CSUG/SPE 149221 Restimulation of Wells using Biodegradable Particulates as Temporary Diverting Agents Dave Allison, Shawn Curry, and Brad Todd, SPE, Halliburton Copyright 2011, Society of Petroleum Engineers This paper was prepared for presentation at the Canadian Unconventional Resources Conference held in Calgary, Alberta, Canada, 1517 November 2011. This paper was selected for presentation by a CSUG/SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract During the life of producing wells, there comes a time when the well approaches its economic viability as a producing well. If the reservoir potential is sufficient to support the expenditure, many wells are candidates for recompletion, reperforation, or restimulation. This type of focus on the Barnett shale began in the late 1990s. Drilling activity dramatically increased during the ensuing years and now there are more than 14,000 wells that have been drilled, most of which are producing wells. A lot of these wells are potential candidates for restimulation (refrac) because their production rates have declined but still have significant reservoir potential. The completion techniques deployed in the Barnett evolved over time to where many wells havedozensofperforationclustersandhundredsofindividualperforations.Generally,refracsareineffectualunlessthe perforationscanbetemporarilyisolatedsothattheenergyofthesubsequentfracturingtreatmentcanbefocusedon individual portions of the reservoir. Additionally,refrac candidate wells often contain challenging wellbore environments that further complicate the ability to successfully refrac the wells. The use of biodegradable particulates to facilitate the temporary diversion and concentration of frac energy has increased the success of restimulation. This paper discusses the recent development of techniques and materials being used in refracturing operations. Included are discussions of laboratory results of new and novel materials, along with case histories of refrac wells demonstrating application of such materials and techniques. Introduction At some point during the life of a producing well that has been stimulated,it will be evaluated for a restimulation. Because a majorityofwellsinNorthAmericarequireanoriginalfracturingstimulationtreatmenttobeaneconomicsuccess,the necessary restimulation is a secondary (or tertiary) fracturing treatment commonly known as a refrac. The initial investment to drill, complete, and hook up a well to a sales line is significant, and logic dictates that a proper evaluation should be undertaken to determine if a refrac is plausible on candidate wells. Refracs are enticing compared to the outlay in capital and the process to drill a replacement (new) well. The refrac greatly reduces the time it takes for production flow to increase, thus having a significant impact on the net present-value calculations. It is not unusual for a refrac to be an order of magnitude less expensive than the alternative of drilling and completing a new well.The discussion of how, why, and when to refrac vertical well completions has been ongoing for decades (Coulter and Menzie 1973) and has been reasonably well-documented for vertical,biwing fractures.Recently, the industry has focused on burgeoning shale plays,such as the Barnett shale. The origins of Barnett production can be traced back to 1979, but many do not consider the true development of this resource to have begun until the early 2000s (Grieseret al. 2006). The evolving completion techniques associated with horizontal drilling, multiple original fracturing treatments, and perforating schemes that made the Barnett such a prolific producing reservoir have dictated an evolution in the refrac process. Operators have evolved drilling and completion processes from a traditional biwing-fracture approach to the manufacturing-like process of perforate, stimulate, and isolate (PSI). Each well was a real-time laboratory where new techniques, process improvements, and material progression took place. Feedback on the success of the improvement was determined by initial and sustained production results balanced against the cost to accomplish the process. Possibly all of these wells in the evolution can be considered candidates for refracs once they reach threshold production criteria, as determined by the operator. Even wells completed with the PSI process may be candidates, should their production fall below the operators threshold criteria. (See