Resin-coated Sand Research Articles

Improved Conductivity and Proppant Applications in the Bakken Formation

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 163849, ’Investigation of Improved Conductivity and Proppant Applications in the Bakken Formation,’ by Bethany Kurz, SPE, Energy and Environmental Research Center, Darren Schmidt, SPE, and Phil Cortese, SPE, Weatherford, prepared for the 2013 SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 4-6 February. The paper has not been peer reviewed. Production from the Bakken and Three Forks formations within the Williston basin is continuing to climb as a result of applied horizontal drilling and hydraulic fracturing. Key to increased oil production is the evolution of reservoir-stimulation techniques, such as fracturing-fluid systems and proppant types. This study evaluated the key factors that may result in conductivity loss within the Bakken and Three Forks reservoirs. The results of this work suggest that certain fluids may affect both rock and proppant strength and, therefore, require consideration. Introduction This work was conducted in an effort to answer questions regarding reservoir stimulation in the Bakken petroleum system, specifically with respect to conductivity loss in hydraulic fractures over time. The key questions that were evaluated include Can conductivity loss be attributed to proppant degradation, rock strength, or both? What role do fluids have in affecting propped-fracture conductivity? To what extent does fluid exposure affect the degradation of rock strength and proppant performance? How do various proppants perform relative to one another under stress using actual core samples from the Bakken petroleum system? Laboratory tests were conducted to evaluate the sensitivity of Bakken and Three Forks formation cores to various fluids; to evaluate the strength of Ottawa sand, an unspecified premium precured resin-coated sand (RCS), and a lightweight ceramic proppant (Econoprop) with respect to various fluids; and to measure the relative laboratory conductivity performance of propped fractures using actual rock core. Fluids used in experiments to examine potential strength degradation for both rock and proppant included the following: Slickwater—a mixture of polyacrylamide and fresh water Crosslinked gel—guar-polymer thickening agent, borate crosslinker, and fresh water Gelled diesel—diesel fuel and phosphate ester Bakken-formation crude—crude oil Bakken-formation brine—highly concentrated saltwater The fluids were selected on the basis of the most common fluids expected to be encountered in the Bakken formation. Embedment Brinell-hardness-index testing is a measure of rock strength that is determined by embedding a metal ball into formation rock at a given applied load. This type of index testing was used to gauge the relative strength of Bakken and Three Forks samples before and after exposure to formation and hydraulic-fracturing fluids. Core samples used to study rock strength originated from the North Dakota Industrial Commission (NDIC) #16771 well, located in the Manitou field of Mountrail County. Rock strength was measured with a Brinell-hardness-test apparatus. Publicly available hardness data were available from two wells in proximity, including NDIC #15986, Robinson Lake field, Mountrail County, approximately 10 miles to the southeast NDIC #16083, Capa field, Williams County, approximately 10 miles to the southwest

Production Acceleration or Additional Recovery? A Look Back at Three Published Field Trials - Long-Term Benefits of Improved Fracture Treatments

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144349, ’Production Acceleration or Additional Recovery? A Look Back at Three Published Field Trials To Determine the Long-Term Benefits of Improved Fracture Treatments,’ by K. Blackwood, SPE, Highmount Energy; P. Handren, SPE, Denbury Resources; and M. Chapman, SPE, T. Palisch, SPE, and J. Godwin, SPE, Carbo Ceramics, prepared for the 2011 SPE North American Unconventional Gas Conference & Exhibition, The Woodlands, Texas, 14-16 June. The paper has not been peer reviewed. Improved fracture-treatment designs can increase production rates from many reservoirs. However, do these changes merely accelerate recovery, or is incremental production gained by changing the fracture design? The authors re-examined three tight gas case studies published in the past 10 years. The original studies were performed specifically to assess the effects of increased fracture conductivity on production. In all cases, the initial analyses documented that increasing conductivity appeared to increase production and recovery. Introduction Since the first commercial hydraulic-fracture treatments in 1949, treatment designs have evolved from experimentation with massive hydraulic fractures to proppantless water-fracture treatments. While the production increase in the first few months or even the first year typically repays the cost of the conductivity upgrade, and is robust enough to make the decision to upgrade relatively simple, it is important to know whether this increase can be translated into additional ultimate recovery. If the ultimate recovery is also increased, then the economics of the completion upgrade may be even more favorable because it leads to a potential increase in reserves and drainage area per well, which in turn can lead to a reduction in the number of wells needed to drain the reservoir effectively. In all cases, comparisons were made between high-quality ceramic proppants and either uncoated or resin-coated sand (RCS). In the past, conventional wisdom incorrectly suggested that hydraulic fractures in most tight gas wells behaved as “infinitely conductive.” This misperception arose from a poor understanding of proppant performance under downhole (realistic) conditions. Under realistic conditions, all proppants should be expected to lose more than 90% of their effective conductivity. By reanalyzing these case studies with longer term production results, the authors sought to determine whether the original conclusions still hold true, and whether confidence in the recovery projections can be determined.

