a vertical well situation, the well should be drilled close to but not into the sand formation. A 1 ft to 5 ft (0.3 m to 1.5 m) interval is perforated in the boundary layer, then a fracture is cre- ated using 180º phasing perforations aligned with the maximum horizontal stress (Fig 3.26). On the other hand, for a horizontal well situation, the well should be drilled in the boundary for- mation close to, but not into, the poorly consolidated sand reservoir. Place ori- ented perforations with 0º phasing at the lower side of the horizontal well. Initiate a hydrofracture designed as a tip screenout treatment, using resin- coated sand throughout the entire job. The above procedure for sand control is based on the following arguments: 1. Compared to a vertical well, a hor- izontal well reduces the pressure draw- down for a given rate. The pressure drawdown places increased deviatoric stress on the formation, and if it exceeds the formation strength for a given fail- ure criterion, failure occurs and leads to sand production from the well. 2. Creating a conductive fracture transforms the radial flow into linear flow away from the wellbore and allevi- Fig. 3.26. Oriented perforating and screenless completions. When combined with oriented perforating and fracturing strategies, novel technologies, such as resin-coated and scale- inhibitor-impregnated proppants (left ), and PropNET fibers (right ), control proppant flowback and sand production to provide effective sand prevention without downhole mechanical screens and gravel packing. 67 Chapter Three Cased-Hole Sandface Completions ates the fluid convergence of radial flow, ultimately decreasing drawdown pressure for a given rate. 3. Formation failure starts near the wellbore due to the stress concentration created after a wellbore is introduced to the formation. In this method a well- bore does not penetrate the weak for- mation at all. In addition to oriented perforation, oriented hydrajetting may be consid- ered to create a single continuous initi- ation path for fracture. In unconsoli- dated formations, sand consolidation may help as a pre-fracturing stage to ensure creating a fracture rather than ballooning a cavity.55 Single-trip perforating/gravel pack- ing. For conventional gravel packing inside casing, three steps are necessary: 1) set a bottom packer, 2) perforate, and 3) circulate gravel behind gravel-pack screens. Disadvantages include long duration of operations and potential for- mation damage from fluid loss or lost circulation material (LCM). Designed to help alleviate these disadvantages, perfo- rating guns and gravel pack hardware can now be run in one step. This technique is a single-trip sand-control method that limits fluid loss, reduces formation dam- age and saves time (Fig. 3.27). Perforating to control sand produc- tion – Sand control utilizes mechanical methods to exclude sand from produced fluids. Perforating for sand control assumes that the production of sand is unavoidable and gravel packing, frac- ture packs or other mechanical tech- niques that exclude sand from produc- tion flow are needed. Perforating must address adequate underbalance to mini- mize pressure drop, or skin, and remove loose sand to clean out perforation tun- nels for optimal gravel placement and efficient gravel packing. Perforation damage, formation fines and charge debris should be removed before gravel packing. Underbalanced perforating and flow before gravel pack- ing are the best methods to achieve this objective. The maximum underbalance pressure must be selected to avoid per- foration collapse and catastrophic sand production during perforating. Perforat- ing with the surface choke open ensures post-shot flow to transport debris into the wellbore. Provisions need to be made to handle transient, finite sand production at surface until the perfora- tions are clean. When pressure drop and flow rate per perforation are low, deep- penetrating charges can be used. Deep- penetrating charges cause less localized damage and debris, and provide a larger effective wellbore radius that reduces pressure drop. As in fracturing applica- tions, perforation diameter needs be 8 to 10 times the gravel diameter. Exposing formations to damaging completion fluids or LCM and chemi- cals during hydrostatic well-control operations should be avoided. Damage to open perforations was observed in tests on Berea sandstone blocks that were perforated, opened to flow, plugged by LCM and then reopened to flow.56 If a well must be killed, non-damaging brines or mutual solvents are best. In addition to internal gravel packs, perforating plays an important role in external sand-control applications like fracture packing and screenless gravel packs.57 Perforating requirements for fracture packing are the same as for internal gravel packs because it is more important to minimize pressure drop through the pack and control sand pro- duction than to create long fractures. IRIS dual-valve tool IRIS dual-valve tool Upper QUANTUM gravel-pack packer Upper QUANTUM gravel-pack packer Screens Bottom packer X-Tool explosive gun release TCP gun TCP gun Gravel packingPerforating Bottom packer Screens Perforations Fig. 3.27. Single-trip perforating and gravel packing. A typical assembly includes a TCP gun with an automatic explosive release, a bottom packer, sand-control screens, a gravel-pack packer with a flapper valve, pressure gauges and recorders, firing head and a dual-drillstring test valve. The TCP guns are positioned, fired, released and dropped (left). The assembly is then repositioned so that the screens are across the perforated interval (right). The upper gravel-pack packer is set and gravel is injected behind the screen. The workstring is then disengaged, leaving the packed screens in place. Operations take place in a controlled environment so formations are not exposed to overpressure, LCM or damaging fluids. 68 Modern Sandface Completion Practices However, efficient proppant placement is required to create an external pack. Big holes with high shot density—12, 16, 18 or 21 SPF—and 60º or 45° phas- ing maximize flow area and prevent proppant screenout, or bridging, in the perforations. In screenless gravel packs, the for- mation is consolidated with resin and then fractured. Proppant injected in the fracture prevents the production of for- mation sand. Because proppant does not fill the perforations, perforating requirements are more like conven- tional hydraulic fracturing stimulations. The length of perforated interval should be limited. Perforations that do not com- municate with the fracture may produce sand and need to be eliminated or mini- mized. Hole diameter needs to be 8 to 10 times greater than the proppant diameter and perforations with 0° or 180° phasing should be oriented to within 30° of the preferred fracture plane.58 Propellant-assisted perforating. The combined use of propellants and perfo- rating for production enhancement is not new to the petroleum industry, espe- cially for natural completions in compe- tent formations. When used together, the propellant and perforating assembly employs a cylindrical sleeve of gas-gen- erating propellant that is simply slid in place over the outside of conventional perforating guns (Fig. 3.28). It can be run on wireline or in a TCP configura- tion. The propellant sleeve is ignited by detonation of the perforating charge and, as the propellant sleeve burns, energetic gases are released sending high-pressure shock waves through the casing and into the formation. This method of perforat- ing does not crush the formation rock, therefore reducing formation damage. A paper by Folse et al59 reviews an application for the combined propel- lant/perforating technique that has been successfully used in unconsolidated sands in the Gulf of Mexico to enhance the placement of proppant during frac- pack and gravel-pack treatments while perforating in a balanced condition. According to the case histories, the pro- pellant/perforating technique was used on several formation types; i.e., long intervals, highly deviated, and highly laminated with extreme permeability contrasts, that would traditionally be deemed as high risk for proper sand placement. In performing this tech- nique, the propellant sleeves are posi- tioned across the lower quality portions of the intervals with low permeability and resistivity to ensure that the perfo- rations in these intervals would be bro- ken down to accept fracturing fluids and proppant during the fracturing treatment consistent with the entire treated interval.60,61 Operators have shown that this tech- nique is effective in both underbalanced and overbalanced perforating situations. With the trend in the industry to reduce cycle time, the elimination of the under- balance/surge process to ensure clean perforations and all the associated rig time in obtaining control of the well following the surge are seen as signifi- cant opportunities for rig-time savings. It has also been proven that combin- ing propellant/perforating in a balanced scenario can offer a cost efficient and safe method when used as a near well- bore clean-up tool for pre-frac prepara- tion or high rate water packing. Perforating Summary Today, perforating often encompasses more than traditional running and firing of guns. Perforating systems are an inte- gral part of well completion equipment and completion operations that are designed to perform multiple operations in permanent completions, such as set- ting packers, pressure testing, perforat- ing one or more intervals and initiating tool functions, all in a single operation. Perforating based on average forma- tion properties and shaped-charge per- formance is being replaced by a more tailored approach. Because perforating is such a critical element of well pro- ductivity, the requirements of each well should be optimized based on specific formation properties. The best way to achieve this is to understand how reser- voirs respond to natural, stimulated and sand-management completions. Factors that need to be taken into account include formation compressive strength and stress, reservoir pressure and tem- perature, zone thickness and lithology, porosity, permeability, anisotropy, dam- age and fluid type—gas or oil. Perforating systems can be designed using new, sophisticated perforating analysis software programs, which pre- dict perforating efficiency under down- hole conditions. To help identify the Fig. 3.28. The StimGun assembly perforates and stimulates the well simultaneously. It employs a cylindrical sleeve of propellant over a specialty configured, perforating carrier. The pressure wave generated by the perforating charge ignites the propellant. Gas from the propellant enters the newly created perforations, breaking them down and stimu- lating the formation. 69 Chapter Three Cased-Hole Sandface Completions appropriate gun systems for a specific application, these programs combine modules that estimate downhole pene- tration, calculate productivity and deter- mine optimal underbalance. With all the tools and techniques that are available to the modern completions engineer, the best perforation designs are always based on specific well requirements to optimize production. Stand-Alone Screens As discussed in Chapter Two, slotted liners, conventional screens or premium screens can be used alone to control formation sand in open-hole comple- tions. They can also be installed as stand-alone screens in cased holes. As such, only their unique application in cased-hole completions is discussed in the Chapter. Using the D10, or tenth percentile from the sand distribution plot from a sieve analysis, as suggested by Rogers,62 is typical for determining slot width, wire spacing or media rating (premium screens) for a stand-alone screen. The tenth percentile or D10 des- ignation, means that the sieve size would retain 10% of the formation sand and allow 90% to pass through, as illus- trated in the sand size distribution plot in Figure 3.29. Here the tenth percentile (D10) size is 785 microns, or 0.030 in. The example in Figure 3.29 applies to sand grains down to 262 microns (0.01 in.) and would retain 77% of the sand. Finer sands and silts would initially pass through the screen. However, as a rubble zone or sand pack develops, they would be trapped by a combination of filtration and bridging on the pore throats of the coarse, well-sorted material. This phe- nomenon is demonstrated in Figure 3.30 and will likely occur when D40/D90 < 3 and Fines (particles smaller than 44 micron) < 2% by weight.63 In addition, the slotted liner or screen diameter need to be as large as possible. Therefore, stand-alone screen longevity is enhanced by increasing the area open to flow and decreasing annular flow outside the sand exclusion device. This type of design is obviously going to be most effective with very weak, medium-to-coarse- grained, mod- erately uniform sands that will quickly build up a highly permeable zone around the screen. It is commonly used for protecting pumps in shallow oil wells and especially for heavy oil wells, where technical problems and eco- nomics limit the effectiveness of other methods of sand control. Where the sands are somewhat stronger and more uniform, the bridging process becomes increasingly ineffi- cient. At low sand influx rates, most of the grains simply pass through the slots; therefore, it takes a long time for the pack to build up and the slots may become sand-cut or plugged with grains that are close to the slot size. Moreover, plugging of part of the screen leads to increased velocities and erosion in other slots. To avoid these problems, it is com- mon for screens used in deeper, more uniform sands to be designed with a smaller slot size in order to increase the chances of bridging. If minor or inter- mittent sand influx is expected, screen openings must be small enough to stop the sand over the majority of the grain size range, so that screen erosion can be avoided before a zone accumulates. Since it is not possible to saw-cut slots below 0.012 in. (305 microns), wire- wrapped screens, prepacked screens or premium screens are usually used in this service. Slotted liners and conventional screens are relatively low-cost sand control methods, and are reasonably successful in medium-to-coarse- grained, low-strength sands. Since they may have to be replaced in time, the outside diameter should be selected to permit washover operations. The OD should therefore be at least 1 in. or, preferably, more than 1.5 in. smaller than the production casing drift ID; and centralizers should be collapsible. There are two major problems with the use of plain screens inside perfo- rated casing: • There is a tendency for the screen to be cut-out by sand blasting from a few highly productive perforations during buildup of the pack zone (Fig. 3.31). This can be minimized by slowly bringing the well through the critical sand producing rate. • The perforation tunnels become filled with formation sand, which imposes an additional pressure loss due to the limited cross-sectional area over which linear flow occurs through the cement and casing. In the higher rate oil wells and in gas wells, this not only increases the Darcy skin factor, but may also introduce a rate-depen- dent skin due to turbulence. These effects can be minimized by perforat- ing at high shot densities with large diameter holes. Both of these problems become increasingly serious as flow rates and gas-liquid ratios (GLR) increase. Therefore, while conventional screens are often effective in low-rate oil wells (and particularly in heavy oil wells pro- ducing from highly permeable, coarse D10 10th percentile (D10)0 20 2,000 Cu m ul at iv e re ta in ed , % 1,000 500 200 100 50 30 20 Micron 40 60 80 100 Fig. 3.29. Sand distribution plot from sieve analysis Fig. 3.30. Effective screen control with coarse, well-sorted material Fig. 3.31. Eroded screen and base pipe 70 Modern Sandface Completion Practices sands), their performance in flowing oil and gas wells is often disappointing. One non-standard application for screens is for keeping marginal, minor sand influx out of sensitive wells (e.g., subsea producers, high-rate gas wells, etc.). In this situation, the perforations are essentially stable and the screen acts as a downhole fitter, forcing what little sand is produced to be deposited in the rathole. This seems to be the logic behind the screens used in the Frigg field in the North Sea, for example.64 However, once the rathole fills up, or sand production becomes significant, gravel packing is often needed. Prepacked screens and premium screens are more suited to this type of service than conventional screens, especially in cased-hole, perforated completions. Gravel Packing No special drilling operation is required for a cased-hole gravel pack. The casing is cemented conventionally at TD. The completion intervals are then perforated with high density, large diameter perfo- rations capable of penetrating the dam- aged zone. The perforation damage is cleaned out behind the pipe by back flushing, underbalanced perforating, back surging or perforation washing. The screen is run and the gravel pumped (using the crossover circulating technique) into the perforation tunnels and casing/screen annular area. The key to success is the creation of a high permeability path through the casing, cement and damaged zone to permit effective packing, out against the native formation. The crossover circulating technique is the most common method used to place the gravel in the perforations and around the screen. The gravel-pack equipment and service tools allow circulating the gravel down the work- string above the packer and into the screen/casing annulus below the packer with returns coming back up the wash- pipe and up the workstring/casing. The fluid used to carry the gravel can either leak off to the formation or be circu- lated out of the hole through the wash pipe (Fig. 3.32) depending on the position of the service tools and the condition of the perforation in terms of accepting fluid leak off. In theory, open-hole gravel packs result in better productivity than inter- nal gravel packs, especially at high rates and/or with viscous crude oil. In practice, they are often more difficult to effectively plan and install. Moreover, improved squeeze-packing techniques and perforation/cleanout methods have greatly improved the success of cased- hole gravel packs. Cased-hole gravel packing, offers more flexibility, selec- tivity, planning time and cost/rig-time savings. An illustration of a success- fully placed cased-hole gravel pack is shown in Figure 3.33. Cased-hole gravel packs are one of the most common methods for control- ling the production of formation sand in oil and gas wells. Cased-hole com- pletions are more popular than open- hole gravel packs for several reasons.65 First, if the operator is not aware of a need for sand control when the well is drilled, a perforated casing completion can be installed with the gravel pack being installed later if the need arises. Also, cased-hole completions are often required for the upper zones of multi- zone completions. In addition, water or gas exclusion is easier in a cased-hole completion, and wellbore stability is more easily maintained. One negative aspect of the cased-hole completion is low productivity unless gravel is placed through and outside the perfo- rations properly. In either type of gravel pack, the gravel-pack sand or substitute must be properly sized if sand is to be controlled and permeability impairment avoided. Fig. 3.32. Schematic of cased-hole gravel pack Fig. 3.33. Successfully placed cased-hole gravel pack 71 Chapter Three Cased-Hole Sandface Completions Techniques to do this were discussed in Chapter Two, along with establishing the proper slot width of slotted liners and wire spacing of conventional screens. There is one principle differ- ence in screen designs between open- hole and cased-hole gravel packs. The radial difference between the OD of the screen and the casing ID should be at least one inch and in an open-hole that annular distance is two inches. The one- inch clearance inside casing is large enough to reduce the chance of forming a gravel bridge during gravel placement and still allow sufficient room to wash over the screen, should it be necessary to remove it. A successful cased-hole gravel pack requires that the perforations or frac- tures extending past any near-wellbore damage (as well as the annular area between the OD of the screen and the ID of the casing) be tightly packed with gravel. Because of likelihood of incom- plete perforation packing in a single placement process (Fig. 3.34), cased- hole gravel packing is sometimes done as a two-stage process. The first stage is packing the perforation tunnels with gravel, which is referred to as a perfora- tion prepack. The second stage is pack- ing the annulus between the screen and the casing ID with the same gravel. Perforation Prepacking Several completion techniques have been developed to help alleviate the problems associated with cased-hole gravel packs. One commonly applied technique, which has demonstrated to be quite effective, is perforation prepacking.66 Perforation prepacking can be done below the fracture pressure or above the fracture pressure. Prepacking below frac pressure. This process involves placing gravel through the perforation tunnels, into the cavity created at each perforation behind the casing, Figure 3.35. Prepacking controls fluid loss, increases perforation filling efficiencies and decreases drawdown pressure drop through the perforations tunnels by pre- venting formation sand filling the tun- nels. Filling the perforations with gravel is the key to obtaining high productivity from the well. In an unconsolidated for- mation, any perforation not filled with gravel will be filled with formation sand. Therefore, the greatest potential for flow restriction is at the perfora- tions, where the flow pattern becomes linear instead of radial. A major chal- lenge of packing operations is to trans- port gravel through the perforations in order to pack the entire area around the perforation tunnels with very high per- meability gravel. Pressure drop through the perfora- tion tunnel is minimized if the tunnel is filled with high permeability gravel as opposed to formation sand. Tables 3.14 and 3.15 compare the calculated pres- sure drops in different perforation Void in annular pack Incomplete perf filling Damaged zone Fig. 3.34. Incomplete perforation packing equals poor communication with native reservior System analysis Production, blpd P w f, ps i Case k, md Q, bpd Skin #1 120,000 4,439 0 #2 900 2,121 14.5 #3 300 1,064 40 #4 150 609 80 0 750 1,500 2,250 3,000 #4 #2 #3 #1 0 2,500 5,000 k = ______L Lj kjj=1 7,500 10,000 ∑ n Fig. 3.36. Effect on productivity of formation material partially filling perforations Fig. 3.35. Prepacked perforations 72 Modern Sandface Completion Practices diameters for formation, sand-filled perforations and for gravel-filled perfo- ration tunnels. These tables dramati- cally emphasize the critical importance of complete perforation filling during the gravel placement process.67 The technique for making these pressure drop determinations is described in the next section. The prac- tical effect of the productivity lost from the increased pressure drop caused by partial filling of perforation tunnels with formation material has been described in a recent publication68 and is illustrated in Figure 3.36. When it is considered that prepack- ing can be defined as any method that intentionally places gravel into the per- foration tunnels and out into the forma- tion, it becomes obvious that several techniques should be available to accomplish this. Filling of perforation tunnels can be accomplished either with a dedicated operation prior to running the gravel-pack assembly, or it can be accomplished by forcing injection into the perforations during gravel packing. So, in evaluating cased-hole, gravel- pack completion techniques the distinc- tion becomes: (1) was a dedicated prepack performed, (2) was the prepack performed with the gravel-pack assem- bly in the hole, or (3) was a circulating gravel pack performed with limited leak-off to the formation. Figure 3.37 shows the open-ended tubing method or prepacking perforations before installing a screen. Tubing can be recip- rocated through gravel while a braden- head squeeze is applied, or a packer can be run to squeeze perforations.69 The applied technique is normally dictated by well parameters such as excessive fluid loss, extended rat hole area, reser- voir acid sensitivity, zone length, etc. An additional concern that must be addressed is which carrier fluid was used for the prepacking operation. A choice might be an acid-prepack method (a combination stimulation and sand control procedure that can help yield high productivity). One of the most beneficial aspects of the acid- prepack method of sand control is the combination of damage removal, or breakdown by the acid, and the excel- lent sand control initiated by the prepacking gravel. Some diverting tech- nique may need to be employed to insure coverage of the entire perforated interval.70 With damage removed from the formation face and the perforations, the carrier fluid can easily leak-off and allow the gravel to more effectively pack the perforation tunnels. Prepacking above frac pressure. One of the main detriments to prepacking below fracture pressure is that gravel can only be placed into spaces created during the perforating and perforation cleanup operations. If this amount of penetration into the formation does not extend completely through the near- wellbore damaged zone, restricted well productivity will result. To overcome this difficulty, it becomes necessary to remove the damage with acid. As just demonstrated, while this is possible, it is not always easy to accomplish. Another technique to eliminate the effects of the damaged zone is to bypass it rather than to attempt to remove it. This can be accomplished by hydraulically inducing a fracture. Techniques available to create these fractures include a high rate water pack (HRWP) or a full-scale frac pack (dis- cussed later in this Chapter). The HRWP technique was pioneered by Exxon71,72 and later refined by Arco/Vastar (now BP Amoco).73 These early jobs were originally placed in two steps: 1. Braden-head prepack with a high-viscosity slurry pack (15 ppa gravel concentration mixed in 80 lb/1,000 gal HEC). 2. Circulating gravel pack with a low-viscosity water pack. The circulating gravel-packing pro- cess places gravel at low concentrations (1 to 2 ppa) into the perforations and around the gravel-pack screen. The gravel is mixed with completion fluid. This is accomplished using a sand injector located on the high-pressure, downstream side of the pumping unit. The sand is inserted in the treating line intermittently in 2 ft3 batches. Pump rates are 2 to 3 bpm. The gravel pack service tool is placed in the circulating position (see Fig. 3.47). The gravel travels down the drill pipe, through a crossover port around a cylindrical gravel-pack screen. Packer location Tubing Cement Perforations Casing Plug depth Unconsolidated formation Perforation tunnel Fig. 3.37. Prepacking perforations with open- ended tubing Pressure Drop (psi) Flow Rate 3/8 in. Diameter 1/2 in. Diameter 3/4 in. Diameter (bpd/Perforation) Perforation Perforation Perforation 1 450 190 64 10 27,760 9,280 2,091 Table 3.14. Pressure drop in packed perforation with 1,000 md formation sand Pressure Drop (psi) Flow Rate 3/8 in. Diameter 1/2 in. Diameter 3/4 in. Diameter (bpd/Perforation) Perforation Perforation Perforation 1 2 1 0.4 10 55 21 6 25 272 99 25 Table 3.15. Pressure drop in packed perforation with 119,000 md 20/40 mesh gravel 73 Chapter Three Cased-Hole Sandface Completions In the late 1980s, water packs (Step 2 above) were refined through new equipment and placement techniques. Service companies developed more sophisticated blending equipment to proportion gravel and water (brine) at consistent concentrations and in large volumes. Surface equipment is reviewed in Chapter Four. In a HRWP (Fig. 3.38) a fracture with a length between 5 and 15 ft (1.52 to 4.57 m) is created with a low-viscos- ity, brine carrier fluid. Pump rates are higher than conventional gravel packing operations, but usually lower than for a frac pack. Typical pump rates are in the range of 8 to 12 bpm. Proppant loading is held constant between 1 and 2 ppa, and total job size is typically from 100 to 150 lb/ft, which provides 2-3 lb/ft2 of fracture conductivity. These treatments can be multi-staged to further enhance the ability to effectively treat several sand subintervals with a single treat- ment. This will better the chances of proppant coverage into all perforations and greatly increase the sand placement behind pipe. The HRWP is designed to be pumped above fracturing pressure, so that a short fracture ( reduction associated with formation sand/gravel intermixing. The procedure consists of pumping gravel at high con- centrations in a viscous transport fluid.78 The slurry is usually batch-mixed in a blender or paddle tank before it is pumped. Although the fluid can be either water or oil-based, hydroxyethyl cellulose (HEC) viscosified brine is the usual choice.79,80 The typical polymer loading is 60 to 80 lb/1,000 gal. In some situa- tions, the gelled fluid is crosslinked so that it creates very high viscosities. The concentrations of gravel usually pumped with slurry-pack fluids are about 10 lb/gal. In certain situations, however, con- centrations have ranged from much less than 10 to more than 18 lb/gal. When these high-density fluids are pumped, the fluid and gravel tend to move as a mass. Compared with the low-density conven- tional gravel-pack fluid, these slurry sys- tems have significantly greater gravel- suspending capabilities. Depending on well conditions, pump rates normally range from 1/2 to 4 or 5 bpm when gravel is placed around the screen. When high-viscosity fluids transport gravel into the completion interval, a reserve volume must be specified. To allow for subsequent resettling, this vol- ume is usually higher than the reserve volume required for low-viscosity flu- ids. Well conditions affect the gravel reserve volume when viscous fluids are used. Before the gravel is pumped, the service provider should calculate the theoretical amount of gravel required to pack the annulus around the screen and the amount of gravel reserve. Place- ment should be approximately 100% under ideal conditions. Depending on the additional gravel placed through the perforations, possible bridging in the tubulars or pumping conditions, the amount of gravel placed could differ from the theoretical volume. If the amount of gravel is considerably less, premature bridging has probably occurred. Therefore, before the well is placed on production, gravel must be settled around the screen and additional gravel must be pumped. When high-viscosity fluids circulate gravel around the screen, the pump rate should be low enough that the viscous drag forces do not exceed the gravita- tional forces once the slurry has reached the completion interval. If the viscous forces become dominant, the gravel will be drawn into the screen rather than set- tling to the bottom of the well. As a result, the gravel will pack radially out- ward from the screen, possibly resulting in premature indications of a completed gravel pack. This type of packing geome- try and sequence is not desirable; ideally, the gravel should dehydrate from the bot- tom of the completion interval upward. The potential for non-uniform packing is one of the significant disadvantages of slurry packs. Therefore, the actual vol- ume of gravel pumped should be care- fully compared to the theoretical volume. This is illustrated in Figure 3.39. If the pumped-gravel volume is much less than the theoretical volume when high-viscos- ity fluids are used, the gravel should be allowed to settle before additional gravel is pumped for completing the pack. An upper tell-tale screen should be avoided when high-viscosity fluids are used for circulating gravel because gravel will probably screenout on the upper tell-tale. This screenout could prevent gravel placement over the main completion interval. A lower tell-tale screen should be used for slurry pack- ing. This lower tell-tale allows the sand- laden slurry to be effectively placed across the payzone to be gravel packed. Because of gravel settling, part of a gravel reserve volume will be filled if well deviations do not exceed approxi- mately 60°. A lower tell-tale screen is usually used with slurry packing. The washpipe is attached to the bottom of the screen section between the lower tell-tale and the primary screen. Slurry packs are effective in certain cases where only low horsepower pumping equipment is available or batch-mixing equipment is preferred. Frac packing has replaced the applica- tion of flurry packing in most cases. Well Productivity It is important to briefly discuss the effects that perforations can have on well productivity, especially in a gravel- packed well. The productivity of a well is usually discussed in terms of a productivity index (PI, or J). The productivity index, J, for a well is defined as the ratio of the flow rate, q, to the difference between the average reservoir pressure, pr, and the bottomhole flowing pres- sure, pwf as follows: The denominator of the above expression, pr – pwf, is referred to as the drawdown. For laminar, radial flow of a single- phase liquid with viscosity, m, in a reservoir of height, h, the relationship between drawdown and flow rate, q, is given by Darcy’s law, as follows: Where: B = formation volume factor, v/v J q p p kh B r r S bpd psi r wf e w = − = − +[ ]141 2 0 75. (µ ln / ) . J q p p bpd psir wf = − Fig. 3.39. Void form while slurry packing 75 Chapter Three Cased-Hole Sandface Completions µ = fluid viscosity at reser- voir conditions, cp k = effective permeability of reservoir to fluid, md re = drainage radius, ft rw = wellbore radius, ft A deviation from the logarithmic pressure change with radial distance from the well can be expected in the near wellbore region and is termed skin effect. Commonly, an additional pressure drop or positive skin is observed. This is generally the result of formation dam- age or ineffective or incomplete perfora- tion of the payzone. Many effects can combine to cause this sort of damage. Some of the most common are: • Completion/workover damage (as a result of plugged perforations, solids deposition in the pores, swollen shales, clay or scale precipitation, water blockage, etc. This results in a zone of reduced permeability around the perforations) • Perforation efficiency (in terms of the length of perforation, shot density, phasing, perforation diameter, and, most critically, the extent and perme- ability of the crushed zone also affects the skin) • Drilling damage (although commonly cited as the cause of skin, it is much less critical now that high-powered perforating guns can fully penetrate the damaged zone) • Turbulent or rate-dependent non- Darcy skin (which is common in gas wells and high-rate oil wells. This effect is generally linear with flow rate and is best determined by multi- rate testing. This effect dramatically increases with partial penetration and is claimed proportional to [h/hp]2) • Pressure losses in the completion (which appears as an additional skin effect-especially in cased-hole gravel packs where both Darcy linear flow effects and non-Darcy effects can be expected) • High liquid gas ratio (> 100 bbl/mmcf in gas wells) • High GOR (> 1,000 scf/bbl in oil wells) • Two or three-phase production in reservoir (Pr > Pbp; Pwf < Pbp) • High drawdown (Pr - Pwf > 1,000 psi) • High flow rate (> 20 bpd/ft) • Inadequately packed perforations (cased-hole gravel pack completions; poor formation/gravel interface due to mixing). Negative skin factor may be caused by: • Zone of increased