Integrated reservoir and decision modeling to optimize spacing in unconventional gas reservoirs
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Despite our increased experience, unconventional gas plays remain risky. In the face of this risk, operators must balance the need to conserve capital and protect the environment by avoiding over drilling with the desire to maximize profitability by achieving the optimal well spacing as quickly as possible. Previous unconventional gas developments such as the Carthage Field (Cotton Valley) have implemented multiple infill drilling programs over several decades to optimize well spacing, with significant reduction in value (McKinney et al. 2002). However, in emerging plays such as the non-core Barnett Shale and the Fayetteville Shale, historical infill programs are not available to evaluate optimal spacing and we do not have the luxury of developing these fields over the next 30-40 years. Existing approaches for optimizing development, such as integrated reservoir simulation studies or statistical moving-window methods, can be either prohibitively time-consuming and expensive or they do not consider the uncertainty inherent in the assessment. The objective of our work was to develop technology and tools to help operators determine optimal well spacing in highly uncertain and risky unconventional gas reservoirs as quickly as possible. To achieve the research objectives, we developed an integrated reservoir and decision modeling system that incorporates uncertainty. We used Monte Carlo simulation with a fast, approximate reservoir simulation model to match and predict production performance in unconventional gas reservoirs. Simulation results are then integrated with a Bayesian decision model that accounts for the risk facing operators. We applied these integrated tools to a hypothetical case based on data from Deep Basin (Gething) tight gas sands in Alberta, Canada, to determine optimal development strategies. We anticipate that the tools and methodologies developed will be applicable in most shale and tight gas reservoirs. These tools should ultimately be able to help operators determine, for example, the combination of primary development strategy (well spacing and/or completion method) and testing (pilot downspacings and/or tests of other completion methods) that maximizes future profitability. The optimal design of such programs in unconventional reservoirs, where the risks are high, is likely to pay large dividends. Copyright 2010, Society of Petroleum Engineers.
