The most common fallacy in the quest for the optimum stimulation treatment in shale plays across the country is to treat them all just like the Barnett Shale. There is no doubt that the Barnett Shale play in the Ft. Worth Basin is the "granddaddy" of shale plays and everyone wants their shale play to be "just like the Barnett Shale." The reality is that shale plays are similar to any other coalbed methane or tight sand play; each reservoir is unique and the stimulation and completion method should be determined based on its individual petrophysical attributes. The journey of selecting the completion style for an emerging shale play begins in the laboratory. An understanding of the mechanical rock properties and mineralogy is essential to help understand how the shale reservoir should be completed. Actual measurements of absorption-desorption isotherm, kerogen type, and volume are also critical pieces of information needed to find productive shale reservoirs. With this type of data available, significant correlations can be drawn by integrating the wireline log data as a tool to estimate the geochemical analysis. Thus, the wireline log analysis, once calibrated with core measurements, is a very useful tool in extending the reservoir understanding and stimulation design as one moves away from the wellbore where actual lab data was measured. A recent study was conducted to review a laboratory database representing principal shale mineralogy and wireline log data from many of the major shale plays. The results of this study revealed some statistically significant correlations between the wireline log analysis and measured mineralogy, acid solubility, and capillary suction time test results for shale reservoirs. A method was also derived to calculate mechanical rock properties from mineralogy. Understanding mineralogy and fluid sensitivity, especially for shale reservoirs, is essential in optimizing the completion and stimulation treatment for the unique attributes of each shale play. The results of this study have been in petrophysical models driven by wireline logs that are common in the industry to classify the shale by lithofacies, brittleness, and to emulate the lab measurement of acid solubility and capillary suction time test. This is the first step in determining if a particular shale is a viable resource, and which stimulation method will provide a stimulation treatment development and design. A systematic approach of validating the wireline log calculations with specialized core analysis and a little "tribal" knowledge can help move a play from concept to reality by minimizing the failures and shortening the learning cycle time associated with a commercially successful project.

Unconventional natural gas systems include fractured shale gas (FSG), tight gas sands (TGS), basin center gas (BCG), shallow basin methane (SBM), and coalbed methane (CBM). Recently, more operators are focusing attention on shale reservoirs. The most notable shale play being developed in the north Texas region is the Barnett shale. This success has encouraged operators to investigate producing potential of the Woodford and Caney shales in Oklahoma. Shale plays are unique in that they often are both the source rock and producing rock contained in the same package. This duality leads to difficulty in log and reservoir interpretation. To date, conventional log interpretation has proved inadequate in identifying producing potential. Simply perforating areas of high porosity and pumping massive hydraulic fracture (MHF) treatments do not always yield commercial production results. Identifying areas of high producing potential using gamma ray, density, resistivity, and sonic transit time to locate high total organic carbon (TOC) has also yielded mixed production results. We believe the addition of mechanical properties of the rock can help identify shale intervals with a high propensity to contain natural fractures and a high probability to create a fracture network during hydraulic fracturing. We propose a linkage between the mechanical properties of the rock and the hydraulic fracture network created during a MHF treatment and the resulting production outcome. Desirable combinations of mechanical properties are selected to help locate areas in the shale that have a propensity to fracture as a network with sufficient aerial extent to impact production results. We use these mechanical properties in addition to TOC and porosity to select fracture initiation sites and give a qualitative assessment of producing capacity. In this paper, we describe calculated log parameters that illustrate this technique. Introduction Finding areas of productive shale is difficult because most logging techniques are based on conventional formations and are calibrated for standard rock types such as limestone, dolomite, or sandstone. The mineral composition of shale is very complex and variation in density, resistivity, and radioactive material content can cause serious errors in porosity and saturation calculations. Specialized logs are used to identify areas of possible hydrocarbon production by locating high total organic carbon (TOC), mature kerogen type III organic material, mineral composition, and areas prone to fracture network development. Identification of these areas is key to successful completion of a shale play. Obtaining a reasonable estimate of shale reservoir quality through logging has evolved by modifying standard log interpretation to fit the complex producing units we call shale. Our initial conceptual model of a shale play as a homogeneous clay-rich, organic source rock is not a valid model. Instead we encounter a multi-layered litho package, comprised of quartz, dolomite, lime, chert, and feldspar, sandwiched in a black shale bulk matrix. These are the shale productive units that most typify commercial Oklahoma shale. Productive shale plays are unique in that they are source rock, reservoir rock, and trap. The primary storage and producing mechanism of shale is a topic of heated debate. In general, most agree that there is a "free" and "adsorbed" component of hydrocarbon present in most shale plays. Exactly where the hydrocarbon is and how it flows out of the rock is still a topic of research. A conceptual model that seems to have some degree of acceptance is one where the "free gas" is stored and produced from micro-porosity in lamina and natural fractures and the "adsorbed gas" is stored and produced from the bulk shale matrix (Fig. 1). The importance of high-resolution log interpretation calibrated to laboratory measurement of mineralogy, organic content, maturation, gas saturation, and mechanical properties is apparent when dealing with multiple storage/flow mechanisms encountered in shale plays. The following will discuss log parameters used to help determine the quality of a producing shale unit. Production potential will be viewed as a mix of geology, geochemistry, mineralogy, hydrocarbon storage and flow, as well as, rock mechanics and its effect on fracture network creation. A commercial shale play will have the necessary mix of all these attributes, and each will have its own impact on the ultimate production.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe evolution of well completions in the Barnett

