Evaluating and Developing Tight Gas Reserves—Best Practices

Abstract

Tight gas is becoming an increasingly important asset for petroleum companies. Proper reservoir evaluation and development planning is critical to the success of a tight gas play. To date, the "best practices" for evaluating tight gas performance have not been well defined, and many companies use unreliable or unnecessary methods. As a result, analysts commonly misinterpret (and incorrectly book) tight gas reserves. Furthermore, the development of tight gas reservoirs is often conducted inefficiently, either through overcapitalization (too many wells, too quickly) or ineffective recovery (overly sparse spacing). This paper presents a straight forward and technically sound approach for evaluating and planning the development of tight gas reservoirs. The critical step in the process is proper identification of the dominant reservoir flow regime. Without this step, we cannot choose the correct analysis plot to use. The techniques detailed in this paper are designed for production data sets ranging from about 3 months and upward. The reservoir and production characteristics (permeability, xf, flow regime) are determined using pressure/rate transient analysis, as are the drainage region and its expansion rate. The resulting model predicts well performance and the rate of increase of accessible recovery over time. Superposition of the appropriate economic model and well constraints allows the analyst to identify a practical range of EUR values that is more reliable than that provided by conventional decline curves. This process can be applied to reserve evaluation as well as optimizing well spacing in the reservoir. The analysis is performed through interpretation of a diagnostic plot paired with an appropriate recovery plot (using well constraints and economics). It is validated using simulated and field examples. Introduction Tight gas is often defined by reservoir permeabilities below 0.1 millidarcies. In the context of this work, tight gas implies a formation that is not productive without some kind of mechanical intervention. In this paper, we limit our discussion to completions consisting of vertical wells with induced hydraulic fractures. However, most of the concepts can be easily extended to horizontal or more complex completions. The major publications in this field are shown in the references 1–16. Best Practices In the following, we describe what we consider to be best practices for evaluating performance data from tight gas reservoirs. The purpose is twofold:To establish reliable and timely estimates of expected ultimate recovery (EUR)To enable effective planning and development of tight gas fields To accomplish the above, a general procedure will be developed, as follows:Use a diagnostic plot (log-log) to characterize the dominant reservoir flow regime(s)Use analysis plots to interpret region-of-influence (ROI), drainage volume (OGIP), and transient properties. These analysis plots are well documented in the literature by Fetkovich 16, Blasingame 1, Agarwal 2 and Wattenbarger 3Use analytical forecast models and recovery plots to assess expected ultimate recovery (EUR) and its associated uncertainty range (new concepts introduced)Use Spacing Optimization plots to establish optimum well spacing (new concepts introduced).

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