Effects of Proppant Selection on Shale Fracture Treatments

This article, written by John Terracina, manager of fracturing technology at Momentive, contains highlights of paper SPE-135502-MS, Proppant Selection and Its Effect on the Results of Fracturing Treatments Performed in Shale Formations, by J.M. Terracina, SPE, J.M. Turner, SPE, D.H. Collins, SPE, and S.E. Spillars, SPE, of Hexion, prepared for the 2010 SPE Annual Technical Conference and Exhibition in Florence, Italy, 19-22 September. In October 2010, Hexion merged with Momentive. The oil and gas industry has strived to provide methods to test the proppants used in shale formation fracturing, but they still do not adequately address many of the factors that impact their effectiveness. There are many factors that occur downhole that need to be considered, such as: Proppant fines generation and migration in the fracture Proppant resistance to cyclic stress changes Effective conductivity vs. reference or baseline conductivity Proppant flowback and pack rearrangement in the fracture Proppant embedment in the fracture face Downhole proppant scaling The hypothesis of this study was that because of the formation characteristics in the three areas studied, curable resin-coated sand (CRCS) with its grain-to-grain bonding technology should provide higher downhole fracture conductivity leading to increased postfracture treatment well production. To verify the hypothesis, laboratory tests outside the traditional long-term baseline conductivity were conducted with proppants and formation core samples from each area. The objective was to more accurately simulate proppant performance under specific downhole conditions of temperature, pressure, fluid, and rock properties pertaining to each area. Proppant Selection Factors Studied Proppant fines generation and migration, as well as proppant flowback, were studied in the Fayetteville Shale of Arkansas. Proppant fines and embedment were studied in the Bakken Shale of North Dakota. And finally, proppant pack cyclic stress, embedment, and scaling were examined in the Haynesville Shale of Louisiana. Proppant Fines Generation and Migration Proppant fines are the small particles that break off from the proppant grain when subjected to fracture closure stress. The small broken pieces reduce pack porosity and permeability, and cause major degradation in the conductivity of proppant packs. When proppant fines migrate down the proppant pack toward the wellbore, they accumulate and reduce flow capacity. Proppant Pack Cyclic Stress When comparing proppants, one factor often overlooked is a proppant’s performance under closure stress changes. The forces of cyclic stress exerted on proppants downhole can cause them to fail. Events often occur multiple times throughout the life of a well, such as shut-ins because of workovers or connections made to a pipeline; in some cases, a well could be shut in because of pipeline capacity. These events lead to cyclic changes in fracture closure stress. This varying amount of pressure and stress can cause the proppants to shift or rearrange, resulting in a decrease in fracture width as well as additional proppant fines and proppant flowback.

