TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractEffective fracture length is the portion of the propped fracture that cleans up after hydraulic fracturing procedure and contributes to well productivity. Studies indicate that this effective length is often less than 10% of the total propped fracture length. A large portion of our fracture stimulation dollars are wasted! This paper presents a comparative well study performed in the Cement field in south central Oklahoma. Stimulation of the Springer Sands using hydraulic fracturing with conventional low polymer fluids was compared with the use of low molecular weight polymer fracturing fluid. The depth of the three Springer Sands (Cunningham, Britt, and Boatwright) ranges from 12,500 feet to 15,500 feet and have an average permeability range of 0.1 to 5.0 md. This evaluation includes several components.Well production history matching and pressure analyses are used to determine effective fracture length. Results of these analyses are compared with calculated values based on laboratory generated cleanup data for the two fluid systems. Flowback rate, pressure, accumulated volume, viscosity, and polymer content were collected following the fracture stimulation treatments.The fluid systems compared in this study are a conventional low polymer system with gel breakers and a new, low molecular weight polymer system that requires no breakers. Both fluids use borate cross-linking chemistry. The low molecular weight fluid system creates transient, high molecular weight polymer chains at higher pH conditions. After exposure to the formation minerals, the pH drops and it reverts to a clean, nearly Newtonian, low viscosity fluid that causes little conductivity damage.The results of this study show that the use of low molecular weight fracturing fluid provides significant improvements in the effective fracture length over conventional low polymer fracturing fluids. Simple engineering tools have also been developed to evaluate both fluid and proppant selection and job design to achieve improved well performance. It also demonstrated that improved recovery of the fracturing fluid can be achieved at excellent rates without the use of conventional gel breakers.

Water-based polymers, guar, and derivatized guar have been the mainstay of fracturing fluids for many years because of their low cost and highly controllable fluid rheology. However, these materials can cause significant fracture conductivity impairment leading to poorer than expected well productivity after fracture stimulation. Considerable effort has been applied to reduce the damage caused by these fluids, including:applying special purification chemical processes,improving polymer breakers,formulating fluids with less polymer, andimproving fluid recovery during well flowback after treatment.Each of these processes has incrementally improved conductivity; however, one-half or more of the native conductivity is lost to frac fluid damage derived from the use of guar-based polymers. Recent application of no polymer, surfactant-based viscoelastic frac fluid technology has demonstrated the value of non conductivity damaging fluids by generating high well productivity with small fracture stimulation treatments. While these fluids are generally nondamaging, they are limited in applicability because of high fluid loss and their inability to generate extended fractures at a reasonable cost. This paper presents the laboratory development and initial field testing of a new, viscoelastic fluid technology that produces highly productive fractures with low conductivity damage while providing excellent fluid-loss control and high proppant-transport properties to generate design fracture geometry. This fluid has little sensitivity to temperature and salinity, and rheology is easily controlled. The fluid system combines the best properties of polymer-based fluid technology with those of surfactant-based technology. Fracture Fluid History Hydraulic fracturing as a well-stimulation method began in 1948, with crude oil as the fracturing fluid. Fracturing evolved rapidly and the use of surfactant-gelled hydrocarbons became common. In an effort to reduce loss of the fracturing fluid to the formation and generate larger dimension fractures, surfactantstabilized water/oil emulsion fluids were developed. The use of water-soluble polymers used to thicken these fluids began in the late 1950s. Polymer-thickened, water-based fluids were first used in the early 1960s, and by the late 1960s, guar gum had become the polymer of choice because of its lower cost and viscoelastic behavior. The early 1970's saw significant growth in guar-based fracturing fluid technology. Controlled crosslinking reactions were evoked to provide the rheological properties required to provide low fluid loss to the formation and adequate elasticity to transport proppant into the fracture for these extensive fractures. While these fluids were robust and large fractures could be achieved, the economic performance did not justify the cost. It became generally recognized that crosslinked guar polymer also caused a dramatic loss in fracture conductivity. Laboratory measurements indicated that often less than 10% of the native fracture conductivity was achieved. Most of the remaining fracturing-fluid history centers on reducing the conductivity damage that guar-based polymers cause. Derivatized guar-based polymers were developed to provide cleaner fluids that have more control in crosslinking reactions. The amount of polymer required to accomplish fracture stimulation was reduced. Foaming these fluids with nitrogen or carbon dioxide reduced the amount of polymer being used while providing the fluid rheology required for handling proppant. Computer-controlled blending equipment made it possible to make ultra-low polymer gels that provided "just enough" rheology. Despite these innovations, the typical fracture conductivity achieved was typically less than 30% of the expected conductivity with these fluids. Significant improvements in gel breaking and polymer degradation technology have recently emerged.

