Application of decline curve analysis in shale gas reservoirs is known to produce reserve estimates that are unphysical and/or unrealistic. It has been suggested that the assumptions inherent to these models may not always be valid in shale gas wells. For example, the boundary dominated flow period that leads to exponential decline may take years to develop in unconventional gas fields. Also, the impact of matrix adsorption/desorption processes on decline curve model parameters has not been fully investigated. To this end, we use a numerical simulator to understand key factors affecting production decline in shale gas reservoirs, and examine the appropriateness of decline curve based forecasting to model long-term flow behavior.

A numerical model was constructed to simulate production from a horizontal well in a hydraulically fractured shale reservoir. Parameters varied in the evaluation include: (a) reservoir properties, (b) hydraulic fracture properties, (c) well properties, and (d) operational parameters. Ranges in values considered for the model parameters were obtained from published data on major shale-gas plays. Simulated gas production rate time histories were evaluated using standard decline curve analysis techniques.

Our results indicate that long-term production estimates are most sensitive to hydraulic fracture and well characteristics, average pressure and permeability in the stimulated reservoir volume, and to a lesser degree on matrix flow and adsorption processes. Fitted decline curve model parameters generally exhibit time dependence, which affects the accuracy of ultimate recovery estimates with limited production data. The findings from this study suggest that although decline curve based reserve estimates may be appropriate under some conditions, it would be useful to apply a mechanistic (physics based) model for history matching production data and verify the results of decline curve analysis.

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