Successful Hybrid Slickwater-Fracture Design Evolution: An East Texas Cotton Valley Taylor Case History

Summary As the development of tight/unconventional and partially depleted gas reservoirs has increased, so has the demand for more-innovative hydraulic-fracture designs. Operators are increasingly placing proppant with slickwater, linear gel, or hybrid fracture designs. While the benefits of these designs typically are attributed to a reduction in gel damage of the proppant pack, many operators mistakenly believe that the resulting fractures are not conductivity-limited. Because few (if any) models on the market can adequately model the propagation of a slickwater fracture along with the associated proppant transport and deposition, it becomes difficult to optimize these fracture designs. This has led many operators to assume incorrectly that only small-diameter sand or resin-coated sand may be placed in these types of designs, and that these products supply ample flow capacity. However, one east Texas operator has combined insight into proppant transport with an appropriate understanding of realistic proppant-pack conductivity to develop a novel, hybrid slickwater-fracture design. This design has allowed the placement of larger-diameter, higher-conductivity proppant in fractures that many believed could not be placed in fractures either operationally or economically. Additionally, this operator has developed a unique pumping strategy to place the highest-conductivity proppant in portions of the fracture where it provides the most value. This paper will present a case history of these new hybrid slickwater-fracture designs in this operator's east Texas Cotton Valley Taylor (CV-T) completions. The design theory and sequential improvements will be documented, including larger-diameter, higher-strength proppants, and a novel placement design. Field results from the first six wells fractured will be presented, showing substantial increases in gas production compared with similar offset completions. Economics will also be shown to illustrate the tremendous value added to completions using this hybrid fracture design.

Investigation on the bonding mechanism of non-occupying coating to resin-coated sand (RCS)

Investigation on the bonding mechanism of non-occupying coating to resin-coated sand (RCS)

Effect of Proppant Failure and Fines Migration on Conductivity of Propped Fractures

Abstract Long-term conductivity testing at realistic environmental conditions has greatly improved the measurement of proppant pack permeability. However, the use of low flow rates to insure Darcy flow in such measurements has masked the total effect of failed proppant fines on proppant pack permeability. As flow rates increase, corresponding with those commonly found in the field, fines are mobilized and migrate into new positions that reduce the permeability of the proppant pack beyond that normally observed in conductivity measurements. This effect has generally been overlooked in proppant pack design. This paper examines the extent of conductivity reduction caused by migrating proppant fines and the effect of proppant type on the extent of that reduction. The role of fines migration on the conductivity of proppant packs containing two different types of proppants, where the more capable proppant is used near the wellbore, is also evaluated. Representative commercially available proppants, including sand, resin-coated sand, and low density ceramics are included in the study.

CATALYTIC DECOMPOSITION OF PHENOLIC RESIN ON RESINCOATED SAND MIXED WITH SEPIOLITE

In the shell molding process, catalytic decomposition of phenolic resin on resincoated sand in the presence of sepiolite was investigated. Phenolic resin-coated sand mixed with sepiolite liberated less amounts of smoke and irritating gases than that without sepiolite not only in the molding, but also in the casting. The results indicate that the sepiolite has promoted thermal decomposition of the irritating gases as catalyst. The bending strength of the mold decreased with the increasing sepiolite contents

Influence of Surfactant Structure on Wettability Modification of Hydrophobic Granular Surfaces

Using the capillary penetration wetting technique, the influence of surfactant structure on wettability modification of hydrophobic granular surfaces was examined. Linear and branched hydrocarbon chain sulfates, 5 mol monodisperse ethoxylates and 5 mol monodisperse ethoxysulfates were used as surfactants and resin-coated sand as the hydrophobic granular surface. Both the surfactant type and hydrocarbon chain branching were observed to exert a significant influence on the rate and effectiveness of wetting. Wetting rates for ethoxylates > sulfates > ethoxysulfates. Wetting effectiveness for sulfates > ethoxylates. For a given surfactant type, hydrocarbon chain branching was observed to increase wetting rate and effectiveness.

