Practical Aspects of Reserves Determinations for Shale-Gas Reservoirs
- Dennis Denney (JPT Senior Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- December 2011
- Document Type
- Journal Paper
- 53 - 56
- 2011. Society of Petroleum Engineers
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This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 144357, "Practical Aspects of Reserves Determinations for Shale Gas," by R. Strickland, SPE, D. Purvis, SPE, The Strickland Group, and T. Blasingame, SPE, Texas A&M University, prepared for the 2011 SPE North American Unconventional Gas Conference and Exhibition, The Woodlands, Texas, 12-16 June. The paper has not been peer reviewed.
Uncertainty in shale-gas reserves has significant implications at both the micro and the macro level. Conventional reservoir-engineering tools must be viewed as potentially inadequate (or even inappropriate) for evaluating shale-gas performance, primarily because of the extremely low aggregate permeability of these systems. Methods for shale-gas evaluation are discussed (including methods and limitations) that represent the physics of shale-gas production more closely; however, their implementation often is prohibitive.
Although some 20,000 horizontal shale wells have been drilled, the longest production history available is approximately 6 years. To complicate matters further, the nature of shale development creates an urgent need for accurate predictions of recovery very early in the life of a play. The industry’s ability to interpret well logs, analyze core, and understand (at least qualitatively) the geological controls on production has increased vastly and has proved to be more important than acknowledged previously. Those geological factors are more numerous and more complexly interrelated than for conventional reservoirs.
Depending upon how the methods are grouped, there are six basic engineering techniques for determining reserves in general: volumetrics, analogy, production performance, material balance, simulation, and, most recently, rate-transient analysis (RTA). Each method has its own predicates and limitations. In the case of shale gas, they also have their own idiosyncrasies for accurate application.
Material balance is not suitable because the ultralow matrix permeability makes obtaining average reservoir pressure impractical. With volumetrics, improvements in core and petrophysical analyses have led to reasonable estimates of gas in place; however, the recovery factor to be applied to an in-place figure is imprecise at best.
The many difficulties caused engineers to rely heavily on the simplest, most accessible tool: production-decline analysis. Often, very large asset purchases or even entire plays have been reduced to a single type curve on the basis of production performance. This fact concentrates and, thus, amplifies potential error. Without the benefit of good analogs or sufficient guidance from first principles, it is possible, even likely, that production analysis results in a carelessly optimistic view of ultimate recovery.
Fortunately, concentrated effort by many engineers and academics has significantly advanced the understanding of, and analysis tools for, shale gas. Simulation, RTA, and decline-analysis methods have demonstrated usefulness in shale-gas reservoirs, but they must be applied in a manner consistent with the uniquenesses of shale reservoirs.
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