Many shale plays are being successfully developed throughout North America. These shale plays are being evaluated based on a number of criteria but primarily through typical unconventional and tight formation gas reservoir characteristics. Prospective shale plays share several interesting characteristics such as mineralogy, rock mechanics, and geomechanics. It is the intent of this paper to highlight and demonstrate the inter-relationship of these characteristics and show their importance on completion and stimulation design and more importantly to the very prospectivity of an unconventional shale play. This paper will show through an analysis of the mineralogy that shale plays are made up of mostly silica and carbonate material and have few clay constituents. In other words, the prospective shale's are actually fine-grained clastics and not shale! Secondly, prospective shale's tend to be brittle with the static Young's Modulus generally in excess of 3.5 x 106 psi. Of course this brittleness is related to the lack of clay constituents that make up these rocks. In addition, prospective shales tend to satisfy clastic correlations of dynamic to static Young's Modulus. They do not behave like typical shales but more like fine-grained isotropic (on a core scale) clastics! Finally, gas can flow through induced fractures or natural fissures under effective stress conditions in these shale plays. As a result, water-frac treatments are the stimulation of choice! However, proppant is still necessary in at least the near wellbore vicinity to provide a conductive pathway to the wellbore. This paper focuses on three key elements (mineralogy, rock mechanics, and geomechanics) of prospective shale plays and benefits the petroleum industry by:Integrating the laboratory core work with multi-disciplinary data to develop a shale and unconventional reservoir prospectivity evaluation tool,Illustrate how this multi-disciplinary dataset influences completion and stimulation design, execution, and well performance, andDemonstrate how this multi-discipline dataset can be used to identify and mitigate well completion and stimulation risks in these unconventional reservoirs. Introduction There are a number of important parameters and technical disciplines that need to be addressed to understand the viability of an unconventional gas reservoir. Unconventional gas reservoirs are somewhat unique, in that, they require "good" reservoir, completion, and fracture stimulation for success. Failure of any one of these key disciplines means a marginal or uneconomic well and success in all three may not guarantee a successful well as they are extremely price/cost sensitive. On the reservoir side Gunter 1–2 and Newsham and Rushing 3–4 correctly tie the geology, petrophysics, and reservoir engineering to develop an integrated work flow for tight and unconventional gas reservoirs. The four stage model included:large scale geologic architecture,description of the rock and fluid systems,definition of flow units through formation evaluation, andcalibration of the geologic and petrophysical models through reservoir simulation. Geomechanics was addressed throughout their workflow. Stage 1 of their work addressed the large scale structural components of the geologic model such as faults, in-situ stresses, and fissures, Stage 2 addressed the stress dependent properties and anisotropy of the rocks, and stage 3 and 4 addresses the hydraulic fracture and natural fissure orientations and effects on well performance. Slatt 5 et al. developed a workflow for unconventional gas shales that included (1) characterization of multi-scale sedimentology and sequence stratigraphy, (2) relate stratigraphy to log response, (3) seismic response, (4) petrophysical and geomechanical properties, and (5) organic geochemistry. In this work, the geomechanics of the prospect are brought in through step 4 and although not discussed in any great detail a relationship between mineralogy and geomechanics is suggested. Further, the authors recommend additional attention be given to the lithologic properties of the shale and the brittleness or ductility.

Guidelines for sand control completion technique and gravel size selection are presented. These new criteria are based primarily on reservoir sand size distribution. Emphasis is on formations with very high fines content and a wide distribution of grain sizes. Upon failure and/or particle movement, these formations can exhibit very high skins and reduced production capacity with traditional control methods. Guidelines are also discussed for formations with little fines and a very uniform grain size distribution. Proposed criteria are based on field experience and experiments conducted with reservoir cores from different sand formations worldwide. Experiments were conducted by "packing" different gravels at the effluent end of core plugs and surging fluids through the plugs and gravel. Cases are presented where traditional methods would lead to an overly restrictive gravel pack and advantages are obtained with use of larger gravel. P. 201

