Summary Laboratory investigation of the interactions between fracturing fluids andresin-coated proppants (RCP's) revealed (among other conclusions) that RCP'sare incompatible with oxidizing breakers. Areas covered included RCP effect onfluid rheology, fluid relationship to RCP strength, theoretical study ofrequired RCP strengths to prevent flowback, and experimental measurement toestablish minimum strength. Introduction This paper describes the use of curable RCP's in fracturing treatments. Their primary purpose is to prevent proppant flow from the fracture duringcleanup and production. The use of such materials is increasing rapidly, yetmany concerns exist in design and application of fluid systems. These include(1) the effect of various crosslinked fluid systems on the strength of thecured, consolidated sandpack, (2) breaking of the gel system, (3) temperatureeffects on the resin system during curing, (4) the closure stress required tocause consolidation, and (5) the compressive strength required to preventproppant flow from the fracture. Laboratory experiments have been conducted todetermine the effect of various components in crosslinked fluid systems on theconsolidation of curable RCP'S. Available RCP products and field- applied resinsystems were investigated under several different curing conditions. Extendedcuring before stress was applied resulted severely reduced strengths. Flowexperiments (through consolidated packs) with oil and water were conducted tocorrelate velocity/viscosity packs) with oil and water were conducted tocorrelate velocity/viscosity relationships and proppant flow from a pack. Fluidsystems and techniques for optimized use of curable RCP's are identified, andgel breaker requirements are presented. Compressive strengths obtained underfield conditions generally were much lower than commonly reported. Background The use of plastic materials for sand consolidation in producing wells datesback to 1945, when a phenolic resin was used. Since then, use of variousmaterials, including phenolic, furan, and epoxy resin systems, has beendescribed for various sand-control applications. In 1975, the application ofcurable RCP with a phenolic-based system was patented. Literature pertaining tothe use of plastic materials to control sand production has focused on gravelpacking and sand control. During the last decade, proppant production fromhydraulically fractured wells has increased. One reason is the use of higherproppant concentrations during the treatment. To control this proppantconcentrations during the treatment. To control this proppant productioneconomically, the use of curable RCP has grown proppant productioneconomically, the use of curable RCP has grown from novelty status to standardpractice. During the recent growth of RCP application, conductivity, compressive strengths, and general effectiveness have been considered, but someareas of their application remain relatively unexplored. These areas includethe RCP's effect on the fracturing fluid, the fracturing fluid's effect on the RCP, and the amount of bonding strength required to hold the cured RCP in aproducing fracture. The objective of this research was not to generate fractureconductivity data or proppant crushing, but to provide better understandingbetween the interactions of fluid and RCP. In addressing these issues, werealized that common fracturing fluids and conditions influence the resultingstrengths of cured, consolidated RCP. A better understanding of proppantconsolidation was desired because the fluid and curing conditions of RCP affectstrength. Therefore, this paper discusses the RCP's effect on fluid rheology, the relationship of fluid to RCP strengths, the theoretical study of required RCP strengths to prevent proppant flowback, and experimental measurements toestablish minimum required strengths. Two general methods are now used duringfracturing treatments to consolidate proppant. The most widespread method isthe use of curable phenolic resins precoated on the proppant. In this case, products are manufactured and delivered to location. Two curable phenolic RCPproducts were evaluated in this study: RCP-A normally contains 4% resin and RCP-B normally contains two layers of resin, 2 % precured followed by 2 %curable resin. A new approach is an on-site coating method where requiredmaterials are to the fluid and allowed to coat the proppant during pumping. This system, RCP-C, uses an epoxy-based resin system. The concentration resinused in this system can be varied to adjust the compressive strength of theconsolidated proppant. A precured similar to RCP-A was used and is called RCP-D. RCP Effect on Fluids The influence of RCP on fluid rheology related to crosslink time andviscosity was examined. The effect of RCP on breakers used oil to obtain acontrolled reduction of the fluid's viscosity also was examined. The first testseries examined the influence of RCP-A on the ambient-temperature fluidcrosslinking rate. In these tests, aluminum-, titanium-, and boron-crosslinkedfluids were examined to evaluate acidic, neutral, and basic fluid systems. Table 1 gives the times to crosslink to a "strong" state. From thesefluids tested, we concluded that RCP-A did not significantly influence