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 life cycle. 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 Eagle Ford, as well as others. 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 US 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 the 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.

Developing a predictive reservoir model involves determination or estimation of key reservoir components, which can vary through the rock volume. Sophisticated, 3-D grid models usually require significant input data and are built for conventional reservoirs producing in Darcy flow. Production from the Barnett shale is not conventional. Shale-rock gas flow involves a complex mixture of free and adsorbed storage and production mechanisms. Free gas can be stored in the microporosity, natural fractures, or thin lamination existing or created during hydraulic fracturing. Adsorbed gas is contained in the organic material randomly distributed in the bulk rock. Horizontal, multistage-fractured wellbores add another level of complexity. Massive hydraulic fracturing of horizontal shale has shown complex fracture networks are created along the wellbore. Mapped data suggests multiple fracture planes are created during injection. These fracture planes can be irregular in length and are not always symmetrical. Conventional reservoir models cannot handle this level of complexity. A new, 3-D, four-phase, nonisothermal, multiwell black oil and "Pseudo-compositional" simulator that allows placement of multiple transverse fractures along the horizontal has been developed. Its ability to model horizontal, multiwing, transverse fractures and account for all three reservoir phases, including injected fluid, makes this model more predictive of production. This paper uses mapped fracture dimensions of horizontal wells in the north Texas Barnett (NTB) to build a reservoir model. Comparisons of model production to real production are made to demonstrate the model's predictive ability. Introduction Horizontal drilling and completion of the NTB began in 1991 and has more than 6,000 horizontal wellbores on production to date. Numerous well construction types and completion strategies that have been investigated in the NTB are listed below.Cemented and uncemented linersCemented production casingProduction casing with mechanical/swell packers and frac portsCemented and uncemented casing using jet-tool perforating and fracturing (East et al. 2004) The most common completion is the cased, cemented production string using the pump down perf-and-plug method of multistage completion (Smith and Starr 2008). Horizontal Completion Design The completion phase of the horizontal Barnett shale is thought to have the most effect on production outcome. Horizontal azimuth for the NTB is usually chosen so that hydraulic fractures created bisect the wellbore in a transverse manner. This option is preferred because it opens multiple fracture planes along the entire lateral length, maximizing the total surface area to flow. Some of the obvious design considerations are:• Lateral length• Fracture spacing or initiation points• Number of stages• gal/ft, lbm/ft• Total gallons and total lbm of proppant per wellbore