Thh papu was pr~ad for pramtatlon qt ltm 1996 SPE E-tern Raglanal Meethg had m COlmblm, Oh/o, 23.26 Octoba1996. TM* papa wwlectod for presentation by .n SPE program Committaa followl~review cd Information conmined b m sbstrsct sibmiuad by the aurbrls). Contrnts of the papa, a praemtad, he rm.tkm rmhwed by the seciet y of Petroleum Ewinmrs qnd qre s~jecwd to ourratlon by the quthor[s). Tlm matwial, 88 printed, doa not necasarily reflect any poaltlon of the society of Petroleum Ef@nOer*, im office+s, or mmiiam. Pape89 prcsanted M SPE mmtiWs Am subject to publlc.tion rwiam by Editorial Cc.mrnltteu of tln Saeiuy of P8trolm En@neaa. Eloctro.{c reproduction, d$atribution, or wor-e of any pan of thh paper for commercial purpo~wltiwuf tlw writtcm cofnml of ttw society of petroleum Endrmers 18Drohlbited. permission to reprcduce in print Is rrntrictui to .ri sbstrmt of WI mom tfmn 300 word$, Illustrmiem WY not be copied. The qbst,tit must comain complcuoua dmowledgemem of wlwre qnd by wham h paper was p,amted. Abstract This paper surnmsri zes the first-year results of a four-year R&D demonstration program sponsored by DOEYMETC entitled "Field Verification of New and Novel Fracture Stimulation Technologies for the Revitalization of Existing Underground Gas Storage Wells". Operations at three of nine planned test sites have been completed or are nearing completion, with highly encouraging results with respect to deliverability enhancement. At one site, fracturing with liquid COZ and proppant is being tested, while tip-screenout fracturing is being teated at each of the other two sitea.Liquid COZ fracturing is being tested at the Galbraith Field in Pemsylvania operated by National Fuel, Pm-and posttreatment pressure transient tests indicated that substantial reductions in sk;n factor were achieved with the restimulations, resulting in deliverability improvements of up to seven-fold. Important criteria were also identified regarding the application of liquid C02 fracturing to gas storage reservoirs, including possible limitations posed by high formation permeability together with high in-situ stresses.Tip-screenout fracturing is currently being tested at the Huntsman Field in Nebraska operated by KN Energy. The preservation of caprock integrity by controlling fracture height growth required that precise, low-volume treatments be designed and executed. Pre-treatment pressure transient tests and fracture-height surveys on one well have been performed, and indicate deliverability improvement can be achieved while successfully avoiding excessive fracture height growth. Final work, including fracturing the two remaining teat wells and post-stimulation pressure transient teats, is now king conducted at this site.The third test site, where tip-screenout fracturing is also being performed, is the Donegal Field in Pemsylvsnia operated by Columbia Gas. Pre-stimttlation testing and the first treatment have been performed at the site. Analyses indicate that horizontal fracturing is evident, suggesting that an alternative approach (other t...

Conventional wisdom states that a coalbed methane (CBM) evaluation program should consist, initially, of core hole and permeability testing, followed by flow testing wells, leading to one or more multiple well pilot programs. Such an evaluation program progresses sequentially from lower initial cost for basic data acquisition to higher cost production testing that normally focuses on the construction of a reservoir simulation-based field development model. However, Applications of this approach minimize any consequence of reservoir heterogeneities, which ultimately dominate later large-scale project performance. Due to these heterogeneities, potentially commercial coalbed methane production areas may be bypassed or prematurely condemned. To reduce the likelihood of missing or overlooking otherwise attractive CBM plays, an alternative evaluation model was developed to focus specifically on reservoir heterogeneity. This alternative evaluation program utilizes production distributions derived from proven productive basin area reservoir/operational analogs. The resulting production variability is then weighed against prospective new play areas in order to define more effective exploration program requirements. This results in a more realistic approach to the exploration process and increases the probability of large-scale technical and financial success. Introduction Development of a new CBM leasehold area requires an initial assessment program to define ultimate field producibility. The program is designed to acquire the required type and amount of data to forecast optimizal field performance while minimizing the expenditure necessary to disprove financial viability. Therefore, the evaluation process requires balancing assessment costs with the risk of over-funding development within an uneconomic or marginal asset. An often unrecognized but critical component of making these balanced decisions is the relative confidence level of the data generated from such an evaluation program, given the inherent variability of coal seam reservoirs across the leasehold area. Many coal basins have numerous core holes associated with mining activities and well logs associated with conventional oil and gas exploration and development. These data usually provide the means to develop an initial understanding of the coal seam geometry (depth, thickness, dip, and number of zones) and drives CBM exploration within any given area. These calculated coal resource parameters are then combined with measured gas content, sorption isotherms, coal chemistry, and estimated depth/pressure relationships to estimated gas in place. Thus, by combining existing information with a limited quantity of new core-derived data, a relatively confident geologic model of the gas resource in place can be developed. However, the level of confidence obtained from production forecasting is often much lower. Production from CBM wells is primarily a function of gas resource in place, flow capacity (permeability and reservoir pressure), and completion effectiveness. With resource (gas in place) broadly and confidently defined and given that reasonable completion techniques are utilized, then leasehold production ultimately becomes primarily a function of reservoir flow capacity, predominantly permeability. Unfortunately, by its very nature, coal seam permeability typically varies significantly from area to area, location to location, and even within areas smaller than an acre. This paper describes how this aspect of permeability, in terms of ultimate flow capacity of a leasehold area, is conclusively defined by using the acquisition of a statistically significant sampling of well data test sets.