thecrosslink rate of these fluids. The RCP effect on fluid viscosity was examinedat 170F for a linear gel and a titanium-crosslinked fluid. For evaluating theinteraction of RCP and base gel viscosity, a 100-lbm/1,000-gal solution ofhydroxypropyl guar (HPG) was monitored for I hour at 170F. Because solidproppant usually is not used directly in the Fann Model 50 TM viscometer, theinfluence of RCP on viscosity was determined by mixing either RCP-A or RCP-B at6 lbm/gal in the water used for preparing the gel and then removing the solidsbefore gelation. Because the water-soluble gel most likely would be influencedby water-soluble components from RCP-A or RCP-B. we decided that this techniquewas a reasonable experimental approach. The gel mix water was exposed for 24hours to RCP-A or RCP-B at ambient and 170F temperatures. In anotherexperiment, RCP-A was allowed to cure in air at 170F and then was exposed towater for an additional 24 hours at 170F to determine whether the cured RCP-Awould affect the break properties. Table 2 shows the results of these tests. The procedures described above were repeated with a 50-lbm/1,000-gal solutionof HPG. In this case, the base gel was crosslinked with a titanate crosslinkerbefore the viscosity profile was run for 1 hour at 170F. Table 2 shows thesedata. profile was run for 1 hour at 170F. Table 2 shows these data. Included inthis data set is an experiment where dust collected from pneumatic transfer of RCP-B during a south Texas fracturing treatment was added directly to thecrosslinked fluid. We concluded that the chemical effects on base gel from RCP-A or RCP-B are minimal but that the titanate-crosslinked system viscositypotentially could be reduced by 50% under these test conditions. potentiallycould be reduced by 50% under these test conditions. SPEPE P. 343
Summary A novel oxidizing breaker system has been developed for fracturing fluids at high temperatures. Below 200°F, the system is not active, but above 200°F, the oxidizing system aggressively attacks the polysaccharide backbone of the fracturing fluids, resulting in a complete break of the crosslinked fluids. In the presence of a gel stabilizer, an intermediate, reactive oxidizing species is formed. The result of this formation is a delayed, soluble, high-temperature oxidizing system. Controlled viscosity reduction at 200 to 300°F in crosslinked gelled fluids with and without a gel stabilizer will be demonstrated. Testing included model 50 viscosity profiles, high-temperature static break tests, and conductivity testing. Results from all testing showed the effect of oxidant concentration in producing a predictable, controlled break of the thermally stabilized crosslinked systems. Data were obtained in low-pH and high-pH Zr-crosslinked fluids as well as in borate-crosslinked fluids. The delayed mechanism of the new breaker system provides fluids with excellent crosslinked viscosity properties at early times with predictable, long-term viscosity reductions. Case histories show that the breaker system can be used throughout the treatment in the pad fluid, proppant-laden fluid, and flush. This article provides data that allow significant improvements in job design. The operations engineer can obtain predictable, controlled gel degradation by using the data provided for temperature, gel type, gel stabilizers, and breaker concentration. The results are optimized treatment designs with rapid fluid recovery, improved proppant-bed conductivity, and increased well productivity. Introduction Breakers are an essential component of fracturing fluids. Ideally, a breaker should maintain high viscosity throughout the pumping of the fluid and sand. Once pumping is complete, the fluid should immediately break back to the viscosity of water. An ideal viscosity profile is shown in Fig. 1. In most cases, current technology provides a quick initial drop in viscosity followed by a slow, gradual decline in viscosity until the fluid is completely broken. Encapsulation helps achieve an improved break profile at low to moderate temperature but, above about 175°F, diffusion from the capsules becomes the determining factor because the breakers are only briefly stable at those temperatures. Improved fluids technology has provided crosslinked gels that can maintain viscosity at elevated temperatures for long periods of time.1,2 These thermally stable fluids improved overall gel viscosity and the ability of the fluid to carry proppant. However, the advancement in fluids technology to provide more stable fracturing gels limited the recovery of the fluid and ultimately the fracture conductivity. The use of breakers in high-temperature fracturing applications would provide a method by which to efficiently recover these thermally stable fluids. Even today, the need for breakers throughout an entire fracturing treatment above 200°F is not a generally accepted concept because of the lack of controllable breaker systems at these high temperatures. Oxidizing breakers, such as persulfate, are effective from about 120 to 175°F. However, these materials react too quickly at higher temperatures.3–5 The rapid oxidation causes uncontrolled breaks and premature gel degradation, which lead to the following:poor proppant