Use of Single-Well Simulators and Economic Performance Criteria To Optimize Fracturing Treatment Design

Summary Low-permeability reservoirs are currently being propped with sand, resin-coated sand, intermediate-density proppants, and bauxite. This wide range of proppant cost and performance has resulted in the proliferation of proppant selection models. Initially, a rather vague relationship between well depth and proppant strength dictated the choice of proppant. More recently, computerized models of varying complexity that use net-present-value (NPV) calculations have become available. The input is based on the operator's performance goals for each well and specific reservoir properties. Simpler, noncomputerized approaches include cost/performance comparisons and nomographs. Each type of model, including several of the computerized models, is examined here. By use of these models and NPV calculations, optimum fracturing treatment designs have been developed for such low-permeability reservoirs as the Prue in Oklahoma. Typical well conditions are used in each of the selection models, and the results are compared. The computerized models allow the operator to determine before fracturing how changes in proppant type, size, and quantity will affect postfracture production over time periods ranging from several months to many years. Thus, the operator can choose the fracturing treatment design that best satisfies the economic performance goals for a particular well, whether those goals are long or short term.

A Study of Phenolic Novolak Resin Chemistry in Relation to the Hot Method of Coating Shell Sand

Phenolic novolak chemistry, the basis of coating and curing processes employed in resin-coated sand technology, has been studied with differential scanning (calorimetry), degree of cross-linking, gas evolution, and infra-red spectrum testing methods. Various thermal properties of phenolic resin during heating at different temperatures have been obtained. It is suggested that the methods employed in this paper could be used to optimise hot-coating and curing processes associated with Croning shell sand.

Proppant Selection: The Key to Successful Fracture Stimulation

Summary Many proppants and mesh sizes are available for thedesign of a fracture stimulation treatment. When proppants-sand (Ottawa, Texas Mining, Unisil), proppants-sand (Ottawa, Texas Mining, Unisil), bauxite, intermediate-strength proppants (ISP), resin-coatedsand (RCS), precured resin-coated sand (PRCS) and Zprop-are considered, the principal questions seem to be, prop-are considered, the principal questions seem to be, "Which one do I select"" and "How should I use it?"Maximized, adequate, long-term productivity inlow-permeability reservoirs depends on fracture penetration and fracture conductivity. How to obtain deeply penetrating fractures that are contained and adjacent to the porous penetrating fractures that are contained and adjacent to the porous interval is one of the questions that challenge the industry. Another is how to obtain sufficient fractureconductivity to use the deep penetration effectively. This is a state-of-the-art paper that attempts to bring the current technology on proppants together. This paper discusses how to determine and to obtain sufficient fracture conductivity. Fracture conductivity is a function ofthe proppant properties (i.e.. strength, roundness, andfines content), closure stress, drawdown rate, formation properties (i.e., proppant embedment conditions), and properties (i.e., proppant embedment conditions), and resultant propped fracture width. The engineering, principles involved in the selection of-the proper type and principles involved in the selection of- the proper type and amount of proppant are supported with a case history. Introduction As we explore for reserves at depths exceeding- 10.00ft 13,048 in], the tendency is to find reservoirs that havelow permeability and contain natural gas. Because of thelow permeability of the formation, the natural rateof production and the drainage area are often too low toprovide a commercial well. provide a commercial well. Propped hydraulic fracture-stimulation treatments thatcreate deeply penetrating, highly conductive flowchannels can be used to increase both the rate of productionand the drainage area. Four factors control improvements in productivity (i.e., the productivity index) provided by hydraulic fracturing.Propped fracture area (sq ft). This is the area of thefracture adjacent to the porous interval that has beenpropped (length times height). All the fracture area propped (length times height). All the fracture area adjacent to the porous interval that is created have not bepropped, and only the fracture area adjacent to the propped, and only the fracture area adjacent to the productive porosity that is propped is considered an effective productive porosity that is propped is considered an effective area.Conductivity of the propped fracture (md-ft). Thisis a measurement of how well the propped fractureconducts the produced fluids. In addition to the effectof closure stress on the permeability of the proppant, factors such as embedment. proppant distribution, andresultant fracture width must be considered to determine theconductivity of the fracture at reservoir producingconditions.Reservoir permeability. This value is used todetermine the fracture conductivity required to use theproposed fracture penetration effectively. proposed fracture penetration effectively.Drainage radius. This value is used, as is reservoirpermeability, to determine the length of fracture needed. permeability, to determine the length of fracture needed. A long, fracture is needed if the well spacing is large andthe reservoir permeability is low. Typical Well To show how the principles that are described in this paperwork, we will use a typical gas well with the propertiesdescribed in Table 1. Effect of Reservoir Permeability on Fracturing. Indeep, hot, low-permeability sandstone reservoirs, development of deeply penetrating fractures with adequate conductivity is important. Once reservoir permeability isknown, it is important to optimize the fracture length andconductivity by comparing treatment cost to expected production. The pressure drop along a propped fracture that production. The pressure drop along a propped fracture that has an insufficient flow capacity will limit the productionfrom a well. A fracture with excessive fracture capacityis not effective. Fig. 1 can be used as a guide in the selection of the desired effective fracture length based on reservoir permeability. When the reservoir permeability is greater than permeability. When the reservoir permeability is greater than about 0.1 md, the desired fracture lengths are generally1,000 ft 1305 mi or less. In low-permeability reservoirs(kg, less than 0.1 md), production can be almost directly proportional to fracture length before boundary conditions are proportional to fracture length before boundary conditions are reached. With adequate fracture flow conductivity, thelonger the fracture, the higher the producing rate. For example, in very-low-permeability reservoirs (i.e., 0.001 to 0.0001 md), fracture half-lengths of 2.500 to 4,000 ft 1762 to 1220 nil can be used to increase production effectively. Fig. 1 shows that in the typical well example with a permeability of 0.03 md. a 1,300-ft [396-m]fracture half-length should be created and propped to achieve maximum production. Effect of Fracture Conductivity and Fracture Length on Production. Fig. 2 was generated with a reservoirsimulators and shows the effect of fracture conductivity(Cf) and fracture half-length on production in dimensionless terms. JPT P. 2163

