Analytical Development of an Improved Inflow Performance Relationship (IPR) Model for Solution Gas Drive Reservoirs

Attempts had been made by many authors to develop an inflow performance relationship model suitable for solution gas drive reservoirs. However, they have not been as successful as most of the developed models suffer from certain degrees of inaccuracies and this necessitates the need for an improved model as the economic analysis of an oilfield greatly depends on the ability to accurately forecast future productions. Therefore, the objective of this research is to develop an improved inflow Performance Relationship model for solution gas reservoirs by employing a purely analytical approach and also compare the performance of the developed model with that of the existing IPR models (Vogel, Wiggins, Fetkovich, and Klins and Majher). A series expansion of the pseudo-steady state solution of the equation that governs fluid flow in reservoirs of radial geometry is obtained using Taylor's method and the infinite series obtained is truncated after a reasonable number of terms to ensure high degree of accuracy while also avoiding computational complexity. Moreover, the unknown coefficients in the truncated series were determined using the available reservoir fluid data. Finally, statistical analysis was carried out to determine the degree of deviation of the new and existing IPR models from the actual IPR. This analysis shows that the improved model (with an average coefficient of determination of 0.97) outperforms the existing IPR models to which it was compared. Therefore, the improved model is recommended for situations where extreme accuracy is of utmost importance. Doi: 10.28991/HEF-2021-02-02-04 Full Text: PDF

Natural Dumpflood in Malaysia Succeeds as Low-Cost Offshore Oil-Recovery Method

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 196498, “First Natural Dumpflood in Malaysia: A Successful Breakthrough for Maximizing Oil Recovery in an Offshore Environment With Low-Cost Secondary Recovery,” by Muhammad Abdulhadi, SPE, Toan Van Tran, SPE, and Najmi Mansor, Dialog Group, et al., prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29–31 October. The paper has not been peer reviewed. The complete paper describes the first successful implementation of natural dumpflooding offshore Malaysia as a case study to provide insight into the value of using the approach to maximize oil recovery in a mature field, particularly in a low-margin business climate. Background Field B, located offshore Balingian province approximately 80 km northwest of Bintulu, has a water depth of 90 ft and is highly compartmentalized and faulted, with almost 100 faults present. The field features three subfields further divided into nine major fault compartments. Eight primary reservoirs exist, with more than 20 subreservoirs stacked atop one another with multiple drive mechanisms, including water drive, gas-cap drive, and solution gas drive. Several of these subreservoirs are thick sands between which communication exists through juxtapositions, shared gas caps, or aquifer. Other subreservoirs are isolated by thin layers of shale apparent in certain wells but absent in others. The high complexity of Field B requires any opportunity identified to be thoroughly evaluated and examined before execution. Field B is a moderately sized field discovered in 1976, with production commencing in 1984. During the 30 years of oil production, the field peaked at 30,000 B/D in 1990 and dipped to 3,000 B/D in late 1999. The facilities consist of four drilling platforms, a processing platform, and a compressor platform. A total of 48 wells were drilled in the field, with most wells completed as dual-string producers. The recovery factor (RF) of the reservoirs ranges from 10% for solution gas drive to 50% for strong water drive. The behaviors of these reservoirs are starkly different. The solution gas-drive reservoirs have poor-quality sand (less than 200 md), a low productivity index, limited sand thickness (less than 30 ft), limited sand connectivity, and sharp pressure decline after 2 to 3 years of production. The water-drive reservoirs, however, have good-quality sand (up to 5,000 md), a high productivity index, thick sand (greater than 40 ft), extensive sand connectivity, and limited pressure decline. The stark differences in the reservoirs’ behavior further complicate field management. The field currently is in late life, with recovery to date of 19% with an RF of 23%. Most of the water-drive reservoirs are already swept up to the crest, while the solution gas-drive reservoirs are depleted nearly to abandonment pressure. After 30 years of production, the total field water cut was at 80%, while oil production was approximately 5,000 B/D, signifying the diminishing economic life of the field.