Candidate Selectionsection for additional discussion on key characteristics that can guide candidate-selection criteria.) To properly refrac a well, timely isolation of certain existing perforations is critical. The isolation is used to restrict or deny certain perforations from receiving the subsequent fracturing treatment. The isolation approach can range from using a 2CSUG/SPE 149221 rig to set physical barriers that redirect the fluid flow to the use of specialized particulates placed in the flow stream to divert the treatment. These specialized particles integrated into the flow stream are commonly called diverting agents, diverting materials, or diverters, for short. Diverters, if used effectively, can eliminate the need for a rig to provide physical barriers, thus improving the economics of the workover operation. Many materials have been used overtime as particulate diverting agents.Theyhaveexperiencedvaryinglevelsofsuccess.Rocksaltandperforationballsealersaretwoofthemore commonly used particulates.Many believe that diverter technology has peaked and the currently available materials performance is reasonable for the cost.However,thegenesisofthecurrentstate-of-the-artdivertershasitsoriginsinverticalwells,andsomecantrace theirroots to acid stimulations.A laboratory study was undertaken to determine if the status quo was good enough.When challenged to create the next generation of particulate diverters for fracturing, the investigation teams efforts had to meet the following criteria: 1.New level of environmental products. 2.Robust enough to survive the placement process. 3.Does not require a secondary treatment to be removed (temporary and self-removing). 4.Self-assembling, temporary blockage inunknown geometries or borehole configurations. 5.Cost-effective. 6.Seamless integration into the pumping process. Table 1 provides insight to certain common diverters and how they compare to the new criteria. Additionally, the next-generation diverter resulting from recent research and development is included for comparison. TABLE 1OVERVIEW OF COMMON DIVERTER MATERIALS Criteria11,2,61,2,6234566 Product type Environmental Profile Compatible with Fracturing Chemicals Compatible with Production Chemicals Temperature Limits (F) Self-Removing Self-Assembling Usage Cost Specialized Surface Equipment Specialized Carrier Fluid Rock saltLow tomedMostMost No Nolow-salinity removal fluid YesMedium Storage tanks Saturated brine Perf-ball sealersLowYesYes350 Nomust flowback NoLow Launcher and catcher No Degradable perf-ball sealers LowestYesYes250YesNoLowLauncherNo 100-Mesh sandLowYesYesNoNoNoLowNoNo Benzoic acid flakes MedSomeSome250YesYesMediumNoNo Biodegradable particulates LowestYesYes320YesYesLowNoNo Laboratory Investigation The focus of laboratory development was to discover solid particles that could create a temporary blockage function in the near-wellbore region, which includes the perforation, perforation tunnels, or early part of an earlier hydraulic fracture, and then subsequently disappear without an external catalyst.When combined with the functional criteria, the laboratory team had guidelines for their investigation. NewLevelofEnvironmentalProducts.Theinvestigationfocusedonmaterialsmainlyfromthefoodindustryand degradable packaging. Based on the current climate of the perception that fracturing fluid components can potentially be in contact with water-bearing aquifers, it was prudent to start with materials associated with food consumption. Unfortunately, the types of materials made to degrade in the human body and in landfills are functional at temperatures too low for broad-based application in the elevated temperatures of the reservoirs. Ultimately, after reviewing multiple candidate materials, a biodegradable polymer became the focus of attention. Robust Enough to Survive the Placement Process. It was important that shelf life of the candidate particulate be sufficient to meet worldwide operations in the long run, but primarily be able to cope with localized north Texas temperatures, ranging fromsub-freezingwintertemperatureto+100Fsummertemperature.Anothershelf-lifeconcernwascompaction,ifthe material was to remain in the warehouse for an extended period of time. A number of candidates passed the warehouse CSUG/SPE 1492213 requirements, including the biodegradable polymer. The candidate materials thatpassed this criterion were received directly from manufacturing and remained free flowing