Stability of Gravel-Packing Materials for Thermal Wells

Summary Several different types of materials have been evaluated for use in gravel packing high-temperature thermal wells. The materials include Ottawa sand, sand from Venezuela, resin-coated sand, sintered bauxite. and high-alumina beads. The materials were evaluated at various temperatums up to 600 deg. F (316 deg. C] and pH's ranging from 7.0 to 11.0. The tests were conducted by passing water in the fluid phase through samples of the various materials at the desired pH and temperature. Weight-loss measurements and visual inspection by a scanning electron microscope (SEM) were performed on each sample to determine the effect of the various temperatures and pH's. The steam evaluation of the various gravel-packing materials shows that the alumina-based materials are best suited for gravel packing thermal wells, where the temperature may reach 600 deg. F 1316 deg. C1 and the pH of the aqueous phase of the steam reaches 11.0. The alumina materials have very little weight loss and maintain a uniform shape. Quartz materials show dramatic weight losses as temperature and pH increase. The weight loss of resincoated sand is most affected by increasing pH al elevated temperatures. Introduction Steamflooding and stimulation by steam are two of the most widely used methods for the production of heavy crudes. Most thermal recovery operations are in formations that are classified as unconsolidated and that require some form of sand control. One accepted method of sand control is gravel packing the well with a highquality silica sand or other suitable materials, such as sintered bauxite or resin-coated sand. Shallow wells generally are stimulated with steam injection at moderate rates and temperatures under 450 deg. F [232 deg. C]. Deeper wells, however, may require steam at temperatures higher than 600 deg. F [316 deg. C to be injected at the wellhead. This high-temperature steam is required to ensure that enough heat is transmitted to the formation in the deep wells to allow for efficient recovery of the heavy crudes. It is well established that the solubility of quartz sand and other siliceous materials in water increases sharply at high temperatures and pH's (see Fig. 1). Because of the composition of certain feedwaters used for steam generation, the liquid phase of the injected steam can have a relatively high pH. Where high pH and high temperatures are observed, gravel packs composed of quartz sand can be relatively short-lived. Steam Evaluation of Gravel-Pack Materials Several different types of common gravel-pack materials were evaluated. Two sources of gravel-pack sand were tested to determine whether differences in quartz content were important to the stability of quartz at elevated pH and temperature. Ottawa sand, which contains 99.9% quartz, and a sand from Venezuela, which contains 95 % quartz and various amounts of impurities (such as feldspar goethic, kaolinite, chlorite, and illite), were as subjected to various temperatures up to 600 deg. F [316 deg. C and pH's up to 11.0. Two types of bauxitic materials were chosen for evaluation. The first material was the sintered bauxite commonly used as a high-strength fracture proppant. The second sintered-bauxite-type material is a byproduct of a manufacturing process and contains more A1203 than the more common fracture proppant. Table 1 shows a comparison of the properties of the two sintered materials. Sintered bauxite and high-alumina beads are very stable in high-temperature/dry-heat environments, as shown in Table 2. Terns at thermal-well conditions of temperature and pH were performed to determine whether the differences in the amount of A1203 of the two bauxitic materials would result in greater stability. The use of resin-coated sand to control sand in thermal wells has been growing in popularity over the past several years. Improvements in resin chemistry and manufacturing processes have helped to increase the thermal stability of this type of material and to prolong its effectiveness in the harsh environment of steam-recovery wells. Tests were performed to determine the stability of one such material as a function of pH and temperature. Effect of Feedwater Many of the waters used to produce steam for thermal recovery projects contain HCO-3. This material is found in the formation feedwater and is not removed during the softening treatment before injection into the steam generator. Thermal degradation of the HCO - ions in the feed-water results in CO2 and OH - . Because most steam generators in the field produce 80% steam, the OH ions remain dissolved in the aqueous phase of the steam and produce a very alkaline solution depending on the concentration of HCO - in the feedwater. JPT P. 2006^

