Waterflooding of A Heavy Oil Marginal Reservoir

Abstract

This paper shows how Gupco (Gulf of Suez Petroleum Company) has successfully developed a heavy oil marginal reservoir by using high technologies such as reservoir simulation, 3-D visualization, coiled-tube dual completion, and coiled tube pipeline. The July 53 block was discovered in January 1986 with the drilling of the vertical platform proving well J-53. The well was drilled to test the Lower Rudeis formation in a 90-acre sliver block to the west of the main Lower Rudeis July field. The test indicated a potential of 1350 BOPD with an API gravity of 19 degrees, an oil viscosity of 7 CP, and a gas-oil-ratio of 85 SCF/STB. For this reservoir fluid type, the recovery factor was expected to be less than 5% under primary conditions. Therefore, the development of this fault block was put on hold until further studies could determine the optimum plan of depletion. Starting in 1993, GUPCO began studying small reservoirs such as the J53 block with a PC-based black oil simulator. In the case of J53, the simulator was used to match the short term DST from the discovery well, and then create multiple depletion scenarios. Waterflooding, it was discovered, would provide the best development plan. Use of the simulator provided insight into the recovery process, and reduced the development risk. Under primary recovery, the simulator confirmed a low ultimate recovery of 3% of the OOIP. With the optimal waterflooding plan, however, recovery could be improved to 23% of the OOIP. Considering that normal Lower Rudeis oil recovery approach 54% of the OOIP under waterflooding (in the main field with 32 degree API oil), the simulator provided a much more conservative estimate. The development of this fault block was started in May 1996 by drilling a high angle producer designed to be parallel and close to a major fault to encounter the full Lower Rudeis section. Waterflooding was started in December 1996 by completing an existing Nezzazat producer with a unique coiled-tube dual water injection - oil production completion. A 3 1/2 inch coiled tubing line was laid to provide injection water from a near platform at almost 7000 BWPD. Performance to date indicates a successful waterflood project. The well's production rate has increased from 1300 BOPD, before waterflood start, up to the peak production rate of 4100 BOPD.

Water-Injection Optimization for a Complex Fluvial Heavy-Oil Reservoir by Integrating Geological, Seismic, and Production Data

“…Water is much more mobile than viscous oil, so it will break through earlier and dominate fluid production much more than it would for light oil in the same reservoir. However, waterflood is still widely used in heavy-oil-field practices because it is economic (Ko et al 1995;Hanafy and Mansy 1999;Smith 1992;Farouq Ali 1974;Alikhan and Farouq Ali 1983;Jennings 1966;Adams 1982;Etebar 1995;Miller 2005;Willhite 1986;Kumar et al 2008). Beliveau (2009) presented a summary of viscous-oil waterfloods around the world.…”

High-Mobility-Ratio Waterflood Performance Prediction: Challenges and New Insights

“…Waterflood has been conducted in many high-viscosity reservoirs in the past, and several water-injection projects in high-viscosity reservoirs are ongoing and planned around the world (Oefelein and Walker 1964;Jennings 1966;Roark 1960;Nelson 1976;Woodling et al 1993;Jenkins et al 2004;Adams 1982;Edgson and Czyzewski 1985;Kasraie et al 1993;Smith 1992;Lim et al 1993;Ko et al 1995;Etebar 1995;Pallant et al 1995;Foerster et al 1997;Yang et al 1998;Forth et al 1996;Yao 1999;Hanafy 1999;Cook et al 2000;Jayasekera and Goodyear 2000;Capeleiro Pinto et al 2001). However, published data on HMRWF performance are limited, and results are sometimes conflicting.…”