and non-clumping, even after month-long periods of storage. Another key hurdle was to find the correct particle size, with the goal of determining the largest-size particle practical to passthroughthe fluidend ofthefracturing pumpunit. Thelarger particleswould providethesubstructure orthemain pluggingcomponentforthedivertersystem.Evaluationoffluidendcomponents(Fig.1)andthefluidstreameffluent providedstrongevidencethatanumberofcandidatematerialscouldbedeliveredtotheperforationsunscathed.Fig.1 providesevidencethattheultimatelyselectedparticlecanwithstandthetransportation,mixing,blendingandpumping process while remaining intact. The evaluation concluded that between 0.10 and 0.15 in. was the largest particle that should be used because anything larger would bridge on the valve openings or embed in the valve insert. It should be noted that a spinoff project to improve the material properties of the frac-valve insert was undertaken. The resulting new composition has increased insert durability and longevity, all the while reducing embedment. Fig. 1Afrac-valve insert with intact di verting materials imbedded in the element. DoesNotRequireaSecondaryTreatmenttobeRemoved(TemporaryandSelf-Removing).Thiscriterionbeganto eliminate a number of the potential candidates. Certain interesting materials required a catalyst or an overflush stage for removal. This extra operation step, although doable, brings additional operational complexity, cost, and risk. Other potential candidates degraded too rapidly. The emerging leading candidate diverting agent is self-catalyzing once having entered the reservoir region. Depending on bottomhole temperature, the material will degrade in 12 hours or up to a few weeks. However, there is no risk of longer-term formation blockage or damage because the degradation process cannot be halted. No subsequent cleanup solutions were needed to remove the material because all the requirements for degradation exist in the downhole environment. An important benefit of using degradable particles is that,because the size of the particle is reduced during degradation, the diverter will permitthe well to flow long before total chemical degradation is achieved. The rate at which physical particle-size reduction takes place is a function of surface area. The smallest particles reduce in size proportionally faster. Once reduction has changed the particle size by 10 to15%, the particles begin to dislodge, permitting the return flow of liquids and gas in the production direction. Wholesale dislodgement did not occur in the laboratory evaluation because the larger particles degradation took longer until they could dislodge. Fig. 2 depicts the nature of the cleanup time at 160F. In the section designated with the DL, the particulate would be subject to degradation and dislodgment. In the SF region, a larger portion of the particulate has converted to liquid, requiring about 18 to 20 days for the diverter system to be totally solids free. The particulate required three to four times longer to have total degradation in a static laboratory environment. Fig.3illustratesthedegradationratesasafunctionoftemperatureat220F.Thedegradationstagesarethesame regardless of the temperature, however the duration of the degradation stage is impacted by the temperature environment. Eventually,thematerialiscompletelychemicallyconvertedintoasmallwater-solublemolecule.Atthispointinthe laboratory, no residue or evidence of damage was observed in core flow tests. Another important consideration of the degradation process was the impact on the use of production chemicals and the recycling/reuse of flowback and produced waters. As noted in Figs.1 and 2, degradation byproducts will be generated for a number of days based on exposure temperature. The combination of large volumes of flowback water and the relatively small amounts of diverter with its slow release of degradation byproduct make the detection of byproduct virtually impossible. For the160Fconditions,anaggressiveflowbackschedulehasthepotentialforsolids-free,water-insolubleliquidtobe 4CSUG/SPE 149221 present,but dilution bytheflowback waterfacilitatesmakingthe presenceofwater-insolublebyproductinconsequential. Therefore, the use of typical production chemicals,such as corrosion inhibitors, scale inhibitors, and oxygen scavengers, is not compromised. If the well remains shut-in (i.e., waiting on production tubing to be run), then the degradation byproducts will have