New Proppant for Deep Hydraulic Fracturing

Summary Much work has focused on developing and evaluating various materials for use as proppants for hydraulic fracturing. Sand is used most often as a fracturing proppant in shallow wells. Deep wells with high closure stresses require a proppant, such as sintered bauxite, that will not crush under adverse conditions. Ceramic and zirconium oxide beads and resin-coated sand proppants also have been developed for deep hydraulic fracturing. A new fracturing proppant has been developed that exhibits the properties necessary for use in deep hydraulic fracturing. This proppant is produced by precuring a specially modified phenolformaldehyde resin onto sand. The new proppant maintains conductivity and resists crushing much better than does sand. The new proppant was compared to intermediate-density sintered bauxitic proppants and cured-in-place proppants and the tests were confirmed by an independent laboratory. Introduction Sintered bauxite commonly is used as a proppant in deep wells, where materials such as sand or glass beads would be crushed. Sintered bauxite resists crushing much better than sand does at high closure stresses, but it is much more expensive and harder to place because of its high bulk density. Several types of materials are used as proppants. Sand is one of the more common materials used because of its availability and cost. However, sand is limited to use in relatively shallow wells where closure stresses of 8,000 psi [55.2 MPa] or less are encountered. When sand does collapse as a result of closure stress, a great volume of fines is generated, which causes an irreversible decrease in conductivity of the fracture. This phenomenon also is observed with glass beads. A new proppant has been developed that resists crushing and maintains conductivity much better than regular fracturing sand. The new proppant is made from sand coated with a modified phenolformaldehyde resin. The resin is cured around each of the sand grains. When the sand grains are coated with the proper amount of resin and cured to the proper degree, the resin adds substantial strength to the sand grain because of the physical characteristics of the resin once it is cured. Results presented in this paper show that sintered bauxite and the new proppant generate very few fines when exposed to the same closure stress. Flow tests also show that the precoated sand grains, which are cured individually, show much less decrease in conductivity than does uncoated sand when confined at closure stresses greater than 6,000 psi [41.3 MPa]. Theory The use of sands coated with phenolformaldehyde resins (i.e., thermoset) has been under development for several years. The basic application has been placement of such a material into a wellbore in an uncured state. The natural temperature of the well or injected steam then causes the resin on the sand to "flow" and set, thus producing a high-strength, consolidated porous medium. This type of material has been used in conjunction with screens to produce a strong, consolidated porous medium in a fracture. The application of sand coated with uncured thermoset resin for both gravel packing and fracturing has met with varied success. This type of process has several limitations to successful application. Sand coated with an uncured thermoset resin must be placed at a relatively low temperature. Exposure to elevated temperatures (i.e., greater than 160 to 200 deg. F [greater than 71 to 93 deg. C]) for long periods during placement may cause the resin to cure partially before placement is complete. Exposure of the sand coated with an uncured thermoset resin to elevated temperatures during placement could be detrimental to the conductivity of the final fracture or gravel pack. This could result from the resin-coated sand becoming "tacky" during placement, thus allowing small particles within the placement fluid to adhere to the coated sand grain. Placement of this type of "dirty" particle within a fracture or gravel pack could decrease the final conductivity substantially. One major concern with using sand coated with an uncured thermoset resin as a proppant is how it is cured once it is in place in the fracture. Test results show that crushing similar to that observed for sand occurs for certain resincoated sands if the closure stress is not kept off the proppant until it is fully cured (Fig. 1). Tests with certain modified thermoset resins have shown that even though a strongly consolidated porous medium can be obtained by using sand coated with the uncured resin, as previously described, a unique property is imparted to sand if the coated sand grains are cured individually under proper conditions. Once the resin-coated sand grains are cured individually, the resulting material has a resistance to crushing similar to that of sintered bauxite. JPT P. 98^