permeability around the wellbore (due to acidizing, underreaming, sand production, or deep perforations) • Hydraulic fractures (causing linear flow patterns in highly permeable fractures) • Anisotropic reservoirs (causing non- radial flow patterns) • Horizontal/deviated wells (resulting in an increased amount of sandface being exposed compared to a vertical well; essentially this can be considered to be the inverse of partial penetration). Thus, the effect of a gravel pack (and/or the efficiency of the gravel- packing operation from a production viewpoint) is seen in terms of a varia- tion in skin factor. Alternatively, we can look at the ratio or deviation between the well's actual productivity (Ja ) and the ideal productivity of an equivalent fully penetrating open-hole completion with zero skin (Jo), which can be com- puted theoretically. Investigations have been done illus- trating methods of theoretically calcu- lating the various skin effects, espe- cially for gravel-pack design and performance prediction – the simplest form being the computation of the addi- tional pressure drop over the perfora- tion tunnel under Darcy and non-Darcy conditions.81 Pressure calculations can be made using the following equation and the β-factor pIot (Fig. 3.40) reported by Saucier:82 = 20% = 30% 102 103 104 105 106 107 108 0.1 1.0 20/40 U.S. mesh Sand 20/40 U.S. mesh Ottawa Flint 20/40 U.S. mesh Glass Spheres Test points from previous gravel pack tests 10 100 1,000 In er tia c oe ffi ci en t, ( ft- 1 ) Gravel permeability, k (Darcy) Fig. 3.40. Relationship between inertia coefficient and gravel permeability HEC Gel Brine Fluid Viscosity 300 - 750 cp 1 -2 cp Typical gravel concentration 10 - 15 ppg 1 - 3 ppg Typical pump rate 1 - 4 bpm 4 - 5 bpm Tell-tale screen used Yes No Table 3.16. Comparison of HEC slurry pack and brine water pack carrier fluids 76 Modern Sandface Completion Practices Where:A = cross-sectional area of perforation, sq ft B = formation volume factor, v/v β = inertia (turbulence) coefficient, ft -1 (Fig. 3.40) k = permeability of fill material, Darcy L = length of perforation tunnel, ft q = production rate, bpd ρ = fluid density, lb/cu ft µ = fluid viscosity under downhole conditions,cp ∆p= pressure drop, psi The calculated data, shown earlier in Tables 3.14 and 3.15, demonstrate the need for high perforation density when high production rates are desired through small gravel, plus the impor- tance of avoiding formation sand influx into the perforation tunnels. While the cased-hole gravel pack inevitably results in some loss of pro- ductivity, the pressure losses across an open-hole pack will probably be less than what would have occurred through the equivalent section of formation prior to underreaming. Maximizing gravel permeability is therefore not so critical in open-hole packs. They have a greater tolerance to inadequate design and installation practices. Carrier Fluid Selection A variety of fluids have been used as gravel-carrier fluids for gravel-packing operations include brine, oil, diesel, crosslinked gels, clarified xanthum gum (XC) gel and hydroxy-ethylcelluse (HEC) gel, and foam. The most com- monly used fluids have been brine and HEC gel. Gravel packs performed with brine carrier fluids are referred to as water packs or conventional packs. Gravel packs performed with HEC gel carrier fluids are referred to as slurry packs or viscous packs. Table 3.16 is a comparison of HEC gel (also referred to as slurry pack) and brine, or water-pack characteristics in regards to their use as gravel transport fluids. When using HEC, the gravel- pack sand is influenced primarily by viscous forces (i.e., the gravel is sus- pended by the gel). When using brine as a transport fluid, the gravel is influ- enced primarily by gravity forces (i.e., the gravel settles quickly). Hence, higher pump rates may be required to cope with settling in some situations as Table 3.16 suggests. Slurry packs, which were introduced earlier in this Section, are used to trans- port sand concentrations of 4 to 15 ppg. The main advantages to this type of system are that a minimal amount of water is used to pump the slurry and the pumping rate can be slowed so that gravel and formation sand intermixing is minimal. The low leak-off rates and the limited amount of water used in this system can also be a disadvantage. Slurry packing can leave voids in the annulus pack and can allow incomplete perforation tunnel packing. Water packs, pumped at 2 to 5 bpm, use brine as a carrier fluid for gravel. In recent years, water packs have become an increasingly popular alternative to slurry-pack methods using HEC and other polymers that can damage forma- tion permeability. Water packs can form very tight annular packs. One disadvan- tage of water packs, however, is their high leak-off rate in high-permeability zones, which can cause bridging in the screen/casing annulus. This bridging can cause a premature screenout of the treatment if not used in conjunction with an Alternate Path screen. An alternative to the water pack is the high rate water pack (HRWP), which is pumped at 5 to 25 bpm and above the frac pressure. This technique will be discussed more completely later. But briefly, it was developed to enhance gravel placement into the perforations to obtain higher completion efficiencies than water packs pumped at lower rates. The main objective of annular gravel placement is to effectively pack the annulus between the screen and the casing or the open hole. For cased-hole completions, as mentioned already, an added objective is to pack the perfo- rations with gravel since the latter sig- nificantly improves well productivity and longevity. In addition to perforation packing, the quality of the pack in the screen/cas- ing annulus is important regardless of whether the well is completed open or cased hole. Figures 3.41, 3.42, 3.43 and 3.44 show gravel-pack log examples from actual wells where both water packs and slurry packs were used. These logs indicate complete annular packing when using water packs. The gravel packs performed with a slurry pack show the presence of large voids in the annular pack which, if not repaired, will result in formation sand production. Gravel-pack evaluation techniques are discussed in Chapter Four. Field Evaluation A common approach to qualitatively assess the results of a gravel pack is to ∆p L k A x L A = + ( ) µ βρ βρ βρ 1 127 0 1 10 13 2 . -. Fig. 3.41. Water pack in gas well - 7,600 ft depth, 51° deviation, 42 ft net perforations Fig. 3.42. Water pack in oil well - 3,600 ft depth, 67° deviation, 76 ft net perforations Fig. 3.41 Fig. 3.42 77 Chapter Three Cased-Hole Sandface Completions determine the “pack factor”. The pack factor is simply a measure of the quan- tity of gravel placed behind casing dur- ing the gravel-packing operations. The pack factor is calculated using a mate- rial balance as follows:83 Where: PF = perforation pack factor, lb of gravel/ft of perfs Vt = total amount of gravel pumped during prepacking and gravel packing, lb Vs = total amount of gravel filling the screen and casing annulus, lb Vb = total amount of gravel filling the blank and casing annulus, lb Vcp = total amount of gravel filling casing after prepacking, lb Vr = total amount of gravel reversed out of well after prepacking and gravel packing, lb Hn = net perforated interval, ft While the pack factor does not pro- vide strong correlation to well perfor- mance, it does provide information upon which comparisons of perforation filling efficiencies of different carrier fluids can be made. Figure 3.45 is a presentation of pack factor for four gen- eral classes of wells, old and new oil wells and old and new gas wells. This plot indicates that regardless of the well type, water-pack fluids are capable of placing more gravel behind casing than are slurry packs. Similar results can also be recognized as a function of interval length and well deviation. These results combine to offer strong support that water-pack, low-viscosity carrier fluids are actually more efficient in filling perforation tunnels than are the gelled slurry-pack fluids. Figure 3.46 illustrates that, although some scatter is present, there is a benefit of increased injection rates when using brine to carry gravel into perforation tunnels. These data suggest that the best practice for prepacking perforation tunnels, especially when packing below fracture pressure, is to inject the brine/gravel slurry at the maximum rate practical. Because perforation filling with gravel is so important, it is recom- mended that the prepacking operation be carried out at the earliest possible opportunity (i.e., immediately after per- forating). In addition to helping control fluid loss, prepacking immediately after PF V V V V V H t cp s b r n = − − − − 0 ( 20 8) 58 (6) 24 (75) 56 (3) 26 (1 40 ) 45 Brine carrier fluid Viscous gel carrier fluid ( ) Number of zones (14) 24 (82) 65 (7) 30 10 20 30 40 50 60 70 New gas Old gas New oil Old oil Gr av el p la ce m en t, lb /ft Well type Fig. 3.45. Perforation pack factor as function of well type Fig. 3.43. Water pack in oil well - 12,800 ft depth, 68° deviation, 50 ft net perforations Fig. 3.44. Water pack in oil well - 13,600 ft depth 0 50 100 150 200 250 300 .05-.1 .21-.3 .31-.4 .41-.5 .51-.6 .61-.7 .71-.8 .81-.9 .91-.1 1.1-2 2.1-3 3.1-4 4.1-5 >5.11-.2 Gr av el p ac k fa ct or , l b/ ft Leakoff rate, gpm/perforation Fig. 3.46. Leak-off rate effect on perforation filling efficiency Fig. 3.43 Fig. 3.44 78 Modern Sandface Completion Practices perforating affords two opportunities to place gravel in the perforations (i.e., during the prepack and during the gravel pack). Although this method may require an additional trip to clean out the well prior to gravel packing, the improved gravel placement typically outweighs the additional cost associated with the additional wash trip. Gravel Pack Methods Various gravel-pack completion meth- ods involve a wide assortment of equip- ment that remains in the well as part of the completion after the gravel place- ment operations are complete. The equipment discussed below does not represent all the types that are available, but does represent a typical gravel-pack completion. The equipment design rec- ommendations discussed below are just that – recommendations. It is important to remember that certain well condi- tions may require compromises in the type and design of gravel-pack equip- ment that can be run. The compromises must be made in light of the risks they create and certain compromises will be preferable to others. Another important concept to remember is that there may be several different, yet equally effec- tive, ways to complete a well. A single- zone gravel may be equipped as illus- trated in Figure 3.47. The sump packer is run with a wire- line setting tool and positioned with a casing collar locator (CCL). The sump packer can also be set on pipe with a hydraulic setting tool. When run on pipe, it must be positioned with wireline using a radioactive marker (CCL and RA tag). It is usually set 8 to 12 ft (2.44 to 3.66 m) below the proposed perfora- tions. This point becomes the reference point for subsequent bottom-hole assemblies (perforating guns and gravel- pack assembly). The well is typically perforated using tubing conveyed perfo- rating guns (TCP). After perforating, the guns are removed (or can be left in the hole for one-trip perforate and pack technique, which is described next) and the following is run in tandem: • Seal assembly • Gravel pack screen • Blank Pipe • Gravel pack packer • Service tool. The gravel-pack packer is set hydraulically with applied surface pressure. This is accomplished with a service tool (Fig. 3.48) placed inside the gravel-pack packer. The service tool provides a means to set the gravel-pack packer and a means for directing the fluid flow with respect to the wellbore. One-Trip Perforate and Pack System The one-trip perforate and pack system (Fig. 3.49) provides the versatility and time savings of running a perforating assembly with a retrievable gravel-pack packer/production packer in a single trip. It can be used in applications for gravel packs or frac packs. Since perfo- rating and packing are done in a single trip, rig-time savings can be substantial. This system should be used to perfo- rate intervals up to 50 ft (15.24 m) long with well deviation angles less than 45°. At deviation angles over 45°, spent perforating equipment and debris may not fall completely to the bottom of the well, making operations difficult. Circulating (pre-perforating) posi- tion. From the bottom up, the compo- nents of the one-trip perforate and pack system are the perforating guns, auto- matic-release drop-bar firing head or pressure-activated firing head, recipro- cation-set packer (without an integrated equalizing bypass), bypass valve, lower O-ring sub or seal sub, tell-tale screen, O-ring sub, production screen, blank, ceramic flapper valve and the retriev- able gravel-pack assembly. A radioac- tive marker (RA tag) is normally run one joint above the multi-position ser- vice tool. This marker provides a stimu- lus for the gamma-ray depth correlation tool that is later run on wireline. Perforating position. The downhole assembly previously discussed is run to the desired depth. Wireline is then run through tubing to provide positive depth correlation. The assembly, with the aid of the wireline correlation, is spaced across the zone of interest and the reciprocation-actuated GO packer is set. The bypass valve above the GO packer is opened and diesel or nitrogen is pumped to displace the packed-off area and provide the desired pressure for underbalanced perforating. The bypass valve is then closed to isolate the annu- lus above the GO packer. When the downhole environment is ready, a drop bar is dropped down the QUANTUM service tool QUANTUM GP packer Ported housing Sealbore housing Locating collar Check valve Safety shear sub Screen Perforations Casing Seal assembly Sump packer Running in/setting QUANTUM packer Fig. 3.47. Downhole equipment for single gravel-pack completion 79 Chapter Three Cased-Hole Sandface Completions tubing to fire the perforating guns. Upon firing, the guns are released and fall to the bottom of the hole. A prede- termined amount of formation fluids are produced to clean the perforation tunnels. The bypass valve is then reopened and the hydrocarbons are flowed out of the tubing. Before retracting the GO packer the bypass valve is shut and pressure is applied to the annulus. This annular pressure opens the annular bypass valve while rig pull is applied to release the GO packer. The annular-pressure-oper- ated bypass valve prevents a possible fluid lock from occurring in the system. After the GO packer releases, the entire assembly is lowered until the screen is properly positioned across the perfo- rated interval. Then, the GO packer is reset and the gravel-pack packer is set. The downhole tool assembly is now ready for the gravel-pack portion of the perforate and pack application. Squeeze position. The squeeze position of the multi-position service tool allows the gravel-pack media to be pumped downhole into fractures, perforations and the annular pack area. Two func- tions are actuated by a setting dart that is dropped down the tubing string at the beginning of the squeeze stage. The set- ting dart first allows the packer to be set and tested against the pressure applied to the annulus. Then, by using rig pull and pressuring the tubing, the dart is forced farther down the tool where it will seat and block the gravel- pack ports. Pressuring the tubing string again opens the gravel-pack ports and rig weight is applied to lower the ser- vice tool into squeeze position. The set- ting dart now functions as a plug for gravel packing and as a ball check valve to prevent fluid loss when the tool is in the circulating and lower circulating positions. Lower circulating position. Rig pull is applied to the downhole assembly to move the multi-position tool from the squeeze position to the circulating posi- tion. Returns are collected at the screen and flow up the washpipe. Pack completed. When the gravel-pack portion of the perforate and pack appli- cation is completed, the service tool is retrieved from the well. As the wash- pipe is pulled up hole it releases a prop Circulating gravel Reversing out excess gravel Producing oil and gas Fig. 3.48. Schlumberger downhole gravel-pack assembly 80 Modern Sandface Completion Practices from the flapper, allowing the flapper to seat. The formation is now isolated from the wellbore fluids. Frac Packing Frac packing was first discussed in Chapter Two as it applied to open-hole sandface completions and was briefly discussed in the previous section. Frac packing is a process that involves pumping gravel or proppant into the perforations at rates and pressures that exceed the frac pressure of the forma- tion. The intention is to bypass any near-wellbore damage remaining from the drilling/perforating phase of opera- tions. A procedure referred to as tip screenout (TSO) is used to achieve a high sand concentration in the near- wellbore area. Frac packing is an alternative that should be considered during develop- ment planning for fields that produce sand. As a percentage of sand-control treatments and in terms of total jobs, frac packing is growing steadily. Use of this technique increased tenfold—from fewer than 100 jobs per year during the early 1990s to a current rate of almost 1,000 each year. In West Africa, about 5% of sand-control treatments are frac packs, and operators frac pack at least 3% of the wells in Latin America. Advances in stimulation design, well completion equipment, treatment fluids and proppants continue to differentiate frac packing from conventional gravel packing and fracturing. US operators now apply this sand-control method to complete more than 60% of offshore wells (Fig. 3.50). Shell used the term frac pack as early as 1960 to describe well comple- tions in Germany that were hydrauli- cally fractured prior to gravel pack- ing.84 In current usage, frac packing refers to tip-screenout fracturing treat- ments that create short, wide fractures and gravel packing around sand exclu- sion screens, both in a single operation (Fig. 3.51). The result is short but wide to extremely wide fractures. While in more traditional, unrestricted fracture growth an average fracture width of 0.25 in. (0.64 cm) would be the norm, in TSO treatments, widths of 1.0 in. (2.54 cm) or even larger are commonly expected. These highly conductive propped fractures bypass formation damage and alleviate fines migration by reducing near-wellbore pressure drop and flow velocity. In the Gulf of Mexico, frac packing became increasingly popular beginning in the late 1980s. Amoco, now BP, per- formed five frac-pack completions in the Ewing Bank area during 1989 and 1990 by batch mixing up to 6 lb (2.7 kg) of proppant added (ppa) per gallon of treatment fluid.85 In 1991, ARCO, now BP, performed frac packing in the South Pass area.86 Pennzoil, now Devon Energy, used this technique in the Eugene Island area.87 At about the same time, Shell began frac packing inland wells from barges in Turtle Bayou field, Louisiana. Later, Shell expanded the use of this technique in the North Sea and to offshore wells in Borneo, and also to onshore wells in Colombia, South America and north- west Europe.88 Frac-packing success led to increased use, and this technique soon became the preferred sand-control method in the Gulf of Mexico, where several thousand oil and gas leases lie in water deeper than 3,000 ft (914 m). During 1992, BP completed frac packs in Mississippi Canyon Block 109, Fig. 3.49. Halliburton one-trip perforate and pack system Frac packs 60% Gravel packs 12% High rate water packs 28% Fig. 3.50. US offshore sand control market Tip screen out Wellbore top view Fig. 3.51. Frac packing process 81 Chapter Three Cased-Hole Sandface Completions where water depths range from 850 to 1,500 ft (260 to 460 m).89 A few years later, Shell and Chevron used frac pack- ing to develop fields in water up to 3,000 ft (914 m) deep. Technology transfer and frac-pack- ing success in other areas, such as Indonesia, the North Sea, the Middle East, West Africa and Brazil, are fur- ther expanding the worldwide applica- tion of this technique. Fracture stimula- tion and frac packing in high-permea- bility reservoirs now represent 20% of the fracturing market.90 The major benefit of a frac pack is theoretically due to forming a high con- ductivity path through the “critical” damage zone. Examples of how a dam- aged zone affects the results of a 25 ft (7.6 m) fracture are shown in Table 3.17. Note that the example fracture in a non-damaged 100 md formation will theoretically increase productivity by 83%, but in a 1,000 md formation by only 31%. The fracture does more rela- tive stimulation of low permeability formations than higher permeability formations. However, if formation damage has reduced the permeability by 90% in a 3 ft (0.9 m) thick zone around the well- bore, the 100 md formation will have been stimulated by 625% and the 1,000 md formation by 420%. A major assumption of these example calcula- tions is that a “perfect fracture” is estab- lished that (1) has no restriction to flow through the fracture, (2) causes no fur- ther damage to the formation, (3) allows production to be in non-turbulent flow through the propped fracture, etc. Means of controlling sand may be significantly different than in a gravel pack. This is because control of forma- tion sand movement in frac packs may be due to the reduction of produced fluid flux into the propped fracture, while a gravel pack must physically stop formation sand. Formation sand may not enter a propped fracture if the velocity of produced fluid flowing from the formation into the proppant is low enough to prevent fluidization of the sand. However, there are some situa- tions where gravel pack sizing criteria must be used to physically stop sand movement. Comparison of Frac Packs and Gravel Packs Not all frac packs exceed productivity results of all gravel packs. For instance, one company’s gravel pack skin factors in the US Gulf Coast ranged from about -3 to +60 and skins of frac packs from -4 to +26.92 Although most operators have reported improved productivity indexes (PIs) and lower skin factors for frac packs than for gravel packs, it is impos- sible to know how well these comparison gravel packs were designed and per- formed in the field. It would be interest- ing to know why some gravel packs had negative skin factors and others had such extremely high skin factors. Theoretically, successful gravel packs should stimulate well productiv- ity and yield negative skin factors. This is clearly seen in open-hole comple- tions, as underreaming removes some of the near-wellbore formation and damaged zone. Then, this low perme- ability sand is replaced by high perme- ability gravel. Figure 3.52 shows that if 6 in. (1.5 cm) of formation sand is removed by underreaming and replaced by 6 in. (1.5 cm) of gravel (Kg/Kc > 25), the resulting well productivity should be increased by more than 10%. Figure 3.53 shows that if the 6 in. (1.5 cm) of formation sand that is removed contains formation damage such that Kd/Ke = 0.05, the well productivity should be increased by more than three times what it would have been without under- reaming and gravel packing. 1.00 0 4 7 101 11125 8 92 3 6 Thickness of gravel pack, in. J g /J o 1.05 1.10 1.15 1.20 Kg/Ke = 2 Kg/Ke = 4 Kg/Ke = ∞ Kg/Ke = 25 Fig. 3.52. Effect of replacing formation sand with gravel pack 1 2 3 0 2 41 3 5 6 Thickness of damage zone, in. Lf = 25 ft, frac width = 1 in. Kg = 1,00,000 md, Ke = 1,000 md re = 660 ft, rw = 0.51 ft (perfect fracture) J g /J d Kd/Ke = 0.05 Kd/Ke = 0.1 Kd/Ke = 0.5 Kd/Ke = 0.2 Fig. 3.54. Effect of damage zone on frac- pack productivity 1 2 3 0 2 41 3 5 6 Thickness of damage zone, in. Kg/Ke >> 25 ~ � Kg = 1,00,000 md, Ke = 1,000 md re = 660 ft, rw = 0.51 ft J g /J d Kd/Ke = 0.05 Kd/Ke = 0.1 Kd/Ke = 0.5 Kd/Ke = 0.2 Fig. 3.53. Effect of replacing damage zone with gravel pack Damage Zone Permeability Damage J/Jo Damage J/Jo (md) (%) Ke = 100 md (%) Ke = 1,000 md 1 99 50.44 99.9 327.27 10 90 6.25 99.0 33.57 50 50 2.32 95.0 7.46 100 0 1.83 90.0 4.20 1,000 – – 0.0 1.31 Assumes: 12.25 in. wellbore, 3 ft thick damage zone, 100 Darcy proppant, 25 ft frac half length, 1 in. frac width, re = 660 ft Table 3.17. Effect of damage zone permeability when fractures bypass the formation damage. Assumes “perfect fracture” with no damage, turbulence or other restriction. Calculations by Raymond and Binder equation.91 82 Modern Sandface Completion Practices Underbalanced perforating, surging or washing perforations attempt to obtain the same effect in a cased hole as under- reaming an open hole. An attempt should always be made to remove as much for- mation sand and formation damage from outside the casing as possible and pack these voids, or unstressed areas, with high permeability gravel. Restriction to flow through gravel filled perforations should be minimized. Ideally, a frac pack should provide somewhat higher well productivity than a gravel pack, but this depends on many design and field operational factors. To assess the effect of a perfect hydraulic fracture in a formation that has a damage zone near the wellbore, the Raymond and Binder equation93 may be used: Where: And: And: Jf = productivity of fractured well (bopd or MMcf/d/psi) Jd = productivity of damaged, unfractured well (bopd or MMcf/d/psi) Ke = permeability of undam- aged formation (Darcy) Kd= permeability of damage zone (Darcy) Kf = permeability of fracture proppant (Darcy) rd = radius of damage zone around the wellbore (ft) rw = radius of wellbore (ft) re = drainage radius of reservoir (ft) Lf = half length of fracture (ft) w = width of propped fracture (ft) The above relationship assumes pseudo-steady-state flow, square drainage area, compressible fluid, no turbulence and perfect fracture. Figure 3.54 shows an example of a 1 in. wide fracture, with 25 ft half length, through a 6 in. thick damage zone (Kd/Ke = 0.05) that results in an increase of more than 3.5 times the pro- ductivity of an unfractured well with the damaged zone in place. The same Ke (undamaged formation permeabil- ity) and Kf (fracture sand permeability) was used as in the gravel packed exam- ple in Figure 3.53. Comparing an ideal gravel pack, with an ideal frac pack indicates that there might not be much difference in produc- tivity results. Consider the productivity increase comparisons shown in Table 3.18. Wider frac widths and longer frac lengths will theoretically increase results of a frac pack, but increased removal of formation damage replaced by increased volumes of gravel packed outside of a cased hole will theoretically improve results of a gravel pack also. Factors that favor frac packs. There are several factors that favor the use of frac-pack completions including: • Bypasses near wellbore formation damage • Accelerates production through increased sandface area • Connects thin sand layers • Stimulates low permeability formations • Reduces potential scale problems • Reduces potential fines migration. Fines are mobilized by velocity, vis- cosity, multi-phase flow and water break- through. This is illustrated in Fig. 3.55. The benefit of reduced fines migra- tion is because of the increased sand- face area. This reduces the drawdown and fluid velocity, increases the PI, and reduces near wellbore pressure drop. Example: 20 ft zone producing 100 bopd from the entire interval. B L w K K r f f e d w K K f e ( ) = + − + − π π 1 1 A r w K K r d f d w w K K f d ( ) = + − + − π π 1 1 J J K K r r r r K K A B r L f d e d d w e d e d e f = + ( ) + ( ) + ln ln ln ln ln Fig. 3.55. Fines migration Damage Zone Perfect Open-Hole Thickness Effect of Damage Gravel Pack Perfect Frac Pack rd-rw (in.) Kd/Ke Jgp /Jd Jfp /Jd 1 1.00 1.02 1.31 0.10 1.22 1.56 0.05 1.43 1.84 2 1.00 1.04 1.31 0.10 1.41 1.78 0.05 1.82 2.30 3 1.00 1.06 1.31 0.10 1.59 1.97 0.05 2.18 2.70 6 1.00 1.11 1.31 0.10 2.05 2.43 0.05 3.11 3.67 Assumes: Perfect gravel pack Kg/Ke >> 25 ~ ∝ , Kg = 100,000 md, Ke = 1,000 md, re = 660 ft, rw = 12-1/4 in., Perfect frac pack Lf = 25 ft, w = 1 in., Kf = 100,000 md, Ke = 1,000 md, re = 660 ft, rw = 12-1/4 in. Table 3.18. Comparison of frac pack with gravel pack 83 Chapter Three Cased-Hole Sandface Completions A 20 ft length, 20 ft height, “penny shaped”, propped fracture has a total surface area in contact with formation of 1,256 ft and fluid flux is 0.08 bopd/ft. An open-hole gravel pack of 20 ft interval with 1 ft thick pack of gravel around a 1 ft diameter wellbore has a total surface area in contact with forma- tion of 188 ft and fluid flux of 0.53 bopd/ft. This phenomena is illustrated in Figure 3.56. Disadvantages of frac packs. Con- versely, there are several factors that do not favor the use of frac-pack comple- tions including: • Frac out of zone (water/oil, water/gas, gas/oil) • Fracturing in a high-angle wellbore interferes with packing of gravel over the entire completion interval • More difficult to do remedial work such as shutting off water or gas • Higher cost than gravel pack • Higher injection pressures and rates are required, especially in long com- pletion intervals • Small casing or tubing restricts pump rates during treatment • Higher casing, tubing, screen, liner strengths needed to reduce collapse risk • Equipment for high pressure pumping not readily available in all locations • Special stimulation vessel needed for offshore locations. Gravel pack HRWP Frac Pack +5 to +10 excellent +2 to +5 reported 0 to +2 normally +40 and higher are reported – 0 to -3 in some reports Table 3.19. Skin values Prepacks above frac GOM frac packs -5 0 Sk in 5 10 15 20 25 30 35 HRWPs W. Africa frac-pacs GOM frac-packs G H F E ID C B A Fig. 3.58. Comparison of treatments pumped above formation fracture pressure 57 frac pack wells 23 HRWP wells 34% 11% 9% 14% 13% 13% 9% 39% 32% 34% Fig. 3.59. Skin distribution comparison between frac-pack and HRWP completions Fig. 3.56. Frac pack (top) vs. open-hole gravel pack (bottom) Fig. 3.57. Frac-pack applications. Frac packing is a viable completion alternative for many wells in reservoirs with sand- production tendencies. In reservoirs with moderate to high permeability that are sus- ceptible to drilling and completion damage that extends deep into the formation, frac packing and wide tip-screenout (TSO) frac- tures connect reservoirs and wellbores more effectively. When perforated interval length is limited, frac packing connects more pay with fewer perforations. Frac-pack comple- tions also improve hydrocarbon recovery from low-pressure and depleted reservoirs by minimizing completion skin across the pay interval, thus reducing drawdown and ultimate abandonment pressure. 