been completely consumed. The degradation products, even in their strongest form (1 lbmof solid per 1 galof liquid), have not been found to interfere with water-recycling techniques,such aselectric coagulation, reverse osmosis, or forward osmosis. Typically, these water-processing techniques take place long after the degradation is complete. Additionally, the byproducts are non-accumulating with multiple uses of the same treating fluid. Fig. 2Typical degradation of candidate material at 160F (tested at 1-lbm gal). Fig. 3Typical degradation of candidate material at 220F (tested at 1-lbm gal). Self-AssemblingTemporaryBlockageinUnknownGeometriesorBoreholeConfigurations.Thereareanumberof possible downhole configurations, mostly unknown, in which the material will need to perform. In refracs, considerable CSUG/SPE 1492215 erosion will likely have taken place in the perforations and in the near-wellbore region from possibly hundreds of thousands of pounds of proppant having been pumped duringthe original fracturing treatment. The original circular geometry of the perforationscouldhave significantly changed because of the erosive nature of the proppant. (See Figs.4and 5 for before and after proppant-erosion test results). Also, within the fracture beyond the casing, it is possible that the proppant could have settled below the perforation and the situation is an open fracture instead of a proppant-filled fracture (Fig. 6). Fig. 4Test specimen before erosion test. Note various orifice geometries. Fig. 5Test specimen after 250,000 lbm of sand pumped through it.Note dramatic erosion of orifices. Fig. 6Core specimen with varying amounts of proppant fill. Self-assembling particles must be able to adjustto unknown downhole conditions. Some operators tail-in with 16/30-meshproppant to maximize near-wellbore conductivity, and the fracture is typically at least three grain sizes wide or more. These fractures, when propped, are in the 0.15-in. wide range. This is approaching the range of the maximum particle that can effectively pass through high-pressure pumping equipment. A particle that is 0.10 to 0.15-in. in diameter, which can go through pumping equipment, could bridge on a fracture that is about 0.25 to 0.4-in. wide. However,particlesofthissizealonewouldnotbeveryeffectiveshutoffagents,astheirpermeabilitywouldbeinthe hundreds of darciesrange. The larger particles must be supplemented with smaller particles that can bridge in the pore throats of the larger particles. Using two different particle sizes is often referred to as bimodal. With rigid particles,such as calcium carbonate or sand, it becomes necessary to continue to add smaller and smaller particles, down to a few microns in size, until such time that the desired level of plugging can be achieved. This continuing of adding smaller and smaller particles was not necessary with the candidate material. The material had the very desirable property of being rigid at ambient conditions and yet developed a level of pliability once exposed to downhole conditions. Upon using the particles pliable characteristic, a very efficient temporary plugging system was achieved by combining just two sizes of particles. With pliable particles, once a differential pressure is established across a particle pack, the permeability of the pack is reduced, further increasing the pressure differential (assuming constant rate). The highest pressure differential observed in the laboratorywaslimitedto10,000psi.Evenataconstantpressuredifferential,theparticleswillcontinuetopackanda reduction in fluid entry with time will be seen. 6CSUG/SPE 149221 CostEffective.Thebimodalmaterialisdesignedtobuildatemporarybridgeinthenear-wellboreenvironment.Itis expected that the bridging will take place in the perforation, perforation tunnel, and/or early portion of the fracture. The calculatedvolumesindicateatemporarypluggingactioncouldbecreatedwitharangeof5to15lbmperperforation. Laboratorytestingindicated thatacolumnlength of12 in.could withstanda pressure differential of10,000psi.Inthe Barnett shale, where the stress contrast is low, only a few hundred psi would be required to block one flow path and open a new one. Therefore, actual job volumes could be in the range of 300 to 1,000 lbm, depending on how adversarial the well conditions are, the number of open perforations, and the necessary pressure differential required to redirect the fracturing energy. The addition of the necessary volume of