transport;insufficient fluid leakoff control;limited ability of the fluid to maintain fracture geometry. Encapsulation technology can provide slow release of oxidant, providing a delay in the breaking process. Encapsulation is basically coating each particle of oxidizing breaker with paint. The coating or "capsule" of paint delays the release of breaker into the fracturing fluid. (Parker and Laramay provide details of encapsulation technology.6) However, these methods offer only limited control above 175°F especially above 200°F and when gel stabilizers are required. Enzymes are the other major class of gel breakers. Typically, the application of enzymes is limited to lower temperatures (150°F or lower) and an optimized pH range (5 to 8).4,7,8 Recent developments show that these limits can be expanded,9 but their use above 200°F has been very controversial.8–10 The use of enzymes in the higher pH borate systems is ineffective without a means to lower fluid pH.9 Encapsulation can improve the stability of enzymes for use in slightly higher pH fluid and at slightly higher temperatures.11 Enzymes and persulfates have an important role as breakers in fracturing treatments above 200°F. As the wellbore and fracture cool during a treatment, these breakers can be added to fracturing fluids. Designing fluids by temperature cooldown during the treatment allows the engineer to remain aggressive in degrading the viscous fluids, thus providing a rapid, more effective cleanup. However, miscalculation in breaker loadings or temperature profiles can be disastrous. A new, soluble oxidizing breaker system has been developed for use throughout the entire treatment-design phase in wells from 200 to 325°F. The application of this new oxidizing breaker system overcomes limitations of current breaker technologies. The breaker provides the following benefits:stability in fluids above 325°F;compatibility with gel stabilizers;ability to remain active when in contact with formation rock;controlled viscosity reduction of crosslinked fracturing fluids. In this article we will present laboratory data and field case histories on the successful use of this novel, high-temperature viscosity-controlling breaker (HT-VCB) in a variety of fracturing fluids.
Summary Gel plugs (GP's) have been used in the eastern U.S. for many years. They area versatile and simple method of temporarily plugging a well. Gel plugs areoften used to control a well while remedial workovers are performed. This paperdescribes the various types of gel plugs and their applications. Case historiesare given for gel plug applications. Introduction Operators performing workovers on gas-storage wells in the eastern regionsof the U.S. have improved operations and reduced expenses by using GP's tocontrol wells while work is in progress. A large number of the gas-storagewells were drilled in the 1950's and 1960's and have nonstandard equipment thatlimits the use of other wellcontrol methods during the initial stages ofworkover. The GP is a highly viscous fluid that can be crosslinked to form aviscous plug. GP's can be tailored to break back to a less viscous fluid forremoval, or they can be broken by acid. Using this type plug can eliminate theneed for various packers, bridge plugs, and plug can eliminate the need forvarious packers, bridge plugs, and associated surface equipment usually neededto control or "kill" a well while remedial workovers are performed. This paper describes chemistry, operating ranges (temperature), and applicationprocedures pertinent to GP's. Also presented are field case histories where GP's were successfully used to plug a well for running casing inspection logs, to plug a well to permit replacement of tubing and wellhead equipment, and tokill a well temporarily to replace an old wellhead and then place a mechanicalplug for a cement squeeze job or additional workover operations. plug for acement squeeze job or additional workover operations. Background Some eastern U.S. oil and gas wells completed in the 1950's and early 1960'sbecame unable to produce economically when their reservoir pressures anddeliverabilities diminished. In some instances, these depleted zones are beingconverted to storage wells for natural gas. However, many of the casings, tubings, and wellheads designed for the original well conditions are notsatisfactory for the application of gas storage. 1. Many of these wells wereoriginally completed with 5 1/2- or 7-in. casings for the production casing. Toprovide annular integrity in these wells today, it is usually necessary tostore and produce gas through 3 1/2-in. tubing and a packer. 2. Most of thesewells were originally penhole completions. 