As our industry focuses more on natural gas production and on wringing the last drop of value from each property, it has become increasingly important to properly characterize and predict the solution gas performance from our oilfields. This paper will review historical techniques for predicting solution gas production under various common process mechanisms including depletion, weak and strong water drive, gas-cap drive, and production of a volatile oil. The paper will also discuss situations where numerical simulation may be required instead of using standard analytical techniques.

The paper will present examples from the Western Canadian Sedimentary Basin that illustrate solution gas performance under each of the drive mechanisms mentioned above. Results are displayed using the "equal-value" concept, which shows the progress of each oilfield from its early life where revenue is dominated by oil sales to its later life when revenue becomes increasingly dominated by solution gas production.

Introduction to the Problem

The prediction of solution gas production is often taken for granted in oilfield forecasts, but is a multi-faceted problem when one considers the many components that impact the process (fluid and rock properties, interactions between fluids/rocks, geological properties, drive mechanisms, wellbore conditions, etc). Years ago, accurate predictions of solution gas volumes were less important because there was little or no value associated with the product. Today, the value of natural gas is essentially the same as oil on a heating value basis, so much more attention is paid to the prediction of solution gas volumes. Further, environmental pressures are driving government and industry to conserve all produced gas; and obviously it is important to understand how much gas will be produced to ensure installation of the appropriate conservation scheme.

On its face, solution gas prediction is a deceptively easy problem: pressure declines, gas evolves from the oil, and is produced. So, if one completely understands the production mechanism and can accurately predict future pressure decline, and understands the PVT properties that govern the release of solution gas, and knows the rock properties that govern the trapping and flow of gas, and has a good picture of the overall geological model, then it can be fairly simple to predict solution gas production. Further, the interplay between these factors can result in non-unique solutions. Since the primary focus is mostly on oil volumes, appropriate attention is not always paid to the variables that govern solution gas production.

The most common analytical methods for predicting solution gas production were developed by Tarner (Ref. 1) and Muskat (Ref. 2). These methods use material balance principles and a dynamic producing GOR to predict reservoir performance at pressures when the gas saturation exceeds the critical gas saturation. However, a number of simplifying assumptions were made in these analytical treatments, including thin horizontal reservoirs with negligible gravity forces (ie. no gas percolation). Other analytical approaches have been proposed that mitigate concerns with the Tarner and Muskat methods; however, all analytical methods have their own limiting assumptions.

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