Study Details Strategy of Bottom-Up Water injection in a Heavy Oil Reservoir

Abstract

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203783, “Challenges, Opportunities, and Threats of Deep Bottom-Up Water Injection in a Heavy Oil Reservoir: Lessons Learned From the G Field, South Oman,” by Chaitanya Behera, SPE, Sandip Mahajan, and Carlos Annia, Petroleum Development Oman, et al. The paper has not been peer reviewed. _ The complete paper presents the results of a comprehensive study aimed at improving the understanding of deep bottom-up water injection, which enabled optimizing recovery in a heavy oil field in south Oman. The work concludes that the well-reservoir-management (WRM) strategy for a heavy oil field is not the same as one for a classic light oil waterflood. Nevertheless, the reservoir heterogeneity, oil-column thickness, and saturation history also are important factors for variable water-injection response in a heavy oil field. Field Background The G field is on the eastern flank of the South Oman Salt Basin 700 km south of Muscat. The main producing reservoir, the Mahwis sand of the Haima group, culminates in two accumulations (G Main and G East). The Mahwis formation is composed of clastic sediments interlayered with several cemented zones, which often act as baffles in some areas (Fig. 1). However, all stratigraphic units are hydrodynamically connected. No major pressure shift along repeat-formation-tester (RFT) pressure profiles was observed, except at few locations across a major baffle in an oil leg in the crestal area. The reservoir quality is good, with porosity averaging 28% and permeability in the range of 200–2000 md. The maximum oil column thickness is approximately 70 m. Oil viscosity ranges from 250 to 1500 cp across the field both laterally and vertically. The viscosity in the northeast crestal area is relatively low compared with the thee southeastern part of the field. The compositional grading, multiple charging, and biodegradation of oil close to the oil/water contact (OWC) contribute to such a widespread variance in oil viscosity across the G field. The field, initially delineated by five vertical wells in 1990–91, was developed in multiple phases by horizontal producers placed at the top of the reservoir. The field produced under primary depletion until deep bottom-up water injection began in 2015. Water-Injection Development A secondary recovery scheme with infill wells and bottom-up water injection was proposed in 2009 as reservoir pressure dropped by 40%. The water-injection development consisted of injecting untreated produced water at a depth of 100 m below the original OWC under fracture conditions through 35 vertical water injectors. One hundred and thirty-three infill horizontal producers (86 single laterals and 47 dual laterals) were proposed to drill at a denser spacing. The infill campaign began in 2010, while water injection was initiated in December of 2014. The plan was to ramp up the water-injection rate to 70 000 m3/d in 3 years and double the field liquid production. After 3 years of water injection, however, only 33% of the predicted incremental rate was achieved. Approximately 40% of the incremental reserves of the redevelopment scheme was estimated to be at risk.