The Upper Devonian-age black shale of the Central Appalachian basin has been a major natural gas production reservoir since the initial discovery in 1921. In the ensuing 80 years, an assortment of drilling and completion techniques have been applied to the black shale with varying degrees of success. Recent efforts at improving well productivity have focused on improving the hydraulic fracturing operations, especially the minimization of fluid damage to the targeted shale reservoirs. The development of fluid systems with lower polymer loadings has been an important achievement in this effort. Recently, polymer-free viscoelastic surfactant-based (VES) fluid systems have been used in the hydraulic fracturing industry as a final step in the elimination of polymer-based damage. A statistical study of the application of a VES foam fracturing fluid in the Central Appalachian basin was performed. The study compared recent results of polymer-free treatments to traditional completions throughout the field. Results from the polymer-free completions were compared to immediate offsets drilled in the same time frame and completed in correlated intervals. In general, the use of polymer-free fluids improved well productivity, when compared to wells that were completed with a conventional polymer-based fluid. The study also compared the economic impact of the use of VES completion fluids from both an operations and production perspective. Introduction Fracturing fluid is a critical component of a hydraulic fracturing treatment. The characteristics of this fluid includesufficient viscosity to suspend and transport the proppant in the created fracture andability to break into a low-viscosity fluid after the completion of the treatment so that a rapid flowback of the fluid to the surface is achieved, andnon-damaging to the reservoir. Polymers (guar or their derivatives) have historically been used for this purpose because of their excellent viscosifying characteristics. However, a recent study has shown that only 30 to 45% of the of the guar-based polymers pumped during a treatment returned to surface during the flowback period.[1] This indicated that a substantial amount of the polymer remained in the proppant pack or as a filtercake on the fracture face. Further, studies have shown that polymer residues that remain in the proppant pack reduce the proppant-pack permeability, thus resulting in a loss of effectiveness of the hydraulic fracture treatment.[2] To offset the negative effects of polymer residue, a VES polymer-free fluid system has been developed. This VES fluid relies on the presence of a hydrophilic water-soluble ionic group and hydrophobic hydrocarbon-soluble chain within a single molecule of the surfactant. In the presence of water the molecules form micelles similar in shape to polymer molecules. The resulting fluid is similar to a cross-linked guar-based gel but without the need for a cross-linker. When organics (such as oil or natural gas) dissolve in this VES fluid, the micelles change from a rod shape to a spherical shape. This change reduces the viscosity of the VES fluid to that of a brine without the need of a chemical or enzyme breaker.[3] Therefore, a VES fluid rapidly flows back after a hydraulic fracture treatment with no gel residue or filtercake remaining in the proppant pack. To assess the impact of this VES fluid on well performance, a comparative statistical study was performed in the Central Appalachian basin gas field. The reservoirs in this area are normally under-pressured and nitrogen foam fluids are typically used. In this study, wells that were hydraulically fractured with the VES fluid were compared with wells fractured with conventional guar-based fluids. Production indicators--- gas production rate, best 6 months of production, etc.---were the basis for comparison and economic analysis and provide the basis for measurement of the effect.

This paper summarizes the first-year results of a four-year R&D demonstration program sponsored by DOE/METC entitled "Field Verification of New and Novel Fracture Stimulation Technologies for the Revitalization of Existing Underground Gas Storage Wells". Operations at three of nine planned test sites have been completed or are nearing completion, with highly encouraging results with respect to deliverability enhancement. At one site, fracturing with liquid CO2 and proppant is being tested, while tip-screenout fracturing is being tested at each of the other two sites. Liquid CO2 fracturing is being tested at the Galbraith Field in Pennsylvania operated by National Fuel. Pre- and post-treatment pressure transient tests indicated that substantial reductions in skin factor were achieved with the restimulations, resulting in deliverability improvements of up to seven-fold. Important criteria were also identified regarding the application of liquid CO2 fracturing to gas storage reservoirs, including possible limitations posed by high formation permeability together with high in-situ stresses. Tip-screenout fracturing is currently being tested at the Huntsman Field in Nebraska operated by KN Energy. The preservation of caprock integrity by controlling fracture height growth required that precise, low-volume treatments be designed and executed. Pre-treatment pressure transient tests and fracture-height surveys on one well have been performed, and indicate deliverability improvement can be achieved while successfully avoiding excessive fracture height growth. Final work, including fracturing the two remaining test wells and post-stimulation pressure transient tests, is now being conducted at this site. The third test site, where tip-screenout fracturing is also being performed, is the Donegal Field in Pennsylvania operated by Columbia Gas. Pre-stimulation testing and the first treatment have been performed at the site. Analyses indicate that horizontal fracturing is evident, suggesting that an alternative approach (other than hydraulic fracturing) may be required for effective well stimulation. Introduction An improved, more efficient natural gas storage system is essential for supporting the growth in US gas demand in the coming decades. A high priority therefore exists to increase current domestic storage capability and offset the persistent 5.2% average annual loss in well deliverability from gas storage fields. Although storage field operators have extensive experience with current well remediation technology, recently published case studies demonstrate the shortcomings of traditional, non-fracturing well revitalization methods. In 1994, CNG Transmission fracture-stimulated 30 wells in five Oriskany gas storage fields using conventional techniques, demonstrating that highly encouraging results can be achieved with fracturing. However there still remains considerable potential for using new and novel fracture stimulation technologies to restore injection and withdrawal capabilities in gas storage wells where conventional fracturing may not be applicable, for example where fracture fluid sensitivities and height growth concerns exist, or in high-permeability reservoirs. Thus a comprehensive evaluation of alternative fracture stimulation techniques is required to demonstrate that certain technologies can be effectively applied to increase well deliverability in these settings. p.155