temporary diverting agent for each fracturing stage would only add minor incremental cost compared tothe refrac treatment itself, and yet be comparable to the system cost of using rock salt. Seamless Integration into the Pumping Process. The degradable diverting agent has a specific gravity (SG) of about 1.25. With this low SG, it can be carried in water, slightly viscosified fluids, or crosslinked fluid systems.In the time frame of pumpingatreatment,thematerialdoesnothaveanyeffectonfracturingfluids,eveninbufferedsystems.These characteristicspermitthedivertingmaterialto beadded at anytimeduringthetreatment.Incontrast,rock-saltdiverting materials require special salt-saturated carrier fluid and the infrastructure to support theirusage. No additional mixing considerations were necessary. The particles can be metered through standard dry-additive systems or through the sand screws on a blender (Fig. 7). Fig. 7Standard dry-additi ve feeder used to introduce particulate di verters into the flow stream. Candidate-Selection Process With the Ft. Worth basin being the one of the first shale plays to draw the interest of the industry, it is understandable for theretobeanevolutionofthedrillingandcompletiontechniques.Inretrospect,itiseasytounderstandthattheearly attempts at stimulating the Barnett shale would incorporate the successful techniques used in traditional formations and tight-gas sands to generate biwing fractures. Although the early approaches were lackluster, each subsequent well was used as a real-timelaboratorytoevolvethetechniquesthatultimatelyledtothesuccessfulexploitationoftheBarnettformation. Todays state-of-the-art completion techniquesvary from operator to operator; however,they are significantly different from the earliest attempts. Wells that were completed with techniques different than todays techniques become prime candidates for refracturing. CSUG/SPE 1492217 ProductionEven if a well has all of the physical characteristics to be considered a prime candidate for restimulation, a critical hurdle is economic assessment of the well and remaining gas resource. The question is if the well is likely to produce enough to pay for the rig operations, perforating, restimulation, and any necessary well maintenance within an acceptable time frame to be economic. Beyond just recovering the cost of the workover and restimulation, another question is if thewellwill produce in suchamannertomeetandexceedreturn-on-investment(ROI)criteria.Onemustreviewoffsetwellsandothersinthe production unit for viability (Valk 2009). Another question to ask is if there are formation hazards that increase the risk. For example, if the well has communicated with the Ellenberger formation and is producing water, then the well might not make the short list for restimulation. Fluid SystemsThe treating-fluid systems (TFS) used in the earliest days of development were a direct transfer from the classical biwing fracturing applications. To carry the necessary proppant, the TFS needed significant viscosity through the use of linear gel with high polymer loadings or with crosslinked gel systems. A number of factors, both technical and financial, contributed to the move to lower-polymer brines, often called slick water or water-fracs.Concerns over polymer damage to nanodarcy permeability. Increased fluid-flow rates could be used to carry the proppant into the formation. Con-current revival of the slick-water systems being used in the Travis Peak formation. Concerns of fracture closure and proppantflowback. The cost of the gelling agents made TFS style of treatments uneconomic when fluid volumes doubled and tripled and the number of frac stages started to increase. For the Barnett shale, wells treated with fluid systems made from high gel loadings and/or crosslinked gelled fluids are prime candidates for refracturing. A typical fluid for refracs in the Barnett shale would be a lower-polymer-loading slick water. Fluid Volumes The volume of fracturing fluid used to successfully stimulate the Barnett reservoir continued to grow for several years. The earliest wells used volumes that were a direct transfer from the successful designs in vertical, tight-gas wells. Because the earlyBarnettwellswerevertical,thistransferseemedmostlogical.Bythemid-2000s,horizontalwellswithmultiple fracturing stages were becoming the norm. The volumes began approaching 3,000 gal per lateral ft compared to the 800 to 1,200 gal/ft of the early wells. Often, the