Calculation of Average Reservoir Pressure during Primary and Secondary Recovery and Under Variable Boundary Conditions

Abstract

Abstract A new method is introduced to calculate the average reservoir pressure around wells from pressure buildup or falloff tests regardless of the shape of the drainage area or the types of boundaries surrounding it. Practicing engineers can apply the proposed method using any of the widely available Well Testing programs. Average reservoir pressure is used in just about all reservoir engineering studies conducted via simulation, material balance, or even decline curve analysis. Existing techniques, such as the Matthews-Brons-Hazebroek (MBH) method (1954), are valid for limited drainage shapes and boundary conditions. In particular, they cannot handle secondary recovery projects (waterflooding, steam injection, etc.), or irregular drainage shapes which are routinely used in the industry. As a result, typically the value of p* is used as a substitute for average reservoir pressure, which may result in significant error. The new method enables petroleum engineers to calculate the average reservoir pressure accurately for every reservoir type by integrating transient, production, and static data. Our technique calculates a robust approximation of the drainage area based on the production/injection history for each well in the reservoir. A given well may be offset by other injection and production wells and no-flow and/or constant-pressure boundaries, all of which are taken into account for estimation of the drainage area. Our technique also accounts for areal variations in reservoir thickness and depth. The size and shape of the drainage area directly impacts the average pressure characteristics, which can be calculated with the help of relatively simple runs using a reservoir simulator. The results are generalized by creating type curves similar to the MBH type curves for each well in the reservoir. The new method was applied to several wells in a large oil field offshore Nigeria with the methodology and results presented in this paper. The new technique enables us to calculate the average reservoir pressure accurately for every reservoir type, all drainage area shapes and boundary conditions, a variety of production patterns, and for multiphase flow conditions. It is difficult to overestimate the value of properly calculated average reservoir pressure. It is one of the main parameters used to history match field data. It affects multiple drilling and production optimization decisions like, infill drilling, mud pressure, and determining flow rates of producers and injectors. With accurate average reservoir pressure, optimization of field management is possible by determining the number and the locations of infill wells, the level of injection and production from different wells, and other reservoir performance related decisions. The new method significantly improves our ability to produce valid values of average reservoir pressure.