Performance Review of Phenolic-Resin Gravel Packing

Summary This paper discusses the application of phenolic-resin-coated gravels in forming linerless, behind-the-casing gravel packs as a method of sand control in shallow steam-displacement wells. Laboratory tests were made to determine the effects of steam temperature, flow rate, and pH on the physical properties of the resin-coated sand (i.e., curing, matrix strength, and permeability). These tests, along with posttreatment production history from a 10-well field test, show that phenolic-resin gravel packing is an effective method of sand control. Introduction Getty Oil Co. operates a major steam displacement project in the Kern River field near Bakersfield, CA. Steam is injected continuously into the productive sand via steam injection wells and ultimately breaks through into the producing wells. Many of these producing wells have experienced severe sand problems because the steam carried large quantities of the unconsolidated formation through the perforations.Unique field characteristics, which have discouraged the use of many modern sand-control methods currently employed throughout the industry, include the following.1. Reservoir temperatures generally exceed 120 degrees C and may go as high as 205 degrees C during steam stimulation.2. To reduce the hydrostatic head, the wells are operated in a "pumped-off" condition. Therefore, the sucker-rod pumps must be placed at the bottom of the producing zone.3. Clearance between casing and sucker-rod pumps in many of Getty's 3,000 producing wells is less than 56 mm.These factors prevent running retaining screens for conventional gravel packs and the use of gravel coatings, which are not stable at these temperatures. However, a linerless, behind-the-casing, consolidated gravel pack using a coated gravel that exhibits high-temperature stability is a sand-control method that is compatible with these field conditions.This paper describes the results of laboratory investigations and a field test program on the use of phenolic-resin-coated gravel (PRCG). Laboratory tests investigated the effect of expected field conditions on the physical properties of the PRCG. The results of these experiments were used to define the physical limitations under which these gravels can be used successfully in field applications. The performance of 10 sand-problem wells that were gravel packed using this coated sand is discussed. The results of this entire program show that PRCG can be used successfully to control sand problems in many of the Kern River wells. Theory The material used in these gravel packs consists of sieved, high-quality gravel, of which each grain has been coated with phenolic resin. After placement in the wellbore, the gravel is heated either by conduction from the reservoir or from injected steam. The resin softens as the temperature increases and diffuses to form "necks" between adjacent sand granules. After a finite period of time, the resin thermosets into a hard, inert coating, forming a highly permeable, consolidated gravel pack.The coated gravel does not require preflushes or postflushes to consolidate uniformly when an adequate heat source is available. This becomes increasingly important as treatment interval length increases. JPT P. 221^