treating fluid volume could not be tied to the ideal treatment volume, but to frac-tank availability and wellsite location size. With the advent of centralized water processing centers that would recycle and reuse both flowback and produced waters, the treating fluid volumeswere consistently in larger increments (gal/lateral ft) per well. On average, the volumes have tended to settle into a range of 1500 to 2,500 gal/lateral ft. This range of fluid volumes has resulted from the influences of stimulation costs, water-management logistics, and ultimately production results. Whendesigningvolumesforrefracturingapplications,onemustrememberthattheentirelateralissubjecttothe treatment rather than the discrete intervals of the original completion unless some type of tubing is used, increasing costs and lowering pump rates. The volumes recently have ranged in the 1,200 to 1,500 gal/lateral foot for a refrac. Fluid-Loss Control Todaysstate-of-the-arttreatingsystemfortheBarnettdoesnotrequirefluid-lossleak-offcontrol.Thenanodarcy permeability of the shale does not accept fluid into its matrix in a manner that impacts a fracturing treatment. If traditional polymeric materials were used to control spurt and leakoffduring a treatment, then the well may be considered a candidate for restimulation.In most shale completions, it is advantageous to connect the man-made fracture to the existing natural fracture network. The Barnett has the challenge of large natural structures,such as karsts, that can drain away frac energy. If the original well completion encountered karsts and no minimizing actions were taken, then a restimulation with deep reservoir-diversion techniques might be in order. Proppant The proppant volumes associated with general/historicalbiwing fractures often centered on a design criterion of averaging 1-2 lbm/ft2 throughout the fracture. For biwing fractures, the higher the deposited proppantconcentration (i.e.,lbm/ft2), the higher the well productivity. Often, larger-diameter proppants at high concentrations (16/40-meshup to 10 lbm/gal) were used in the final stages of a treatment to maximize the conductivity in the near-wellbore region. Early attempts to use conventional wisdom for proppant concentrations in the Barnett failed to achieve the desired goal. It was ultimately determined that the inability to create fracture width and the twisting, turning nature of the complex fractures would not permit the use of large proppant sizes or high concentrations of proppant. Therefore, the industry migrated away from viscous gelled fluids and to smaller proppants (100-mesh and 40/70-mesh) at much lower concentrations (0.25 to 1 8CSUG/SPE 149221 lbm/gal).Itseemsapparentthatmanyofthefractureswithinthenewlycreatednetworkmustcontributetoproduction without being truly propped open by the proppant, at least in the far-field parts of the fracture system. For refracturing applications, proppant volumes have often ranged from 1,500 to 2,000 lbmper lateral foot. Pump Rates Thefluid-pumpingratescontinuedtoriseasthecompletionprocessmatureduntilbeinglimitedbytubularpressure constraints. High flow rates through an individual perforation can lend to the shattering effect, thus exposing more surface areaandmoreproduction.Whencombinedwithlargenumbersofperforations,fluid-pumpingrateshaveexceeded150 bbl/min. Using the limited-entry perforating technique to try and distribute the fluid to all perforations has proven to be problematic, especially when perforations are spaced out evenly across long intervals (i.e., 1 shot per 10 ft over 250 ft of lateral). Most operators now consider clusters or groups of perforations in regular intervals to be a preferred method (i.e., 2 spf over 4 ftspaced every 250 ft). The high flow rates appear to be needed to propagate the desired fracture network. As more fractures open up to create the desired complexity, fluid must be available to flow in and propagate the new fracture.If the original stimulation treatment was performed with low pump rates (less than 50 bbl/min) and/or a significant amount of open perforations were treated in one stage, then it is unlikely that the desired fracture network complexity was achieved. This can be a key indicator that the well should be considered as a refracture stimulation candidate. Additionally, the higher flow rates are required to transport the proppant in slick-water fluid systems.Pumping rates for refracture stimulation trend in the 