Almost three decades have passed since the early exploration of the north Texas, Barnett Shale. The Barnett serves as an example study for the shale lifecycle. Operators in North America have used the Barnett-shale development as a roadmap for the exploration of new shale plays like the Marcellus, Haynesville, and Eagleford. Each new shale play is unique in nature with respect to geologic setting, lithology, and production mechanism. It is useful to have a defined strategy for the discovery, development, and decline phases of each individual shale play. The roadmap to shale well-completion designs should include the following key factors: Fracability: capability of the reservoir to be fracture stimulated effectivelyProducibility: capability of the completion plan to sustain commercial productionSustainability: capability of the field development to meet both economic and environmental constraints This paper reviews the evolution and development of completion practices of the major USA shale reservoirs in the last two decades and presents a roadmap for effective completion practices for shale stimulation. The completion roadmap uses the history of 16,000 shale frac stages in the Barnett, Woodford, Haynesville, Antrim, and Marcellus shales. Following the map through specific decision points will alter the path for individual shales. These decision points will be influenced by geologic, geochemical, and geomechanical information gathered along the way. The path toward a commercially viable shale play from the early asset-evaluation phase to late asset maintenance-and-remediation phase evolves from a series of decision trees throughout the process. Information presented in this paper provides a completion engineer with better understanding of the factors involved in shale-play stimulation and provides a methodical approach to select appropriate and optimum solutions that have evolved during the last two decades.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractThe popularity of water fracs has increased in recent years. The reduction in fluid cost and overall fracture stimulation cost has in some cases revived exploration in low-permeability reservoirs like the Barnett shale in north central Texas. Water fracs have also been used effectively in reservoirs with low permeability and large net pays, which require large volumes of fluid to attain adequate fracture half-lengths to achieve commercial production.In the past, the design of water fracs has been more of an art than a science. While the term "water frac" implies that the fluid is proppant-free, in most cases some proppant is usually pumped. The amount and concentration is usually low when compared to conventional fracture treatments. Water-frac designs are further complicated by the fact that fracture geometry, conductivity, and proppant transport are not easily modeled.Despite these difficulties, the attractiveness of water fracs requires the implementation of a design methodology. This paper discusses a design procedure for water fracs from a field operation/design standpoint. Volume and rate requirements are discussed for a specific zone height, desired fracture length, and aerial width. A fracture width vs. proppant size requirement is applied, and a simple material balance calculation is performed to generate a fracture volume taking fluid leakoff into account. Fracture conductivity of a low proppant-concentration, high fluid-volume fracture is estimated to optimize proppant length and fracture conductivity ratio (C fd ). A pump schedule is generated based on the results of the previous calculations. All design calculations are simple and require only a handheld calculator or simple spreadsheet.The design model was calibrated to a microseism-mapped Cotton Valley Lime test well. A leakoff coefficient multiplier was used to calibrate the model. The model-predicted volume was then compared to actual volume on a second Cotton Valley Sand test well and on a 10-well average Barnett shale microseism fracture-mapping data set. The overall modelpredicted volume for the mapped microseism geometry is compared to actual volume pumped.