The quality and quantity of information available in the public domain is growing rapidly. Companies are creating in-house databases to track and improve operating and service performances in an effort to keep up with this explosion of data. The hardware and software used to obtain and manipulate massive amounts of information are constantly improving. All these events have created an opportunity to evaluate the complex interaction of variables and quantify how they relate to the required end result. The Redfork formation is a prolific, low-permeability, natural gas and gas-condensate reservoir deposited during the middle Pennsylvanian Period. The reservoir is located in the deep Anadarko basin of west-central Oklahoma. The Redfork is an interesting reservoir because of its high level of heterogeneity and the varied stimulation/completion methods used in the formation. The volume and diversity of information available on Redfork completions make the Redfork formation unique. This paper analyzes Redfork completions in Roger Mills and Custer Counties. The study uses artificial neural networks (ANNs) trained on a data set of 107 Redfork completions to analyze and quantify the effect of well/reservoir parameters and completion methods on production results. Specific areas of interest include controllable/quantifiable aspects of a well's completion/stimulation procedure that affect the production outcome. The paper will document a methodological test that supplements standard completion-optimization techniques. P. 555

Hydraulic fracturing-fluid systems are used to create fractures in hydrocarbon-producing reservoirs and to transport proppant into the fracture to support it and provide optimum production increase. Many reservoirs in North America and the world would not be economical prospects without this technology. Currently, most systems use water-soluble polymers composed of guar or guar derivatives. Additional materials are used to optimize the fluid characteristics for the application and to degrade the water-soluble polymer, making the fluid easier to recover from the well before production. The recovered fluids cannot be used again and must be disposed of in a proper manner. A new hydraulic fracturing-fluid system has been developed that can provide excellent performance during the fracturing process with post-fracture treatment-fluid recovery approaching 100%. This fluid has the added benefit of being reusable after it is recovered following the treatment and before production. The benefits of reusing the treatment fluid include the cost savings associated with recovery and reuse of chemicals, the cost savings from reduced water volume requirements for subsequent treatments, and the elimination of disposal costs. In addition, the total volume of chemicals required for fracturing operations is significantly less, reducing the demand on the environment. Reuse of this fluid system requires field analysis of the returned fluid and treatment of the fluid to preserve and maintain it for future use. To achieve the best results from the recovery, preparations should be made to capture and store the fluid for subsequent treatments. This paper presents the application of the fluid system and the concept for recycling and reuse. The results of eleven treatments in the Barnett Shale in the Fort Worth Basin using the new fluid system and the recycled fluid system are provided. Introduction The Barnett Shale is a Mississippian Age formation located in the Fort Worth Basin in north Texas. It is a black, organic-rich, siliceous zone that is considered a source rock for shallower formations in the basin. It has very low matrix permeability (<0.001 md) and porosity (5 to 6%). The formation outcrops to the south in central Texas. It thickens and dips to the north and is found at depths ranging from 6,500 to 8,000 ft in the center of the basin. It is bounded on the east by the Quachita Mountains and on the northeast by the Munster Arch. The Bend Arch running north and south forms the western margin of the Fort Worth Basin.1 The most productive areas are where the Lower Barnett is approximately 300 ft thick and the Upper Barnett is approximately 