80- to 110-bbl/min range. Other factors that can impact the pump rate on refracs include but are not limited to Casing integrity Casing repairs,such as a casing patch;this would reduce the ID and pressure rating of the casing Wellhead integrity Location size Water availability Perforations Uniform-PerforatingScheme.Forperforationspacingthatisevenlydistributedalongthe wellbore,thereissignificant opportunity to restimulate in areas where low production has occurred. It is most likely that many perforations were not fully stimulated. As most treatments rely on a limited-entry treating technique to redirect fracturing fluids, too many perforations reduce the effectiveness of the limited-entry technique. Production logging and spinner surveys can help identify poorly producing wellbore segments. The existing perforations can be restimulated as is; however, most operators will add new perforations based on Gaining more access to sweet spots Assumptions that old perforations are damaged (i.e., from scale buildup) Avoiding formation hazards Typically, the new perforations are added in clusters. Typical characteristics of the perforation clusters include 4 to 6 spf 0.3 to 0.5 dia 2- to 4-ft length Perforation-ClusterScheme.Withwellsthatwereoriginallyperforatedwithaclusterscheme,itmightbepossibleto reperforate between clusters and tap into more reserves. The nanodarcy permeability of the Barnett shale does not facilitate the gas moving great distances to enter a productive fracture.When adding perforations for a refracture stimulation in a well that was originally perforated in clusters, many operators will add new perforations halfway between existing clusters. Typical characteristics of the perforation clusters include 4 to 6 spf 0.3 to 0.5 dia 2- to 4-ft length The use of self-degrading particulates as temporary perforation-blocking agents can permit successful stimulation of old perforations and/or new perforations. Case Histories There have been more than 30 successful applications of degradable particulate diversion in the Barnett shale, with a majority of those being refracs. Presented next are two of the refrac wells. The success of the refracs has given operators confidence to usetemporarydivertingmaterialsinavarietyofscenarios,includingnewandopenholecompletions, CSUG/SPE 1492219 uncementedrecompletions, casing-integrity issues, horizontal and vertical refrac treatmentsapplied to regain circulation in millouts, and acid treatments. WellA.The first case study is a horizontal well with a cemented lateral approximately 1,700-ft long in the Barnett shale located in Wise County, Texas.The well was drilled in the south-east direction perpendicular to the maximum horizontal stress to facilitate transverse fractures and a complex fracture network.The well was completed with 5.5-in.17-lbf/ft N-80 casing.The original stimulation treatment was pumped in mid-2004, followed by a refracturing treatment pumped just six years later in late 2010.Before the refracturing treatment, new perforations were added in five separate clusters to promote betterlateralcoveragethroughtighterclusterspacing.Thenewparticulatedivertersdiscussedabovewereseamlessly incorporated in the refrac design to provide better lateral coverage and increase stimulation effectiveness.The refrac treatment was pumped continuously in fourparts, each separated by diversion sequences(Fig. 8). Fig. 8Treatment plot for Well A with treatment numbers and di version sequences highlighted. Pressure increases were observed during each diversion sequence, and each treatment had a higher wellhead-treating pressure during the pad stage compared to the end of the previous treatment, providing positive indication that diversion had taken place.At the end of the first treatment, the surface-treating pressure was approximately 5,334 psi at 90 bbl/min, the diversionsequencewasplaced,andapressureincreaseofapproximately500psiwasobserved.Asmallacidstagewas pumped to reduce perforation friction in the newly opened perforations before proceeding to the pad stage of Treatment 2, which began treating at approximately 6,000 psi at 65 bbl/min.Acid was pumped into the perforations at approximately 14:30 (Fig. 8) and led to a 550-psi pressure drop, indicating stimulation of different perforations and successful diversion.The initial pressuredifferentialbetweenTreatment1and2wasgreaterthan666psi,providingasecondindicationofsuccessful diversion in the lateral.As fracturing sand