84 Modern Sandface Completion Practices Frac packing also may not be eco- nomical for low-rate wells, water-source or injection wells that do not produce revenue directly, and reservoirs with limited reserves or homogeneous thick zones where horizontal gravel packing in open-hole is more appropriate.94 In more prolific reservoirs, flow tur- bulence associated with perforated cas- ing restricts production, so operators often drill and complete open-hole hori- zontal wells to optimize productivity. Stand-alone screens, open-hole gravel packs, or expandable or other premium screens are sand-control options in these settings, especially for thick reser- voir sections. Frac packing in open-hole completions is the next logical step to provide long-term sand control without sacrificing productivity95 (see the “Open-Hole Frac Packing” section of Chapter Two). Frac-pack candidate selection. Expe- rience from more than 4,000 Gulf of Mexico frac packs in formations with permeability’s ranging from 3 md to 3 Darcy helps oil and gas producers iden- tify frac-pack candidate wells (Fig. 3.57). Frac-packing well-completion applications include the following: • Wells prone to fines migration and sanding • High-permeability, easily damaged formations • High-rate gas wells • Low-permeability zones requiring stimulation • Laminated sand-shale sequences • Heterogeneous pay zones • Low-pressure and depleted reservoirs.96 Comparison of Frac Packs and HRWPs Frac packing is a general term applied to process of combining a hydraulic fracture with a gravel pack. An HRWP, which was described previously in this Chapter as a perforation prepacking technique, is usually done above frac pressure as well. In addition, the general term, frac pack, does not specify a car- rier fluid, therefore an HRWP is in most instances actually a frac pack method. The principle difference in these two techniques is the placement method: • Frac-pack placement: pump viscosi- fied fluid with “ramped” gravel con- centration (typically 1/2 - 15 ppa) at 5 to 40 bpm • HRWP placement: pump low-viscos- ity completion fluid with low gravel concentration (typically 1 to 2 ppa) at 5 to 15 bpm. Empirical data reported by Tiner et al,97 condensed and presented in Table 3.19, support the frequent notion that HRWPs have an advantage over gravel packs, but do not afford the productivity improvement of frac packs. This im- provement over gravel packs is reason- able by virtue of the additional proppant placed in the perforation tunnels. While not shown in the table, the performance of these completions over time is also of interest. It is commonly reported that production from HRWPs (as in the case of gravel packs) deterio- rates with time. By contrast, however, others,98,99 reported that production has progressively improved (skin values decrease) during the first several months following a frac pack treatment. Another study comparing frac packs with HRWPs has demonstrated that, although the fractures generated during a HRWP treatment are significantly shorter than those created during a frac pack treatment, the net result of both of these techniques is that good damage bypass is obtained.100 The parameter selected for comparison of frac pack with HRWP per- formance was skin. Skin was selected because of the industry acceptance of this parameter and because previous frac- pack data available had been reported in terms of skin. Figure 3.58 shows skin data from field data for frac-pack and HRWP completions. Similarly, Figure 3.59 presents pie charts of these same data so that the overall distribution of skins may be evaluated. The elevated skins in Figure 3.58, depicted by points letter A through I, can be attributed to conditions beyond what would normally result from the treat- ments. Therefore, these nine treatments are eliminated from the comparison. Hence, well productivity resulting from frac-pack treatments is indistin- guishable from those reported for HRWP completions. In the majority of situations, the decision concerning which technique to employ should be based upon cost and logistical issues. Even though in the majority of situa- tions these two techniques are inter- changeable, because of differences in reservoir properties, fluid properties and pumping practices, there are spe- cific applications that are better suited for one technique or the other. Table 3.20 lists the benefits and risks associ- ated with a frac pack and HRWP. Hydraulic Fracturing Concepts, Geometry and Rock Mechanics Details of rock mechanics and cre- ation of a hydraulic fracture are beyond the scope of this text. However, certain general principles are assumed to be understood and believed valid for most reservoirs: • Fractures are nearly always vertical (exceptions may be in very shallow wells and in tectonically active areas) • Fractures are oriented perpendicular to the direction of minimum principle stress (in most formations, this is the direction toward the maximum hori- zontal stress) • Fracture initiation pressure is nor- mally higher than fracture extension pressure • Fracture height and length continue to increase as long as the fluid pres- sure inside the fracture is larger than the least in-situ principal stress or until a barrier is reached or a sand out obtained. Hydraulic fracturing is most com- monly done in strong formations that have permeabilities less than 1 or 2 md, where a contrast between the proppant and formation permeabilities of 10,000 or more is desirable. Fracture lengths of 500+ ft (152.4+ m) and propped frac- ture widths of 0.2 in. (0.5 cm) or less are common. This is enough for good production results in low permeability formations. There are many unknowns and dis- agreements on the best means of frac- turing strong, low permeability rocks where fracturing has been applied for several decades. For instance, the SPE Monograph Volume 12, Recent Advances in Hydraulic Fracturing, published in 1989,101 states “fracture height is a variable that can be only grossly estimated with today’s technol- ogy.” Today, the technology of fractur- ing has improved in fracture designs for both the software and data needed in fracture design. The sophisticated computer pro- grams used to design, model and evalu- ate fracture treatments have greatly helped the process, but are often based on certain assumptions and question- able input data that affect the results of 85 Chapter Three Cased-Hole Sandface Completions fracture geometry. Length and height of a fracture are used to calculate the fracture width. A fracture is usually assumed to be elliptical, rectangular or “penny shaped” and both wings are equal length, height and width (Fig. 3.60). Therefore, a logical question is “How much confidence can be given to these computer programs for designing, modeling and evaluating fractures in weak, high permeability formations?” The above question can be answered based upon knowledge of rock mechan- ics, linear elastic fracture mechanics and laboratory and field based studies published by SPE. The fracture geome- try (height, length and width) is uncer- tain if the rock or soil mechanics prop- erties are uncertain. On the other hand, the fracture geometry can be predicted by software if the rock mechanical properties are known. The rock and soil mechanical properties measured or cal- culated in the laboratory for fracture designs are: • Young’s modulus (for fracture length, width and pressures) • Poisson’s ratio (for fracture height and formation stress determination) • Fracture toughness (for fracture height and length) • Minimum principal horizontal stress versus depth (for fracture height and pressure) • Proppant embedment (for fracture width and fracture conductivity) • Leak off coefficients (for fluid leak off into formation) • Biot’s poroelastic coefficient (for formation stress determination). If all or most of the above properties are known, successful fracture treat- ments are expected. All of the above properties are often measured in the laboratory and used to calibrate sonic and dipole sonic logs. During the initial design (see the “Design and Simulation Software” sec- tion in Chapter Four) of a frac-packing treatment, completion engineers deter- mine the required fracture geometry based on reservoir conditions, rock properties and barriers to fracture- height growth. Fracture length and, more importantly for high-permeability formations, fracture width enhance well productivity. Fracture width. It is important that the fracture width be large enough to offset the effect of sand embedment in soft Frac pack HRWP Benefits Eliminates risk of not fracturing Non-damaging • Important for moderately damaged high kh formations Much greater fracture lengths Improved gravel-pack quality • Important for low permeability formations • Better perforation filling • Better annular packing Enhanced vertical fracture growth Gravel transport mechanism • Important for long intervals of thinly laminated formations • Concentrate gravel close to wellbore • Do not over displace during multi-stage operations Higher near-wellbore proppant Less efficient fluid concentration • Less chance of out-of-zone fracture growth • Lower non-Darcy skin in high rate wells • Allows for more proppant embedment into formation • Possible mechanism for longer sustained production Risks Unable to obtain TSO Inability to fracture • On-site mini-frac analysis and job redesign needed • Moderately damaged high kh formations with relatively low viscosity reservoir fluids • Treating high-temperature formations with low-density brine • Hydraulic horsepower limited Failure of gel system to break Insufficient height growth • Proper gel /breaker combination for formation temperature • Laminated sand greater than 50 feet thick Unfavorable fracture growth Insufficient fracture length • Do not attempt to treat multiple sands • Low permeability formations • Hazardous when close to oil/water or gas/oil contact • Proven “deep” damage Poor annular growth Reduced fracture conductivity • Do not treat intervals with deviations >60° • Potential for higher non-Darcy skin in high-rate completions • Can be handled by reducing fluid viscosity at end of job Table 3.20. Benefits and risks of frac packs and HRWPs Low-Permeability formations Bilinear flow Proppant Pack Fracture with viscous fluid Fracture with viscous fluid Fracture with water Fracture with water High-Permeability formations Formation Proppant embedment Fig. 3.60. Fracture geometry. In low-permeability formations, viscous fracturing fluids generate long, narrow fractures; less viscous fluids, such as water, leak off quickly and create shorter fractures (top left ). Hydraulic fracturing increases effective completion radius by establishing linear flow into propped fractures and dominant bilinear flow to a wellbore (top right ). In high- permeability formations, fracturing treatments create short, wide propped fractures that provide some reservoir stimulation and mitigate sand production by reducing near-wellbore pressure drop and flow velocity (bottom left ). In low-strength, or soft, formations, proppant concentration after fracture closure must exceed 2 lb/ft2 (10 kg/m2) to overcome proppant embedment in fracture walls (bottom right ). 86 Modern Sandface Completion Practices formations and to obtain a high enough fracture conductivity to minimize any turbulent flow through the fracture as fluid nears the wellbore. Fracturing technology indicates that a proppant concentration of 4 lb/ft (5.95 kg/m) should be enough, but gravel packing technology suggests that formation sand may invade 3 to 4 grain thick- nesses into a propped fracture, which may be compensated for by providing a minimum of 12 grain diameters. The average diameter of 20/40 U.S. Mesh sand is about 0.025 in. (0.064 cm). Thus, the minimum fracture width should be 0.3 in. (0.76 cm) to allow a 4-grain thickness of uninvaded sand. Obviously, it is best to have a larger fracture width near the wellbore. Labo- ratory testing can be used to determine the amount of proppant embedment versus closure stress. It is easy to become confused by fracturing literature when proppant loading (lb/ft) is related to fracture width (in.). Theoretically, fracture width can be calculated by the follow- ing equation: W = Vb/2Lh Where: W = fracture width (ft) Vb = bulk volume of proppant (ft) L = propped fracture half length (ft) h = propped fracture height (ft) This means the average width of a propped fracture loaded with 4 lb/ft2 would be 0.04 ft, assuming the bulk volume of the proppant after packing under downhole conditions is 100 lb/ft3. Obviously, the bulk density of prop- pants will be somewhat less than 100 lb/ft3. Assuming the bulk density of a proppant, after compaction and embed- ment, is 83.3 lb/ft3 makes this an easy conversion, as 10 lb/ft2 loading = 1 in. frac width. An estimate of the amount of embedment in weakly consolidated sand is that it will reduce proppant loading by 2 lb/ft2.102 This is a reason- able estimate, but the actual amount of embedment depends on many factors, primarily rock mechanical properties and closure stress. Embedment in “quicksand” type formations will prob- ably be more and in “friable” type for- mation may be less than this. Embed- ment may actually increase slightly as a well is produced and pore pressure declines. Two studies in this area were done by Lacy, et al in recent years.103,104 “Creep” is another phenomenon that will affect fracture width and conduc- tivity as a well is being produced. Creep may be defined as the slow invasion of sand and formation particles into the pores of the proppant from fluid move- ment and reservoir pressure decline. This is very difficult to assess except in much generalized terms (i.e., it is more likely to be a significant factor in “quicksand” type formations than in stronger formations). Proper underbalanced perforating, surging or washing perforations, com- bined with erosion caused by proppant being pumped into the fracture at high rates, contribute to achieving wide propped fractures near the wellbore. Ideally a fracture width should be more than 2 in. (5.1 cm) or 3 in. (7.6 cm) near the wellbore. One company speci- fies frac pack designs of 10 lb/ft2 and other companies are attempting to pack more than 20 lb/ft2. These proppant loadings are averages, and the actual fracture width near the wellbore should be wider than these numbers indicate. Providing the widest possible frac- ture near the wellbore is the only practi- cal way of minimizing the effects of embedment and creep. Examples of the relative effect of width on well produc- tivities are shown in Table 3.21. Fracture length. Length is less impor- tant than width, because the main bene- fit of fracturing most high permeability formations is to bypass formation dam- age. The critical zone where most for- mation damage occurs is approximately 2 ft (0.6 m) to 5 ft (1.5 m) radially around a wellbore. Thus, the minimum length of a fracture should be 5 ft (1.5 m). The effect of extending a fracture much beyond this length may be insignificant to well productivity, may cause the fracture to extend out of the desired productive zone, and will affect job economics. However, extension of fracture length may aid controlling sand by reducing the velocity of fluid enter- ing the proppant. Designing fracture lengths of 30 ft (9.1 m) to 50 ft (15.2 m) is probably needed to achieve a proper tip screenout and adequate propped width near the wellbore. This TSO and fracture inflation is generally accompanied by an increase in net fracture pressure, the difference between the pressure at any point in the fracture and that of the fracture closure pressure. Thus, the treatment can be con- ceptualized in two distinct stages: frac- ture creation (equivalent to conventional designs) and fracture inflation/packing (after tip screenout). Effective frac pack- ing relies on a carefully timed tip scree- nout to limit fracture length and to allow for fracture inflation and packing. This process is illustrated in Fig. 3.61. Fracture height. Fracture height should increase as the length of the fracture increases, except when high strength barriers exist or where multiple frac- tures are being generated. A fracture is thought to form two “penny” shaped wings in weak, high permeability sand- J/J0 J/J0 Fracture Width Kd = 10 md Kd = 100 md (in.) Ke = 100 md Ke = 1,000 md 0.25 5.05 2.85 1.0 6.26 4.20 2.0 6.71 4.85 Assumes: 12.25 in. wellbore, 3 ft thick damage zone, 100 Darcy proppant, 25 ft frac half length, re = 660 ft. Perfect fracture with no damage, turbulence or other restriction. Calculations by Raymond and Binder equation. Table 3.21. Fractures bypass formation damage effect of fracture width 105 Fig. 3.61. Width inflation with the tip- screenout (TSO) technique at the designed fracture length 87 Chapter Three Cased-Hole Sandface Completions stone unless there are barriers that pre- vent this. A fracture in reservoirs with sand, shale sequences or with hard lay- ers intermingled with the soft sand lay- ers, may form multiple elliptical frac- tures that extend deeper than predicted in some layers and shallower in other layers. Logs cannot measure this effect because there may be sand outside the casing throughout all perforated zones. This can have an unpredictable effect on the result of a frac treatment. Minimizing fracture growth in the vertical direction will help reduce the possibility of fracturing out of the zone of interest. Where horizontal barriers do not exist, the fracture height may only be limited by limiting its length. Frac Fluids and Proppants Frac packing represents a marked departure from historical gravel-pack treatments. This trend is evident in the proppants and fluids applied. While the original frac-pack treatments involved sand sizes and clean fluids common to gravel packing, the typical proppant sizes for hydraulic fracturing (20/40 mesh) now dominate. The increased application of crosslinked fracturing fluids also illustrates this trend. Fluid selection. After evaluating reser- voir characteristics, engineers choose an optimal fluid for combined stimulation and gravel packing. The polymer-based hydroxyethyl cellulose (HEC) fluids used in gravel packing, hydroxypropyl guar (HPG) fracturing fluids with a borate crosslinked for additional viscos- ity, and more recently, viscoelastic sur- factant (VES) fracturing fluids, all are applicable. Frac-packing fluids must have a variety of properties.106 Fluid selection depends primarily on TSO fracturing criteria. Unlike massive hydraulic fracture stimulations in low- permeability formations, a low leakoff rate, or high fluid efficiency, is less desirable for frac packing. In fact, a somewhat inefficient fluid helps achieve tip screenout and promote grain-to-grain proppant contact from fracture tip to wellbore. However, frac-packing fluids also must maintain sufficient viscosity to create wide dynamic fractures and place high proppant concentrations that ensure adequate conductivity after frac- ture closure. After tip screenout, fluid systems transport proppant in the low- shear environment of a wide dynamic fracture, but also must suspend prop- pant under higher shear rates in tubing, around screen assemblies, through the perforations and during fracture initia- tion and propagation. Fluid viscosity should break easily to minimize formation and proppant-pack damage after treatments. Optimal fluids need to be compatible with formations and chemicals like polymer breakers; they must also produce low friction and clean up quickly during post-treatment flowback. To maximize retained fracture conductivity, operators exercise great care with viscosity breakers or acid treatments after frac packing to optimize post-treatment cleanup for maximum productivity and hydrocarbon recovery. Finally, frac-packing fluids should be safe, cost-effective and easy to mix, especially in offshore applications. Fluids based on HEC have many preferred frac-packing characteristics, but also several drawbacks. Systems based on HEC exhibit increased friction pressures compared with delayed crosslinked HPG or VES fluids, and frictional losses become significant in deeper wells or smaller diameter tubu- lars. In addition, proppant transport characteristics for HEC fluids are not as good as those of crosslinked HPG or VES fluids. High temperatures cause HEC fluids to thin, and viscosity is not as high at low shear rates. High-viscosity crosslinked HPG sys- tems leave some polymer residue, but maximize fracture-height growth in moderate-to-high-permeability forma- tions. They also perform well in longer intervals and transport higher proppant concentrations for greater fracture con- ductivity. Pumping pressures increase with HPG systems, but service compa- nies can used a delayed crosslinked to reduce tubular friction. Delayed-crosslink HPG fluids start at a lower viscosity and require less hydraulic horsepower to pump down- hole. Prior to reaching the perforations, temperature in the wellbore and fluid pH cause the viscosity of these fluids to increase in order to achieve low fluid-leakoff rates. The majority of frac packs are pumped with crosslinked or delayed-crosslink HPG fluids. Viscoelastic polymer-free fracturing fluids, introduced in the mid-1990s, use a VES liquid-gelling agent to develop viscosity in light brines. This type of fluid provides low friction pressures while pumping, enough viscosity at low shear rates for good proppant transport, adequate leakoff rates to ensure tip screenout and high retained permeabil- ity for better fracture conductivity. Field data also indicate that fracture confine- ment using VES fluids is better than with conventional fracturing fluids, which is an advantage when frac-pack- ing near water-bearing zones. These VES systems mix easily and do not require additives such as bacteri- cides, breakers, demulsifiers, crosslink- ers, chemical buffers or delayed- crosslink agents. Systems based on VES also are not susceptible to bacte- rial attack. If wells must be shut in for extended periods before flowback and cleanup, solids-free Viscoelastic poly- Temperature °F °C Gelled Fluid 148.89 Zinc or Titanate Crosslink Table 3.23. Fluid system recommendation vs. temperature Permeability Gas Oilmd-ft 700 Cross Link Fluid Borate Table 3.22. Fluid system recommendation vs. permeability 88 Modern Sandface Completion Practices mer-free fluids are recommended to avoid precipitation of damaging poly- mer materials. Fluids based on HEC and VES sys- tems minimize formation damage in zones with low to moderate permeabil- ity, but high leakoff rates and deeper invasion often result in slower recovery of treatment fluids.108 Adding enzyme or oxidizing breakers to frac-packing fluids reduces formation damage and improves well cleanup. Slow-release encapsulated breakers deposited in the proppant pack allow higher breaker concentrations to be used without sacri- ficing fluid efficiency. In addition to fluid leakoff and fric- tion pressure considerations, shear rate and temperature are critical in selecting frac-packing fluids and polymer con- centrations.109 The first frac-pack treat- ments were performed using the same HEC fluid systems as gravel-packing operations. Later, a shift to more con- ventional fracturing fluids occurred because of increasing temperature requirements and the need to maximize fracture conductivity in high-perme- ability formations. Initially, selection criteria for these fluids were similar to those of conven- tional fracturing applications in which narrow hydraulic fractures in consoli- dated, low-permeability formations cre- ate high shear rates with low fluid- leakoff rates. These factors result in breakdown of fluid viscosity and less cooling of formations, and greater poly- mer concentrations are required to maintain viscosity throughout a treat- ment. The use of higher polymer con- centrations carried over into fracturing and frac-packing designs for high-per- meability reservoirs. In frac packing, however, fractures are wider with lower fluid velocities and shear rates. Pretreatment fluid injection also decreases formation tem- perature near the wellbore. Pumping large volumes of treatment fluid decreases heat transfer from a reservoir, resulting in cooler temperatures inside a fracture. Failure to consider these effects results in use of higher polymer concentrations than actually required. This increases the potential for forma- tion damage and decreases the likelihood of a tip screenout. For example, because of differences in shear rate, a crosslinked fluid with a polymer loading of 20 lb per 1,000 gal (2.4 kg/m3) of base fluid can have the same viscosity in a high-permeability formation as a 40 lb per 1,000 gal (4.8 kg/m3) fluid in a low-permeability for- mation. Proper fluid selection and speci- fication dramatically increase frac-pack- ing efficiency and well productivity.110 Tables 3.22 and 3.23 are some guide- lines for choosing a gel system based on formation permeability and temperature. Proppant selection. The type of prop- pant chosen to keep fractures open and form a granular filter is an important design consideration. Frac packing suc- cess is due, in part, to larger proppant sizes than those commonly used in gravel packing. High concentrations of large, spherical proppants minimize embedment and offset the effects of tur- bulent flow in propped fractures. Operators use various grain sizes and proppant types (Fig. 3.62), includ- ing natural sand, custom-sieved sand, resin-coated sand, intermediate strength man-made ceramic proppants, and high-strength bauxite, depending on formation stress and fracture-closure stress. Table 3.24 shows typical prop- pants used in frac pack applications and Table 3.25 lists available gravel/prop- pant sizes. Fracture closure stress increases as the flowing bottomhole pressure decreases (Fig. 3.63) according to the following relationship: Fracture closure stress = øin situ - Pwf As the well is produced, the effective stress on the propping agent will nor- mally increase because the value of the flowing bottom hole pressure will be decreasing. The phenomenon of US Mesh Natural Sands Man-made Materials 10/20 X – 12/18 – X 12/20 X X 16/20 – X 16/30 X X 20/40 X X 30/50 X X 30/60 – X 40/60 X – 40/70 X X 50/70 X – Table 3.25. Available gravel/proppant sizes for frac-pack applications Class Proppant Type Examples Natural Material Sand White sand – SG 2.65 Brown sand – SG 2.65 Resin-coated sand – SG 2.65 Man-made Material Ceramic Light weight ceramic – SG 2.70 Intermediate ceramic – SG 3.20 High strength aluminum oxide Sintered bauxite – SG 3.49 NOTE: SG = Apparent specific gravity Table 3.24. Proppants used in frac pack applications Fig. 3.62. CarboProp 20/40 (intermediate strength proppant) 89 Chapter Three Cased-Hole Sandface Completions decreasing in situ stress as the reservoir pressure declines was proven conclu- sively by Salz.111 Proppants for frac packing should accomplish four fracturing objectives: • Provide an effective permeability contrast • Control sand influx and fines migration • Minimize proppant embedment in soft rock • Maintain fracture conductivity with- out proppant crushing. In the past, gravel-packing consider- ations dominated proppant selection.112 Gravel packs require gravel, or sand, sized to prevent formation particles and fines from invading the annular pack. The widely accepted Saucier rule dic- tates that sand, or gravel, particles be five to six times the mean particle diameter of formation grains.113 Frac- ture permeability and conductivity improve as proppant sizes become larger, but production of formation sand grains and fine particles that reduce pack permeability also increases. Frac packs require proppants sized to opti- mize fracture permeability. In the early 1990s, operators began evaluating larger sizes of stronger prop- pants to increase fracture permeability and relative conductivity in high-perme- ability reservoirs.114 For example, larger 20/40-mesh proppants were used for frac packing instead of smaller 40/60- mesh proppants often required for gravel packing. Experience indicated that proppant sizes dictated by gravel- packing criteria could be increased to next larger size for frac packing. Saucier criteria for sizing proppants in relation to formation grain size were relaxed in frac-pack designs because the large flow area of hydraulic fractures mitigates formation failure and sand influx. Balancing the mechanisms of sand production (flow velocity, proppant particle sizes and fluid properties) allows operators to increase fracture conductivity and improve frac-pack per- formance by using larger proppant sizes. Completing deeper wells with high fracture-closure stresses led operators to use more man-made ceramic prop- pants because they are stronger and their consistent spherical shape reduces embedment, which also increases frac- ture conductivity (Fig. 3.64). The majority of frac packs use ceramic 20/40-mesh intermediate-strength prop- pant (ISP) when reservoirs have good pressure support and closure stresses are not excessive.115 For example, a formation with 1 Darcy permeability would need a prop- pant with in-place permeability of 10,000 darcies, which means using a proppant size of 5 x 7 US mesh (0.111 x 0.157 in.) or larger. A large size such as this would certainly provide high fracture conductivity and minimal pres- sure loss through the perforations. However, it would be difficult to effi- ciently transport, more difficult to pump through perforations without bridging, more prone to erosion, more susceptible to crushing and less able to prevent embedment and invasion of sand into the propped fracture than smaller proppant sizes. Thus, a compromise must be made between the need for high permeability versus field operating constraints, which favor smaller sized, higher strength proppants and help prevent loss of fracture conductivity, by inva- sion of formation sand into the propped fracture. Do not attempt to use large proppant for the fracture and small gravel for the pack because there is doubt as to when a tip screenout will occur and when pumping of the gravel should begin. In addition to proppant sizing, the density of the proppant is now consid- ered an important variable as well. Cre- ated fracture width and proppant selec- tion determines conductivity and stimulation effectiveness is proportional to conductivity. Therefore, by compar- ing proppant conductivity at any given closure stress, the most effective prop- pant can be selected for maximum stim- ulation. Consider the proppant conduc- tivity listed in Table 3.26. Proppant conductivity at consistent concentrations indicate that more dense/higher strength proppants have significantly higher conductivity only at stresses above 6,000 psi. The Actual width shown at the bottom of the chart is for 4,000 psi closure. This width indicates that there is substan- tially more width required to hold 12 lb/ft2 of light weight prop versus denser prop. If the created width is held con- stant then looking at conductivity, will yield a true comparison of achievable conductivity (Table 3.27). When conductivity for equal widths between the proppant types are com- pared at 4,000 psi closure stress, Inter- Prop has 27% more conductivity than EconoProp. Sintered bauxite has 37% more conductivity than EconoProp. Furthermore, the beta factor for each of the more dense proppants is lower, sig- nificantly reducing the effects of non- Darcy flow, by 21% for InterProp and 30% for sintered bauxite. Beta factor is alternatively referred to as the “inertial flow coefficient.” The beta factor is a proportionality coeffi- cient that is determined by laboratory measurements. Beta is essentially a measure of the tortuosity of the flow Conductivity (md-ft) 20/40 Closure Stress 20/40 EconoProp 20/40 InterProp Sintered Bauxite (psi) (12.0 lb/sq.ft.-200°F) (12.0 lb/sq.ft.-200°F) (12.0 lb/sq.ft.-200°F) 2,000 36,995 36,672 38,795 4,000 30,568 31,195 32,527 6,000 21,848 23,188 27,194 8,000 13,349 18,292 21,688 10,000 8,225 14,610 15,693 12,000 4,371 10,718 11,175 Median diam. (mm) 0.6460 0.6620 0.6620 Actual width (mm) 1.3892 1.1207 1.0848 Table 3.26. Comparison of proppant conductivity Proppant viscosity Pwf Fig. 3.63. Fracture closure pressure on proppant 90 Modern Sandface Completion Practices path. Beta is determined by flowing realistic velocities through the API con- ductivity cell116 and solving the follow- ing equation for beta to match the observed pressure drops.117 Where: ∆p/L= pressure drop per length of proppant pack µ = fluid viscosity ν = superficial fluid velocity k = permeability of porous media β = coefficient of inertial resistance ρ = fluid density It is inappropriate to select proppants based on reference conductivity alone because reference conductivity are measured with a single phase fluid under laminar flow conditions in accor- dance with API RP 61. Beta factors must be considered as well. In an actual fracture, the effective conductivity will be much lower due to non-Darcy and multiphase flow effects. Finally, to aid in the selection of proppants, refer to the charts in Appendix 1. The first chart is the per- meability of a number of proppants that might be used in a frac pack. It illus- trates the importance of mean diameter rather than API designation. The sec- ond chart shows the over-riding impor- tance of non-Darcy flow on the effec- tive permeability in a high-rate gas flow as related to the beta factor discussed above. The third plot illustrates perme- ability decreasing with increasing clo- sure stress for several branded prop- pants. A closure pressure of 4,000 psi is representative of frac-packed wells. Pretreatment Testing Laboratory testing and history match- ing of previous treatments provide insight into stress profiles and the per- formance of treatment fluids, but in-situ formation properties vary significantly in high-permeability unconsolidated reservoirs. After developing prelimi- nary stimulation designs, engineers per- form a pretreatment evaluation, or minifracture, to quantify five critical parameters, including fracture-propaga- tion pressure, fracture-closure pressure, fracture geometry, fluid efficiency and leakoff.118 This procedure consists of two tests, a stress test and a calibration test, per- formed prior to the main treatment to determine specific reservoir properties and establish the performance charac- teristics of actual treatment fluids in the pay zone. A stress, or closure, test determines minimum in-situ rock stress, which is a critical reference pres- sure for frac-pack analysis and proppant selection (Fig. 3.65). A calibration test involves injecting actual fracturing fluid without proppant at the design treatment rate to deter- mine formation-specific fluid effi- ciency and fluid-loss coefficients. Fracture-height growth can be esti- mated by tagging proppants with radioactive tracers and running a post- treatment gamma ray log. A pressure- decline analysis confirms rock proper- ties and provides data on fluid loss and fluid efficiency. An integral part of pretreatment testing is live annulus monitoring and real-time measurements from down- hole quartz gauges to obtain pressure responses independent of frictional pumping pressures. Accurate analysis of the data ensures that the current ∆ρ µν βρν L k = + 2 Conductivity (md-ft) 20/40 Closure Stress 20/40 EconoProp 20/40 InterProp Sintered Bauxite (psi) (12.0 lb/sq.ft.-200°F) (14.5 lb/sq.ft.-200°F) (15.4 lb/sq.ft.-200°F) 2,000 36,995 45,677 50,033 4,000 30,568 38,854 41,949 6,000 21,848 28,882 35,071 8,000 13,349 22,784 27,970 10,000 8,225 18,198 20,238 12,000 4,371 13,349 14,413 Median diam. (mm) 0.6460 0.6620 0.6620 Actual width (mm) 1.3892 1.3888 1.3894 Beta, atm-sec2/g 0.00037 0.00029 0.00026 Table 3.27. True comparison of proppant conductivity 1,000 Pe rm ea bi lit y, d ar ci es 0 2 4 6 8 10 12 Closure stress, 1,000 psi 100 10 30/50 Ceramic 20/40 Natural sand 40/60 Natural sand 20/40 ISP ceramic 20/40 Ceramic Fig.3.64. Proppant specifications. In the mid-1990s, operators began using larger, stronger and more conductive proppants in frac-pack completions. Man-made ceramic materials have since become the proppant of choice in the US Gulf of Mexico to maintain fracture conductivity at higher closure stress in deeper formations. For example, switching from smaller 40/60-mesh sand (green) to a larger intermediate-strength 20/40-mesh ceramic proppant (yellow) increases proppant permeability and fracture conductivity by a factor of six in laboratory tests at 2,000 psi of closure pressure (inset). An intermediate-strength proppant (ISP) is priced competitively with custom-sieved natural sands. 91 Chapter Three Cased-Hole Sandface Completions frac-pack design and subsequent treat- ments achieve wide fractures with a tip-screenout for optimal results. Surface data from pretreatment tests combined with bottomhole injection pressures are history matched using a computer simulator to calibrate the fracturing model and finalize treatment design. Calibrated data from computer analysis are also used to assess stimula- tion effectiveness during post-treatment evaluations. (See the “Design and Sim- ulation Software” section of Chapter 4.) Treatment design, particularly TSO fracture stimulation, is critically impor- tant to successful frac packing. If pre- mature screenout or failure to achieve a tip screenout results in insufficient fracture width to overcome proppant embedment in the formation, well productivity may, at best, be equivalent to that of a conventional gravel pack. Standard frac-packing practice is to redesign treatments on-site after minifracture testing and analysis are complete.119 Frac-Pack Methods/Applications As stated, frac packs are a combination of a fracture treatment and an annular gravel pack. A successful frac pack must not only stop sand movement, but must create a wide fracture that is held open by a high permeability proppant extending through the near-wellbore zone. Importantly, the induced fracture must not make contact with nearby zones that contain unwanted fluids. Control of proppant flowback is important to maintain connection between the fracture and wellbore, maintain fracture conductivity, maintain formation stresses, and prevent well- bore fill and pumping problems. The nature of the completion itself (perfora- tions, liners/screens, etc.) influences proppant flowback. Stability is a strong function of flow rate, particle size, frac width and closure stress. The flowback initiation rate decreases as the closure stress increases and as the fracture widens. Conversely, it increases with the proppant size. Proppant control measures should be employed both during and after the fracturing process. During fracturing, measures can include inner liners/ screens, fiber and bridging techniques, resin coated proppants or surface modi- fier agents. After fracturing, measures Dynamic fracture Fracture inflation Annular opening Cement Perforation Screen Casing Propped fracture “External” proppant pack Tip screenout Proppant Fig.3.66. Tip-screenout (TSO) fracturing. In high-permeability reservoirs, fracture stimulations require fluid systems that leak off early in a treatment. Dehydration of the slurry causes proppant to pack off at the fracture tip, halting further propagation, or extension (top ). As additional slurry is pumped, biwing fractures inflate and proppant packs toward the wellbore (middle ). A TSO treatment ensures wider fractures and improves conductivity by promoting grain-to-grain contact in the proppant pack. This technique also generates enough formation displacement to create an annular opening between cement and formation that becomes packed with proppant. This “external” pack connects all perforations and further reduces near-wellbore pressure drop (bottom ). Bo tto m ho le p re ss ur e Time Increasing injection rate Constant injection rate Constant flowback Shut in Constant injection rate Net pressure Fracture closure pressure Instantaneous shut-in pressure (ISIP) Fracture- extension pressure Rebound pressure Pressure falloff Fig.3.65. Pretreatment minifracture testing. Stress, or closure, tests involve injecting low-viscosity, non-damaging fluid at increasing rates to initiate a fracture and determine the pressure required to propagate, or extend, fracture length. Fracture-closure pressure is determined by monitoring pressure decline during a slow, constant-rate flowback. 