150 ft thick and separated by the Forestburg lime. Development of the Barnett Shale is expanding to the west where the Forestburg lime plays out and the Barnett Shale is considered one unit. However, hydraulic fracturing is required in these developments to achieve economic production rates, and fracturing treatments have evolved with the Barnett Shale development. The treatments began as large-volume gelled water frac treatments in which over 1 million pounds of sand were placed in most cases.2,3 Although the results were positive in these cases, the economics of the fracturing treatments required improvement. To improve the economics and the results, the fluid systems were changed and the gel loading was reduced. Production from some wells was encouraging, but most still experienced a fairly steep decline during early well life. The next types of treatments were high-rate water frac treatments composed of large volumes of water with little or no polymer added to increase the viscosity and proppant-carrying ability of the fluid.4 The high treatment rates facilitated the proppant transport through the surface equipment and into the tubulars in the wellbore, but distribution in the fracture was thought to be poor. Most of the proppant settled to the bottom of the fracture and did not effectively prop the entire created fracture height or length. However, these types of treatments were equally effective based on production results.

@yri9ht199S, %ciaty c!/ Pabolaum Enghaara, k. This papnr was prepared fcf pfeaenlatii at IfM 1SSS SPE Rc&y Mountain RagionaVLcw-Psm'mability Reservoirs Symposium and WWficm bald m Dsnver, Colwado, S-S April 1SS6. Tlvs pa@r was salected for presmtation by an SPE Program CommMee following review d Wmnation contained h an abatnxt 5Mwnitted W the SS.Ithcf[s). Cc@ank d the paper, as p_asanted, have cat ken reviawed by the Scc@y d Pehlaum Enginaam and we subject to axaclkm EW tha auihcf(s) Tha material. as presOrW-d, dcas not necassarity refkt any position c4 ttw Sociaty d Patrolewn Engmeere, its ofkara, or membars. Pepars presented at SPE maatings am aubjad 10 pubkation raviaw by Editorial CommiKaas of the Society of PetfOieum Engineers. Ektrlmii Npc&dOn , distribution, or storage M any part of this papar for mrnmercial purposes W&X4 the writtan cunsanl C4 tha Sockty of Patrolman Engineers is pohibiwd Pannission to rafxduca in print m mstrktad to an abstracl d not mom than 300 wwds; itiuslrat"mns may rid be cc@3d. Tha abstract must contain campicuous dmwbdgment cf whera and by w4wxn the paper was presented. Write LtiariarI, SPE, P.O. s0xss3a2e.R~, TX ?S3S3-3S3S, U.S.A. fax 01-972-9S2-943S. AbstractThe quality and quantity of information available in the public domain is growing rapidly. Companies are creating in-house databases to track and improve operating and service performances in an effort to keep up with this explosion of data. The hardware and software used to obtain and manipulate massive amounts of information are constantly improving. All these events have created an opportunity to evaluate the compIex interaction of variables and quanti~how they relate to the required end result.The Redfork formation is a prolific, low-permeability, natural gas and gas-condensate reservoir deposited during the middle PennsylvanianPeriod. The reservoir is located in the deep Anadarko basin of west-central C)klahoma. The Redfork is an interesting reservoir because of its high level of heterogeneity and the varied stimulation/completion methods used in the formation. The volume and diversity of information available on Redfork completions make the Redfork formation unique.This paper analyzes Redfork completions in Roger Mills and Custer Counties. The study uses artificial neural networks (ANNs) trained on a data set of 10'7 Redfork completions to analyze and quanti~the effect of well/reservoir parameters and completion methods on production results. Specific areas of interest include controllable/quant ifiable aspects of a well's completiotistimulation procedure that affect the production outcome. The paper will document a methodological test that supplements standard completion-optimization techniques. ANNs