3. As a result of fluid depletion, many of these wells will not hold the column of fluid necessary to kill thewell during routine workovers, e.g., pulling the tubing and setting amechanical plug. When replacing the tubing, packer, and wellhead assemblybecame necessary, several alternatives were investigated. The options usuallyavailable included kill fluids (e.g., weighted brines) and temporary packerbridge plugs, but because no known packers or bridge plugs could be run inside3 1/2-in. tubing and packers or bridge plugs could be run inside 3 1/2-in. tubing and set in 5 1/2 or 7-in. casings, mechanical methods of pressureisolation were not available. Gas-storage wells have highly predictablepressure patterns; it is easy to determine the pressures necessary to kill thewells. These wells, however, can also lose large volumes of kill fluids whenthe delicate balance of reservoir pressures and hydrostatic pressure isdisrupted. Large volumes of kill fluids lost to the formation can create manyproblems in gas-storage wells, including long cleanup times, increased fluidproduction, and possible fluid introduction into an otherwise dry collectionsystem. Snubbing the tubing and packer is possible, but it is a costly and notreadily attainable packer is possible, but it is a costly and not readilyattainable service. Replacing tubing and wellhead assemblies safely andeconomically while minimizing damage to the production capabilities andgathering systems of the well requires a fluid with special properties. 1. Thefluid must be easy to apply. 2. It should not require special equipment ormaterials for mixing. 3. It should resist forces from both formation andhydrostatic pressures. pressures. 4. The fluid should work over the lowtemperature range (60 to 100 degrees F) for these particular applications. 5. It must mix in a wide variety of waters. 6. It must have predictable anddependable fluid properties. 7. The fluid should break back to a fluid verynear to the viscosity of the base mixing fluid. 8. It must leave little residueupon break to minimize formation damage. These properties were incorporatedinto a fluid that can easily be pumped as a thin fluid to the zone of interestbefore becoming thickly gelled. Once gelled, this GP protects the producingzone by minimizing fluid loss to the formation; this allows the killing ofwells for tubing or wellhead replacement and well logging, while keepingformation damage to a minimum. Several cases exist in which a zone requiredisolation and temporary GP's were applied as an efficient and economicalsolution to the problem. The chemical nature, placement technique, andapplication of the technique are described. Geology The case histories discussed in this paper are from jobs located in West Virginia, Ohio, and Indiana. The West Virginia jobs (case history Wells 1 and2) were performed in the Big Injun and Oriskany formations, which represent the Mississippian and Lower Devonian, sands of the Appalachian sedimentary basin, respectively. The Appalachian sedimentary basin covers about 175,000 sq miles, and consists of the Pennsylvanian, Mississippian, Upper and Lower Devonian, Silurian, Ordovician, and Cambrian ages. The sediments contained represent theentire Paleozoic section from Permian through Cambrian, with a thickness of30,000 ft. Permian through Cambrian, with a thickness of 30,000 ft. Sedimentaryvolume is estimated to be 500,000 cu miles. The upper portion of the Mississippian in West Virginia and eastern Kentucky is composed of fluvialsandstones that produce gas from stratigraphic traps. Underlying these classicsis the Greenbrier limestone, commonly identified by drillers as the "BigLime" in West Virginia. Stratigraphic reservoirs composed of oolitic zonesin southern West Virginia and eastern Kentucky produce gas; in central West Virginia, however, the porosity zones are composed of dolomite, sandy dolomite, and sandstone, which are called "Big Injun" or just "Injun."The Lower Devonian includes Oriskany sandstone, which produces gas with onlysmall amounts of oil and condensate. Structural traps are productive in the Overthrust Belt of eastern West Virginia and adjacent Pennsylvania. While someof these structural entrapments are partly stratigraphic, the Oriskanyproduction in the large Elk-Poca field in west-central West Virginia isentirely stratigraphic as a result of westward pinchout of the sandstone. SPEPE P. 70
fax 01-972-952-9435.References at the end of the paper. AbstractBorate-crosslinked fracturing fluids have been among the fluid choices in the early growth of the frac-and-pack treatments in the Gulf of Mexico. 1 Highly conductive fractures connecting the wellbore and formation were recognized as key to the success of frac-and-pack treatments. 2 To enhance fracture conductivity, one suggestion was minimizing polymer loading and maximizing breaker loadings to a point that does not adversely affect fluid stability during the frac-and pack-treatment. 3 All three of these elements have been combined in a new fracturing fluid system for fracturing and packing treatments. This new fluid system provides higher viscosity with lower gelling-agent concentrations than conventional, boratecrosslinked fluids. A new, non-persulfate breaker system has been developed for use with this fluid system specifically for use from 170° to 200°F.The new, optimized borate-crosslinked fluid system (OLGB), with application to 200°F, was applied to frac-and-pack treatments in the Gulf of Mexico. This paper provides laboratory data and examples discusses the field application of the new fracturing fluid system compares the new OLGB fluid system to existing conventional borate fluids discusses the newly-developed breaker system presents viscosity, fluid-loss, and conductivity data for the new system.