92 Modern Sandface Completion Practices can include inner liners/screens, in situ resins with external catalyst, or sand “squeeze” with resin or surface modify- ing agent. Applying sand control mea- sures during fracturing is much more cost effective than remedying problems after the fact. Tip-screenout fracturing. The most common technique of fracturing weak, high permeability formations is the tip- screenout fracture, which was introduced earlier in this section.120 It differs from a conventional hydraulic fracture by forcing an early screenout and creating a short, wide fracture of perhaps 25 to 50 ft (7.6 to 15.2 m) in length and 1 or 2 in. (2.5 to 5.1 cm) in width. The criti- cal elements of a TSO treatment design, execution and interpretation are sub- stantially different than for conventional fracture treatments. In particular, TSO fracturing relies on a carefully timed tip screenout to limit fracture growth and to allow for fracture inflation and packing (Fig. 3.66). In a perfect fracture design the prop- pant is carried by the frac fluid to the tip of the fracture where it packs just as the fracture has extended to the desired length and height. This generates a true “screenout.” A screenout may occur early if fluid leaks off to the formation faster than predicted. Conversely, a screenout may not occur during the job if leakoff is much slower than predicted. An early screenout is undesirable because it means that the fracture has not achieved its designed length and height. No screenout results in less than designed fracture width and conductivity. Pumping continues after a sandout occurs to “balloon” the fracture and pack it with as much proppant as possi- ble. This creates a wider fracture than can be obtained in stronger formations. TSO fracture widths result in very high conductivity that can only be obtained if screenout occurs, or when there is limited amount of “ballooning” time. Hence, among the most critical parame- ters for obtaining a successful tip scree- nout are the fluid spurt loss, leakoff rate and dynamic leakoff profile. Unfortu- nately, there is not an accurate means of measuring or predicting these fluid loss rates in short frac packs, especially in reservoirs where permeabilities and rock properties change by significant orders of magnitude. Fracture initiation and propagation in weak formations are affected by the variations of the same properties as in stronger formations, such as: • In-situ stresses • Stratification • Rock strength and properties (such as elastic modulus, Poisson’s ratio, toughness, ductility) • Fluid, pressure and permeability profile in the fracture • Pore pressures. The permeability profile and rock strength of most weak, high permeabil- ity formations vary much more than in high strength, low permeability forma- tions. For instance, the permeabilities of weak sandstone commonly vary from near zero in shale and clay strata to higher than one Darcy; whereas, the permeabilities of strong sandstone com- monly range from near zero to only 5 or 10 md. Similarly, weak sandstone for- mations that are candidates for frac- pack treatments often have strata or pockets of very strong sandstone, shales or carbonates. Strengths may range from nearly zero to many thousands of psi unconfined compressive strength. Fracture orientation in weak forma- tions is the same as in stronger forma- tions. The static stress fields that force them to always be perpendicular to the minimum principal stress dictate the direction of all fractures. This means that the fracture is usually in the same direction as, and parallel to, the maxi- mum horizontal stress. Typical frac-pack running procedure. Initially, operators performed frac pack- ing in multiple steps—a TSO fracturing treatment followed by wellbore cleanout, installation of sand-exclusion screens and separate gravel-packing operations.121 However, high positive skins and limited productivity indicated damage between the propped fracture and internal gravel pack. Frac packing was simplified into a single operation to further improve well production and reduce operational costs.122 The TSO fracturing treatment now is pumped with screens in place (Fig. 3.67). Gravel packing of screen assemblies is accom- plished at the end of a treatment.123 A typical running procedure for a frac-pack treatment is to: • Pick up and trip-in hole with gravel pack assembly. • Set the packer, test packer and pickle pipe. • Perform step rate test (0.5 to 15 bpm), mini-frac test (10, 12 or 15 bpm) and monitor fall-off. • Determine closure pressure, closure time, fluid efficiency, leakoff coeffi- cient and fracture geometry. • Determine optimum fracture size and conductivity. • Determine sand stages, and sizes; then, slow down procedure in case screenout is not evident. • Hold safety meeting to go over procedures with all personnel. • Pump frac treatment. When well screens out, reverse out excess slurry. If screenout is not evident, begin slowing the rate at the predetermined point to induce the final wellbore screenout. • Once fluid loss in under control, pull out of hole. Like conventional gravel packing, fluids and proppants for frac packing are injected through tubing and a Flapper valve Washpipe Perforations Tubing Bottom packer Conventional screens Gravel-pack packer Fig. 3.67. Relatively short perforated intervals accommodate a single completion and frac pack installation using standard screens. 93 Chapter Three Cased-Hole Sandface Completions gravel-pack packer with a service tool in squeeze or circulating configuration (Fig. 3.68). However, to withstand higher pressures during TSO fracturing, service companies adapted standard gravel-packing assemblies. Modifica- tions include increased metal hardness, larger cross-sectional flow areas and minimizing sudden changes in flow direction to reduce metal erosion by fluids and proppants. Squeeze configuration is used for most frac-pack treatments, especially in wells with production casing that cannot handle high pressures. Circulating posi- tion provides a path for fluid returns to surface through the tubing-casing annu- lus or communication—a “live” annu- lus—to monitor pressure at surface inde- pendent of friction in wellbore tubulars, depending on whether the annular sur- face valve is open or closed. Friction pressures generated by pumping prop- pant-laden slurry through tubing and completion equipment often mask true downhole pressure responses when mon- itoring treating pressure on the tubing. Early service tools used a conven- tional check valve that prohibited pres- sure declines from being observed after fracturing. More recent designs of gravel-pack packer tools eliminate the check valve, replacing it with an improved downhole ball valve that allows pressure fluctuations to be moni- tored in real time during treatments when the ball valve is open. A live annulus allows more accurate evalua- tion of treatments.124 Frac packing usually begins in squeeze configuration. After tip screen- out occurs, establishing circulating con- figuration ensures complete packing of the screens and grain-to-grain proppant contact. The service tool then is shifted to clean out excess slurry by pumping fluid down the annulus and up the tub- ing. The amount of upward movement required to shift some service tools pulls reservoir fluids into a wellbore. This swabbing effect can bring forma- tion sand into perforation tunnels before a fracture is completely packed or reduce conductivity between frac- tures and the internal gravel pack, which can limit frac-pack productivity. Set-down service tools close the downhole ball valve and shift tool con- figuration with upward movement. This type of tool also is used for deep com- pletions and treatments conducted from floating rigs or drillships. In addition to a variety of reservoir conditions and of fracturing and gravel- packing requirements, treatment execu- tion must address the complexity of completing multiple zones and long intervals. Even the best frac-pack designs end in failure if excess fluid loss into formation causes proppant bridges to form between screens and casing, restricting or blocking annular flow. Annular proppant packoff, or bridging, results in early treatment termination, low fracture conductivity and an incom- plete gravel pack around screens. Placing proppant with sand-exclu- sion screens in place requires close attention to annular clearances. As fric- tional pressure increases, there is poten- tial for fluid from slurry in the screen- casing annulus to pass through the screens into the washpipe-screen annu- lus. Fluid bypass worsens as the slurry dehydrates, and proppant concentration increases to an unpumpable state, caus- ing proppant to bridge in the screen- casing annulus. Annular blockage near the top of a completion interval prevents continued fracturing of deeper zones or zones with higher in-situ stress and inhibits subsequent packing of the screens. Even a partial flow restriction in the annulus increases frictional pressure drop, restricts rate distribution and lim- its fracture-height growth across the remainder of the completion interval. Annular voids below a proppant bridge increase the likelihood of screen failure from erosion by produced fluids and fine formation sand.125 Alternate path technology. For homo- geneous reservoirs where pay intervals are less than 60 ft (18 m) thick, fracture- height growth typically covers the entire zone. In longer intervals, the probability of complete fracture coverage decreases, and risk of proppant bridging increases dramatically. Long intervals can be split into stages and treated separately. This requires more downhole equipment, such as two stacked frac-packing assem- blies (Fig. 3.69), and additional installa- tion time, but increases frac-packing effectiveness. Alternate path technology is also available to gravel pack and frac pack longer intervals (Fig. 3.70). Schlum- berger Shunt-tube screens use hollow rectangular tubes, or shunts, welded on the outside of screens to provide addi- tional flow paths for slurry. Exit ports with carbide-strengthened nozzles located along the shunt tubes then allow fluids and proppant to exit below annu- lar restrictions, which allows fracturing and annular packing to continue after restrictions form in the screen-casing annulus. To accommodate higher injec- tion rates for fracturing, shunt-tube screens for frac packing employ slightly QUANTUM gravel-pack packer Mechanical fluid-loss control device Washpipe Screens Perforations Screens Perforations Ball seat Ball valve Fluid flow Crossover ports Service tool Annular BOP Annulus surface valve and pressure gauge Circulating ports Temperature and pressure gauge Bottom packer Fig. 3.68. Downhole tools. In gravel packing and frac packing, a service tool directs fluid flow through a gravel-pack packer and around the screen assembly. Squeeze config- uration is established by closing the annular blowout preventer (BOP) and the tubing-cas- ing annulus surface valve (left ), or by closing the ball valve downhole (right ). Shutting in the annulus with the downhole ball valve open allows bottomhole pressure to be moni- tored independent of friction in the tubing. Closing the downhole valve prevents fluid returns to surface and protects weak casing from high pressures; pressure also can be applied to the annulus to offset high pressure in the tubing. Mechanical devices such as flapper valves or formation isolation valve systems prevent excess fluid loss into forma- tions after the service tool is retrieved. 94 Modern Sandface Completion Practices larger tubes than shunt-tube screens for gravel packing. Shunt tubes provide conduits for slurry to bypass collapsed hole and external zonal isolation packers as well as annular proppant gravel bridges at the top of intervals or adjacent to higher per- meability zones with high fluid leakoff. If annular restrictions form, injection pressure increases and slurry diverts into the shunt tubes, the only open flow path. This ensures fracture coverage and com- plete gravel packing around screens across an entire perforated interval.126 The Halliburton Concentric Annular Packing Service (CAPS) is designed to obtain the same results. Fracturing vertical wellbores. Tip- screenout fractures in homogeneous, high permeability formations are thought to form “penny” shaped verti- cal fractures, which are usually vertical and parallel to the maximum horizontal stress in the formation. Thus, the entire vertical height of the fracture should be in direct contact with the entire well- bore and perforations in a cased hole. Hence, fluids flowing into and being produced from the propped fracture should exit and enter the wellbore uni- formly. However, it usually does not work this way because of natural sand- stone/shale layers and radial hetero- geneities of sandstone reservoirs. The weakest zone will probably be the first to break down and initiate a fracture. Another zone or zones may then break open as injectivity into the first zone is restricted by friction, low permeability barrier or as tip-screenout is approached. However, it is not likely that one continuous propped fracture will be generated from the top to the bottom of a long perforated completion. The result will be that a limited length of only 15 to 30 ft (4.6 to 9.2 m) of a long perforated interval might be in direct contact with the propped fracture. Thick shale beds, longer than ~10 ft (~3.1 m), in a completion interval tend to limit a frac pack to above or below the shale. Even some thinner shale streaks have restricted the height of fractures in weak, high permeability formations. It is often necessary to do two or more sepa- rate treatments to stimulate long comple- tions in stratified formations. High treating pressures while initiat- ing, extending and ballooning a fracture usually open some perforations that are filled with mud, sand, gel or solids. This may account for much of the well productivity improvements observed after some frac pack jobs, and is one of the arguments in favor of doing “high rate” gravel packs rather than more expensive frac pack jobs. However, high-treating pressures may also cause the following: • Breaking the cement bond, which may allow communication with unwanted water or gas producing reservoirs. • Initiating a fracture in an adjacent zone. This may be very desirable, as it may contact more oil or gas pro- ductive reservoirs, but any fracture that goes out of the target zone may cause early water or unwanted gas breakthrough. A fracture generated into a zone that was not part of the frac plan will take some of the energy Tubing Perforations AllFRAC screens Gravel-pack packer Flapper valve Gravel-pack packer Washpipe Bottom packer Conventional screens Perforations Flapper valve Fig. 3.69. Two separate treatments using a stacked-screen assembly to frac pack these longer intervals. Standard screens were used for the lowest zone, which was shorter. Shunt-tube screens were installed to complete the longer upper zone. Screen Basepipe Fracture Shunt tubes Nozzle Casing Shunt tubes Perforations Screens Annular proppant bridge Void Nozzle Fig. 3.70. Alternate Path Technology. Proppant bridges, or nodes, that form in the screen-casing annulus, commonly as a result of slurry dehydration or premature fracture screenout in zones with lower in situ stress, cause early treatment termination. In wells with conventional sand-exclusion screens, this limits fracture height and frac-pack efficiency. Alternate path technology uses shunt tubes with strategically located exit nozzles welded on the outside of conventional screens (top and middle ). Shunt tubes provide a flow path for slurry that bypasses annular restrictions to allow continued treating of lower intervals and packing of voids around the screens (bottom ). 95 Chapter Three Cased-Hole Sandface Completions away from the planned fracture and reduce its width and conductivity. • Branching of the primary fracture within the reservoir may occur when the primary fracture encounters a high strength or low permeability barrier. This is much less likely to occur in short frac packs than in long hydraulic fractures. Fracturing horizontal or deviated wells. If wellbore azimuth is nearly the same orientation of the fracture, a frac- ture in a non-vertical wellbore will behave in much the same way as a ver- tical wellbore. However, a wellbore angle of >~15° from vertical that is not in the same plane as a vertical fracture will have limited contact with the frac- ture. Although multiple fractures may occur, it is unlikely that fractures will be connected to the entire wellbore. That is not to say that this occurs in all wellbores with angles greater than ~15° from vertical. However, more problems are likely at wellbore angles greater than this.127 Discontinuous contact of multiple fractures results in higher velocity of fluid and/or gas produced through gravel-filled perforations, which may significantly restrict production. There- fore, high-shot density perforating is more critical for fractured zones in non- vertical wellbore. The perforation skin effect will be much greater if a limited numbers of perforations are in contact with the fracture. For example: In a well producing 500 b/d from a 50 ft (15.2 m) thick formation with a fracture in contact with only 5 ft (1.5 m) of 6 spf perforations (assuming all fluid is produced from only the frac- tured zone), the pressure loss through the gravel filled perforations could be 15 times more than if 500 b/d were pro- ducing through all 50 ft (15.2 m) of perforations of the unfractured well. This assumes: µ = 1 cp Bo = 1 L = 0.1487 ft Kg = 100 Darcy in 0.5 in. perfs β = 31,623 ft-1 fluid density = 55 lb/ft3. A vertical fracture in a non-vertical wellbore interferes with the packing of gravel in perforations that are not con- nected with the fracture. Once a frac- ture is initiated through one point of the completion interval, most, if not all, of the fracture fluid and proppant will flow into the fracture, which reduces the flow of fluid past this point in the well- bore. This may result in a bridge being formed in the screen/casing annulus and loss of sand control beyond the break point. A way to prevent these problems may be to: • Perforate and frac pack only one short zone ers, which can be used for production management during the life of the well. In addition, the system will allow all stimulation treatments and perforation of all well zones in a single trip (Fig. 3.72). If it is not possible to identify high- strength layers or insufficient informa- tion is available to consider a screenless frac pack, use conventional frac-pack methods instead. Gravel-Packing Method Selection The goal of a gravel pack is to satisfy two criteria: • Provide sand control • Maximize and maintain well performance. The most popular method to accom- plish this is in gravel-pack installations. The gravel-pack installations require placement of gravel or proppant around the gravel-pack screen and against the formation face. These placement meth- ods are as follows: High Rate Water Packs (HRWP). These treatments can be pumped at matrix rates, but more commonly at frac rates, depending upon the well conditions. Slurries contain sand (proppant) and completion fluid (or light brine). Proppant is mixed at low concentrations (1 to 2 ppa). Slurry Packs. These treatments are pumped at matrix rates. Slurries are typically batch mixed with polymer based carrier fluids. Sand concentra- tions are typically 8 to 15 ppa. They are used primarily in areas with low horsepower (100 ft) inside casing ≤ 5 1/2-in. Frac packHigh ratewater pack Yes 2 step frac pack No No No No No No No Gas Yes Yes Yes Yes Yes Yes No Yes Oil Yes Yes Fig. 3.73. Method selection of cased-hole sandface completions – frac pack vs HRWP 97 Chapter Three Cased-Hole Sandface Completions • Fracturing operations compromises the operational success of the com- pletion. All options should be considered before completing a well. The first decision to be made is the selection of an open-hole or cased-hole completion. Actual and perceived risks should be reviewed and the probability to success- fully execute the various treatment methods should be weighed. Then, a specific treating option can be selected. The selection of each phase of the com- pletion program should be based upon the characteristics of the specific inter- val being treated. References 1. Aubert, C., Jr. and Bercegeay, E., “Field Tested Meth- ods Improve Sand Control,” World Oil, January 1971. 2. Maly, G., “Close Attention to the Smallest Job Details Vital for Minimizing Formation Damage,” SPE 5702, 2nd Symposium on Formation Damage, Hous- ton, Texas, January 29-30, 1976. 3. Colle, E.,“Increased Production with Underbalanced Perforation,” Petroleum Engineer International, July 1988, 39-42. 4. Tuttle, R., and Barkman, J., “The Need for Non- damaging Drilling and Completion Fluids,” SPE 4791, First Symposium on Formation Damage, New Orleans, Louisiana, February 7-8, 1974. 5. Howard, S., “Formate Brines for Drilling and Com- pletion: State of the Art,” SPE 30498, Annual Techni- cal Conference & Exhibition, Dallas, Texas, October 22-25, 1995. 6. Krook, G. and Boyce, T., “Downhole Density of Heavy Brines,” SPE 12490 Formation Damage Sym- posium, Bakersfield, California, February 13-14, 1984. 7. 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American Petroleum Institute, “Recommended Practices for Evaluating Short Term Proppant Pack Conductivity,” API RP 61, October 1989. 117. Vincent, M., Pearson, C. and Kullman, J., “Non- Darcy and Multiphase Flow in Propped Fractures: Case Studies Illustrate the Dramatic Effect on Well Productivity,” SPE 54630, Western Regional Meeting, Anchorage, Alaska, May 26-28, 1999. 118. Monus, F., Broussard, F., Ayoub, J., and Norman, W., “Fracturing Unconsolidated Sand Formations Off- shore Gulf of Mexico,” SPE 24844, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. 119. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 120. Smith, M., Miller II, W., and Haga, J., “Tip Screenout Fracturing: A Technique for Soft, Unstable Formations,” SPE Production Engineering, May 1987, 95-103. 121. Monus, F., Broussard, F., Ayoub, J., and Norman, W., “Fracturing Unconsolidated Sand Formations Off- shore Gulf of Mexico,” SPE 24844, presented at the SPE Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. 122. Hannah, R., Park, E., Walsh, R., Porter, D., Black, J., and Waters, F., “A Field Study of a Combination Fracturing/Gravel Packing Completion Technique on the Amberjack, Mississippi Canyon 109 Field.” SPE 26562, presented at the SPE Annual Technical Con- ference and Exhibition, Houston, Texas, October 3-6, 1993; also in SPE Production & Facilities 9, no. 4 (November 1994), 262–266. 123. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 124. Mullen, M., Stewart, B. and Norman, W., “Evalu- ation of Bottom Hole Pressures in 40 Soft Rock Frac- Pack Completions in the Gulf of Mexico.” SPE 28532, presented at the SPE Annual Technical Conference and Exhibition, New Orleans, Louisiana, September 25-28, 1994. 125. Ali, S., Norman, D., Wagner, D., Ayoub, J., Desroches, J., Morales, H., Price, P., Shepherd, D., Toffanin, E., Troncoso, J. and White, S., “Combined Stimulation and Sand Control.” Oilfield Review 14, no. 2, Summer 2002: 30-47. 126. Ibid. 127. Weng, X., “Fracture Initiation and Propagation from Deviated Wellbores,” SPE 26597, Annual Techni- cal Conference, Houston, Texas, October 3-6,1993. 128. Hagist, P., Abass, H., Harry, J., Hunt, J., Shun- way, M. and Besler, M., “A Case History of Completing and Fracture Stimulating a Horizontal Well,” SPE 29443, Production Operations Symposium, Oklahoma City, Oklahoma, April 2-4, 1995. 129. Ddeimbacher, F., Economides, M. and Jensen, O., “Generalized Performance of Hydraulic Fracture with Complex Geometry Intersecting Horizontal Wells,” SPE 25505, Production Operations Sympo- sium, Oklahoma City, Oklahoma, March 21-23, 1993. 130. Kirby, R., Clement, C. and Asbill. S., “Screenless Frac Pack Completions Utilizing Resin Coated Sand in the Gulf of Mexico,” SPE 30467, Annual Technical Conference, Dallas, Texas, October 22-25, 1995. 131. Putra, P., Nasution, R., Thurston, F., Moran, J. and Malone, B., “TSO Frac-Packing: Pilot Evaluation to Full-Scale Operation in a Shallow Unconsolidated Heavy Oil Reservoir, SPE 37533, International Thermal Operations & Heavy Oil Symposium, Bakersfield, Cali- fornia, February 10-12, 1997. Chapter Three Cased-Hole Sandface Completions Summary Prior to leaving the discussion of downhole operations and moving to a discussion of surface operations and equipment, it might be appropriate to restate the factors that make a successful sand control completion. The true success or failure of a sand control application must always be measured against three related criteria: • Stopping the movement and production of sand • Maintaining maximum well productivity • Paying for treatment costs and realizing a satisfactory return on investment within a reasonable period of time. 102 Modern Sandface Completion Practices All of the sand control techniques,which have been discussed previ-ously in this handbook, employ various types of surface equipment at the rig site, whether offshore or on land. The only possible exception being the installation of a stand-alone screen in an open-hole sandface completion. The costs associated with deploying and using specialized equipment for what- ever type of treatment should always be considered during the completion selec- tion and design process. For example, open-hole gravel pack- ing eliminates the cost of cementing and perforating casing. Additionally, an open-hole gravel pack requires consid- erably less hydraulic horsepower and blending equipment than a cased-hole HRWP or frac-pack. Offshore, a stimu- lation vessel is usually the only practi- cal way to deliver the surface equip- ment necessary to perform downhole treatments. Availability and the high cost of stimulation vessels are major considerations in the decision to per- form cased-hole HRWP or frac-pack completions offshore. Regardless of location, open-hole gravel packs can be performed at lower cost using more readily available equipment, either installed on an offshore rig or trans- ported to a land wellsite.1 Another example of potential cost savings in offshore operations is to use seawater as the base completion fluid. Because a stimulation vessel can obtain water at sea instead of having to travel back to shore to take on fresh water between frac-pack treatments, the use of seawater as a base fluid minimizes completion costs and valuable rig down- time.2 When considering this option for a frac-pack treatment, formation com- patibility must be established and a proper gel system must be specified. The various companies providing stimulation services invest heavily in research and development related to all aspects of well completions, including the equipment used to pump, control and monitor sand control treatments. The following is at best a brief overview of surface operations and equipment requirements necessary to perform various pumping procedures. An overview of the systems used to control, monitor and evaluate sand con- trol treatments has also been included. Surface Equipment and Techniques Specialized equipment mounted on trucks, skids or offshore vessels is avail- able for all types of sand control tech- niques. Skid-mounted equipment has become very popular and somewhat of an industry standard because it provides maximum deployment versatility. In most treatments, a blender is used to mix and transfer gravel/proppant and a treating fluid to high-pressure frac pumps. The proppant-laden treating fluid is then pumped through a high- pressure manifold to the well. Over time, treatments have grown in com- plexity involving various flow rates, pressures, proppant concentrations, liq- uid and dry additives and total volumes of fluid. Service companies employ a wide variety of equipment for various types of well completions. Today, a well treatment, and the equipment required to perform the treatment, is often custom packaged to meet a specific set of job design param- eters. There are four basic types of equipment used for both land and off- shore sand control treatments: mixing and blending, pumping, proppant han- dling and monitoring/control. The fol- lowing discussion is only representative of the many variations of this equip- ment, which is available from numerous service companies. Mixing and Blending Equipment Blending equipment is used to prepare the treatment fluid by mixing the cor- rect proportions of liquid and dry chemical additives into the stimulation fluid. Mixing can be done either contin- uously throughout the treatment or batch-mixed in fracturing tanks before the stimulation treatment. For continu- ous mixing of the treatment fluid that contains polymer, the base fluid is pre- pared using a preblender. The pre- blender is used to mix a liquid gel con- centrate with water from tanks. It provides sufficient hydration time to yield the required base-fluid gel viscos- ity. The hydrated gel is then pumped from the hydration tank to the blender. In addition to the additives, a blender is used to mix gravel/proppant with the treatment fluid. For a low viscosity treatment, such as a water pack or HRWP, gravel can be delivered by a gravel-injection auger that precisely measures feed rates to the mixing tub of a Baker Hi-Rate Gravel Infuser (Fig. 4.1). It can be mixed continuously with a Halliburton Constant Level Additive Mixing (CLAM) system (Fig. 4.2). Both of these units eliminate the necessity of batch-mixing large volumes of low gravel concentration slurries, while allowing the sand concentration to be Surface Operations and Equipment Surface Equipment and Techniques • Monitoring and Control • Evaluation Techniques CHAPTER FOUR Fig. 4.1. Baker Hi-Rate Gravel Infuser 103 ramped as necessary. Comparable equipment is available from several sources. The time versus mix ratio/rate plot (Fig. 4.3) illustrates the accuracy of gravel addition, which is possible with any of these units. When frac packing, blenders such as those illustrated in Figures 4.4, 4.5 and 4.6 are capable of blending and pump- ing proppant slurry at the designed rates. These units are computer con- trolled to precisely deliver the solid/liq- uid ratio at design values throughout the entire job in either ramp or stair- step mode. A slurry pack (high viscosity/high gravel density) gel is prepared with a batch blender like the one in Figure 4.7. Wellsite computers, programmed with predetermined set points for mix- ture concentrations, are used to control the quality of the mixing process. Regardless of the mixing flow rate, the computers maintain the required slurry concentrations. Operational parameters (i.e., tub level, mixer agitation and pres- sures) for the blender are also placed under automatic control, thereby mini- mizing the potential for human error. Pumping Equipment Pumping equipment has evolved from pumps rated at 300 horsepower (hp) to today's pumps rated at 2,000+ hp pro- duced from a single crankshaft pump. The pressure requirements for well treatments have also increased from 2,000 psi to 20,000 psi. Computer con- trolled, power-shift transmissions syn- chronize the engine speed with the gear shift so that pump rates before and after the shift are the same. Computer-con- trolled pumping equipment also allows automatic pressure and/or rate control. It is important to understand that horsepower is a rating of the energy a pump can supply to move fluid. Hydraulic horsepower (HHp) refers to the power actually applied to moving the fluid, assuming there are no efficiency losses in either the pump portion of the unit or the engine that drives the pump. This is not what the manufacturer adver- tises as the horsepower of the pump. Brake horsepower (BHp) is the power supplied to the pump by the engine and takes into account the pump’s efficiency rating. BHp is the figure that manufac- turers list as the "horsepower rating" of Fig. 4.2. Halliburton CLAM mixing system Fig. 4.6. BJ skid-mounted blender 0 15 20 25 30 Elapsed time, min. 35 40 45 1 2 3 M ix ra tio , p pa Ra tio , b pm 4 5 0 2 Rate Sand auger Densimeter 4 6 8 10 Fig. 4.3. Time vs mix ratio/rate plot Fig. 4.4. Halliburton single-skid FracPac blender Fig. 4.7. Slurry pack batch blender Flow rate hA i e BH p Ef fic ie nc y Fig. 4.8. Pump chart – performance curves.3 Head or pressure (labeled hA, black ), efficiency (labeled e, green ), and brake horsepower (labled i, red ), based on the flow rate. Fig. 4.5. Schlumberger POD II bender Fig. 4.9. Schlumberger 1,200 HHp frac pump Fig. 4.10. Baker SC-1,200 frac pump 104 Modern Sandface Completion Practices their pumps. A pump chart provides information to determine HHp in con- junction with the following equation: Where: e = Efficiency ratio All pumps have a corresponding pump chart similar to Figure 4.8. In this chart, note that brake horsepower can and usually does change with flow rate. In addition, as pressure increases, flow rate decreases. It is a good idea to have a pump chart that is as complete as possible. Required flow (injection) rates and pressures required to pump a sand con- trol treatment can be obtained from a number of frac pumps. Figure 4.9 is a 1,200 HHp frac pump from Schlum- berger and Figure 4.10 is a 1,200 HHp frac pump from Baker. Figure 4.11 is a BJ skid-mounted frac pump. Similar pumps are available from other service companies. Also, note the following HHp relationship and reference suppli- ers’ pertinent pump charts to determine the required number of frac pumps for a given sand control treatment: Where: Q = Rate, bpm Pw = Pressure, psi Proppant Handling Several methods are used to store, move and deliver proppants to the blender for mixing. Bagged proppant can be manually dumped into a blender or the blender can be fed via a pneu- matic delivery system. Larger well treatment designs using ever-increasing quantities of gravel/proppant have necessitated the use of large-volume, field storage bins (Fig. 4.12) and auto- mated blender feed systems. Offshore Equipment For offshore sand control operations, to save the costs associated with building and equipping a stimulation vessel, the required surface equipment can some- times be mounted on the rig platform. Figure 4.13 illustrates an example equip- ment layout diagram for an offshore rig. When a frac pack or HRWP treat- ment is specified offshore, a specially equipped stimulation vessel may be required to do the job. Major service companies have made large investments in the construction of purpose-built ves- sels equipped with high-volume mixing equipment, high-pressure pumps and sophisticated monitoring systems. I llustrated are stimulation vessels from Baker (Fig. 4.14), BJ Services (Fig. 4.15), Halliburton (Fig. 4.16) and Schlumberger (Fig. 4.17). Monitoring and Control Monitoring sand control treatments has progressed from analog pressure gauges, stopwatches and chart recorders to full computer monitoring and con- trol. More than a thousand different parameters can be monitored and recorded during a stimulation treat- ment. These parameters are not limited to treatment fluids, proppant and addi- HHp Q Pw= ×( ) 40 81. e HHp BHp= x Fig. 4.12. Proppant silo, which is completely weather proof Holding tank Acid tank From rig floor Pickle return To rig floor C-Pump Additive pump Blender Sand silo HP pump Cat walk Work box Monitoring unit Fig. 4.13. Equipment layout diagram for deck of offshore rig Fig. 4.11. BJ skid-mounted frac pump 105 Chapter Four Surface Operations and Equipment tives. They can include various parame- ters used to monitor the equipment per- forming the treatment. Monitoring the treatment fluids is an essential part of quality control. Pri- mary fluid parameters monitored and recorded during a stimulation treatment include, but are not limited to, pres- sures, temperatures, flow rates, prop- pant and additive concentrations (pH, and viscosity). All of these parameters can be plotted or displayed during the job along with real-time calculations of downhole parameters. Equipment parameters, which are monitored and recorded, provide data for future treatment design improve- ments and diagnosis of equipment prob- lems. The following control equipment is representative of the systems being employed by service companies today for various types of well treatments. Monitoring and Control Equipment Control rooms on Baker’s stimulation vessels have the following capabilities: • Network communications and remote data transmission via satellite • Full data monitoring capabilities, including Baker SMARTS (Stimula- tion Monitoring and Reservoir Testing Software) • State-of-the-art data acquisition and display • Backup computer systems. These control units are packaged on a truck