Average reservoir pressure determination for homogeneous and naturally fractured formations from multi-rate testing with the TDS technique

Abstract

Average reservoir pressure is an important parameter which is utilized in almost all reservoir and production engineering studies. It also plays a relevant role in the majority of well intervention jobs, field appraisal, well sizing and equipment and surface facilities design. The estimation of the average reservoir pressure is normally obtained from buildup tests. However, it has a tremendous economic impact caused by shutting-in the well during the entire test. Since buildup tests are the most particular case of multi-rate tests, these are also used for estimation of the average reservoir pressure. Among them, two-rate tests present drawbacks because it is operationally difficult to keep constant the flow rates. Conventional methods for determination of the average reservoir pressure can be readily extended to multi-rate tests once the rigorous time is converted to equivalent time by time superposition. In this article a new, easy and practical methodology is presented for the determination of the average pressure in both homogeneous and naturally fractured reservoirs from multi-rate tests conducted in vertical oil wells located inside a close drainage region. The methodology which follows the philosophy of the TDS technique uses a normalized pressure and pressure derivative point found on any arbitrary point during the pseudosteady-state flow regime to readily provide the average reservoir pressure value. For verification of the effectiveness of the proposed solution, several field and simulated examples were worked out. We found that the average reservoir pressure results obtained from the proposed methodology match very well with those estimated from either conventional techniques or simulations.