TX 75083-3836 U.S.A., fax 01-972-952-9435. AbstractThe popularity of water fracs has increased in recent years. The reduction in fluid cost and overall fracture stimulation cost has in some cases revived exploration in low-permeability reservoirs like the Barnett shale in north central Texas. Water fracs have also been used effectively in reservoirs with low permeability and large net pays, which require large volumes of fluid to attain adequate fracture half-lengths to achieve commercial production.In the past, the design of water fracs has been more of an art than a science. While the term "water frac" implies that the fluid is proppant-free, in most cases some proppant is usually pumped. The amount and concentration is usually low when compared to conventional fracture treatments. Water-frac designs are further complicated by the fact that fracture geometry, conductivity, and proppant transport are not easily modeled.Despite these difficulties, the attractiveness of water fracs requires the implementation of a design methodology. This paper discusses a design procedure for water fracs from a field operation/design standpoint. Volume and rate requirements are discussed for a specific zone height, desired fracture length, and aerial width. A fracture width vs. proppant size requirement is applied, and a simple material balance calculation is performed to generate a fracture volume taking fluid leakoff into account. Fracture conductivity of a low proppant-concentration, high fluid-volume fracture is estimated to optimize proppant length and fracture conductivity ratio (C fd ). A pump schedule is generated based on the results of the previous calculations. All design calculations are simple and require only a handheld calculator or simple spreadsheet.The design model was calibrated to a microseism-mapped Cotton Valley Lime test well. A leakoff coefficient multiplier was used to calibrate the model. The model-predicted volume was then compared to actual volume on a second Cotton Valley Sand test well and on a 10-well average Barnett shale microseism fracture-mapping data set. The overall modelpredicted volume for the mapped microseism geometry is compared to actual volume pumped.

Horizontal drilling and multistage hydraulic fracturing have been credited for much of the success achieved in ultralow permeability shale reservoirs, making it possible to produce natural gas, natural gas liquids, and crude oil at economic rates. Although thousands of wells have been drilled and completed using these techniques, there are relatively few design tools and processes available within the industry designed specifically for these applications. In the past, much of the optimization process has been the result of trial and error techniques that can be both costly and time consuming. This paper examines a step-out development project where new processes and tools were used to accelerate the de-risking of the asset area by identifying the best quality reservoir targets and significantly improving production and economics by implementing a completion optimization process. This reservoir centric process uses earth modeling, complex fracture modeling, and reservoir simulation tools developed specifically for shale type formations. It also focuses on designing the wellbores to best accommodate the staged stimulation treatments that can help maximize the stimulated volume and the connected fracture area within this volume. When optimized, this process can help maximize the estimated ultimate recovery (EUR) while sustaining economically viable production rates. A detailed example is presented illustrating how these tools were successfully applied within a new development to accelerate reservoir understanding, help improve well performance consistency through more effective well placement, and significantly increase well performance through applied engineering processes, completion designs, and effective stimulation treatments. The success of the project is discussed to illustrate both the initial and sequential performance improvements as new processes and designs were implemented. Total well cost comparisons are also included to verify the economic benefit achieved within this asset.

Refracturing in the US midcontinent is not a new method. In 1980, a refracturing program was begun in the shallow, low-pressure Brown Dolomite gas pay in the Texas panhandle. The results were mixed, but the overall outcome was economically beneficial. Currently, operators are refracturing horizontal shale wells, especially those completed from 2003 to 2010. However, results continue to be mixed and unpredictable. This paper presents lessons learned during refracturing treatments performed between 1980 and the present that led to the creation of a new approach to refracturing treatments. This paper discusses the factors to consider when planning a refracturing program. Refracturing failures are also discussed as a means to understand the controllable and uncontrollable variables that lead to these failures. Failures are categorized and specific failure types and modes are identified. Examples of successful refracturing treatments are also included. The resulting newly developed refracturing approach includes a four-step process: Candidate identification Refracture diversion design Execution and diagnostics Production analysis and diagnostics Examples of using the four-step process are provided to show the incremental improvements that resulted from identifying potential candidates and designing, executing, and analyzing the project. Production results and incremental estimated ultimate recovery (EUR) values are discussed to illustrate the economic viability of refracturing, and the economic benefit of this incremental production increase is compared with the cost of the refracturing treatment. While incremental production from refracturing in the midcontinent has more than doubled, pre- and post-fracture diagnostics should improve the success rate by defining lateral coverage. Real-time diagnostic techniques are discussed as potential tools for pre- and post-refracturing analysis. Despite the history of mixed results, refracturing efforts are improving through the implementation of this new four-step approach. Repressurization of the original fracture system is common to successful refracturing throughout time. New diversion materials and placement processes help achieve repressurization and refracturing placement success. Also, additional insight from new diagnostic tools and techniques can help improve the overall refracturing project success.