chassis for land operations and in skid-mounted configurations (Fig. 4.18) for treatments performed on an offshore rig. The Schlumberger fracturing com- puter-aided treatment system (Frac- CAT) comprises hardware and software for monitoring, controlling, recording and reporting all types of fracturing treatments. Its real-time displays, plots, surface schematics and wellbore anima- tions present a clear picture of the treat- ment as it occurs, providing decision- makers with real-time detailed job information from the surface to the perforations. During the job, the Frac- CAT system tracks multiple perfor- mance parameters, then compares and displays them against planned values (Fig. 4.19). Using FracCAT, or similar computer-aided technology from other service companies, a treatment design can be executed and tracked in a very precise manner. Fig. 4.17. Schlumberger’s Galaxie stimulation vessel Fig. 4.18. Baker BDAQ skid-mounted control cabin Optimum frac half length, 40-50 Frac half length, Xf No rm al iz ed , N PV 0 0.8 0.9 1.0 1.1 1.2 1.3 1.4 1.5 1.6 20 60 80 10040 Fig. 4.20. Frac length optimization: NPV vs frac half length Fig. 4.19. Schlumberger FracCAT control and monitoring system Fig. 4.14. Baker’s RC Baker stimulation vessel Fig. 4.15. BJ Services’ Blue Ray stimulation vessel Fig. 4.16. Halliburton’s Stim Star stimulation vessel 106 Modern Sandface Completion Practices 107 The Halliburton TECHCOMMAND Center is a minicomputer-based system designed specifically for stimulation control. This system provides data acquisition, real-time data analysis and direct control of automatic, remote-con- trolled pumping and blending equip- ment. TECHCOMMAND offers the following features: • monitors and records more than 1,200 surface treatment parameters including injection rates, additive rates, slurry density, pressures, mate- rial inventories and equipment oper- ating status • communicates with a wireline com- puter logging system via an RS-232 serial port to monitor bottomhole treating pressures and other parame- ters during treatment so that data can be used to analyze the treatment in real time • monitors real-time minifrac data to provide critical onsite fracturing parameters and, if necessary, data to redesign the fracture treatment onsite • displays the log/log plot of the net bottomhole treatment pressure versus time, to aid in decision making for real-time adjustments to the fractur- ing treatment • transfers data to a portable computer, if necessary, to interface with stimu- lation software such as FracProPT (discussed below) • interfaces with fracture design soft- ware and FracProPT which can be used in combination to assist in real- time fracture analysis • transfers job data from remote well- sites via satellite to a central technol- ogy center, allowing additional stimu- lation experts to use design/analysis software to make difficult real-time decisions, if necessary. Design and Simulation Frac length optimization, the best objective of an HRWP or frac-pack design, is determined by economics. Well performance is enhanced by the presence of the fracture and the cost of these sand control treatments is deter- mined at various frac half lengths. The incremental income increases with increasing fracture length. At a certain point the frac half length becomes pro- hibitive due to cost constraints. The cost is expressed as net present value (NPV). The NPV expresses the value of the reservoir after production over a finite time period. This time period cumulates the discounted incremental income of the project. The investment and operating costs are subtracted from the discounted incremental income to arrive at the net present value.4 Figure 4.20 illustrates such an optimization. Several software packages to assist with the design and execution of sand control treatments are available. Schlumberger, for example, has propri- etary software called FracCADE and SandCade. All service companies employ some type of computer-aided design and control software. These packages have several modules, which can perform various functions such as: • Calculating numerous engineering parameters • Simulating innovative pseudo-3D gravel placement • Simulating hydraulic fracturing treatment • Accounting for wellbore hardware for the duration of treatment pumping • Converting surface treatment condi- tions to bottomhole conditions • Allowing users to graphically analyze step rate tests, injection tests and G- function decline to determine fracture closure stress, fracture geometry and fluid leakoff coefficient • Presents log data to graphically define layers and zones • And many more. The following discussion will touch on some of the more popular software programs used by other service companies. Mfrac. Mfrac is a comprehensive design and evaluation simulator con- taining a variety of options including three-dimensional fracture geometry and integrated acid-fracturing solutions. Fully coupled proppant transport and heat transfer routines, together with a flexible user interface and object ori- ented development approach, permit use of the program for fracture design, as well as treatment analysis. Capabilities of this program include: • Automatically design a pumping schedule to achieve a desired fracture length and conductivity • Parametric studies and “what-if ” scenarios • Geometry and design optimization for proppant, acid and foam treatments • Pressure history matching and model calibration in real-time replay • Performs analyses to anticipate frac- ture behavior (e.g., fracture growth, efficiency, pressure decline, etc.). MFrac uses numerical, state-of-the- art, frac-pack and TSO methodologies to design “fully packed” or TSO-type proppant distributions. The modeling techniques used require that the fracture propagation and proppant transport solution be linked in such a way that each can influence the other. Normally, this means that for each time step in the fracture propagation calculation, the proppant transport simulation must be assessed and coupled. This methodol- ogy differs substantially from a conven- tional fracture stimulation approach, which by design tries to prevent prop- pant screen-outs or bridging. The criteria for automatic TSO and frac-pack designs include: • Designing to a pre-specified fracture length to optimize near wellbore conductivity • Basing the design on a maximum allowable inlet concentration • Designing to achieve a minimum concentration per unit area • Maintaining pumping pressures below a critical maximum pressures. Figure 4.21 illustrates the method- ologies for TSO and frac-pack designs and demonstrates that the net-fracture pressure and width both increase with time after a TSO. It also shows the final proppant concentration at the end of the job. FracProPT. This program is the Gas Technology Institute (GTI) fracture- stimulation engineering software that is being supported by Pinnacle Technolo- gies. Prior to 1999, earlier versions of FracPro supported by Resources Engi- neering Systems, Inc. (RES) were used in the industry. The Halliburton version of this software incorporates their extensive fluid rheology and conductiv- ity data and allows the user to "build" a custom fluid. The FracPro fracture design model was the first to go beyond standard sim- ulators by acquiring and analyzing real- time fracturing data during treatment. The program can be used to design fracturing treatments and then acquire downhole data during field operations or information from a treatment Chapter Four Surface Operations and Equipment Fracture length increases as a function of time up to the point of screenout (tso). After a perimeter screenout is achieved the propagation of the fracture stops and the width increases as a function of the increasing net pressure. In MFrac, these treatments may be automatically designed and a target length can be entered and used as a criteria for the design. The minimum and maximum proppant concentra- tions are user-specified parameters. Based on these values, the target length and average concentration per unit area entered, the program produces a pumping schedule that meets the criteria specified. For frac packs, an iterative approach is used to determine the time or volume for the maximum proppant concentration (tCmax). For either a tip-screenout or frac pack design the fracture area approaches a state of equilibrium once a screenout occurs (tso). Beyond this point, the rate of leakoff declines. For a TSO design the program allows the pressure to increase by main- taining a constant rate of injection (i.e., ballooning). A frac pack requires a decrease in rate to eliminate excess fluid and produce a stable net pressure. The time at which screenout occurs (tso) for both the tip-screenout and frac pack methods is characterized by a prominent rise in pressure. For a TSO treatment, the increase in pressure continues until the end of the job. In a frac pack, the rate is decreased at the time the maximum proppant con- centration is reached (tCmax). This creates a stab- ilization of the net pressure and corresponding fracture volume. Because width is a function of net pressure, their trends appear similar. Notice that “ballooning” is allowed in the tip-screenout example for the duration of the injection period. For the frac pack, on the other hand, width is held constant by allowing the rate to decline to affect the net pressure. This is the most efficient way to produce a uniformly packed proppant concentration throughout the fracture. Depending on which method is used, the prop concentration per unit volume in the fracture will vary. Because “ballooning” is permitted in a TSO design the inlet concentrations required to “pack” a fracture are typically not feasible. For these types of treatments the stages pumped early in a job concentrate near the front of the fracture and result in higher concentrations at the tip (≤Cbank). tso Time Tip screeenout Methodology Frac pack Fr ac tu re le ng th tso Time In le t p ro p co nc en tr at io n tsoInjection rate Leakoff rate Time Ra te Time tso Time Ne t p re ss ur e tso Time Fr ac tu re w id th Fr ac tu re w id th Cbank Fracture length Co nc en tr at io n at E OJ tso Time Fr ac tu re le ng th tso tCmax Time In le t p ro p co nc en tr at io n tso tCmax tCmax tCmax Injection rate Leakoff rate Time Ra te Time tso Time Ne t p re ss ur e tso Time Cbank Fracture length Co nc en tr at io n at E OJ Fig. 4.21. TSO vs frac pack methodology 108 Modern Sandface Completion Practices database to confirm design estimates or perform detailed post-treatment analy- sis. Onsite pumping schedule changes can be made to optimize the frac design based on formation frac-fluid parame- ters obtained from the minifrac analy- sis. Even real-time changes can be eas- ily incorporated while the job is in progress. The ability to design, monitor and analyze the fracturing treatment makes the FracProPT program a versa- tile model for both minifrac analysis and fracture design, real-time data anal- ysis or when used as a post-frac analy- sis tool. FracProPT’s integrated fracture pic- ture allows the display of multiple stages and logs (Fig. 4.22). WellWhiz. This is a program that mod- els production from wells with varying completions, such as vertical, deviated and horizontal with or without hydraulic fractures. Optimizing well performance is a vital task, yet existing analytical tools often make gross simplifications in geology or fracture shape, resulting in predictions that can be unreliable and misleading. WellWhiz answers a wide range of key questions such as: • What type of well should be drilled? • Should one consider a vertical well, perhaps with a fracture, or a horizon- tal well with several fractures? • How much improved production will various types of well comple- tions yield? • What about water influx in a naturally fractured reservoir? WellWhiz uses a numerical simulator to model multi-phase flow in the reser- voir and around the well, including in hydraulic fractures, to give an accurate prediction of well production rate and pressure response. Crucially, WellWhiz models non-Darcy flow in fractures and the reservoir, using proprietary labora- tory-measured beta factors. Non-Darcy flow can be an important flow mechanism in fractures in a gas well producing at 20 mmscf/d from a 100 ft (30.48 m) fracture height. For example, non-Darcy flow effects in the fracture will result in a reduction in fracture conductivity of up to 90% leading to dramatic over-estimation of a well production potential. StimPlan. This program, developed by NSI, is a fracture design simulator with special modifications that allow for TSO designs. At tip-screenout initia- tion, fracture extension is stopped and the program calculates a width increase based on the increase in net treating pressure. This program will analyze complex formations composed of mul- tiple productive layers with varying fluid-loss coefficients. Evaluation Techniques Once a gravel pack or frac pack is in place, it is important to determine or evaluate the effectiveness of many key aspects of the completion operation. A poorly executed treatment may result in early failure of the screen and prema- ture sand production, requiring costly remedial operations. Determination of the treated formation intervals, annular gravel-pack success and pack-assembly placement provides the necessary feed- back to make important decisions immediately following the completion. When voids or plugged packs are detected early, remedial action can be taken to help optimize production and prolong the life of the well. Historically, the tools used for treat- ment evaluations have been conveyed by wireline. Depending on the applica- tion, there are now tools available, which can be conveyed by wireline, slickline, tubing and coiled tubing. Additionally, memory-based tools, conveyed at the end of washpipe for logging after completion of the packing operation when coming out of the hole, are growing in popularity. Washpipe conveyance reduces rig costs and speeds time to production. It is quickly becoming the conveyance method of choice in deepwater opera- tions due to rig-time cost savings and for horizontal completions where it is sometimes difficult to run wireline tools. It provides immediate results after the washpipe is removed allowing for a quick decision while the pumping equipment is still on location. Gravel-Pack Evaluation A number of logging services and eval- uation techniques are available to assess the placement of material in gravel packs. These include: • Density log – a fullbore detector senses gamma rays from a tool- mounted radioactive (RA) source. • Dual-Detector Neutron log – changes in the count rate of neutrons emitted by a tool mounted RA source indicate changes in the hydrogen index. • Spectral Gamma Ray “tracer” log – in a single logging operation, spectral gamma measurements can help iden- tify multiple RA isotopes tagged to pumped materials. Density log. The historical wireline tool for gravel-pack evaluation is a porosity log commonly referred to as a density or nuclear density log. The tool consists of a chemical source of gamma radiation and a shielded gamma detec- tor (some tools may have more than one detector, which are callibrated to auto- matically compensate for borehole size, Fig.4.22. Example of FracProPT’s integrated fracture picture Intigrated fracture picture FracproPT layer properties Shale EB Up ... EB Mid ... EB Low... Shale Rockt... Stress... Modul... 0 500 Perm... Concentration of proppant in fracture (lb/ft≤) 25 50 75 100 125 150 175 200 225 10,450 10,475 10,500 10,525 10,550 10,575 10,600 10,625 10,650 0 0.50 1.0 1.5 2.0 2.5 3.0 3.5 4.0 4.5 5.0 Proppant concentration (lb/ft≤) Width profile, in. 10.500.51 109 Chapter Four Surface Operations and Equipment casing diameter and thickness, cement thickness, etc.). Gamma ray emissions bombard the pack and are backscattered to the detec- tor(s). The count rate at the detector is an indication of and inversely related to the bulk density of the borehole and its immediate environment. The gravel and its liquid filled porosity are denser than the borehole fluid alone. Hence a prop- erly packed interval will have a higher density (lower counts) than a packed interval that has voids or “holidays” or where no pack exists at all. Wireline service companies have traditionally provided this log under familiar brand names such as Nuclear Fluid Density (NFD) log, the Photon log, etc. Figure 4.23A illustrates a density log curve indicating a dramatic increase in gamma ray counts in relation to non- packed intervals. Protechnic’s PackScan Gravel Pack Density Imager is a dual detector den- sity tool specifically designed to mea- sure changes in the bulk density of a gravel-packed annulus (detects voids and top of gravel reserve). The memory- based density tool, which is used as either a stand-alone pack evaluation tool or as a complementary technique in conjunction with radioactive tracers, identifies small voids in the gravel pack. Since it is unaffected by the presence of radioactive tracers, it can also be used to evaluate proppant placement. Effects of borehole fluid variations and changes in tubular size and geometry are mini- mized. The tool functions much like other dual-detector density tools. Poor gravel-pack quality or voids will allow more gamma rays to reach the detector. This is seen on the log as a higher count rate response. However, to enable inter- pretation of the log, it is necessary to superimpose an exact graphic of the well completion hardware over the log presentation (Fig. 4.24). This comple- tion graphic is exact in relative wall thickness and depth. The importance of the well diagram is to determine the dif- ference between count rate increases and decreases that are caused by hard- ware from those that are caused by changes in the annular pack. Dual-dectector neutron log. Another technique uses the dual-detector neu- tron log, which employs a chemical source of neutrons and two thermal neutron dectectors, one near (N) and one far (F). The source emits high- energy neutrons which are slowed down (or moderated) by collisions with other nuclei. The main factor slowing down these neutrons is hydrogen, as found in water or oil, but not gravel. Neutron count rates at the N and F detectors will be high where a good pack is present and low when it is not. This occurs because the neutrons more easily propa- gate out to the detectors through gravel than through fluid. When the appropri- ately scaled N and F count rates are overlaid in a well-packed zone, the logs separate in poorly packed intervals. Small variations in the surrounding fluid can cause large variations in the neutron capture cross section. There- fore, the log response is a function of both pack and fluid variations. Figure 4.23B illustrates how the log responds to gravel-packed intervals. Spectral gamma ray “tracer” log. Perhaps the most commonly used gravel-pack evaluation technique is to tag the gravel with radioactive tracer materials. The materials commonly used are Iridium-92 (Ir) and Scandium- 46 (Sc). In the past, a single RA agent was used. Today it is more common to use Sc for tagging the packing of the perforations and Ir for tagging the main annular-pack stage. A detector is then run across the packed interval. If the RA agent is uniformly mixed with the gravel, the count rate indicates the pres- ence or absence of gravel pack. The Sc and Ir can be discriminated to assure gravel placement in the annulus and identify the perforated intervals (Fig. 4.23C). HRWP and Frac-Pack Evaluation Following an HRWP or frac-pack com- pletion, logs can be run to help evaluate the treatment effectiveness, including determining the height of hydraulically induced fractures, verifying the place- ment of pack materials and analyzing flow from treated formations. To verify the placement of pumped materials such as fracturing fluid, prop- pant and gravel, spectral gamma ray or tracer logs (Fig. 4.25, see page 112) are most commonly used. Most logging companies offer some type of tracer tool, for example: • Multiple Isotope Tracer Tool (MTT) (Schlumberger) • Precision Radioactive Isotope Spec- trometry Measurement Tool (PRISM) (Baker Atlas) Ir Sc GR counts RA tracer Counts Dual-dectector neutron GR counts Fluid density Well schematic A B C F N Fig.4.23. Gravel-pack log evaluation. Density log plot (A ), Dual-detector neutron log plot (B ), and a Tracer log plot (C ) 110 Modern Sandface Completion Practices • SpectraScan Tool (ProTechnics, a division of Core Laboratories) • TracerScan Tool (Halliburton) The treatment materials to be pumped are tagged with radioactive tracers that have dissimilar gamma ray spectra (i.e., Iridium-192, Scandium-46, Antimony-124). Each tracer emits gamma rays of different energies and different intensities than the other trac- ers. When fracturing, the fracturing fluid may be tagged with one tracer, the proppant with a second tracer and the gravel with a third tracer. Since the tracer tool can distinguish gamma rays in different energy ranges, it can differ- entiate the tracers after they have been pumped downhole during the treatment. Tracer logs record spectral gamma ray data as a function of depth and therefore can evaluate the vertical dis- tribution of the tagged materials. This allows the total and propped fracture heights to be estimated and voids in the packs to be located. Tracer log data also gives information regarding the approx- imate radial location of tracers and per- mits tracers in the borehole to be distin- guished from those in the formation. References 1. Corbett, T. and Vickery, E., “Multiple Zone Open Hole Gravel Packing Techniques with Zonal Isolation, IADC/SPE 77214, presented at the Asia Pacific Drilling Technology Conference, Jakarta, September 9-11, 2002. 2. Terracina, J., Parker, M. and Slabaugh, B., “Frac- turing Fluid System Concentrate Provides Flexibility and Eliminates Waste,” SPE 66534, presented at the Exploration and Production Environmental Conference, San Antonio, Texas, February 26-28, 2001. 3. Lindeburg, M., “Mechanical Engineering Reference Manual, 10th Ed., Professional Publications, 1997. 4. Voneiff, G. and Holditch, S., “An Economic Assess- ment of Applying Recent Advances in Fracturing Tech- nology to Six Tight Gas Formations,” SPE 24888, pre- sented at the Annual Technical Conference and Exhibition, Washington, DC, October 4-7, 1992. Fig.4.24. This PackScan gravel-pack evaluation log identifies good pack through the screen interval with an inconsequential void detected in the blank pipe interval. The top of pack is easily identifiable along withthe change in density at the top of screen. 111 Chapter Four Surface Operations and Equipment Fig.4.25. This tracer log example identifies the location of formation stimulation and the annular pack interval including the top of sand. It also verifies the position of the gravel-pack assembly by identifying the depth of the radioactive markers placed in the assembly near the sump and gravel-pack packers. 112 Modern Sandface Completion Practices Agood completion design shouldalways emphasize practices thatmaximize well productivity and help operators realize the most benefit from the selected solutions. The best completion designs are based on specific well requirements. Besides those that have been previously discussed in this handbook, other options to obtain effec- tive sandface completions exist. Several of these alternative practices and special techniques are covered in this Chapter. Rigless Sand Control Techniques Marginal or secondary payzones are often bypassed because of the breadth and cost of services required for reme- dial or workover operations. New tech- nologies employing small diameter tools and expandable sand-exclusion screens show real promise in expediting the rou- tine application of “rigless” or thru-tub- ing completions. Accessing wellbores in a workover environment without using a costly conventional drilling or workover rig provides countless new opportunities for maximizing production from these marginal zones. There are four major types of rigless or thru-tubing, sand control techniques: • Chemical – Resins or chemicals are injected into poorly consolidated for- mations to provide in situ grain-to- grain bonding. • Mechanical – These include the use of small diameter or expandable screens, which are designed to be run- through tubing and then placed inside casing, tubing or other larger screens. These are commonly combined with various hydraulic methods. • Hydraulic – These methods involve applying fracturing techniques, such as HRWP and frac packs, on a well without the aid of a drilling structure. • Chemical/mechanical/hydraulic combination – These completion methods involve frac packing using resin-coated proppant. This process is also referred to as a screenless frac pack and was discussed in the “Frac Packing” Section of Chapter Three. Wedman, et al, presented a successful application of this tech- nique, in a recent multi-zone com- pletion case history.1 Since hydraulic fracturing and screenless frac packs have been dis- cussed in previous Chapters, only chemical and mechanical thru-tubing, completion techniques will be dis- cussed in this Section. Chemical Methods Chemical treatment techniques are sometimes employed for sand control. These processes are designed to pro- duce a chemical reaction with the for- mation sand for the purpose of inhibit- ing its mobility. Two techniques, resin consolidation and steam consolidation, are discussed here. Resin consolidation. This sand control method involves injecting chemicals (usu- ally resins) into the unconsolidated for- mation to provide grain-to-grain cementa- tion. Cementing the sand grains together at their contact points creates a strong consolidated matrix. Subsequent flushes displace excess resin material further into the formation to clear the pore spaces between grains, allowing the best possible permeability for oil and gas flow. Resin consolidation systems help control sand without mechanical screening devices restricting the well- bore or limiting access to lower produc- ing zones. Ideal for dual-zone comple- tions, these systems permit access to a lower zone without disturbing the upper zone. This is accomplished by consoli- dating the upper zone and gravel pack- ing the lower zone. A successful consolidation treatment must provide the additional strength required while maintaining as much formation permeability as possible. Successful consolidation treatments also depend on obtaining complete cov- erage of all perforations in the payzone. For this reason consolidation treatments are generally performed on short inter- vals of 15 ft (4.6 m) or less. Perforations are a prime concern in chemical consolidation treatments. Suc- cess depends on either all perforations being open to accept the resin or using excess resin so that the interval around any plugged perforation is also treated. In most cases, treating 90% of the per- forations will result in a failure rather than a 90% success. Advantages of chemical consolida- tion include: • Wellbore is left free of obstruction, making this method more adaptable to multiple completions. • Does not require recovery of liners to repair failure of a sand control treat- ment or recompletion of another zone. • Repair jobs can be attempted without pulling downhole equipment by pumping the chemical down the exist- ing tubing string or by using coiled tubing or hydraulic workover units. • Method is more desirable than gravel packing in monobore or thru-tubing completions. Disadvantages of chemical consoli- dation include: • Treatment results in reduced forma- tion permeability. • Treatments are generally more expensive on a per foot basis than a gravel pack. • Interval length is limited to 15 ft (4.6 m) at a time. • Materials used are generally haz- ardous to handle and hard to dispose. • Treatment is subject to deterioration with time. Alternative Practices and Special Techniques Rigless Sand Control Techniques • Specialty Tools and Techniques CHAPTER FIVE 113 The principal behind chemical con- solidation is relatively simple - inject resin, coat the formation sand grains, allow the resin to harden and bond at sand-grain contact points, then place the well on production. However, in actual field applications, it is difficult to consistently obtain successful plastic treatments. Not only is proper place- ment of the materials critical to success, but the materials must be injected into all perforations in the correct sequence: first the preflush and conditioning flu- ids, then resin, overflushes and activat- ing agents. Figure 5.1 shows the typical steps involved in a resin consolidation. Resins are also finding applications in remedial treatments. If the completion interval is free of any fill inside the cas- ing, the plastic can be injected through the production tubing. In some cases, either small diameter tubing or coil-tub- ing units are used to clean out the well- bore and inject the resin. Repeated resin consolidation attempts are not recom- mended because excessive permeability reduction may occur. In instances where significant sand production has occurred, the well should be prepacked with gravel before the consolidation chemicals are injected or a resin-coated gravel system should be used. Steam consolidation. The use of the hot alkaline/steam sand-consolidation technique to complete wells is based on the geochemical bonding. In this process, unconsolidated formation sand grains are bonded with a lattice of pri- marily high-temperature, complex syn- thetic silicate cements and possibly other lower-temperature precipitates, such as silica cements and carbonate scales. The complex silicate cements and other mineral precipitates are cre- ated by the high-temperature and high- alkaline pH steam condensate, which preferentially dissolves sand grains with high-specific surface area. The injected fluids rapidly lose heat to the formation and various cement precipi- tates with changes in temperature, alka- linity and contact time. The lattice of cement bonds are created by the rela- tively high-volume and high-velocity steam vapor phase, which quickly dissi- pates through the near-wellbore region and carries away excess cements and other precipitates so they do not adversely affect formation porosity and permeability. The wells completed with this tech- nique have equivalent or higher pro- ductivity and injectivity than wells completed with open-hole, gravel- packed, slotted-liner completions. In addition, steam consolidation signifi- cantly lowers drilling and completion costs. It improves fluid entry or injec- tion profile control, provides a low-cost means of eliminating unwanted com- pletion intervals, and provides flexibil- ity to use wells interchangeably as pro- ducers or injectors.3 Mechanical Methods There are three basic mechanical meth- ods (Fig 5.2) of rigless sand control completions that involve placement of gravel into the perforations where no returns are taken.4 • The pack-off or squeeze-pack method – which uses a gravel-pack screen with a blank spacer pipe and pack-off or packer seal assembly run thru-tubing. It can be placed inside casing or an existing gravel-pack screen, spaced-out so that the pack- off or packer assembly is landed inside the production tubing. • The vent-screen method – which uses two screen sections, separated by blank pipe placed and packed in the casing with production entering the lower section of screen and exit- ing the upper section. • The wash-down method – which uses a pre-pack (HRWP or frac) with the gravel-pack screen being “washed” into position and sealed or packed-off. This method is applicable for both casing and tubing. Pack-off or squeeze method. In a pack- off method gravel pack, a screen, with a length of blank pipe attached to a releas- Formation water Formation sand grain A. Oil and formation water before consolidation Oil Oil Resin solution C. Resin solution displaces preflush E. Well ready for production Overflush B. Preflush miscibly displaces oil and formation water Preflush D. Overflush immiscibly displaces resin and activates resin cure Resin Resin Fig. 5.1. Saturation changes during resin consolidation 114 Modern Sandface Completion Practices 115 ing tool and coiled tubing, is run across the perforations. Once the screen is placed, a ball is dropped and circulated through coiled tubing. The ball will land on the releasing tool forming a seat. When pressure is applied to the ball seat, the releasing tool, attached to the coiled tubing, will be free from the blank pipe and screen. It also opens the circulating port that allows fluids to be pumped through coiled tubing, exiting to the annulus of the blank pipe and casing. A certain set-down weight is neces- sarily applied on the hydraulic release tool to prevent it from being pushed upward during the squeezing operation. Gravel exits the releasing tool and is packed in the perforation tunnel. When screenout occurs, the excess sand is cir- culated out. Coiled tubing is then pulled- out to surface. Slickline will run the pack-off and anchor assembly to prevent sand that passed through the annulus and the screen from moving upward. 