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SPE_110187_(Ilk)_Eval_Waterfrac_Tech_on_Gas_Recovery_Elliptical_Flow_PDA_(wPres)

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Copyright 2007, Society of Petroleum Engineers This paper was prepared for presentation at the 2007 SPE Annual Technical Conference and Exhibition held in Anaheim, California, U.S.A., 11–14 November 2007. This paper was selected for presentation by an SPE Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Papers presented at SPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes 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 where and by whom the paper was presented. Write Librarian, SPE, P.O. Box 833836, Richardson, Texas 75083-3836 U.S.A., fax 01-972-952-9435. Abstract This paper presents results from an evaluation of water-based hydraulic fracture stimulation treatments (or "waterfracs") performed in the Bossier tight gas sand play in the East Texas Basin. The primary objectives of our study were to not only assess stimulation effectiveness, but also to compare recovery efficiencies of various waterfrac technologies. Our primary evaluation tool is a set of new decline type curves developed specifically for the analysis of production data acquired from the elliptical flow period commonly observed in hydraulically-fractured wells completed in tight gas sands [Amini et al (2007)]. In this study we evaluated 12 gas wells from three Bossier tight gas fields located in Freestone County, Texas. Stimula-tion treatments for the wells in this study include water-based hydraulic fracture stimulation treatments with little or no sand, cases with large sand concentrations, as well as "hybrid water-fracs." "Hybrid waterfracs" are defined as fracture stimula-tion treatments where water is pumped initially to create the fracture geometry (i.e., width and length), followed by sand-laden gels to transport and place sand in the fracture (presently low concentration gels are used as opposed to large concen-tration gels used in the 1980s). Results from our study confirm that "hybrid waterfracs" yield longer, more conductive hydraulic fractures and are more effective at recovering gas-in-place for a given well spacing. Although less expensive to implement, small "waterfracs" (with little or no sand/proppant) are less efficient at gas recovery — which suggests more wells may be required to maximize gas recovery when "waterfracs" are employed. Introduction The practical goal for oil and gas operators exploiting any type of hydrocarbon resource is to maximize economic returns by optimizing field development activities. More specifically, the key to effective exploitation of tight gas sands is to develop the field at a sufficiently dense well spacing that maximizes gas recovery while avoiding drilling more wells than is necessary (i.e., establishing the optimum well spacing as early as possible during field development). In addition, significant reductions in capital expenditures may be achieved by optimizing well stimulation treatments. Most wells completed in tight gas sands require some type of stimulation (i.e., hydraulic fracturing) to achieve economic production. Depending on the type and size of stimulation treatment, hydraulic fracturing may be very expensive — often representing a significant portion of the total well completion costs. In the past, hydraulic fracture treatments utilized polymer gels combined with large proppant volumes in an attempt to create long, conductive fractures. Although gels are very efficient for transporting proppant, these gels often damage the frac-ture, are difficult to clean-up (i.e., remove from the forma-tion), and often yield high net fracturing pressures — and are expensive. Under these conditions, minimal effective stimula-tion was achieved, sometimes resulting in sub-economic or even uneconomic wells. "Waterfrac" technologies were developed in the 1980s as less expensive alternatives to gel treatments. Waterfracs initially ranged from low fluid volume treatments with little or no sand to larger treatments with higher sand concentrations. The industry has recently demonstrated considerable success using hybrid waterfrac technologies that combine advantages of both large gel and waterfrac treatments. Although slightly more expensive, field evidence indicates that hybrid waterfracs generate longer, more conductive effective fractures than smaller water-fracs [Rushing and Sullivan (2003)]. Published case histories make evident the relationship between stimulation effectiveness and gas recovery — i.e., wells with longer, more conductive fractures recover more gas over a larger drainage area. This concept seems obvious, but from a practical (i.e., economic) standpoint, this issue must be revisited continuously — particularly at present, as more and more marginal plays (tight gas/shale gas) are exploited. As the economic viability of tight-gas-sand fields depends (almost exclusively) on minimizing drilling and completion SPE 110187 Evaluating the Impact of Waterfrac Technologies on Gas Recovery Efficiency: Case Studies Using Elliptical Flow Production Data Analysis D. Ilk, SPE, Texas A&M University, J.A. Rushing, SPE, Anadarko Petroleum Corp., R.B. Sullivan, SPE, Anadarko Petroleum Corp., and T.A. Blasingame, SPE, Texas A&M University2 D. Ilk, J.A. Rushing, R.B. Sullivan, and T.A. Blasingame SPE 110187 costs, it is crucial that we find the proper balance between well spacing, stimulation treatment selection, and gas recovery efficiency. To that end, we have evaluated the production performance for wells in the Bossier tight gas sand play where different types of stimulations were used — including: ● small waterfracs with no proppant. ● small waterfracs with 20/40 or 40/70 proppant. ● large waterfracs with 20/40 or 40/70 proppant. ● hybrid waterfracs. Specifically, we provide 2 example analysis cases for


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