The main goal in stimulating shale formations is to maximize the reservoir contact with the hydraulic fracture face. In order to achieve this goal current practices include pumping low-viscosity fluids at high rates with small mesh proppant cycles. A novel approach was used in a well in the Eagle Ford shale to enhance the stimulated area. This technique, called "relax-a-frac", was developed by an operator/service company alliance during the exploration phase. Real-time microseismic hydraulic fracture monitoring (RT HFM) indicated that the conventional slickwater treatments were not providing adequate lateral coverage across the planned stage. To address this issue, controlled changes were made to the pumping schedule, and the effects were evaluated using RT HFM. The results indicated that relax-a-frac proved to be highly successful in increasing the estimated stimulated volume (ESV) in this formation and area.In relax-a-frac, a part of the stimulation treatment was pumped (usually pad plus proppant slugs), followed by an extended shutdown to relax the formation. Once the surface pressure reached a predetermined value, the treatment was resumed, as per program, with monitoring for microseismic activity. The microseismic activity observed during the second part of the treatment showed a significant increase compared to that of the first part, with improved lateral coverage. The resultant ESV increased significantly from this technique as compared to any other specific changes tried on these wells. Production log results from Well 1 showed a definitive correlation between production contribution and the ESV derived from HFM analysis. This paper documents that this novel approach more effectively stimulates the Eagle Ford shale when compared to the typical treatment designs. Conclusions from a detailed comparison of the well performance and its relation to the treatment design are included.

Examples of an integrated approach for quantifying oil and gas production potential in different hydrocarbon windows of the Eagle Ford Shale are presented. The Eagle Ford basin is unique in that reservoir fluids range from black oil to dry gas depending on the geology, burial depth, and temperature. The main goal of this paper is to guide operators to an understanding of potential reserves and their distribution in the Eagle Ford through the use of our specialized analysis and methodology to estimate ultimate recoveries. Data from the Eagle Ford Shale was compiled and analyzed to gain knowledge about the basin. The geology aided in indentifying "sweet spots" based on the various thermal maturation windows. Also, recent drilling and completion activities were examined in addition to the observed production from public databases. The intent was to determine curent completion practices in different parts of the Eagle Ford and also provide insight on the relationship between geologic features and production trends. A rapid asset evaluation case study is presented to demonstrate technique and workflow that uses vintage vertical well data to provide an estimate of asset value and reserves for a typical horizontal well in the Eagle Ford. The results of the study identifies "sweet spots" of oil and gas production and indicates that 1) Eagle Ford production is related to the maturation windows, as well as structure; 2) the best wells in the Eagle Ford are in the thicker areas; 3) Austin Chalk production relates to the underlying Eagle Ford production; 4) different completions for different areas and types of hydrocarbons should be considered, and 5) data and knowledge integration is the key for rapid evaluation of asset value in the Eagle Ford Shale. Operators can use this information and technique to help 1) better understand the uniqueness of the Eagle Ford Shale, 2) optimize their completion design and field development plan, and 3) calibrate expectations on oil and gas reserves potential under their acreage.

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Integrating logging-while-drilling (LWD) measurements with pilot well log data and 3D seismic data provides a more accurate predictive mapping of unconventional reservoir properties than evaluations from the individual measurements alone. In this project, the final probability of drilling in a zone of good reservoir quality, as defined by the seismic attributes, had the highest correlation with production of any spatially mappable variable and provided the operator with a ranking of potential drilling locations. This link between production drivers and causal mechanisms allows optimal decision making, partly by distinguishing reservoir quality variation, which cannot be controlled, from operational behavior, which can be modified; untangling these two can mean optimal use of capital resources to exploit these challenging reservoirs. Fast shearHoriz shear slowness perpendicular to borehole Matrix, J 1 , and J 2 fractures 0.51 DTSH--FAST DTCO Well PathNuclear J 2 J 1

For any resource play, quantifying production potential is key when transiting from exploration phase to development phase. In a self-sourcing environment, a host of reservoir properties such as clay type, mineral content, organic content, fluid saturations, pore pressure, texture, source, storage, mobility, natural fractures and structural features, defines the quality of the reservoir. Recently several published articles alluded to this fact and the term reservoir quality is loosely defined, vague or contradicting. In evaluating the success of an unconventional reservoir, this paper segregates the reservoir properties into two main categories. Reservoir quality (RQ) is defined by the combination of rock properties leading to hydrocarbon storage and producibility, including hydrocarbon-filled porosity, effective permeability, organic content, and pore pressure. Completion quality (CQ) is defined by the combination of rock properties leading to fracture surface area contacting the reservoir during production, including rock mechanical properties that will impact fracture containment, fracture complexity, retention of fracture area, and retention of fracture conductivity. This paper assesses each parameter thoroughly and rationalizes their impact and importance. A case study using a comprehensive data set is published here to support and understand the importance of reservoir quality, along with its utilization for selective grading of prospective locations. This paper concludes a detailed workflow for determining key parameters in defining reservoir quality towards a successful shale gas play development and its exploitation.