was being placed in the second treatment, pressure gradually decreased as the newlyopenedperforationclusterswereeroded,atrend thatistypicalinBarnettshalecompletionsandevident ineach treatment of Well A. On completion ofTreatment 2, pressure was observed to be 4,782 psi at 90 bbl/min,and another diversion sequence was placed before beginning Treatment 3.A pressure increase of approximately 1,250 psi was observed during this diversion sequence.Pressure was observed to be 5,610 psi at 86 bbl/minduring the pad stage of Treatment 3, resulting in an 828-psi differential between the end of Treatment 2 and the pad stage of Treatment 3, once again providing positive indication of treatment diversion.Treatment 3 was placed as designed, and pressure was observed to be 4,355 psi at 90 bbl/minat the end of the stage. The thirdand final diversion sequence was then placed with a pressure increase of approximately 1,200 psi.Wellhead-treating pressure was approximately 5,176 psi at 77 bbl/minduringthe pad stage of Treatment 4, resulting in more than800-psi pressure differential between Treatments 3 and 4, once again indicating successful diversion and stimulation of a previously untreated portion of the lateral.The pressure responses observed on the diverter sequences and between the start and end of eachtreatmentaresummarizedinTable2,alongwiththetreatment-summarygraphinFig.8.Thejobwaspumpedto completionasdesignedandplacedapproximately700,000galofslickwaterand268,000lbmofsand.Followingthe refracturing treatment, a plug and guns were pumped down to isolate the refractured portion of the lateral and a small heel stage was also perforated and fractured. 10CSUG/SPE 149221 TABLE 2TREATMENT COMPARISON WELL A Well APressure ComparisonWell AAverage Rate and Pressure Diversion Sequence Diverter Pressure Response (psi) Differential Between Treatments (psi) Treatment Average Pressure (psi) Average Rate (bbl/min) 150066615,29289.8 21,25082825,28288.5 31,20082135,39189.3 45,56678.5 WellB.The second case study is a cemented, vertical well with approximately 350-ft gross pay in the upper and lower Barnett shale located in Tarrant County, Texas.The well was completed with 5.5-in.17-lbf/ft N-80 casing and was stimulated in mid-2003. It was then refractured in mid-2010, approximately sevenyears later.In both cases, the upper and lower Barnett weretreated.Beforetherefracturingtreatment,40newperforationswereaddedinthetopsectionofthelowerBarnett, bringingthetotalnumberofperforationsto240.Becauseofthelargenumberofperforationsintheverticalsection, particulate diverter was incorporated into the treatment design to improve stimulation effectiveness and distribution. The refrac treatment was pumped continuously in threeparts,with each treatment separated by diversion sequences. Fig. 9Treatment Plot for Well B with treatment numbers and di version sequences highlighted. TABLE 3TREATMENT COMPARISON WELL B Well APressure ComparisonWell BAverage Rate and Pressure Diversion Sequence Fluid-Loss Material Pressure Response (psi) Differential Between Treatments (psi) Treatment Average Pressure (psi) Average Rate (bbl/min) 190030615,47089.8 255170823,92896.6 34,01895.8 Results Both wells showed a significant production increase, with Well A peaking at 23,813 Mcf/month and Well B peaking at 18,061 Mcf/month (Fig.10). The successful application of diverters provided production increases that reached peak daily productionratesof55and70%oftheoriginalIPs,respectively.Theproductionratesobservedaftertherefracare comparable to the rates observed after the first few months of production from the initial completions. CSUG/SPE 14922111 Fig. 10Monthly production results. References Coulter,C.R.andMenzie,D.E.1973.TheDesignofRefracTreatmentsforRestimulationofSubsurfaceFormations.PaperSPE4400 presented at the SPE Rocky Mountain Regional Meeting, Casper, Wyoming,USA,1516 May.doi: 10.2118/4400-MS. Grieser, B, Shelley, B,J ohson, B.J ., Fielder, E.O.,Heinze, J.R., andWerline, J .R. 2006.Data Analysis of Barnett Shale Completions.Paper SPE 100674 presented at the SPE Annual Technical Conference and Exposition, San Antonio, Texas, USA, 2427 September.doi: 10.2118/100674-MS. Valk, P. 2009. Assigning Value to Stimulation in the Barnett Shale: A Simultaneous Analysis of 7000 Production Histories and Well Completion Records. Paper SPE 119369 presented at the SPE Hydraulic Fracturing Technology Conference, The Woodlands, Texas, USA, 1921 J anuary.doi: 10.2118/119369-MS.