A Type Curve Approach to Reserves for the Big Piney Gas Field

Abstract

Various methods have been used to define the reserves for the Frontier/Muddy formations of the Big Piney Gas Field. This paper reports the results of a Piney Gas Field. This paper reports the results of a study based on production histories interpreted with constant pressure type curves. Over 80 wells were studied in detail with resulting data used to develop relationships between rate, permeability, and net pay. Using these empirical relationships, reserves for the field were determined. Gas-in-place was calculated for each well as well as effective drainage area and recovery efficiency. Individual well deliverabilities were calculated. A relationship between effective well spacing and recovery was developed. The results of the study generally agree with previous work. The type curve approach should prove previous work. The type curve approach should prove useful in providing details about effective gas-in- place and drainage area. This is not easily obtained from conventional testing. It also provides a link to analyzing newer tight gas wells by showing that type curve solutions are valid over the life of a well. Introduction An effort has been made to estimate reserves for the Frontier-Muddy formations of the Big Piney, Wyoming gas field. Because of the age of the field and extensive production history, the study attempted to link production performance with theory of flow through a production performance with theory of flow through a porous media to estimate reservoir properties which porous media to estimate reservoir properties which will control future behavior and reserves. Results show that as of June, 1980, remaining reserves of 1.94 TCF, (55 giga M), excluding the Birch Creek Unit, existed. OGIP is shown to be 5.37 TCF (153 giga M). Recovery efficiency, with no additional development, will be 45.4% of the original gas-in-place and will increase to 57.8% if the number of net producing completions doubles. Discussion The fluid flow equation used is the standard diffusivity equation:(1) The rate equation is: (2) The solution for a no flow outer boundary and a constant pressure inner boundary is given in Figure 1. It was selected because it matches production characteristics of tight gas wells. It also allows curve matching to determine reservoir properties based on the well's age and production history. Important assumptions are:The difference between initial reservoir pseudopressure and flowing wellbore pseudopressure is constant;The reservoir is homogeneous and isotropic;Wellbore damage is constant over the life of the well;The average drainage area is equal to the average well spacing;The log-log decline slope shown in Figure 1 can be approximated by a straight line for a "short" period of time not to exceed three years;Well period of time not to exceed three years;Well performance corresponds to that predicted by Equations performance corresponds to that predicted by Equations 1 and 2. Theoretical solutions to the tight gas performance problem must include the effects of fracturing. problem must include the effects of fracturing. Fractures, either natural or artificial, can normally be represented by a single vertical fracture in an elliptical reservoir (Figure 2). The fracture is centered at the wellbore, W, and extends from -Xf to +Xf. P. 123