Summary This paper discusses low-temperature applications for an optimized low-gel borate fluid system that does not rely on a separate component to maintain system pH. This fluid system's viscosity, fluid loss, static proppant settling, and dynamic proppant transport were tested; experimental procedures and results are described. Case studies from Argentina, Ecuador, the Texas Panhandle, and Permian Basin are also included. A new, borate-crosslinked hydraulic fracturing fluid system has been developed. This new, optimized fluid system provides higher viscosity with lower gelling-agent concentrations compared to conventional, borate-crosslinked fluids. Application of the optimized low-gel borate (OLGB) fluid system at low temperatures is discussed. Viscosity, proppant transport, and fluid-loss data of the OLGB fluid system are compared to conventional, borate-crosslinked fracturing fluids. Treatment designs are also presented. Introduction The use of borate-crosslinked, hydraulic fracturing fluids has become routine in the oilfield-service industry. Although these fluids are successfully used on a daily basis, returned fluids can recrosslink at the surface. At low temperatures, high concentrations of oxidizing breakers are required for a complete break. Generally, a catalyst must be used to obtain the necessary break profile. Enzyme breakers can be used in conventional, borate-crosslinked fluids at low temperatures, but these fluids require an additive (acid) to lower the fluids' pH before the enzyme breakers can function properly.1 If such acids are not delayed or modified to be controlled-release, fluid stability is compromised. The pH of a borate-crosslinked fracturing fluid is critical to its successful use.2 Adjusting the pH of the fracturing fluid to maintain the correct pH value is often difficult. One way to overcome these difficulties is to adjust the pH of the fracturing fluid using a buffering agent, instead of a base such as sodium hydroxide. Buffering agents resist changes in fluid pH. The optimized low-gel borate (OLGB) fluid system combines a buffer with a crosslinker into a single component to adjust fluid pH to an optimum value for crosslinking, consequently allowing for simplicity and reliability in field applications. To assist in resolving the difficulties of breaking borate-crosslinked fluids in low-temperature applications and maintaining proper fluid pH, the OLGB fluid system has been developed. In addition to reducing the aforementioned difficulties, the OLGB fluid system allows a lower gel concentration to be used compared to conventional borate-crosslinked fluid systems. Discussion The OLGB fluid system consists of two primary components: a guar gelling agent and a crosslinking agent. The difference between the OLGB fluid system and most crosslinked fluid systems is that a third component is normally necessary to adjust the pH of most borate-crosslinked fluid systems. System pH is important to all crosslinked fracturing fluids, particularly in borate-crosslinked fluids. The use of a single component buffer/crosslinker additive has been important to the successful application of OLGB in fracturing applications. The inability to adjust and maintain the proper fluid-system pH can result in job failures. The importance of maintaining the correct fluid pH for a borate fluid system has been discussed by Harris.2 The relationship of temperature, system pH, gelling agent concentration, and crosslinker concentration is critical to the stability and ultimate viscosity of the fluid. This complex relationship is true whether the fluid is used in high- or low-temperature applications. This paper discusses low-temperature applications involving a borate-crosslinked fluid system that does not rely on a separate component to maintain system pH. In this system, the crosslinker and buffer are combined into a single component. The concentrations of gelling agents for fracturing treatments have decreased over the past several years. Lower amounts of gelling agents provide better and more complete breaks in a fracture. Several papers have discussed the merits and applications of reduced gel-concentration fluid systems.1,3,4 In this paper, laboratory test results and field applications that use 15 to 25 lb/Mgal of guar concentrations will be discussed. These lower gel concentrations are for fracturing applications at 70 to 140°F. It is generally believed that lower gel concentrations increase regained conductivity of the resulting proppant pack, which can result in higher production compared to treatments that use high concentrations of gelling agent. Many parameters are used to describe and characterize a hydraulic fracturing fluid. Some of these parameters include rheological characteristics, such as viscosity. Other parameters include dynamic fluid-loss behavior and proppant transport characteristics of the fluid. These parameters can be tested in the laboratory. The parameters provided by these test results can be used in fracture-design simulators. One of the current methods of studying the rheology or flow characteristics of fracturing fluids is to use a viscometer with a concentric bob-and-sleeve configuration, such as a Fann Model 50 viscometer. Various bob-and-sleeve configurations and test methods have been described in the literature.5 The use of a Fann Model 50 viscometer has been the conventional technique to measure the flow characteristics of a crosslinked fracturing fluid. The apparatus can be used daily in a laboratory setting or modified for use in a mobile field laboratory.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
customersupport@researchsolutions.com
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.