5 Thru-Tubing Systems, Inc. has a similar system (the One-Trip, Squeeze- Pack System). It allows for the deploy- ment and placement of the gravel pack in one trip on coil tubing or jointed pipe. It utilizes a thru-tubing retrievable seal-bore, gravel-pack packer and a two-position, crossover-tool combina- tion. This system contains similar com- ponents to that of typical cased-hole, rig-deployed systems. It allows for the setting and testing of both sealing and anchoring components prior to the plac- ing of the gravel-pack proppant. This easily accommodates the identification, removal, and replacement of any failed components prior to producing the well. The system is also designed to handle both low bottomhole pressure and live well applications. Typically, screen, blank pipe, a shear-out safety sub, and a gravel-pack packer/crossover-tool BHA is deployed into the well via coil tubing. The screen assembly is spaced out across the pro- ductive interval while blank pipe ties the packer assembly back into the production tubing. Once the assembly is located on depth, a setting ball is pumped around the coil tubing reel and allowed to gravi- tate on a seat in the crossover/setting tool. Pressure is then applied to the coil tubing and the packer is set and disconnected from the two-position crossover tool. The coil tubing/production tubing annulus is then pressurized in order to pressure test the packer. Once the component setting and test- ing is complete the gravel pack slurry is pumped down the coil tubing though the packer/crossover tool and out a perfo- rated sub located below the packer. The gravel pack slurry then travels down the blank pipe and screen/casing annulus and into the production perforations until a screenout occurs. Following the screenout, pressure is bled off the coil tubing. The crossover tool is then repo- sitioned into the upper circulating or reverse position by picking up on the coil tubing +- 3 ft (+- 0.91 m). At this time, pumping down the coil tubing is resumed while taking returns up the coil tubing/production tubing annulus, allowing for the removal of any excess gravel-pack slurry remaining inside the coil tubing or work string. Seal exten- sions on the crossover tool maintain zonal isolation during this sequence of the operation, thus providing for the removal of the excess gravel-pack slurry even in wells that are under pressured. Once the excess slurry is removed from the well, the crossover tool/running tool assembly and coil tubing are removed. As the crossover tool exits the packer assembly, a sliding sleeve is landed across the ports in the perforated sub isolating the same. Once out of the hole with the coil tubing the well is returned to production. Vent-screen method. This technique has been used for many years in situa- tions requiring remedial sand control. Chapter Five Alternative Practices and Special Techniques Fig. 5.2. Pack-off method (left ). Vent-screen method (center ). Wash-down method (right ). The vent-screen technique uses two screen assemblies separated by blank pipes that are placed and packed in casing. Production enters the lower screen section and exits the upper screen section. The screen and blank assembly are run into the hole through the production tubing on electric line (e-line), slickline or coiled tubing and set on the bottom. The dual-screen, thru-tubing assembly does not require the top of the blank liner to be extended into the production tubing. Once the bottomhole assembly (BHA) has been properly located across the perforations, the desired gravel pack is pumped through the coiled tubing and then completely over and around the dual screen, covering the entire screen assembly. The gravel slurry is re-stressed by pumping from the annulus to pack around the lower section of the BHA. Once screenout pressure is observed, the gravel is washed from around the upper screen section, again using the coiled tubing. Production is directed through the lower section of the screen, up the blank pipe and out the top sec- tion of the screen (Fig. 5.3). Most of the wells that employ this completion method are plugged-back through tubing to the next zone as soon as the completion depletes or fails. Pro- duction and/or formation logs are not always needed because of the limited reserve size. Many operators are using this and similar methods for their pri- mary means of sand control in new well completions due to successes and cost efficiencies on primary as well as plug back completions. Wash-down method. The wash-down method consists of a lower jet shoe, screen, blank pipe and hydraulic dis- connect. Inside the screen and blank pipe, an inner tube is spaced, running from the hydraulic disconnect down to the shoe. The system is run on coiled tubing. The first step is to clean out the wellbore to a point approximately 10 to 15 ft (3.05 to 4.57 m) below the perfo- rations. With the wellbore clean, a pack medium is placed across the perforated interval. This pack medium may be sized gravel, ceramic proppant, sintered bauxite or other spherical material. Once placed, the top of the material is “tagged” (radioactively marked) to ver- ify that the perforations are covered. Any excess material is washed out usu- ally with coil tubing to +-10 ft (+- 3.05 m) above the top perforation shot. The screen assembly is run in on coiled tub- ing and washed-down until properly placed across the perforated interval. A ball is then dropped, and the running tool is disconnected. The coiled tubing is removed from the wellbore, and wire- line is rigged-up to install the pack-off and tubing stop or packer assembly on top of the liner. Fig. 5.4. Wash-down, gravel-pack system Fig. 5.3. Vent-screen, rigless through-tubing completion 116 Modern Sandface Completion Practices Thru-Tubing Systems has a wash- down gravel-pack system that has sev- eral unique features. The system can be deployed on coiled tubing in one trip and does not require subsequent trips into the well to install pack-off or tubing stops. Unlike conventional thru-tubing wash- down systems, its sealing and anchoring component allows for failures to be detected and repaired prior to producing the well. This system is frequently employed following frac-pack treatments and in applications where excessive wellbore sloughing hinders normal deployment of conventional gravel-pack hardware. Figure 5.4 illustrates the vari- ous positions of this tool system. Thru-tubing circulating gravel pack. The Eclipse Packer Company (recently acquired by Weatherford) offers an alternative method. It is a one-trip, cir- culating gravel-pack system that is hydraulic-set, retrievable and can be run on coiled tubing or jointed pipe. The design eliminates the need for work- string manipulation to achieve run-in, setting, gravel-packing and circulating- out positions. After placement of the gravel, the packer remains in the well- bore as the production packer. Thru Tubing Systems also offers a similar circulating gravel-pack system, which employs a large-bore, retriev- able/inflatable packer and crossover tools combination. It too is designed to be deployed in one trip on coil tubing or jointed pipe. The main feature differ- ence of this system is the ability of the inflatable packer, with a 2:1 expansion ratio, to be deployed through smaller well tubulars and set inside of larger tubing or casing sizes. This feature is beneficial when wellbore restrictions exist that prohibit the use of conven- tional packer or pack-off systems. In many cases this system will allow for the gravel-pack assembly to be landed in the wellbore below the end of the production tubing, thus not hindering future plug backs. In most remedial applications, the work involves placing a small diameter screen through the tubing and setting the completion into either casing or an existing screen with a greater diameter than the tubing ID. As long as the screen diameter is approximately 1 in. (2.54 cm) smaller than the casing or existing screen diameter, the gravel placement can proceed without undue concern for premature bridging due to the small annular clearances. However, there are times when it is advantageous to maximize the size of the new screen section to minimize the pressure drop across the new comple- tion. If these applications cause very small radial clearances on the outside of the screen, then premature bridging of the sand particles becomes a major con- cern. This is particularly true when these clearances get to be as small as 0.25 in. (0.64 cm). The two flow areas, where flow occurs on both sides of the screen, are shown in Figure 5.5. Tests have been run to determine new washpipe size recommendations (Table 5.1). Table 5.2 lists common washpipe sizes. The ratio of outer annu- lus area to inner annulus area for the newly recommended washpipe sizes is shown in Figure 5.6 as a comparison.7 Thru-tubing perforating and screen deployment. This system (Fig. 5.7) can be run on coiled tubing, e-line or slick- line in one trip, thus saving time and expense of multiple systems. It allows for perforating gun deployment into the well followed by tubing patch work needed to remedy tubing/casing com- munication. Once the tubing straddle or patch work is completed, the guns can be fired hydraulically from the surface with nitrogen and the well returned to production. Guns are fired independent of packer setting, allowing for the packer to be set on wireline or with coiled tub- ing. Perforating guns can be fired after the slickline or coiled tubing is rigged down and moved off of the well. Thru-tubing frac pack/HRWP. A rig- less frac-pack or HRWP system allows sand control across a lower zone via a gravel pack or frac pack and, at the same time, ensures that the completion Screen Base Pipe Size Washpipe Size (in.) (in.) 2.375 1.315 2.875 1.900 3.500 2.375 4.000 2.875 4.500 2.875 5.000 3.500 5.500 4.000 6.675 4.500 Table 5.1. Recommended washpipe sizes Casing Screen Washpipe Outer annulus area Inner annulus area Fig. 5.5. Flow areas during gravel transport Screen Base Pipe Size Washpipe Size (in.) (in.) 2.375 1.315 2.875 1.900 3.500 2.375 4.000 2.875 4.500 3.500 5.000 4.000 5.500 4.500 6.675 5.500 Table 5.2. Common washpipe sizes 117 Chapter Five Alternative Practices and Special Techniques assembly above the lower zone is opti- mized for a future thru-tubing gravel pack on an upper zone. The lower zone is packed as normal. If necessary, a spacer assembly and upper packer are stung into the gravel-pack packer and set. To shutoff production from the lower zone and access the upper zone, a thru-tubing bridge plug is set in the blank pipe above the lower zone. The upper zone is perforated. A dual-screen assembly is placed across the upper zone, and an HRWP or frac-pack treat- ment is performed to place sand in the perforation tunnels and around the screen assembly. Excess sand is washed clear of the upper screen using coiled tubing. The well can then be placed on production. Figure 5.8 is a schematic of the downhole tool assembly. A thru-tubing frac pack, incorporat- ing a vent-screen system, can also be done using releasable “one-trip” TCP guns. In a geopressured well this method could significantly reduce the well com- pletion cost by eliminating the need for high-density completion fluid and a 15,000 psi blowout-preventer (BOP) stack. The TCP guns, with the vent- screen/blank assembly attached, is run in the hole and positioned with a depth veri- fication tool on a workstring. The tubing and production packer are then run, the packer is set and the wellhead is nippled- up. The rig then can be released. The TCP guns are fired by pressur- ing-up at the surface. The guns are released into the rathole, and the vent- screen assembly moves downward into place. The high-pressure frac pack is performed down the production tubing using a wellhead isolation tool/treesaver. Excess proppant above the vent screen can be flowed to surface due to high reservoir pressure. In other cases, it may be necessary to use coiled tubing to washout to the vent screen.8 There are more rigless sand control techniques available than what space allows for discussion here. Information on additional or newer rigless-comple- tion systems can be obtained by contact- ing any number of service companies. Specialty Tools and Techniques Discussions in this Section will include selected specialty tools and techniques for sand control including wireline gravel packing, the VibraPak rotary vibration system, multilateral tech- Fig. 5.7. Thru-tubing perforating and screen deployment 5-in. 18# isolation tubing Future thru-tubing assembly Flapper 3 1/2-in. blank 3 1/2-in. screen Bridge plug 7 5/8-in. casing “VTA” packer “VTA” packer Fig. 5.8. Rigless frac-pack or HRWP system 0.5-in. common 0.25-in. common 0.25-in. recommended 0.0 2.0 2.5 3.0 3.5 4.0 4.5 Screen base pipe size, inches 5.0 5.5 6.0 6.5 7.0 0.5 1.0 1.5 Ou te r/ lin er a nn ul us ra tio 2.0 2.5 3.0 3.5 Fig. 5.6. Ratio of the annulus area outside of the screen to the annulus area inside of the screen for common washpipe sizes inside of the screen. Comparison for 0.50 in. and 0.25 in. radial clearance between the screen OD and the casing. 118 Modern Sandface Completion Practices niques, and systems used with rod pumps and electric submersible pumps (ESPs). While there are numerous spe- cial tools and techniques available for achieving various levels of sand con- trol, these are representative of some newer and some unique technologies. Wireline Gravel Pack Perf-O-Log has developed a thru-tub- ing, wireline gravel-pack (TTWGP) system. It is an alternative to thru-tub- ing sand-control methods, which were discussed in the previous Section. A TTWGP is deployed with an electric wireline. It can be installed in: • Damaged conventional gravel-pack completions • Zones that have been washed out • Newly perforated zones. Most importantly, the entire proce- dure can be done under pressure.9 A typical job consists of the wireline plugback (setting the thru-tubing bridge plug and/or dump bailing cement plug), perforating, screen deployment, con- veying the gravel-pack slurry via dump bailers, then placing a cement cap with dump bailers. The screen assembly (Fig. 5.9) consists of (from bottom-up): solid spacer bar (can be cut to desired length on location), screen sections (wire-wrapped or pre-packed), bow- spring centralizers, blank joint, vent screen, and retrievable vent-screen cap. At the end of the job, the vent-screen cap is pulled, enabling flow through either the top of the assembly or through the vent screen. Once the assembly exits the tubing and enters the casing, the bow springs expand, thereby centralizing the assem- bly. The assembly is then placed across the perforated interval on a cement or sand bottom situated directly below the perforated interval as illustrated in Figure 5.10. A gravel-pack slurry, consisting of a suspension agent (sheared and filtered HEC polymer) and gravel-pack sand is then dumped around the TTWGP, using wireline gravity bailers. The slurry is dumped in-place in its original blended form. The sand, distributed across the zone, is checked via electric-wireline depth control on each trip into the well. Bailer runs of cement are then per- formed, placing approximately 3 to 4 ft (0.9 to 1.22 m) of cement around the blank pipe to hold the gravel pack in place (Fig 5.11). The cap plug is then removed from the top of the assembly. Hydrocarbons are produced through the gravel-pack sand into the screen, up the blank and out the vent screen or the opened top of the gravel-pack assembly (Fig. 5.12). Vibra-Pak Vibra-Pak technology was pioneered in the early 1980s in California by Solum Oil Tools, now a division of PT Pipa Mas Putih in Indonesia. The technology Retrievable vent screen cap Vent screen Bow-centralizer Bow-centralizer Bow-centralizer Bow-centralizer Blank pipe Screen Screen Spacer pipe Fig. 5.9. Wireline gravel-pack components Retrievable vent screen cap Vent screen Bow-centralizer Bow-centralizer Bow-centralizer Bow-centralizer Blank pipe Screen Screen Spacer pipe Cement TTBP GP sand Dump bailer Electric-line Perforations on low side 0°-30° Fig. 5.10. Gravel slurry around tool string Retrievable vent screen cap Vent screen Bow-centralizer Bow-centralizer Bow-centralizer Bow-centralizer Blank pipe Screen Screen Spacer pipe Cement TTBP GP sand Cement cap Fig. 5.11. Cement cap in place 119 Chapter Five Alternative Practices and Special Techniques involves a rotary vibration system in a downhole tool that imparts enough amplitude to move the gravel into hexagonal packing during the gravel- packing period, regardless of fluid vis- cosity. This action fluidizes the gravel and creates a highly permeable, yet truly high-density primary completion gravel pack free of voids.10 Vibra-Pak has been successfully applied in both open-hole and cased- hole completions. Figure 5.13 illus- trates two typical gravel-pack comple- tions using this rotary vibration technique. Vibra-Pak tests have shown that in a full-scale, horizontal gravel-packing model the rotary vibration resulted in 100% gravel compaction between the open hole and the liner in a water-pack system. In addition, there was no bridg- ing, no after-pack settling, no voids at the roof of the hole and the vertical perforation tubes were tightly packed with gravel.11 Multilaterals Drilling more than one drainhole from a primary borehole has become a com- mon industry practice. Multilateral drilling and completion technology is used in both new wells and for reentry applications in existing wells. Multilateral wells can be broadly divided into two groups – those that offer no hydraulic isolation between the laterals (Levels 1-4) and those that do (Levels 5-6). The Level-3 and Level-6 systems have emerged as the prime can- didates for applications that require no or full hydraulic isolation between the laterals. Level-3 junctions provide a pre-milled window system with a liner tieback. This mechanical junction pro- vides full-reentry access to the main wellbore and the lateral. As full-bore access is available, pumps can be placed below the junction and closer to the reservoir. Level-6 junctions have full-pressure integrity achieved by the main casing string.12 In an effort to provide parity when comparing multilateral systems indus- try wide, a classification system was developed by Technology Advance- ment for Multilaterals (TAML), a con- sortium group comprised mainly of North Sea operators. The classification system divides wells into “levels” depending upon junction functionality. Table 5.3 lists the definitions of the various levels.13 Early Level-3 multilateral-well com- pletions were constructed using a flow- through guide stock and slotted liner or screen in the lateral, which was anchored to the main wellbore by a liner-hanger packer. Flow was allowed through the flow-through guide stock from the main bore completion, where it became com- mingled with the lateral production via perforations or slots in the lateral-liner overlap in the main bore. The challenge was to provide a means for allowing main bore reentry. With this increased functionality, Level 3 could be a viable, simple replacement for Level 4, as well as the Level 1 and 2 completions.14 With a focus on simplicity, design iterations led to the development of the Hook Hanger system. The intent was to construct a tool that was mechanically basic (no moving parts) and easy to install. Baker’s Hook Hanger is a liner with a machined window for main well- bore reentry. A “hook” at the bottom of the machined window is used to “hang” the system at the bottom of the casing exit window. Hold-down slips at the top of the system ensure that it is engaged to the main-bore casing. Reentry is achieved using a main-bore or lateral diverter, which orients and locates in the system at the junction, to deflect coiled tubing or coupled pipe into the desired wellbore. With this design, Level-3 mul- tilaterals have full reentry functionality into both the main bore and lateral com- Multilateral Classification Definition Level 1 Open-hole sidetrack or unsupported junction Level 2 Cased and cemented main wellbore; open-hole lateral or drop-off liner Level 3 Main bore is cased and cemented; lateral bore is cased but not cemented Level 4 Main wellbore and lateral are cased, cemented and mechnically connected Level 5 Cased and cemented main wellbore and uncemented or cemented lateral liner with hydraulic and pressure integrity provided by additional completion equipment inside the main wellbore (packers, seals and tubulars) Level 6 Cased and cemented main wellbore and uncemented or cemented lateral liner with hydraulic and pressure integrity provided by the primary casing at the lateral liner intersection without additional completion equipment inside the main wellbore Table 5.3. Technology Advancement for Multilaterals (TAML) classification system Vent screen cap removed Vent screen Bow-centralizer Bow-centralizer Bow-centralizer Bow-centralizer Blank pipe Screen Screen Spacer pipe Cement TTBP GP sand Perforations Cement cap Fig. 5.12. Well producing 120 Modern Sandface Completion Practices pletions.15 Fig. 5.14 illustrates a basic wellbore configuration that allows for coiled tubing or other compatible size tool re-entry. These installations begin with a standard horizontal open-hole well with a slotted liner anchored to the main-bore casing. Figure 5.15 is a TAML Level-3 schematic of a Smith MX junction with an open-hole gravel pack. With this sys- tem, a one-trip whipstock is used to mill the long, full-gauge window. Here too, the lateral wellbores can be re- entered through the production tubing string with size-compatible tools. Addi- tional open-hole drilling, out the lower end of the lateral liner, may be needed to meet completion objectives requiring open-hole slotted liners, conventional screens or premium screens (Fig 5.16). At this point, access to the lower pro- ducing borehole is achieved. For a TAML Level 4 completion in a depleted zone, Weatherford’s StarBurst system can be considered. It provides a cemented-liner, tieback junction with main bore production access, as well as production and tool access to the lateral leg or new drainage point. This system is ideal for existing wells in mature fields, particularly where additional nearby reserves can be accessed while still maintaining the original wellbore production. Figure 5.17 uses a hollow whipstock that can be combined with an UltraPak permanent packer to with- stand high pressures during well con- struction. Again, re-entry into the lat- eral sections can be made with size compatible tools. Sand control installations can be run in both TAML Level-5 and Level-6 wells. However, these types of comple- tions are not yet common place. Rod Pump and ESP Sand Control Techniques Formation sand, frac sand fragments and other abrasive particles, which are roughly 50 microns to 200 microns in diameter, cause most rod pump damage. These particles are small enough to enter the space between a rod pump plunger and barrel, and large enough to cause damage. As the pump cycles, particles are crushed between the two surfaces, scoring the plunger and barrel. This results in the need for premature pump replacement. ESPs are typically damaged by sand production across a Fig. 5.13. Vibra-Pak completions in an open hole (left ) and a cased hole (right ) +/- 4,500 ft long 8-1/2 in. openhole laterals with 7 in. slotted liners 2,700 ft MD 5.50 in. drift into mainbore with diverter in place in the HOOK hanger 5.75 in drift into lateral with diverter in place in the HOOK hanger ESP HOOK hanger with hold down slips Fig. 5.14. TAML Level 3 hanger with hold down slips and slotted liner 121 Chapter Five Alternative Practices and Special Techniques broader particle size range, impacting bearings, impellers and diffusers. Numerous methods have been devel- oped to minimize the impact of sand on wells, which employ various forms of artificial lift. These methods include: • Minimizing the amount of sand entering the wellbore • Minimizing the amount of sand entering the pump • Minimizing impact of sand on pump. Fig. 5.18. Conventional rod-pump plunger (left ) and the Farr plunger (right ) Drillpipe 9 5/8-in. casing Centralized lateral liner hangers Centralized liner joint 8 1/2-in. open hole 7-in. casing Production packer Running tool 6-in. open hole Float shoe with sealbore sub Seal assembly Expandable flapperWashpipe 3 1/2-in. dual prepack screen Fig. 5.16. TAML Level 3 washdown system for stand-alone screens run in a open hole (sized-solids DIF displaced) Liner hanger Whipstock Float shoe Packer Liner hanger Fig. 5.17. TAML Level 4 with StarBurst system and cemented liner tieback junctionFig. 5.15. TAML Level 3 with MX junction, screen and gravel pack 122 Modern Sandface Completion Practices Minimizing sand entry into the well- bore must be done during the initial well completion or through implementation of a post completion sand-control treat- ment (both of which have been covered extensively in this Handbook). Numer- ous modifications to the conventional sucker rod pump, including the Farr plunger and the Muth dual string sys- tem, have been developed to minimize the impact of sand on these pumps.16,17 Filters or membranes, including the Stren PumpGard, and centrifugal sand separators attached to the pump intake can also reduce the amount of sand entering a pump system. Most of the engineered systems and techniques used to prevent abra- sive particles from entering a pump have been designed to achieve the following objectives: • Reduce well pulling cost • Increase pump life • Reduce down time • Eliminate stuck plungers • Increase pump efficiency • Reduce pump repair costs. Farr plunger. The connector on the top of a conventional plunger (Fig. 5.18 left), which connects the pull rod to the plunger, is 60 thousands smaller in diameter (OD) than the plunger itself. This connector is tapered downward and outward from where the pull rod connects. The smaller diameter allows for a gap at the top of the plunger. The taper on top of the connector creates a funnel. As the plunger moves upward, the sand (or any solids in the produced fluid) is forced down into the funnel and stuffed inside the gap, pushing abrasive material between the connector and the pump barrel wall. The sand will eventually migrate down between the plunger and the pump barrel wall. This abrasive material starts wearing on the two metal surfaces, creating lower and lower pump efficiencies. Eventually the pump will not move the fluid volumes required and will need to be pulled. The unique aspect of the Farr plunger (Fig. 5.18 right) is the manner in which the sucker rod string is connected to the plunger. The connector, which is thought to create the problems in the conventional plunger, has been moved from the top of the plunger to the bot- tom of the plunger in the Farr design. Essentially, the Farr design eliminates the funnel and the wedge, and moves the 60 thousands gap to the bottom of the plunger. Hence, the top of the plunger has only a 2 or 3 thousands clearance between the plunger and pump barrel as opposed to the 60 thousands in the con- ventional design. Additionally, the angle at the top of the plunger has been reversed to force sand inward as opposed to outward in the conventional design. The likelihood of sand getting between the plunger and pump barrel is greatly diminished, and the plunger now acts like a scraper, cleaning off the pump barrel wall and throwing sand inward as opposed to outward. PumpGard. The PumpGard from Stren, unlike formation sand screens (which were discussed in Chapter Two), brings protection directly to the rod pump, tub- ing pump or ESP. It consists of a preci- sion 316 stainless steel membrane con- tained in a protective steel carrier (Fig. 5.19) that installs directly to the pump. The membrane filters production fluid before it enters the pump inlet, prevent- ing sand cutting of the pump. PumpGard intercepts particles in the critical size range (Table 5.4, see page 124). The screen sizes are selected according to well characteristics; how- ever, screens rated at 100 microns are effective for most “general purpose” service applications. For precise speci- fication of micron rating, Stren can pro- cess customer-supplied solids samples in it solids characterization laboratory. There are several PumpGard models designed for specific applications. For rod pump applications – Pump- Gard is available in single or multiple tool configurations. It threads directly to the pump standing valve by universal connections for easy installation and retrieval via the rod string. Pressure drop across the membrane is typically less than 1.0 psi when first installed. For tubing pump completions – The PumpGard HiFlo connects to the seat- ing nipple or tubing string below the pump. The HiFlo Series 400 and 500, for 5-1/2 in. and 7 in. cased wells, pro- vide high capacity. They are hydrauli- cally balanced for service with standard and big-bore tubing pumps. API 25, E30-sized cartridges are the modular building blocks around which these units can be assembled to meet virtually any capacity. For ESP applications – The Pump- Gard HiFlo ESP prevents “sand cut” damage and helps maintain pump effi- ciency. These units are available in capacities up to 20,000 bfpd. Units may be threaded directly to the pump shroud, or for unshrouded pumps, used with standard packers or the Stren ESP Auto-Set sub. This sub automatically inflates to casing to direct de-sanded production into the pump intake, but retracts to tubing collar diameter for easy production tubing removal from the well. Fig. 5.19. The PumpGard sand-screen membrane filter 123 Chapter Five Alternative Practices and Special Techniques References 1. Wedman, M., Lynch, K., and Spearman, J., “Hydraulic Fracturing for Sand Control in Unconsoli- dated Heavy-Oil Reservoirs,” SPE 54628, Western Regional Meeting, Anchorage, Alaska, May 26-28, 1999. 2. Coulter, A. and Gurley, D., “How to Select the Cor- rect Sand Control System for Your Well,” SPE 3177, AIME, Petroleum Engineers, 1971. 3. Hara, P., Mondragon III, J., and Davies, D., “A Well Completion Technique for Controlling Unconsolidated Sand Formations by Suing Steam,” U.S. DOE Oil and Gas Conference, Dallas, Texas, June 28-30, 1999. 4. Freiman, O. and Johnson, K., “Use of the Dual- Screen Thru-Tubing Sand Control Method,” SPE 28698, International Petroleum Conference, Veracruz, Mexico, October 10-13, 1994. 5. Lee, C. and Darby, M., “Effective Thru Tubing Gravel Pack Methods in Attaka Field,” Asia Pacific Improved Oil Recovery Conference, Kuala Lumpur, Malaysia, October 8-9, 2001. 6. Bell, R., Jr., Morrison, D., and Martch, W., Jr, “Achieving High-Rate Completions with Innovative Through-Tubing Sand Control,” SPE Drilling & Com- pletion, March 2002, 50-53. 7. Vickery, E., “Through-Tubing Gravel Pack with Small Clearance: The Important Factors,” SPE 73773, International Symposium on Formation Damage Con- trol, Lafayette, Louisiana, February 20-21, 2002. 8. Ebinger, C., “Rigless Frac Packs Provide Cost Effec- tive Completions,” World Oil, October 2000, 9. Rice, R., Navaira, G., and Champeaux, G., “Through-Tubing Gravel Packs Performed by Electric Wireline – Case History,” SPE 58784, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 23-24, 2000. 10. Solum, J., “A New Technique in Sand Control Using Liner Vibration With Gravel Packing,” SPE 12479, Formation Damage Control Symposium, Bak- ersfield, California, February 13-14, 1984. 11. Solum, J., “Horizontal Well Gravel Compaction Simulator Tests with Rotary Vibration in a Water Pack- ing System,” SPE 24958, International Symposium on Formation Damage Control, Lafayette, Louisiana, February 26-27, 1992. 12. Betancourt. S., Shukla. S., Sun, D., Asii, J. Yan, M. Arpat, B. and Sinha, S., “Developments in Completion Technology and Production Methods,” SPE 74427, International Petroleum Conference, Villahermosa, Mexico, February 10-12, 2002. 13. MacKenzie, A. and Hogg, C., “Multilateral Classifi- cation System with Example Applications,” World Oil, January 1999. 56. 14. Pasicznyk, A., “Evolution Simplifies Multilateral Wells, “ Hart’s E&P, June 2000, 53. 15. Pasicznyk, A., “Evolution Toward Simpler, Less Risky Multilateral Wells,” SPE/IADC 67825, Drilling Conference, Amsterdam, The Netherlands, February 27-March 1, 2001. 16. Muth, G. and Walker, T., “Extending Downhole Pump Life Using New Technology,” SPE 68859, SPE Western Regional Meeting, Bakersfield, California, March 26-30, 2001. 17. Evans, B. and Muth, G., “Increasing Heavy Oil Pro- duction Utilizing Dual String New Technology,” SPE 46220, SPE Western Regional Meeting, Bakersfield, California, May 10-13, 1998. US & ASTM Std. Sieve No. Equivalent Opening (mesh) in. mm microns 20 0.0331 0.841 841 30 0.0234 0.595 595 40 0.0165 0.420 420 50 0.0117 0.297 297 60 0.0098 0.250 250 70 0.0083 0.210 210 80 0.0070 0.177 177 100 0.0059 0.149 149 120 0.0049 0.125 125 140 0.0041 0.105 105 170 0.0035 0.088 88 200 0.0029 0.074 74 240 0.0025 0.063 63 270 0.0021 0.053 53 400 0.0015 0.037 37 550 0.0010 0.025 25 800 0.0006 0.015 15 1,250 0.0004 0.010 10 – 0.0002 0.005 5 – 0.00006 0.002 2 Table 5.4. Conversion table for standard screens indicating PumpGard particle size control for protection of rod pumps. Typical proppant (frac sand) Typical pump plunger/barrel tolerance Table salt PumpGard cartridge control point 124 Modern Sandface Completion Practices Hydrocarbons are a non-renewableresource and reserves of thisresource are rapidly depleting. Analysts first predicted that the world was running out of oil and gas reserves in 1940. Today’s depleted fields are often being replaced by lower-quality fields and smaller, low-permeability and more complex reservoirs. Larger new discoveries are often in ultra-deepwater, which introduces a whole variety of technological chal- lenges adding to the difficulties of maintaining current reserve levels. In the face of diminishing supplies, industry experts forecast that world- wide demand for oil and gas will grow steadily during this century. The petroleum industry will face increased pressure to provide even larger volumes of reasonably priced oil and natural gas. Success will require operators to lower operating costs, increase production rates and increase over-all recovery from each reservoir. To economically produce the growing number of deplet- ing reservoirs will require significant breakthroughs in technology. Today, completion techniques are more than ever based on economics, and that is how it will remain for the future. Several operational factors will always have a direct impact on comple- tion costs. They include: • Design simplicity • Rig time • Rig floor assembly time • Well depth • Well control problems • Zone spacing and the number of zones to be completed • Bottomhole pressure, temperature and fluids • Availability of surface pumping and blending equipment • Well completion life • Workover costs • Safety considerations Each of these factors contributes to the selection of a suitable, well-specific completion solution. The following are ongoing developments related to com- pletion technologies that may have an impact on some of the above cost drivers. Candidate Selection Wellbore stability is approached holisti- cally with vertical, highly-deviated, hori- zontal/multilateral wells and potential fracture treatments, such as HRWPs or frac packs. To reduce drawdown while obtaining economically attractive pro- duction rates, proactive well completion and/or workover strategies are critical to wellbore stability and sand production control. Identifying and matching the candidate well’s reservoir characteristics with optimum well completion configu- ration is critical to economic success. Necessary steps include (1) appropriate reservoir engineering, (2) formation characterization, (3) wellbore-stability calculations and (4) the substantive com- bination of production forecast with an assessment of sand production potential. Drill-In and Completion Fluids The next generation of drill-in and completion fluids are being developed. Some envision “smart” fluids that would consider application and formation specific issues affecting wellbore stability and formation damage. New gels, polymers and leakoff-control additives are urgently needed for drilling complicated multilateral wells and for drilling through difficult formations. Non-damaging fluids will be critical to the future of production engineering. Stimulation treatments are often expensive, cumbersome and, at times, unsuccessful (partially due to adverse effects of improper fluids contacting the formation). Production- induced problems, such as inorganic and organic materials deposition and especially sand production, can be avoided if the forma- tion remains undamaged from contact with fluids and large drawdown is not required for adequate production. Filter cake removal services cur- rently used for simultaneous gravel packing and cleanup in open-hole gravel packs may find similar applica- tion in open-hole frac packing. Incorpo- rating aggressive breakers and filter- cake removal chemicals into fracturing fluids, without affecting their base properties, would be advantageous to ensure chemical contact with the entire open-hole section during frac-pack treatments. It could also provide a uni- form production profile. The increasing use of synthetic oil- base mud, especially in high-permeabil- ity reservoirs, will require compatible fracturing fluids. This need will become increasingly important as operators per- form more open-hole frac packs. Fluid compatibility, formation wetability and filter-cake cleanup must be addressed in the context of expensive displace- ment to water-base systems and oil- base fluid handling. Completion Hardware Completion hardware will be improved in conjunction with other completion developments. There will always be a need to simplify, eliminate or otherwise advance beyond the modified gravel- pack hardware currently being used in frac packs. In wells that are more marginal, smaller tools are needed for rigless completions. There is also a need for improved zonal isolation hardware, for the execution of hydraulic fracturing in complex well-fracture configurations and conventional sand control treat- ments. In fact, lack of appropriate drilling, completion and stimulation hardware is often the limiting factor in Next Generation Completion Technologies Candidate Selection • Drill-In and Completion Fluids • Completion Hardware Fracture-Well Connection • Frac-Pack Analysis • Improved Well Test Interpretation Eliminating Hardware • Global Databases CHAPTER SIX 125 new completion configurations. Clearly, all fracture treatments must be con- ducted separately, in stages; conse- quently, inexpensive and robust zonal isolation schemes are necessary. Zonal- isolation hardware is currently available, but it can be expensive and often