Horizontal wells have become the industry standard for unconventional and tight formation gas reservoirs. Because these reservoirs have poorer quality pay, it takes a good, well-planned completion and fracture stimulation(s) to make an economic well. Even in a sweet spot in the unconventional and tight gas reservoir, good completion and stimulation practices are required; otherwise, a marginal or uneconomic well will result. But what are good completion and stimulation practices in horizontal wells? What are the objectives of horizontal wells and how do we relate the completion and stimulation(s) to achieving these goals? How many completions/stimulations do we need for best well performance and/or economics? How do we maximize the value from horizontal wells? When should a horizontal well be drilled longitudinally or transverse? These are just a few questions to be addressed in the subsequent paragraphs. This paper focuses on some of the key elements of well completions and stimulation practices as they apply to horizontal wells. Optimization studies will be shown and used to highlight the importance of lateral length, number of fractures, interfracture distance, fracture half-length, and fracture conductivity. These results will be used to discuss the various completion choices such as cased and cemented, open hole with external casing packers, and open hole "pump and pray" techniques. This paper will also address key risks to horizontal wells and develop risk mitigation strategies so that project economics can be maximized. In addition, a field case study will be shown to illustrate the application of these design, optimization, and risk mitigation strategies for horizontal wells in tight and unconventional gas reservoirs. This work provides insight for the completion and stimulation design engineers by: 1. developing well performance and economic objectives for horizontal wells and highlighting the incremental benefits of various completion and stimulation strategies, 2. establishing well performance and economic based criteria for drilling longitudinal or transverse horizontal wells, 3. integrating the reservoir objectives and geomechanic limitations into a horizontal well completion and stimulation strategy, and 4. identifying horizontal well completion and stimulation risks and risk mitigation strategies for pre-horizontal well planning purposes.

Hydraulic fracture geometry (i.e., critical results of length and proppant placement) is driven by four major in situ parameters: Fracture Height (H), Modulus (E), Fluid Loss (C), and "Apparent" Fracture Toughness (KI c-app ). In many (even most) cases, "Height" is the most important of these parameters – due to the need for some height confinement to achieve long fractures, or the need for height growth to insure good pay coverage. Due to this importance, industry research effort and most field measuring techniques concentrate on "Height." In particular, the growing use of seismic imaging is offering a tool to measure height growth away from the wellbore. Results from such diagnostics have often shown, as one expects, that in situ stress variations control height. However, results have also shown situations where this is apparently not the case. This paper examines another in situ parameter, "Layered Modulus," which also affects height. In addition, by controlling the "local" width of a fracture, layered modulus (i.e., layered formations with different layers having significantly different modulus) can have a critical effect on final proppant placement. The importance of layered modulus in directly controlling fracture height is illustrated in this paper, and this is compared with published solutions. In general, it is found that, just as concluded in the past, modulus contrast is probably not an important parameter in terms of direct control of fracture height. The greater importance lies in the effects on local fracture width. These local width changes can have a significant influence on controlling proppant placement – and this can be critical for low net pressure cases such as "water fracs" or fracturing in "soft" formations. It is also noted that layered modulus significantly impacts the average width of a fracture, and thus impacts the critical material balance aspects of fracture modeling if not properly accounted for. Finally, some of the theoretical solution problems created by "Layered Modulus" formations for fracture modeling are discussed and compared. This is done by comparing with 3–D Finite Element (static) solutions, and shows how some common industry "approximations" for layered modulus give incorrect results. Based on this, examples with a fracture propagation model using a finite element-generated stiffness matrix are used to define types of cases where a simple "average" modulus is acceptable, versus cases where more complex calculations are needed. Introduction Six major variables control hydraulic fracturing, fracture geometry, proppant placement, etc. Two of these are the "controllable" variables of fluid viscosity, µ, and pump rate, Q. The remaining four variables are "natural" variables and include:Height. Fracture height (or more generally fracture geometry) is possibly the most important unknown for fracture design and post-frac production success. Generally, it is recognized that in situ stress differences (the in situ stress profile) is the major controlling factor for this behavior. [1] At a minimum, in situ stress differences control the maximum fracture height, i.e., if the net pressure is not available to grow through high stress shale layers, then fracture height must be contained. The importance of fracture height/geometry is clear, and there are many research efforts and technical publications addressing this issue. [1–6]Fluid Loss. Fluid loss is typically characterized for hydraulic fracturing by a fluid loss coefficient, C, which characterizes linear flow fluid loss out of the fracture. This gives the familiar C/ (t-t) form of fluid loss behavior. Again, this variable has been exhaustively discussed in the literature including wall building characteristics of specific fluid systems, effects of natural fractures, behavior of fluid loss additives, etc. [7–16]

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