logisti- cally difficult to use. Alternative tech- niques to the use of zonal-isolation hardware, such as polymer or sand plugs, are often prone to failure. Application of stand-alone screens will create improvements to long-term produc- tivity. This will involve advancements in the various screen designs and techniques to uniformly collapse the open hole around these devices. Expandable screens will also be used for more sand control appli- cations as installation and expansion proce- dures continue to improve. Alternate path screens will further improve frac-pack treatment diversion across longer intervals, and multiple tem- perature gauges with electronic memory placed strategically in the washpipe will monitor slurry diversion to other zones. Fracture-Well Connection New fracture-and-well interfaces should be developed, which could include the next generation of screens and replace- ment technologies. Hydraulic fractures are prone to sand production, both from the reservoir and from the proppant pack itself. This problem is particularly prevalent in high-rate wells where, although the reservoir problem may be resolved, the near-well fracture portion may be susceptible to sand production. The current solution, stand-alone screens, should be replaced. Although they are reasonably effective, stand- alone screens can cause a serious choke effect at the fracture-well interface in these high-rate wells. New consolidation techniques, or perhaps oriented long perforations and alternative sand-exclu- sion devices, are potential solutions. Frac-Pack Analysis Frac-pack placement data generally indicate creation of a fracture and subse- quent tip screenout, but post-treatment pressure data often indicate positive skin values and some remaining damage. This raises questions about the effec- tiveness of propped fractures. Computer models, used to manage the data, have been developed to resolve discrepancies between geophysical evaluations, well- log interpretation, fracturing data from frac-packing treatments and well-test pressure analysis. Generating consistent solutions and resolving discrepancies require measurement of multiple param- eters within a discipline, and integration across disciplines. Treatment-pressure analysis is based on an understanding of the leakoff pro- cess and on the concept of net pressure. Soft formations and their rock mechan- ics are not yet well understood, and an appreciation of which mechanisms control fracture length and width is more evasive than ever. Many of the debates could be settled by determining the closure pressure, and hence the net pressure, with more confidence. While there is a lot of activity in this area, new results are very limited. Reiterat- ing old ideas is common (flowback or not, two mini-fracs or three, crosslinked fluid or not, step-rate or not, etc.). These ideas are revealing lit- tle new information. There is a definite need for innovative thinking here. For example, an independent and possibly direct instrumental determination of closure pressure would be a significant step forward in the engineering of hydraulic fracturing. Improved Well Test Interpretation For the evaluation of high-permeability fracture treatments, it is imperative to improve the well-test interpretation pro- cedure and to understand the phe- nomenon of positive apparent skins. The lack of desired (negative) post-treatment skins is still haunting the industry. Well productivity is obviously being improved by frac-packing, but it is not clear whether they could be significantly improved with more aggressive treat- ment parameters. Would schedules that are more aggressive provide additional benefit, or are the possibilities limited by the choke effect at the perforations? These issues are not clearly addressed by current pressure-transient methods. Eliminating Hardware New technologies have been recently introduced that promise to speed rou- tine application of rigless completions. Coiled tubing-conveyed fracturing tech- nology is rapidly becoming a viable tool for exploiting bypassed payzones. This new technology has been applied successfully onshore in multi-layered, low-permeability reservoirs. The next step is to take it offshore. Accessing offshore wellbores in a workover envi- ronment and placing a frac-pack or screenless completion in a new zone without using a costly conventional drilling or workover rig opens count- less future, cost-saving opportunities. Significant friction reduction with VES fluids may increase application of coiled tubing-conveyed fracturing by allowing this type of rigless completion to be performed at greater depths. In increasing numbers, operators are installing sand-exclusion screens that expand against the borehole wall. Hence, an annular gravel pack is not required to achieve wellbore stability. Expandable screens may also be installed after frac-packing treatments to eliminate internal annular packs. Emerging screenless techniques potentially produce completions with a negative skin and reduce completion costs while maintaining effective sand control. In this case, TSO fracturing and the proppant ring around a well- bore act as a sand filter. However, any area not covered leaves perforations open to produce sand. This technique requires various combinations of ori- ented perforating, injection of organic resins to hold formation grains in place and resin-coated proppants or fiber technology to prevent proppant flowback. Global Databases An emerging consensus points to the importance of establishing global databases of formation and other prop- erties, for specific geographic areas and specific activities. The main challenge is not securing funds or even identifying proper intelligence tools. The major obstacle is providing incentives and methods to encourage continuous input of data and the tailoring of data formats to a common standard. Once a database is established, simple interpretive tools can be used to efficiently evaluate a large number of treatments. Estimated fracture dimensions and conductivities could then be compared with results from pressure-transient analysis and production results. Discrepancies could be resolved using a large number of data sets from various independent sources. 126 Modern Sandface Completion Practices APPENDIX ONE 1 10 100 1,000 10,000 0.0 0.2 0.4 0.6 0.8 1.0 1.2 1.4 1.6 1.8 Mean grain diameter, mm Pe rm ea bi lit y, D White sand Brown sand Lightweight ceramic Intermediate ceramic Resin coated 70/140 20/40 12/18 40/60 16/20 12/2030/50 40/70 16/30 Appendix 1.1. Permeability at 4,000 psi net confirming stress 295 14 21 28 40 52 73 126 221 403 0 0.01 0.02 0.03 0.04 0.05 0.06 0.07 0.08 0 10 20 30 40 50 60 MMCFD 1/ K 0 50 100 150 200 250 300 350 Permeability (D) values Appendix 1.2. Effect of non-darcy flow on permeability (assuming a 100 ft high fracture filled with 4 lb/ft2 20/40 CarboLite at 4,000 psi closure stress at 1,000 psi BHFP at 180°F). 127 0 100 1,000 0 2,000 4,000 6,000 8,000 10,000 12,000 Closure stress – psi 20/40 sand 30/50 EconoProp 20/40 EconoProp 20/40 CarboLite Pe rm ea bi lit y, D ar cy Appendix 1.3. Permeability vs. closure stress of proppants 128 Modern Sandface Completion Practices APPENDIX TWO Chapter Page No. Figure No. Graphic/Data courtesy of: One 4 1.3 Baker Hughes Incorporated Two 14 2.1 Baker Hughes Incorporated 15 2.4 M-I L.L.C. 15 2.5 Flo Trend Systems, Inc. 17 2.6 Halliburton 18 2.8 Baker Hughes Incorporated 18 2.9 Core Laboratories 19 2.10 Red Wing Perforating Service 19 2.11 Red Wing Perforating Service 20 2.17 Nagaoka USA 21 2.18 Baker Hughes Incorporated 22 2.19 Reslink 22 2.20 Reslink 22 2.21 Reslink 22 2.22 con-slot 22 2.23 Baker Hughes Incorporated 22 2.24 Baker Hughes Incorporated 23 2.25 Weatherford International LTD. 23 2.26 Halliburton 23 2.27 Stren Inc. 24 2.28 Schlumberger 24 2.29 Weatherford International LTD. 25 2.30 Weatherford International LTD. 25 2.31 Singa Engineering 25 2.32 Smith Services 26 2.33 Baker Hughes Incorporated 27 2.34 Core Laboratories 27 2.35 Topac Instruments 27 2.36 Baker Hughes Incorporated 31 2.42 Baker Hughes Incorporated 32 2.43 Baker Hughes Incorporated 33 2.45 Baker Hughes Incorporated 33 2.46 Baker Hughes Incorporated 36 2.52 Baker Hughes Incorporated 36 2.53 Baker Hughes Incorporated 37 2.54 Halliburton 37 2.56 Baker Hughes Incorporated 38 2.57 BJ Services 38 2.58 Schlumberger 39 2.59 Schlumberger 39 2.60 Schlumberger 40 2.61 Halliburton 40 2.62 Schlumberger 40 2.63 Schlumberger 41 2.64 Baker Hughes Incorporated 41 2.65 Schlumberger Oilfield Review Three 49 3.4 Well Flow International 54 3.8 Halliburton 54 3.10 Algae Image Archive Dept. of Biological Sciences, Bowling Green St. Univ., Bowling Green, Ohio 55 3.11 BJ Services 56 3.13 Greig Filters, Inc. 58 3.15 Filtration Technologies 58 3.16 Filtration Technologies 60 3.19 Schlumberger Oilfield Review 61 3.20 Schlumberger Oilfield Review 63 3.21 Schlumberger Oilfield Review 64 3.22 Schlumberger 64 3.23 Halliburton 65 3.24 Schlumberger Oilfield Review 67 3.26 Schlumberger Oilfield Review 68 3.27 Schlumberger Oilfield Review 129 Chapter Page No. Figure No. Graphic/Data courtesy of: 69 3.28 Computalog/Precision Drilling Corporation 70 3.31 Baker Hughes Incorporated 71 3.32 Halliburton 71 3.33 Schlumberger 72 3.34 Baker Hughes Incorporated 75 3.39 Baker Hughes Incorporated 77 3.41 Baker Hughes Incorporated 77 3.42 Baker Hughes Incorporated 78 3.43 Baker Hughes Incorporated 78 3.44 Baker Hughes Incorporated 79 3.47 Schlumberger 80 3.48 Schlumberger 81 3.49 Halliburton 81 3.50 Schlumberger Oilfield Review 84 3.57 Schlumberger Oilfield Review 86 3.60 Schlumberger Oilfield Review 89 3.62 Carbo Ceramics, Inc. 91 3.64 Schlumberger Oilfield Review 92 3.65 Schlumberger Oilfield Review 92 3.66 Schlumberger Oilfield Review 93 3.67 Schlumberger Oilfield Review 94 3.68 Schlumberger Oilfield Review 95 3.69 Schlumberger Oilfield Review 95 3.70 Schlumberger Oilfield Review 97 3.71 Baker Hughes Incorporated 97 3.72 Halliburton Four 103 4.1 Baker Hughes Incorporated 104 4.2 Halliburton 104 4.3 Halliburton 104 4.5 Schlumberger 104 4.6 BJ Services 104 4.7 Halliburton 104 4.9 Schlumberger 104 4.10 Baker Hughes Incorporated 105 4.11 BJ Services 105 4.12 Baker Hughes Incorporated 105 4.13 Schlumberger 106 4.14 Baker Hughes Incorporated 106 4.15 BJ Services 106 4.16 Halliburton 106 4.17 Schlumberger 106 4.18 Baker Hughes Incorporated 106 4.19 Schlumberger 108 4.21 Meyer & Associates, Inc. 109 4.22 Pinnacle Technologies 111 4.24 ProTechnics, a Core Laboratories Company 112 4.25 ProTechnics, a Core Laboratories Company Five 115 5.2 Halliburton 116 5.3 Halliburton 118 5.7 Thru-Tubing Systems, Inc. 118 5.8 Halliburton 121 5.13 PT Pipa Mas Putih 121 5.14 Baker Hughes Incorporated 122 5.15 Smith Services 122 5.16 Halliburton 122 5.17 Weatherford International LTD. 123 5.19 Stren Inc. Appendix One 127 1 Stim-Lab, a Core Laboratories Company (Proppant Consortium) 127 2 Stim-Lab, a Core Laboratories Company (Proppant Consortium) 128 3 Stim-Lab, a Core Laboratories Company (Proppant Consortium) 130 Modern Sandface Completion Practices Contributor Profiles and Acknowledgements The publisher and authors of this handbook greatly appreciate the technical and editorial assistance of the individuals listed in this appendix. Without their cooperation the publication of this handbook would not have been possible. APPENDIX THREE Charles Boatman is a global Dril-N product line champion for Halliburton. He joined Baroid in 1962 as a field engineer. A graduate of Rice University, Mr. Boatman is a member of SPE, AAIDE, API and the Rice Owl Letterman Club. John Cameron, technical manager-Expandable Sand Control for Weatherford Completion Systems in Houston, has 22 years of industry experience. Prior positions include technical manager for conventional well screens at Weatherford and Pall Stratapac, and assignments for Baker Atlas in Aberdeen, Syria, Norway and Abu Dhabi. He graduated from Imperial College at the University of London with a B.Sc. in physics. Bruce Comeaux is Gulf Coast technical manager for BJ Services. He has experience in cementing, sand control and matrix stimulation, and was involved in the evolution of sand control from low-rate gravel packing to frac-packing. He has a BS degree in petroleum engineering from Louisiana State University. Dr. Mike Conway, president of Core Laboratories’ STIM- LAB Div., has worked in stimulation research since 1978. He has evaluated fracturing fluid leakoff, proppant conductivity damage, multiphase non-Darcy flow’s impact on effective conductivity and proppant flowback. He holds a BS in phar- macy, MS in pharmacology and PhD in organic chemistry from University of Oklahoma. Mary Edwards is Sand Control Product Line technical manager for BJ Services. Earlier, she was responsible for sand control technical support in the Gulf of Mexico and served as Gulf Coast lab manager for Baker Hughes INTEQ and production & facilities engineer with ARCO. She holds a BS degree in petroleum engineering, University of Tulsa. Brian Evans, Sand Control section leader, joined BJ Hughes in 1983, later rejoining BJ Services to lead sand control research. He has provided engineering support for sand control pumping, including acidizing and gravel packing. He holds a BS in petroleum engineering, Texas Tech University. Harvey J. Fitzpatrick, Jr., is Sand Control product manager for Halliburton Energy Services. His key interests include integration of technology and completions operations to enhance completion performance. He earned a BS in chemical engineering from Tulane University in 1979. Mike Flecker, director of technology for ProTechnics, is responsible for research, development, manufacturing and maintenance of Completion Diagnostics. He provides interpretation training and support to log analysts, sales and field personnel, and global support on special problems related to petrophysical analysis of cased- and open-hole logs. Kent Folse is a global product champion for Halliburton Energy Services Tools, Testing & TCP product service. He holds a BS degree in petroleum engineering from the University of Louisiana at Lafayette. He began his career with Halliburton in 1990. Nicholas Gee, vice president, Weatherford ESS, holds a degree in chemical engineering from Birmingham and an MBA from Warwick Business School. He spent six years with BP in the UK and Norway, followed by positions with Agip, Petroline and Global Marine. He joined Weatherford in 2000 as region manager, NECIS. Terje Gunneroed is president of ResLink. He earned BSc degrees in mechanical and petroleum engineering, and has more than 20 years of international experience within well construction, production optimization, stimulation, sand- control, well intervention and management. Brad Hoffman, manager of the Tubing Conveyed Perforating engineering group at Schlumberger’s Reservoir Completions Center, Rosharon, Texas, received a BS in petroleum engineer- ing from Texas A&M University. He worked for Trilogy Oil Corp. before joining Schlumberger as a testing engineer. He has worked in field service, Cased Hole and Perforating Systems. Dr. Lewis Lacy is director of Geomechanics for Core Labora- tories’ Houston Advanced Technology Center. He holds BS and MS degrees in physics from Virginia Tech and a PhD in applied physics from the University of Tennessee. He has more than 20 years of experience in applying rock and soil mechanics. Stephen P. Mathis is manager of Baker Oil Tools’ Technical Services Group, providing support for sand control tools and pumping. Before joining Baker, he spent 11 years with Exxon Production Research Co. He holds BS and MS degrees in geological engineering from the University of Arizona. 131 Paul Metcalfe, vice president of Expandable Technology for Weatherford International, has 15 years of oil industry experi- ence. At Petroline Wellsystems Ltd., he was responsible for development of the first commercial expandable technologies, including expandable sand screens. He worked seven years for Shell International, and is a graduate of the University of Manchester with a B.Sc. in chemical engineering. Mehmet Parlar is business development manager for Schlumberger Sandface Completions-Fluid Systems in Rosharon, Texas. He holds PhD and MS degrees from the University of Southern California, Los Angeles, and a BS from Istanbul Technical University, Turkey, all in petroleum engineering. He has 13 years of industry experience. Hugh Peek is area manager of Routine Rock Properties, US Gulf Coast, with Core Laboratories in Houston. He attended the University of Texas at Dallas, earning a BS degree in geosciences in 1977, joining Core Lab shortly thereafter. He is a member of SPWLA. Dan W. Pratt, vice president of Engineering and Explosives Technology, Owen Oil Tools LP, has spent nearly 25 years in the design and manufacture of oil-field explosives products, more specifically with shaped charges. He holds a BS in mechanical engineering from the University of Texas at Arlington, and 6 US and numerous foreign patents relating to design of perforators/shaped charges. Paul Price is with Schlumberger Sandface Completions. A registered Professional Engineer in Texas, Louisiana and Oklahoma, he holds BS degrees in chemical and petroleum engineering from Mississippi State University and an MS in advanced petroleum studies from IFP in Paris, France. Ed Van Sickle is product line manager for Baker Oil Tools Perforating and Baker Atlas Pipe Recovery in Houston. During 22 years with Baker Hughes, he worked in completion, sand control and pipe recovery operations. He earned a BS in mechanical engineering from the University of Houston. Paul B. Vorkinn is vice president of Marketing for ResLink. He holds a BSc in petroleum engineering and an MSc in chemical engineering, and has 20 years of international experience in well construction, production optimization, sand control, pressure pumping and well intervention. David Walker, Completion Tools Product Line manager, joined BJ Services via a merger with OSCA. He is experienced in sand control, multi-lateral completions and intelligent completion systems, and holds a BS degree in mechanical engineering from the University of Southwestern Louisiana. Donald Wells has 28 years of petroleum industry experience, which includes 10 years of global involvement with sand control. An SPE and CIM member, he is market manager, Oil and Gas, Purolator Facet Inc. R. J. Wetzel, Sandface Completions business development manager for Schlumberger, holds a BS in mechanical engineering from the University of Louisiana at Lafayette and has nine years of experience in the North Sea and Europe and more than 12 years of US-based experience in completions technology, operations and management. Pat York, director of Sales & Marketing, Solid Expandable Tubulars for Weatherford Completion Systems in Houston, has 30 years of oilfield experience. Before joining Weatherford he served in management for Enventure, Halliburton and Dresser Atlas in operations, business development and marketing. He holds a BS in electrical engineering and an MBA from Northwestern State University. The following individuals contributed both their time and talents toward making this publication as successful as possible: Mary Atchison Aileen Barr W.T. Bell Bill Bellenger James Cashion Beth Cunningham Allan R. Duckett Don Dumas Valerie Edwards Mary Fouts James Garner Walt Glover Amy Green Alan Greig Roger Horton David Hubbard J.M. “Johnnie” Jackson Hauke N. Jürgens Kathleen Keeler Paddy Keenan William Lang Debbie Markley J'Nette Davis Christine McGhee Bill Miller Brian Minton C. Mark Pearson Robert Picou Lindy Pollard Jimmy Priest Jim Redding Jason Renkes Greg Salerno Kenneth Schmitt Stephen Schubarth Brenda Sharp Richard Sinclair Jim Smolen Phil Snider Jan Stafford C.O. “Doc” Stokley Mark Teel David Weeks Cheryl Willis 132 Modern Sandface Completion Practices Manufacturing and Service Suppliers A listing of completion equipment, product and service suppliers. DIRECTORY BAKER OIL TOOLS 9100 Emmott Road 77040 P.O. Box 40129 Houston, TX 77240-0129 USA Tel: 713-466-1322 Fax: 713-466-2502 www.bakerhughes.com/bot/ Baker Oil Tools provides completion, workover and fish- ing solutions that help exploration and production com- panies maximize value from their hydrocarbon-bearing assets. Since its earliest days, the Baker name has been synonymous with excellence in downhole and sur- face technology, performance and reliability. In the cur- rent era of riskier environments and higher stakes, those qualities are more valuable than ever. U.S. Offices: ALASKA Anchorage 907-273-5100 CALIFORNIA Bakersfield 661-327-7201 COLORADO Denver 303-595-3675 OKLAHOMA Oklahoma City 405-842-4005 TEXAS Houston 713-625-6800 Odessa 915-563-7979 Tyler 903-509-9056 Outside U.S. Offices: AUSTRALIA Canning Vale W. A. 618-9-455-0155 NORWAY Tananger 47-51-717000 UNITED ARAB EMIRATES Dubai 971-4-8836322 UK Egham, Surrey 44-1784-477 050 Dyce, Aberdeen 44-1224-223500 VENEZUELA Caracas 58-212-77-2253 BJ SERVICES COMPANY 5500 Northwest Central Drive Houston, TX 77092 USA Tel: 713-462-4239 Fax: 713-895-5851 www.bjservices.com
[email protected] BJ Services is a leading provider of cementing, stimu- lation, completion systems and remedial well services to oil and gas operators worldwide. Operating in 50+ countries, BJ crews deliver best-in-class cement slur- ries, fracturing fluids, acid systems and production chemicals with state-of-the-art pumps, injection systems or coiled tubing units to provide zonal isolation and opti- mize production. Executives: Chairman, President & CEO J.W. Stewart President, US/Mexico Division Kenneth A. Williams President, International Division David D. Dunlap Vice President, Technology Mark E. Hoel US Region Offices: ALASKA Anchorage 907-349-6518 CALIFORNIA Bakersfield 661-831-5084 COLORADO Denver 303-832-3722 LOUISIANA Lafayette 337-261-0615 New Orleans 504-299-8200 OKLAHOMA Oklahoma City 405-810-1448 PENNSYLVANIA Pittsburgh 412-494-3312 TEXAS Corpus Christi 361-882-6177 Dallas 214-220-9200 Houston 713-683-3400 Midland 915-683-2781 Outside US Region Offices: BRAZIL Rio de Janeiro 55-21-3410-9909 CANADA Calgary 403-531-5151 MEXICO Villahermosa 011-52-993-3521-444 SCOTLAND Aberdeen 44-1224-401401 SINGAPORE Singapore 65-6-877-8700 UAE Dubai 971-4-2821500 BORDEN CHEMICAL, INC. OILFIELD PRODUCTS 12777 Jones Road, Suite 255 Houston, TX 77070 USA Tel: 281-618-1600 Fax: 281-618-1698 www.bordenchem-oilfield.com
[email protected] Borden Chemical is the world’s leading provider of resin coated sands and ceramics for use as propping agents in oil and gas wells. With more than 2 decades of research and development experience, Borden offers a full line of products specific to the sand control and associated Frac Pack marketplace under its BorPac‚ product line. Executives: Business Development Manager Daryl Johnson Marketing Manager Jason Renkes CABOT SPECIALTY FLUIDS, INC. Waterway Plaza Two 10001 Woodloch Forest Drive, Suite 275 The Woodlands, TX 77380 USA Tel: 281-298-9955 Fax: 281-298-6190 www.cabot-corp.com/csf
[email protected] Cabot Specialty Fluids, a wholly owned subsidiary of the Cabot Corporation, was formed in August 1996 as part of Cabot’s market-focused business model. Serendipity was at work in 1993, when Cabot purchased the Tan- talum Mining Corporation of Canada to obtain access to tantalum reserves for Cabot’s Performance Materials division. Not only did we obtain tantalum reserves, but also we obtained some 82 percent of the worlds known reserves of pollucite, a mineral rich in cesium. Today, CSF’s 158 employees manage the mining and produc- tion of cesium chemicals, tantalum and spodumene. Executives: President William J. Lang Marketing Norman P. Kenney CARBO CERAMICS INC. 6565 MacArthur Blvd. Suite 1050 Irving, TX 75039 USA Tel: 972-401-0090 Fax: 972-401-0705 www.carboceramics.com
[email protected] For a quarter century, ceramic proppants manufactured by CARBO Ceramics have helped make oil and gas wells around the globe more productive. The uniform shape and consistent size of CARBO proppants create a more permeable pathway for oil and gas to flow into the well- bore, resulting in greater productivity and financial return. Executives: President & CEO C. Mark Pearson, Ph.D. Sr. Vice President & CFO Paul G. Vitek 133 http://www.bjservices.com mailto:
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[email protected] Http://www.bakerhughes.com/bot/ CHAMPION TECHNOLOGIES INC. SPECIAL PRODUCTS DIVISION 3355 West Alabama - Suite 400 Houston TX 77227-7727 USA Tel: 713-627-9011 Fax: 713-623-4652 www.champ-tech.com Special Products is the wholly owned specialty chemi- cal division of Champion Technologies, Inc. We provide chemical products and technologies specifically tar- geted to oilfield service companies. We have based our business philosophy on satisfying customer needs in a cooperative environment, working closely with our cus- tomers’ research and development groups to create cost-efficient solutions that work. Executives: Chairman of the Board Steve Lindley Director Special Products Elwin Myers CON-SLOT SCREENS INTERNA- TIONAL GMBH Graue Riethe No. 2 WITTINGEN Lower Saxony D-29378 Germany Tel: 49-05831-8021 Fax: 49-05831-7643
[email protected] con-slot Screens is a world leading company specialized in application design and manufacturing fusion-welded wire screen products and accessories. The company is active in the fields of downhole completions of crude oil and natural gas production wells as well as injection stim- ulation wells, and also downstream processing screens, groundwater exploitation, many industrial process appli- cations from potable and industrial water treatment, domestic and industrial waste-water treatment, mining washeries, paper pulp processing, to chemical and petro-chemical processing. Associated companies and representatives around the world gaurantee the close contact and fast assistance in solving the problems of our customers. Executives: General Manager Hauke Newton Juergens Assistant Manager Andreas Dawed CORE LABORATORIES 6316 Windfern Houston, TX 77040 USA Tel: 713-328-2673 Fax: 713-328-2150 www.corelab.com
[email protected] Core Laboratories is a leading provider of proprietary and patented reservoir description, production enhance- ment and reservoir management services for the global petroleum industry. These services enable the Compa- ny's clients to optimize reservoir performance and max- imize hydrocarbon recovery from their producing fields. The Company has over 70 offices in more than 50 coun- tries and is located in every major oil-producing province in the world. The Company provides its services to the world's major, national and independent oil companies. Executives: CEO & President Dave Demshur COO Monty Davis Sr. Vice President, President Reservoir Management Jim Gresham President, ProTechnics, A Division of Core Lab Tom Hampton President, Petroleum Services, A Division of Core Lab Steve Lee President, Integrated Reservoir Solutions, A Div. of Core Lab Randy Miller President, Owen Oil Tools, A Div. of Core Lab Jeff West President, Stim Lab, A Div. of Core Lab Mike Conway U.S. Offices: Core Lab Instruments TEXAS Houston 713-328-2673 Core Lab Petroleum Services ALASKA Anchorage 907-562-2939 CALIFORNIA Bakersfield 661-392-8600 COLORADO Aurora 720-532-2666 LOUISIANA Broussard 337-837-8616 New Orleans 504-733-6583 TEXAS Corpus Christi 361-289-5457 Garland 972-926-4900 Houston 713-328-2673 Midland 915-694-7761 Core Lab Reservoir Technologies TEXAS Houston 713-339-1616 Houston 713-328-2673 Integrated Reservoir Solutions TEXAS Houston 713-328-2673 Owen Oil Tools LOUISIANA Broussard 337-837-0021 Houma 958-868-7010 Scott 337-984-1181 Shreveport 318-220-9009 NEW MEXICO Farmington 505-324-9068 TEXAS Corpus Christi 361-241-9575 Ft. Worth 817-551-0540 Houston 713-328-2673 Pearland 281-993-9991 Pencor LOUISIANA Broussard 337-839-9060 TEXAS Houston 713-328-2673 Promore TEXAS Houston 713-328-2673 ProTechnics CALIFORNIA Bakersfield 661-399-4994 COLORADO Denver 303-757-6222 Trinidad 719-846-1685 LOUISIANA Scott 337-264-1958 NEW MEXICO Albuquerque 505-888-0144 Farmington 505-326-7133 OKLAHOMA Oklahoma City 405-848-6296 Tulsa 918-742-0590 TEXAS Alice 361-668-3382 Ft. Worth 817-332-9607 Houston 713-328-2673 Kilgore 903-984-4223 McAllen 956-664-1972 Midland 915-563-5879 Tyler 903-581-4598 UTAH Vernal 435-789-6621 WYOMING Casper 307-237-1140 Rock Springs 307-362-2030 Stim-Lab OKLAHOMA Duncan 580-252-4309 Outside U.S. Offices: Core Lab Instruments UK Dyce, Aberdeen 44-1224-421-000 Core Lab Petroleum Services ANGOLA Luanda +244 2 441-980 AUSTRALIA Perth 61-8-9353-3944 BRAZIL Rio de Janeiro 55 21 3868 9888 CANADA Calgary 1 403 250 4000 Edmonton 1 780 468 2850 Estevan 1 306 634 7379 Grand Prairie 1 780 532 4047 Mount Pearl 1 709 747 2673 CHINA Shekou 86-755-2669-1696 COLOMBIA Bogota 57-1-674-0400 EGYPT Cairo 20-2-272-9972 INDONESIA Balikpapan 62-542-63627 Jakarta 62-21-780-1533 Surabaya 62-31-397-2651 KAZAKHSTAN Aksai 7-311-33-93050 Aytrau City 7-3122-228-775 MALAYSIA Darul Ehsan 60-3-5031-0088 MEXICO Reynosa 52-899-925-6364 Villahermosa 52-993-352-2000 Villahermosa 52-993-314-1273 PAKISTAN Karachi 92-21-589-7750 TRINIDAD Marabella 1-868-658-0681 UAE Abu Dhabi 971-2-5-554-428 Dubai 971-4-883-5070 UK Dyce, Aberdeen 44-1224-421-000 VENEZUELA Barcelona 58-281-275-2815 Maracaibo 58-261-757-4611 Core Lab Reservoir Technologies CANADA Calgary 1-403-571-1555 MEXICO Ciudad del Carmen 52-938-383-1860 Poza Rica 52-782-824-0882 Reynosa 52-899-925-6364 Villahermosa 52-993-352-2000 UAE Abu Dhabi 971-2-5-554-428 134 Modern Sandface Completion Practices http://www.champ-tech.com mailto:
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[email protected] UK Croydon 44-208-253-4000 VENEZUELA Maracaibo 58-261-721-1269 Integrated Reservoir Solutions U.K. Redhill 44-173-785-2390 Owen Oil Tools AUSTRALIA Thebarton 61-8-8152-0244 CANADA Brooks 1-403-362-2633 Calgary 1-403-571-2400 Edmonton 1-780-449-2021 Grand Prairie 1-780-539-0506 Lloydminster 1-780-871-0670 Redcliff 1-403-548-2888 Red Deer County 1-403-340-1017 Slave Lake 1-780-849-9789 CHINA Beijing 86-10-6434-9501 MEXICO Cuidad del Carmen 52-938-383-1860 Poza Rica 52-782-2-91-05 Reynosa 52-899-23-41-25 Villahermosa 52-993-52-20-00 OMAN Muscat 968-503-639 THAILAND Amphur Muang 66-74-33-4070 UAE Dubai 971-4-394-6889 UK Dyce, Aberdeen 44-1224-421-000 Promore CANADA Calgary 1 403 264 4246 Edmonton 1-780 988-5105 VENEZUELA Cuidad Ojeda 58 65 318 872 Maracaibo 58-261-757-4611 Pencor KAZAKHSTAN Aksai 7-333-558-4028 U.K. Dyce, Aberdeen 44-1224-421-000 Reading 44-1189-637-479 ProTechnics AUSTRALIA Gerringong 61-2-4234-0996 CANADA Calgary 1-403-269-2055 Grand Prairie 1-780-538-2144 Red Deer 1-403-340-8850 INDONESIA Jakarta 62-21-780-1533 MEXICO Villahermosa 52-993-502245 UK Dyce, Aberdeen 1-44-1224-421-068 VENEZUELA Caracas 58-212-238-6525 Stim-Lab CHINA Beijing 86-10-6434-9501 GREIG FILTERS, INC. P.O. Box 91675 Lafayette LA 70509 USA Tel: 337-237-3355 Fax: 337-233-9263 www.greigfilters.com
[email protected] Established in 1982, Greig Filters specializes in com- pletion fluid filtration. Worldwide sales of filtration equip- ment includes GFI Model Vertical Pressure Leaf Diatoma- ceous Earth Filter packages that set the standard for DE filtration equipment.Pakages include VPL, cartridge fil- ters and pumping equipment on a single skid. GFI designs multiple size and combination cartridge filter units and oil removal equipment. Executives: Owner Alan Greig Manager Tammy Roy GRUPO ROYSO, C.A. Carretera Via La Toscana Maturin Edo, Monagas Venezuela Tel: 58-291-6437203 Fax: 58-283-6435501
[email protected] Grupo Royso is dedicated to oil field service – oil well cementing (plug and abandont), oil well stimulation ser- vices, hot oil services, high and low pressure pumping ser- vices, trucking services and oil tool rental services. Executives: Operation Manager Francisco Monagas HALLIBURTON ENERGY SERVICES 10200 Bellaire Blvd. Houston TX 77072 USA Tel: 281-575-3000 Fax: 281-575-4995 www.halliburton.com Halliburton, founded in 1919, is one of the world's largest providers of products and services to the petroleum and energy industry. U.S. Offices: ALASKA Anchorage 907-344-2929 CALIFORNIA Bakersfield 661-393-8111 COLORADO Denver 303-308-4227 LOUISIANA New Orleans 504-593-6700 OKLAHOMA Oklahoma City 405-231-1800 TEXAS Dallas 972-418-4230 Midland 915-682-4305 WYOMING Evansville 307-265-2105 Outside U.S. Offices: BRAZIL Rio de Janeiro 55-21-3974-0000 INDONESIA Jakarta 62-21-780-11-00 MEXICO Villahermosa 52-931-01100 NIGERIA Lagos 234-53-231-798 RUSSIA Moscow 7-095-755-8300 SCOTLAND Aberdeen 44-1224-795-001 UAE Dubai 971-2-676-3635 M-I L.L.C. P.O. Box 42842 Houston, TX 77242-2842 USA Tel: 281-561-1300 Fax: 832-295-2660 www.midf.com
[email protected] M-I is a leading supplier of drilling and completion fluid products/systems, services and equipment to the world- wide petroleum industry. Its SWACO division is the world’s leading provider of pressure control, solids con- trol, rig instrumentation and waste management equip- ment and services for the worldwide petroleum drilling industry. Executives: Eastern Hemisphere Vice President, Completion Fluids Pete MacKenzie Western Hemisphere Vice President, Completion Fluids Dan Douglass NORTON PROPPANTS, INC. 5300 Gerber Road Ft. Smith, AR 72904 USA Tel: 479-782-2001 Fax: 479-783-9984 www.nortonproppants.com
[email protected] Norton Proppants, Inc., a Saint Gobain company, man- ufactures quality ceramic proppants globally for the oil & gas industry for use in hydraulic fracturing and sand control operations. We have been the industry’s right choice since 1973 when we manufactured our first man-made ceramic proppant, Sintered Bauxite, at the request of the Exxon Corporation. Executives: Business Unit Manager Tom Duncan Sales & Marketing Manager Roy Webber RED WING PERFORATING SERVICE, L.L.C. 5357 Goodrich Rd. Crowley, LA 70526 USA Tel: 337-788-1666 Fax: 337-788-1777 www.redwingintl.com
[email protected] Established in 1996, Red Wing Perforating Service L.L.C. is unique in that we are the only independent pipe per- forating and slotting service on the Gulf Coast. We can per- forate and/or slot pipe with your custom designed hole or slot pattern to achieve desired open area. While our ser- vice area is global in nature, the approach to business is always personal. Executives: President Tim Zaunbrecher General Manager Gerard Zaunbrecher 135 Directory http://www.greigfilters.com mailto:
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[email protected] RESLINK 1121 Buschong Road Houston, TX 77039 USA Tel: 281-227-9854 Fax: 281-227-6834 www.reslinkus.com
[email protected] Reslink specializes in sand control solutions for open- hole completion of oil and gas wells. Innovation, risk min- imization and thorough product qualification are essen- tials of Reslink’s product development and manufacturing. Based in Norway and the USA, Reslink provides techni- cal expertise and delivers products meeting customer requirements; Simple, Robust and Reliable. Executives: CEO and President Norway Ole S. Kvernstuen President USA Terje Gunneroed. President Africa Dapo Oshinusi Executive Vice President Africa Dr. Onuoha E. Ibe Vice President Marketing Paul B. Vorkinn SCHLUMBERGER OILFIELD TECHNOLOGIES 5599 San Felipe, Suite 1600, Houston, TX 77056 USA Tel: 713-513-2448 Fax: 713-513-2008 www.slb.com/oilfield Schlumberger has been providing the energy industry with oilfield technology and service since 1927, the year the company introduced the then revolutionary technique of wireline logging for evaluating oil and gas wells. Today Schlumberger offers a comprehensive range of advanced technology and value creating ser- vices covering oil and gas companies’ full spectrum of needs, from pore to pipeline. Executives: Chairman and Chief Executive Officer Andrew Gould Vice President, Oilfield Technologies Satish Pai Vice President, Oilfield Marketing Rod Nelson President, Well Services Mark Corrigan Marketing Mgr, Well Services Daniel D. Domeracki President, Well Completions Zaki Selim Marketing Mgr, Well Completions Maarten Propper Service Areas and GeoMarkets: NORTH/SOUTH AMERICA Alaska 907-273-1700 Canada 403-509-4000 US Gulf Coast 504-592-5275 US Land 281-285-8500 Argentina, Bolivia, Brazil, Chile 55-21-3824-6926 Mexico, Central America 52-55-5263-3000 Peru, Colombia, Ecuado 57-1-376-50-05 Venezuela, Trinidad and Tobago 58-212-9074800 CONTINENTAL EUROPE AND AFRICA Continental Europe 39-02-5754-2208 Scandinavia 47-5194-6000 Caspian 44-207-576-6705 Russia, Sakhalin 7-095-935-8200 United Kingdom 44-1-224-385600 Algeria, Morocco, Tunisia 213-21-92-22-40 Nigeria 234-1-2612679 West and South Africa 244-2-310-357 MIDDLE EAST, ASIA AND AUSTRALIA Saudi Arabia, Kuwait, Bahrain, Pakistan 966-3-857-3440 Egypt, Syria, Sudan, Jordan 20-2-380-7780 UAE, Qatar, Yemen, Oman 9712-633-3600 India 91-11-26108354 Libya 218-21-3350060 Iran 98-21-877-2474 Australasia 61-8-9420-4800 Brunei, Malaysia, Philippines 60-3-2166-7788 China, Korea, Japan, Taiwan 86-10-6474-6699 Indonesia 62-21-522-7050 Thailand, Myanmar, Bangladesh 66-2-937-0700 SMITH SERVICES A BUSINESS UNIT OF SMITH INTERNATIONAL, INC 16740 Hardy Street Houston, TX 77032 USA Tel: 281-443-3370 (800-877-6484) Fax: 281-233-5425 www.smith.com
[email protected] Smith Services offers a range of drilling optimization tools, fishing services, completion and production enhance- ment products. Technologies such as multilateral junction systems, borehole enlargement, liner hangers and pro- duction packers are brought together to deliver improve- ments in wellbore construction efficiency and a reduction in the cost of reservoir exploitation. Executives: Smith Services President Richard Werner Completion Systems Vice President Roger Matheson STREN INC. 15045 Woodham Dr. Houston, TX 77073 USA Tel: 281-820-0202 Fax: 281-820-5909 www.stren.net
[email protected] Stren is an international engineering and manufacturing company serving key industries, including the petroleum production industry, from its Houston manufacturing facilities since 1988. A recognized leader in rod and ESP pumping systems optimization, Stren manufactures effective, cost efficient sand control equipment for rod, ESP pumping and well completion sand control liner with installations in most major petroleum producing basins worldwide. Executives: President Kenneth J. Schmitt Applications Engineer Stan Burton TBC-BRINADD 4800 San Felipe Houston, TX 77056 USA Tel: 713-877-2700 Fax: 713-877-2604 www.tbc-brinadd.com
[email protected] A global, wholesale distributor and manufacturer of non-damaging additives for drill-in, completion and workover fluid systems. TBC-Brinadd utilizes its ISO 9001 certification to supply value-added service to their customers. Executives: President Jay Dobson CEO Bert Wolford THRU-TUBING SYSTEMS, INC. 3621 Ridgelake Drive, Suite 200 Metairie, LA 70002 USA Tel: 504-833-2074 Fax: 504-833-2075 www.thrutubingsystems.com
[email protected] Thru-Tubing Systems, Inc. is an engineering, manufac- turing, and service company specializing in thru tubing workover, completions, and sand control systems. TTS offers a variety of thru tubing sand control and packer systems designed to be deployed on either coil tubing or wireline. TTS has developed many innovative appli- cations designed to allow the oil and gas operator to suc- cessfully conduct thru tubing wellbore remediations using coil tubing and/or wireline. Executives: President Danny Teen Engineering Manager Robert Picou TUCAN PETROLEUM SERVICES, C.A. Ave. Intercomunal, El Tigre El Tigre Edo. Anzoategui 6050 Venezuela Tel: 58-283-2552064 Fax: 58-283-2550704
[email protected] Tucan is dedicated to oil field service – oil well cement- ing (primary and secondary), oil well stimulation services, gravel pack services, high and low pressure pumping ser- vices, wireline services, oil tool rental services (packers). Executives: General Manager Williams Cedeno WEATHERFORD INTERNATIONAL LTD. 515 Post Oak Blvd., Suite 600 Houston, TX 77027 USA Tel: 281-873-6686 Fax: 281-876-1531 www.weatherford.com
[email protected] Weatherford Completion Systems (WCS) provides a full range of completion products and services, including cased hole and liner systems, solid expandables, intel- ligent well systems and expandable and conventional screens for sand control. President, Weatherford Completion Systems Stuart Ferguson Vice President, Liner Systems Kevin Trahan Vice President, Expandable Sand Screens (ESS) Nick Gee Vice President, Well Screens Bill Rouse Director Sales & Marketing, Solid Expandable Tubulars Pat York Vice President, Solid Expandable Systems Paul Metcalfe Technical Manager, Expandable Sand Control John Cameron Senior Research Advisor Tracey Ballard U.S. Offices: ALASKA Anchorage 907-561-1632 136 Modern Sandface Completion Practices http://www.reslinkus.com mailto:
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[email protected] CALIFORNIA Bakersfield 661-746-1391 Long Beach 562-426-6863 Paramount 562-808-1193 Ventura 805-643-1279 COLORADO Denver 303-893-0287 Greeley 970-339-9747 LOUISIANA Houma 504-851-0600 Lafayette 337-893-0231 New Orleans 504-679-9700 Shreveport 318-221-4338 MISSISSIPPI Laurel 601-649-1183 NEW MEXICO Farmington 505-326-5141 Hobbs 505-939-1717 OKLAHOMA Oklahoma City 405-773-1100 Tulsa 918-299-9655 Woodward 580-254-3229 Yukon 405-577-5590 TEXAS Andrews 915-523-9091 Big Lake 915-884-2354 Bridgeport 940-683-2244 Corpus Christi 361-904-0300 Dallas 972-702-9222 Denver City 806-592-3827 Houston 281-873-6686 Levelland 806-894-6653 Longview 903-759-3601 Midland 915-563-7957 Odessa 307-754-7234 Snyder 915-573-3376 UTAH Vernal 435-789-7121 WYOMING Casper 307-234-7011 Hurricane 304-562-5724 Powell 307-754-9554 Rock Springs 307-362-1883 Outside U.S. Offices: ARGENTINA Buenos Aires 54-11-5077-0000 AUSTRALIA Malaga 61-8-9249-7900 BRAZIL Rio De Janeiro 55-21-2266-8900 CANADA Calgary 403-279-9300 CHINA Beijing 86-10-6561-9009 COLOMBIA Santafe de Bogota 571-616-1130 FRANCE Senlis 33-344-322-402 INDONESIA Jakarta 62-21-5273050 ITALY Ortona 39-085-905161 MALAYSIA Kuala Lumpur 603-2168-6000 MEXICO Reynosa 52-899-923-0145 SINGAPORE 65-778-8323 UAE Dubai 9714-3312999 UK Aberdeen 44-1224-225200 VENEZUELA Caracas 58-212-265-6544 WELL FLOW INTERNATIONAL 600 Kenrick, Suite B-14 Houston, TX 77060 USA Tel: 281-448-2900 Fax: 281-448-0199 www.well-flow.com
[email protected] Well Flow International manufactures specialty chemi- cals and engineered products used in the completion of oil and gas wells. The company’s origin was with the development of DIRT MAGNET. The company has since expanded its product line to include other varieties of sur- factants, solvents, scale dissolvers, formation scale and damage removers and casing cleanup tools. Executives: President Paul Kesterton CEO Paul Bell WELL COMPLETION TECHNOLOGY 7903 Alamar Houston, TX 77095 USA Tel: 281-859-6464 Fax: 281-855-3004 www.wcthou.com
[email protected] Founded in 1986, Well Completion Technology was cre- ated to provide well completion consulting services and related technical training to the petroleum industry. Our capabil it ies include: Training Management/ Coordination, Technical Training, Technical Tours, On Site Job Supervision and Project Management, Equip- ment Trading, Well Completion Design and Technical Con- sulting on all aspects of Well Construction and Produc- tion. Executive: President William K. Ott, P. E. 137 Directory http://www.well-flow.com mailto:
[email protected] http://www.wcthou.com mailto:
[email protected] INDEX 139 Abrasive wearing, 60 ABS filter cartridge, 54-55 Absolute filter, 53 Absolute rated, 53 Acid, 14, 17-18, 30, 33, 36, 47-48, 51, 59, 66-67, 73-74, 88 Acid solubility, 30 Acid soluble, 14, 18 Acid stimulation, 66 Acid treatment, 47, 66, 74 Acidizing, 3 Acidizing treatments, 3 Acid-prepack method, 73 Acids, 11, 14, 16, 48, 66 Acid-soluble, 14, 18 Acoustic collar, 9 Acoustic transducers, 9 Agglomerates, 48 Alpha wave, 35-36 Alpha-beta wave principle, 37 Alternate path screens, 39, 126 Alternate path technology, 36, 38, 94-95 Aluminum oxides, 30 Ammonium chloride, 18 Amphoteric, 46 Anionic, 46-47 Anionic surfactants, 46 Anisotropic reservoirs, 76 Anisotropy, 69 Annular blockage, 94 Annular bridge, Annular flow, 18, 70, 94 Annular pack, 20, 37-38, 40, 77, 80, 90, 110, 112 Annular pressure, 50, 64, 80 Annular ring, 20-21 Annular voids, 94 Anticipated flow rates, 2 API fluid loss data, 48 Asphaltene/paraffin deposition, 7 Available flow area, 5 Average grain size, 26, 28-29 Azimuth, 96 Back surging, 71 Backflow volume, 66 Bactericide, 57 Baffle cups, 16 Bailed sand samples, 27 Bailer, 2, 119 Base completion fluid, 103 Base fluid, 14-15, 49, 89, 103, 125 Batch mixed, 97 Batch-mixing equipment, 75 Beta coefficient, 54 Beta ratio, 53-54 Beta wave, 35-37 Beta-rated cartridge, 54 Bicarbonate, 45 Biocide, 45, 49 Biopolymer, 48 Biot's poroelastic coefficient, 86 Blast joints, 10 Blender, 104 Blending equipment, 74, 103, 107, 125 Borehole stability, 12, 27 Bow-spring centralizer, 31-32, 119 Braden-head squeeze, 73 Brake horsepower, 104-105 Breakable polymers, 14 Breaker soak, 17 Breakers, 17, 38, 48-49, 88, 125 Breaking fluid, 14 Bridge matrix permeability, 52 Bridging agent, 14, 49 Bridging material, 11, 14, 66 Bridging particle, 13 Bridging pill, 16 Bridging salt, 17 Bridging theory, 20 Brine, 13-14, 16-17, 30- 33, 35-36, 43-51, 55, 66, 74-75, 77-78, 86, 97 Brine carrier fluid, 74 Brine completion fluid, 13 Brinnell hardness of the rock, 3 Bromide brines, 18, 44 Bubble point method, 55 Buffer fluid, 65 Bulk density, 87, 110 Bypass valve, 79-80 Calcium brine, 45, Calcium carbonate, 66-67 Calcium chloride, 18, 46 Calcium sulfate, 45 Caliper log, 32 Capillary pressure, 1, 51 CAPS, 38, 40, 64, 95 Capsule guns, 60, 63-65 CarboLite, 30, 127 Carbonate, 13, 45, 66-67, 114 Carrier guns, 60, 63-64 Cartridge filters, 52-56 Cased-hole frac packing technique, 35 Cased-hole gravel pack, 71-72, 76-77 Casing collar locator, 79 Casing scraper, 53 Catastrophic sand production, 68 Cationic, 46-47 Cellulose--polymer-specific enzymes, 48 Cement filtrate, 11 Cementation, 1-2, 4, 6, 66, 113 Cementing, 5, 10, 17, 24, 48, 103, 112, 131 Cesium formates, 44 Channeling, 10, 16-17, 54 Charge performance, 59, 62, 69 Charge type, 59 Chemical additives, 103 Chemical buffers, 88 Chemical consolidation, 6-7, 113-114 Chemical degradation, 48 Chemical soak, 17 Choke effect, 126 Circulating fluid, 2 Clay content, 2, 60 Clay stabilization, 26 Closing sleeve, 16, 36 Closure stress, 87, 89, 90, 91-92, 106, 128 Coberly equation, 52 Coil tubing, 24, 33, 115-117, 134 Coiled tubing, 2, 17, 36, 61, 63, 109, 113, 115-118, 120-21, 126 Completion fluid, 7, 11, 13, 43-46, 49-56, 61, 73-74, 96, 102, 118 Compressible fluid, 83 Compressive strength, 2-4, 7, 66, 69, 93 Conditioning fluid, 114 Conductive tunnels, 59 Connate water, 3 Contamination, 36, 45, 50-51, 58 Conventional core analysis, 27 Conventional core barrels, 26 Conveyance method, 56, 61, 63, 65, 109 Core, 3-4, 26-27, 29 Core flow, 29 Coring, 26 Correction algorithms, 49 Corrosion inhibitor, 47 Creep, 87 Critical zone, 87 Crosslinked fracturing fluids, 88 Crosslinked gels, 77 Crosslinked pill, 17 Crosslinked polymer gels, 97 Crosslinkers, 88 Crossover assembly port, 16 Crossover circulation technique, 33 Crossover method, 31 Crossover tool, 31-32, 36, 40, 114-115 Crushed zone, 60-61, 65, 76 Crystallization curve, 46 Crystallization points, 44-46 Crystallization temperature, Cup-type service packer, 31 Damaged zone, 6, 13, 70, 73-74, 76, 82-83 Darcy flow, 109, 127, 131 Darcy skin factor, 70 Darcy's Law, 5, 47, 74-75 DE filter cycle, 50 DE filter unit, 54 DE presses, 56 Debris, 11, 31, 43, 53, 60, 64 Delayed crosslink agents, 88 Demulsifiers, 88 Density, 4, 9, 13-14, 16-18, 25, 27, 31-32, 43-45, 50, 58, 60-61, 64, 71, 75-76, 87, 90, 96 Density log, 109-110 Depth verification tool, 118 Design/analysis software, 107 Determination of particle size distribution, 57-58 Determining slot width, 70 Detonating cord, 59-60, 64 Detonation methods, 59, 64 Deviated holes, 11 Deviated wellbores, 59 Deviatoric stress, 67 Diatomaceous earth, 52, 54-55 Diatomaceous earth filters, 55 Diatoms, 54-55 DIF, 12-14, 18, 23-24, 33, 36, 122 Dilatant sand formation, 12 Dilation of the formation rock, 8 Dimensionless skin factor, 7 Dipole sonic log, 86 Directional wells, 33 Dirty fluid, 21, 56-57 Displacement, 11-12, 15-18 Double-tube core barrels, 26 Downhole erosion, 10 Downhole exclusion device, 23 Downhole filter, 21, 24, 42 Downhole sand monitoring systems, 9 Downstream sand injection, 33 Drag forces, 3, 9, 65, 75 Drainage radius, 5-7, 76, 83 Drawdown, 3-6, 9-10, 14, 67-68, 72, 75-76, 83-84, 125 Drill-in fluids, 10, 13-14 Drilling fluid, 14-16, 21 Drilling mud, 7, 27, 43-45, 49-51, 53 Dual-detector density tools, 110 Dual-screen prepack, 21 Dynamic leakoff profile, 93 Eccentric annulus, 16-17 Efficiency ratio, 105 Elastomers, 44 Electric submersible pump, 40 Embedment, 40, 86-88, 90, 92 Emulsifying, 44 Emulsion, 46 Enhance radial flow entry, 67 Enzyme, 14, 16, 89 Epoxy resin, 96 Erosion, 2, 8-11, 16-21, 23-24, 30, 38, 60, 70, 74, 87, 90, 94 Erosion monitoring, 8 Ester, 49 Evaluation simulator, 107 Expandable sand screen design, 24 Expandable screens, 7-8, 16, 112, 126 Expendable guns, 61 Exploiting bypassed payzone, 126 Extended production test, 3 Extreme overbalanced, 64 Extruded pipe dope, 49 Field evaluation, 77 Field-scale testing, 35 Filter, 13-18, 20, 22, 24, 31, 36, 38-40, 42, 45, 49, 51-52, 53-58, 89, 96, 122, 124-126 Filter cake, 14-17, 31, 36, 38, 40, 49, 55, 125 Filtrate, 56 Filtration, 129, 133 Filtration guidelines, 51 Filtration polymers, 16 Fine migration, 5, 7, 39, 60, 74, 81, 83, 85, 90 Fines, 2-3, 5, 7, 18-20, 25, 30, 39, 42, 60, 66, 68, 70, 74, 81, 83, 85, 90 Finite element analysis, 5 Firing pin, 64 Fish eyes, 15, 48 Flow back testing, 14 Flow convergence, 19 Flow efficiency, 5, 7, 64 Flow erosion, 74 Fluid density, 16, 44-45, 77, 91, 96, 110 Fluid displacement, 16, 49 Fluid filtration, 14, 24, 26, 40, 43, 51 Fluid flow, 2-3, 5, 14, 16, 57, 79, 94 Fluid invasion, 14, 61, 64 Fluid leakoff, 89, 95, 107, 131 Fluid loss, 13-15, 17, 25, 33, 36, 43-45, 47-49, 68, 72-73, 78, 80, 91, 93-94 Fluid loss coefficient, 93, 107 Fluid loss control, 15, 33, 47, 49 Fluid saturation, 27 Fluid spurt loss, 93 Fluid velocity, 36, 83, 91 Fluid viscosity, 2-3, 74, 76-77, 86, 88-91, 120 Fluid volume, 65, 74 Fluid/fluid compatibility, 45, 125 Fluid/formation compatibility, 13-14, 45, 103 Fluid/slurry densities, 17 Fluid loss, 13-15, 17, 25, 33, 36, 38, 43-47, 68, 72, 78, 88, 91-94 Foam treatments, 107 Formates, 13, 44 Formation compaction, 7 Formation consolidation, 2 Formation cores, 27 Formation damage, 5,7, 11-12, 14, 17, 25, 33-48, 51, 59, 61, 68-79, 76, 81-83, 87, 89, 98-100 Formation erosion, 16 Formation grain size, 19, 28 Formation sand sampling, 18, 26 Formation sand size distribution, 18 Formation skin damage, 33 Formation stress, 5, 86, 89 Frac fluid, 93 Frac packing, 10, 30, 38-39, 43, 61, 66, 75, 81-85, 87-90, 92-94, 97, 104, 113, 125 Frac pressure, 36, 72-73, 77, 80, 85 Frac pack, 7, 40, 42, 73-74, 81-87, 89, 91-94, 97, 105, 109, 108-113, 117-118 Frac-pack technique, 39, 96 Fracture closure stress, 89, 107 Fracture, 8, 24, 38-40, 59-61, 64, 66-69, 72-74, 78, 81-83, 85-96 Friable, 26, 32, 86 Full-closure core catcher system, 26 Full-hole-volume of completion fluid, 50 Full-scale frac pack, 73 Functional tendencies of surfactants, 46 Furan resin, 96 Gamma ray spectra, 111 Gamma-ray depth correlation tool, 79 Gas aphrons, 14 Gas propellant fracturing, 81 Gas-liquid ratio, 70 Gel pills, 47 Gel strengths, 17 Gel system, 86, 89, 102 Gelled fluids, 17, 30, 75, 78, 88 Gelled slurry-pack fluids, 78 Geochemical bonding, 114 Geomechanical numerical models, 5 Glass beads, 30 Grain density, 27 Grain size distribution, 26-27 Grain-to-grain Bonding, 113 Gravel bridges, 31, 95 Gravel pack, 1-2, 10-12, 20, 24, 26, 29-31, 33-43, 51, 66, 68, 71-73, 75-77, 79, 82-85, 92-94, 96-97, 103, 109-111, 113-119, 122-124, 126 Gravel pack evaluation techniques, 77, 109 Gravel packing, 1, 7-8, 10-11, 16, 19, 21, 24-25, 30, 33-36, 38-39, 43, 45, 51, 53, 61, 66-68, 71-72, 74, 78-79, 85, 87-90, 93-95, 103, 110, 113, 118, 125, 131 Gravel placement, 25, 31-36, 38, 66, 68, 72-75, 77, 79, 107, 110, 117 Gravel size determination, 28 Gravel slurry, 30, 36, 78, 96, 116, 119 Gravel-pack screen, 79 Gravel-packing method selection, 97 Gravimetric analysis, 53, 57-58 Gun clearance/centralization, 63 Gun design, 59, 61, 63 Gun orientation, 9 Gun size, 59, 61 Halide brines, 44 HCI acid, 48-49 Heavier weight completion fluids, 47 HEC, 14, 17, 33, 47-49, 73-74, 76-77, 88, 119 HEC slurry pack, 76 Hexagonal packing, 120 High rate water packing, 31, 69, 97 High shear rate, 48 High shot density, 9, 61, 69 High-angle wells, 14, 26, 63 High-flow capacity, 21 140 Modern Sandface Completion Practices 141 High-pressure frac pumps, 103 High-pressure pumps, 105 High-shot density, 96 High-viscosity high-density gravel slurry, 31 High-viscosity high-density slurry, 25 High-volume mixing equipment, 115 Hole spacing, 67 Hole stability, 24, 33 Hook hanger system, 120 Horizontal AllPAC screens, 38 Horizontal gravel pack, 35-37 Horizontal gravel-packing, 34, 120 Horizontal holes, 11 Horizontal open-hole, 22, 24, 37, 121 Horizontal stress, 67, 86-86, 93-94 Horizontal wells, 13-14, 20-21, 24, 34-35, 37-38, 63, 67, 85 Horizontal/deviated wells, 24, 38, 76, 96 Horizontal/multilateral wells, 125 Horsepower rating, 104 Hot spot, 18 Hot/alkaline/steam sand-consolidation technique, 114 HPG, 48, 88 Hydrates, 46, 48 Hydraulic fracture, 59-60, 67, 83, 85, 88, 93, Hydraulic fracturing, 38, 67, 85, 88, 107, 113, 125-126 Hydraulic horsepower, 50, 86, 88, 103-104 Hydraulic jets, 59 Hydraulic setting tool, 79 Hydraulic shear, 14, 55 Hydraulic shearing device, 15 Hydraulic workover unit, 113 Hydraulic-fracture stimulation, 61 Hydrochloric acid, 66 Hydrofluoric acid, 66 Hydrostatic, 66 Hydrostatic balance, 44 Hydrostatic pressure, 14, 17, 40, 44, 47 Hydroxy-ethylcelluse, 77 Hydroxypropyl guar, 48, 88 Impairment, 6, 11, 34-35, 66, 71 In situ sand consolidation,10 Induced damage, 59, 61 Inertial flow coefficient, 90 Inflatable packers, 32 Inflow area, 8, 19-20, 23-24 Inflow control devices, 21 Inflow damage, 60 Inflow performance, 24, 59-60 Influx, 7-8, 39, 44, 65-66, 70-71, 77, 90, 109 Injection rates, 78, 94, 107 Injectivity, 59-60, 66, 95, 114 In-line sand cyclone, 9 Inside-casing gravel packing, 8 Interface, 11, 18, 25, 50, 53, 76, 107, 127 Interfacial tension, 46, 50 Intergranular friction, 1 Intermediate strength proppants, 89-91 Internal gravel packs, 68, 71 Intervals, 4, 8-9, 17, 25-26, 31, 38-39, 63-66, 69, 71, 74, 79, 84, 86, 88, 93-96, 109-110, 113-114, 126 Invert emulsion mud, 46 Iridium, 110-111 Iron sulfide scale, 45 Isolation plug, 36 Isopropanol, 48 Jet perforating, 59 Kerosene, 48 Kozeny's method, 52 Laboratory core analysis, 4 Laboratory core test scatter, 48 Laboratory-measured beta factors, 109 Laminar, 49, 74-75, 91 Laminated sand, 12, 39, 85-86 Laser-optics, 27 Laser particle size analysis, 118 Log/log plot, 107 Lost circulation material, 68 Low filtrate, 14 Low fracture gradient, 24 Low gravel permeability, 29 Matrix, 2-3, 14, 23, 44, 46, 52, 61, 113, 131 Median grain size, 26, 29 Memory-based tools, 109 Mercury injection, 51 Mesh gravel, 30, 73 Metal liners, 20, 59, 60 Metal mesh, 23, 56 Mfrac, 107 Micro-bubbles, 14 Micro-emulsified oil, 51 Microgels, 48 Micron membrane, 58 Milling, 43 Mineralogy screening, 27 Minifrac, 91-92, 107 Mini-frac test, 93 Minifracture, 91-92 Minimum horizontal stress, 67 Mix ratio/rate plot, 104 Mixing flow rate, 104 Monitoring and control equipment, 106 Monitoring systems, 9, 105 Monobore completion, 113 Mud cake, 25-26, 34, 50, 53 Mud filtrates, 11 Multi-cartridge filter housing, 54-55 Multilateral completion, 23 Multiphase flow, 5, 91 Multiple zone completion, 25 Multi-position service tool, 79-80 NaCl, 13-17, 44 Nephelometric turbidity units, 57 Neutron logs, 4 Nominal filters, 53 Nominal median pore size, 55 Non-Darcy, 39-40, 76, 86, 90-91, 109, 127, 131 Nonionic, 46 Non-penetrating fluid, 66 Nuclear density log, 109 Oil-based mud, 13, 49 Oil-soluble resin, 66 Oil wetting, 46 One trip tool, 32 One-trip perforate and pack system, 79, 81 One-trip TCP gun, 118 Open-channel flow, 20 Open-hole gravel packing, 8, 24, 31-32, 35, 38, 103 Open-hole horizontal completions, 21 Optimal gravel placement, 68 Optimal screen wire spacing, 21 Optimum sand control, 29 Oriented hydrajetting, 68 Oriented perforating, 8-10, 67, 126 OSU (Oklahoma State University) F-2 standard, 54 Overbalanced, 43, 47, 63-65, 66-69 Overbalanced pressure, 47, 66 Over-the-top system, 31 Over-the-top tool assembly, 31 Oxidizer, 14, 17 Oxidizing agents, 48 Oxidizing breakers, 89 Pack damage, 31, 88 Pack factor, 74, 78 Pack-assembly placement, 109 Packer/crossover tool assembly, 31 Pack-off method, 114-115 Pack-off seal assembly, 114 Pad, 39, 74-75 Paddle tank, 75 Paraffin, 7, 51 Particle contamination, 58 Particle count, 52-54, 58 Particle distribution, 13-14, 17 Particle invasion, 49, 51 Particle removal efficiency, 55 Particle removal efficiency testing, 52 Particle size, 13, 15-16, 24, 50-54, 57-59, 90, 92, 122, 124 Particle size distribution, 53-54, 58 Particle-size analysis, 27 Particulate impairment, 51 Perforated intervals, 61, 93, 110 Perforating, 8-11, 43, 48-49, 53, 59-61, 64-73, 80, 87, 96, 103, 117, 119, 126 Perforating analysis software program, 69 Index Perforating charges, 59 Perforating damage, 7, 60 Perforating debris, 11, 64-65 Perforating for sand prevention, 7 Perforating gun systems, 60 Perforating to control sand production, 66 Perforation efficiency, 76 Perforation orientation, 9, 61 Perforation prepacking, 72, 85 Perforation skin, 61, 96 Perforation tool orientation, 8 Perforation tunnel, 1-2, 11, 24, 45, 51-52, 59-60, 64, 66, 68, 70-73, 77-78, 80, 85, 94, 96, 114, 118 Perforation wash tool, 52, 66 Perforation washing, 43, 66, 71 Perforation/cleanout methods, 71 Permanent completion perforation, 63, 68 Permeability, 2-3, 5-10, 12-14, 17, 23-27, 29-30, 34, 38-40, 43, 45, 47-48, 51-52, 59-61, 64-66, 69, 71-72, 74, 76-77, 82-96, 113-114 Permeability impairment, 6, 71 Permeability profile, 93 Permeability recovery, 8 Permeability reduction, 6-8, 14, 48, 51, 74-75, 114 Permeable formation, 14 Phasing, 9, 58, 61, 67, 69, 76 Phasing perforation, 67 Phenolic resin, 96 Pickle pipe, 93 Pill material, 16 Pipe base, 20-21, 23 Pipe dope, 49, 51 Pipe rams, 50 Pipe-based screens, 21 Pipe-wall cleaning, 50 Plastic treatments, 114 Plastic viscosity, 49 Pleated absolute cartridge, 54 Pleated cylinders, 54 Plugged slot, 20 Plugging, 2, 5, 7-8, 14-15, 18-21, 24, 26, 29, 30, 32, 42, 44-45, 52-53, 68, 70 Plugging ratio, 20 Poisson's ratio, 86, 93 Polymer, 12-18, 25, 35, 44, 47-49, 51, 55-56, 74-75, 77, 88-89, 99, 103, 119, 125-126 Polymer fluid system, 17 Pore fluid compressibility, 61 Pore openings, 14, 23 Pore pressure, 2-3, 87, 93 Pore space, 5, 23, 39, 51, 113 Pore throat, 5, 20, 39, 49, 51-52, 58, 70 Pore throat bridge, 52 Pore throat plugging, 20 Porosity, 4, 24, 27, 52, 61, 69, 74, 109-110, 114 Porosity log, 109 Porous cake, 56 Porous metal fiber, 23 Port collars, 31-32 Positive tool positioning, 31 Post-completion isolation, 16 Post-treatment analysis, 109 Post-treatment flowback, 89 Potassium chloride, 15 Potassium formate, 13 Practical solids loading, 57 Preblender, 103 Precipitates, 20, 43, 45, 114 Precipitation of calcium fluoride, 67 Precipitation of sodium fluosilicates, 67 Pre-frac preparation, 69 Pre-fracturing stage, 68 Premature annulus bridges, 38 Premature bridge, 40 Premature sand production, 109 Premature screenout, 74, 77, 95 Pre-milled window system, 120 Premium screens, 14, 19-21, 34, 70-71, 85, 121 Prepacked screens, 20-21, 30, 34, 70-71, 96 Pressure calculations, 50, 76 Pressure decline analysis, 87, 90, 92, 94, 107 Pressure differential, 3, 47, 61, 64-65 Pressure drawdown, 3-5, 67 Pressure drop, 2, 5-7, 11, 19, 29, 32-33, 40, 54, 56, 59, 61, 68, 72-73, 76-77, 83, 86, 91, 94 Pressure leaf, 56 Pressure-activated firing head, 65, 68, 79 Pressure-depleted formation, 43 Pressure-transient method, 126 Pretreatment, 74, 89, 91-92 Primary fracture, 96 Producing interval, 2, 65 Producing rate, 70 Producing water cut, 1 Production packer, 31-32, 79, 117-118 Production screen, 12-15, 79 Productivity index, 6-7, 75, 82 Propagation, 88, 91-93, 107 Propellant sleeve, 69 Propellant/perforating technique, 69 Propellant-assisted perforating , 69 Propellants, 69 Proper size gravel, 26, 28 Proppant, 8, 38-40, 42, 59-60, 67, 69, 74, 81-82, 85-97, 103-105, 107-108, 110-111, 115-116, 118, 124, 126, 128 Proppant conductivity, 90-91 Proppant control, 92 Proppant embedment, 86-87, 90, 92 Proppant flowback, 67, 92, 126 Proppant particle size, 90 Proppant screenout, 67 Proppant selection, 89-91 Proppant sizing, 90 Proppant stages, 74 Proppant transport characteristics, 88 Proppant transport solution, 107 Proppant-laden gels, 59 Propped fracture, 39-40, 81-82, 84-87, 89-90, 93, 95, 111, 126 Propped fracturing, 8, 10 Propping agent, 89 Pseudo-3D gravel placement, 107 Pump rate, 10, 18, 30, 35, 39, 50, 73-77, 84, 104 Pumping practices, 85 Radial flow, 5, 47, 67-68, 75, 76 Radial flow geometry, 5 Radioactive marker, 79, 112 Radioactive tracer material, 110 Radioactive tracers, 91, 110 Ramp mode, 104 Rate exclusion, 9 Rathole, 71, 118 Recessed plate press, 55-56 Remedial operations, 2, 109 Removal of formation damage, 33, 83 Reservoir compaction, 7 Reservoir connectivity, 59 Resin, 8, 10, 15, 21, 27, 30, 36, 66-67, 89, 92-93, 96-97, 113-114, 126 Restricted flow, 29 Retrievable packer, 36 Reverse circulation, 31, 50, 53 Reverse-pressure, 64 Rheology, 12, 16, 49, 107 Rigless completion, 125-126 Rigless intervention, 63 Rigless sand control completions, 114 Risk assessment, 8 Robust zonal isolation schemes, 126 Rock failure, 3-4 Rock mechanics, 85-86, 126 Rock strength, 2, 59, 64, 93 Rod-based screens, 21 Rod-based, wire-wrapped screen, 21 Rotary vibration system, 118, 120 Salinity, 11, 16-17, 45, 66 Salt crystals, 13 Sand arch, 3 Sand bridge, 20, 39 Sand detector technology, 9 Sand disposal, 10 Sand embedment, 86 Sand erosion, 8, 10 Sand exclusion, 7, 14-16, 18-21, 23-24, 30, 39, 70, 81 Sand exclusion device, 14-16, 18-21, 23-24, 30, 39, 70 Sand exclusion philosophy, 7 Sand exclusion techniques, 16, 24 Sand failure, 24, 67 Sand fill cleanout, 43 Sand filling the annulus, 25 Sand grain impacts, 9 142 Modern Sandface Completion Practices 143 Sand grains, 2-3, 9, 14, 17, 25, 27, 28, 51, 70, 90, 113-114 Sand influx, 7-8, 39, 67, 70-71, 77, 90 Sand injector, 33, 73 Sand life cycle, 8 Sand management, 7-9 Sand packing, 10 Sand particles, 10, 20, 23, 48, 51, 117 Sand placement, 11, 69, 74 Sand prediction analysis, 7 Sand production, 1-11, 21, 24, 38-39, 58, 61, 67-69, 73-75, 84, 90, 96, 109, 114, 125-126, 131 Sand retention characteristics, 23 Sand screens, 20, 123 Sand size distribution plot, 28, 68 Sand size optimization, 28 Sand transport, 8 Sand traps, 8 Sand-cut, 9, 122 Sanding risk, 8-9 Sand-management completions, 69 Saucier rule, 90 Saucier's technique, 29 Scale inhibitor, 45 Scale precipitation, 7-8, 13, 76 Scale problems, 83 Scandium, 108-109 Scope of filtration, 52 Screen characteristics, 19 Screen cleaning, 16 Screen deployment, 117-119 Screen design, 21, 23-24, 30, 38, 73, 126 Screen erosion, 8, 24, 70, 74 Screen failure, 18, 94 Screen opening size, 19 Screen out, 67 Screen plugging, 18, 24, 30, 32 Screen standoff, 16 Screen wire-spacing design, 21 Screenless completions, 67 Screenless frac packing, 30 Screenless gravel packs, 68-69 Screenless single-trip multizone, 97 Screenout, 6, 38, 67, 69, 74-75, 77, 81, 84, 87-90, 92-93, 95-96, 109, 115-116, 126 Screenout pressure, 74, 116 Screens, 7, 8, 10, 14, 16, 18-21, 23-24, 38, 30-31, 34, 36-40, 68, 70-72, 81, 85, 92-96, 113, 121, 123-124, 126 Secondary payzone, 113 Secondary placement, 35 Selective and oriented perforating, 10 Selective perforating, 8-9, 67 Selective perforating practices, 9 Selective perforating techniques, 67 Set-down service tool, 94 Shaped charges, 59-61, 64 Shaped-charge design, 59, 61 Shear force, 3 Shear rate, 17, 48, 88-89 Sheared microgels, 48 Sheared polymer, 15 Shielded gamma detector, 109 Shot density, 9 59, 61, 69, 76, 94 Shots per foot (SPF), 63 Shunt tubes, 37-38, 40, 94 Shunt-tube screen, 94-95 Sidewall cores, 26-27 Sieve analysis, 18, 23, 27-29, 70 Silica cements, 114 Silica material, 30 Silt, 18, 27, 52, 70 Single salt brines, 46 Single-screen prepack, 21 Single-shot perforate, 65 Single-trip gravel packing, 65, 68 Single-trip perforating, 67-68 Single-trip sand control method, 68 Sintered bauxite, 30, 89-91, 116 Sintered metal mesh layers, 22 Sintered metal powder, 23 Sintered-laminates screen, 23 Situ stress field, 9 Sized bridging solids, 17 Skid-mounted equipment, 101 Skin effect, 76, 96 Skin factor, 6-7, 70, 74, 82 Slickline perforating, 61 Slot factor comparison, 19 Slot induced flow convergence, 19 Slot plugging, 20 Slot rows, 19 Slot width, 15, 18-21, 28, 70, 72 Slotted liners, 8, 14, 16, 18-21, 30, 34, 70, 72, 121 Sloughing, 13, 25, 32, 40, 117 Slurry, 11, 17, 25, 31-32, 34, 38, 55-56, 73-75, 77-78, 92-97, 104, 115-117, 126 Slurry pack, 25, 73-75, 77-78, 97, 104 Slurry skid, 56 Slurry skid manifold, 56 Slurry-pack technique, 32 Snubbing units, 61 Soak solution, 17-18 Sodium bromide brines, 18 Sodium chloride, 17-18, 67 Sodium formate, 44 Solids invasion, 6, 14, 45 Solids-free brines, 42, 44 Solids-free pills, 17 Solids-laden fluid (mud), 43 Soluble bridging material, 66 Soluble bridging solids, 16 Solvent treatment, 26 Solvent wash, 49 Sonic log, 4, 86 Sorting coefficient, 18 Sorting factor, 23, 29 Spacer fluids, 11 Spacer pill, 50 Special core analysis, 27 Special filters, 8 Special perforating techniques, 59, 65 Spectral core gamma, 27 Spectral gamma ray data, 111 Spectral gamma ray logs, 109-111 Spiral phasing, 66 Square drainage area, 83 Squeeze configuration, 94 Squeezed perforations, 50 Squeeze-packing techniques, 71 Stabilizing the formation sand, 35 Stable arch concept, 1 Stable filter cakes, 13, 17, 38 Stable pack, 53 Stable tunnels, 67 Stable wellbore, 36 Stacked frac-packing assembly, 94 Stainless steel lattice screen, 23 Stair-step mode, 104 Stand-alone completion, 15, 18, 21, 24-25, 42 Stand-alone completion assemblies, 24 Stand-alone liners, 24 Stand-alone screen, 13, 18-21, 37, 39, 70, 85, 103, 122, 126 Standard crossover circulation tool system, 33 Standard displacement, 50 Static bottomhole pressure, 40 Steam consolidation, 113-114 Steam flood techniques, 3 Steam injection, 26 Steel-wing centralizer, 32 Step rate test, 74, 93, 107 Stimulation design, 81, 91 Stimulation treatments, 7, 27, 97, 125 Stimulation vessel, 84, 103, 105-106 Stratification, 93 Sulfate, 45 Sulfate-reducers, 45 Sump packer, 79 Surface density, 44-45 Surface density completion fluid, 45 Surface equipment, 1-2, 50, 74, 103, 105 Surface filtration systems, 66 Surface modifier agents, 92 Surface pressure-control equipment, 64 Surface sand deposition, 8 Surface schematics, 106 Surface tension forces, 3 Surface-modification agent, 74 Surfactant spacer, 49-50 Surfactant sweep, 50 Surfactants, 13, 46-47, 51 Surge, 40, 61, 64-65, 69, 96 Surge flow, 61, 65 Surging, 23, 31, 71, 83, 87 Suspended solids, 15, 49-50, 54, 57-58 Swab pressure, 40 Swabbing, 31, 66, 94 Swabbing effect, 94 Index Swelling clay, 7 Synthetic oil-based DIF, 38 Synthetic oil-based mud, 13, 49 Tagged, 109, 111, 116 Tagging proppant, 91 Tangential forces, 17 Tell-tale screen, 31-32, 36, 75-76, 79 Terminal pressure drop, 54 Test particles, 54 Theoretical flow rate, 7 Theoretical modeling, 8 Theoretical productivity, 24, 25 Theoretical volume, 75 Thermal neutron log, 110 Thermal stability, 48 Thief zone, 24-25, 33 Three-dimensional fracture geometry, 107 Thru-tubing bridge plug, 118-119 Thru-tubing circulating gravel pack, 117 Thru-tubing completion, 113 Thru-tubing, wireline gravel pack, 119 Tight filter cake, 38 Tip screenout, 67, 81, 87-90, 92, 93 Tortuosity of the flow path, 90 Tracer logs, 110-111 Transient surge, 65 Transient, finite sand production, 68 Treating fluids, 11, 43 True crystallation temperature, Tubing, 2, 10, 16-17, 21, 23-24, 31, 33, 36, 49, 51, 59, 61, 63-67, 73, 79-80, 84, 88, 93-94, 109, 112, 114-121, 123, 126 Tubing conveyed perforating gun, 78 Tubing guns, 61, 65 Tubing straddle, 117 Tubing-conveyed perforating, 61, 63 Turbidimeter, 58 Turbidity, 57 Turbidity testing, 58 Turbulent flow, 10, 16, 50, 82, 87, 89 Turbulent non-Darcy skin, 76, 86 Two-phase flow, 5 Two-stage frac-pack technique, 96 Unconsolidated core analysis, 27 Unconsolidated formation, 27 Unconsolidated formation samples, 27 Unconsolidated rock, 1 Unconsolidated sands, 1, 10, 27, 63, 66, 69 Underbalance pressure differential, 65 Underbalance/surge process, 69 Underbalanced perforating, 63-66, 68, 71, 79, 83, 87 Underbalanced perforating guidelines, 65 Underflushed, 96 Underlying drainage, 23 Underream, 25, 31-33, 76-77, 82-83 Underreamed hole, 32 Underreaming, 25, 33, 76-77, 82 Uniformity coefficient, 18, 23, 29 Velocity of the reservoir fluid, 3 Vent-screen cap, 119 Vent-screen method, 114-115 Vertical fracture, 86, 94-95 Vertical leaf pressure filter, 55-56 Vertical open-hole well, 32, 38 Vertical wells, 31 VES fluid, 89, 126 VibraPak rotary vibration system, 118 Viscoelastic polymer-free fracturing fluid, 88 Viscoelastic surfactant, 88 Viscosifier, 17 Viscosity, 2-7, 16-17, 25, 30-34, 47-49, 53-54, 73-78, 82, 85-86, 88-89, 91-92, 103, 106, 120 Viscous polymer gels, 47, 49 Viscous transport fluid, 75 Volumetric methods, 8 Volumetric response, 44 Wash solution, 17-18 Wash tool, 16, 33, 36, 52, 66 Wash-down method, 114-116 Wash-down technique, 96 Washing perforations, 53, 83, 87 Washing the pack, 33 Washouts, 11 Washpipe conveyance, 109 Washpipe screen, 37 Water packing, 29, 69, 74, 97 Water packs, 74, 77, 97 Water soluble, 14, 48-49 Water-based completion fluids, 45 Water-bearing zones, 88 Water-soluble additives, 33 Water-soluble salts, 43-44 Water-wet fines, 5 Wedging of out-of-size gravel, 30 Well geometry, 116 Wellbore animation, 106 Wellbore cleanout, 93 Wellbore clean-up tool, 69 Wellbore flow restrictions, 6 Wellbore geometry, 17 Wellbore-stability calculations, 125 Wellhead isolation tool/treesaver, 118 Well-log interpretation, 126 Well-test pressure analysis, 126 Wetting phase, 5 Wire spacing, 20-21, 23, 30, 70, 78 Wire-wrapped screens, 7, 16, 18-21, 34 Wireline, 4, 59, 61, 63-67, 69, 79, 107, 109-110, 116-119 Wireline gravity bailers, 119 Wireline-logging, 4 Wireline orienting tools, 67 Wireline plugback, 119 Wireline setting tool, 79 Wireline-conveyed guns, 65 Wire-wrapped screens, 7, 16, 18-21, 34 Workover fluids, 10, 43, 47 Workover strategies, 125 Xanthan gums, 48 Xanvis, 14, 48 XC gel, 48-49 XC polymer, 48 Yield point, 50 Yield stress, 17, 38 Young's modulus, 86 Zonal isolation, 8, 24, 74, 95, 111, 115, 125-126 Zone spacing, 125 144 Modern Sandface Completion Practices Printed in USA ©2003 Gulf Publishing Company WO3-2003/12M HALLIBURTON PREMIER SPONSORS SPONSORS SMITH SERVICES A Business Unit of Smith International, Inc. Cover Premier Sponsors: Sponsors: ABOUT THE AUTHORS Acknowledgments PREFACE CONTENTS CHAPTER ONE Causes and Effects of Sand Production Understanding the Reservoir Productivity, Formation Damage Damage and Flow Efficiency Sand Management Techniques Justification for Sand Control Types of Sand Control Drilling, Cementing and Completion Considerations CHAPTER TWO Drill-In Fluids Stand-Alone Screens Gravel Packing Open-Hole Frac Packing CHAPTER THREE Completions Fluids Debris Removal and Mysteries Fluid Filtration Perforating Stand-Alone Screens Gravel Packing Frac Packing Gravel-Packing Method Selection CHAPTER FOUR Surface Equipment and Techniques Monitoring and Control Evaluation Techniques CHAPTER FIVE Rigless Sand Control Techniques Specialty Tools and Techniques CHAPTER SIX Candidate Selection Drill-In and Completion Fluids Completion Hardware Fracture-Well Connection Frac-Pack Analysis Improved Well Test Interpretation Eliminating Hardware Global Databases APPENDIX ONE APPENDIX TWO APPENDIX THREE DIRECTORY INDEX