Incremental-Oil Success From Waterflood Sweep Improvement in Alaska
- Danielle Ohms (BP Alaska) | Jennifer D. McLeod (BP Alaska) | Craig J. Graff (BP Alaska) | Harry Frampton (BP) | Jim C. Morgan (Jimtech) | Stephen K. Cheung (Chevron) | Kin-Tai Chang (Nalco)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Operations
- Publication Date
- August 2010
- Document Type
- Journal Paper
- 247 - 254
- 2010. Society of Petroleum Engineers
- 1.6 Drilling Operations, 5.7.2 Recovery Factors, 4.1.2 Separation and Treating, 2.4.3 Sand/Solids Control, 5.6.4 Drillstem/Well Testing, 5.4.1 Waterflooding, 2.5.2 Fracturing Materials (Fluids, Proppant), 5.6.5 Tracers, 4.1.5 Processing Equipment
- heat-activated polymer, sweep improvement
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Waterflood thief zones in communication with the rest of the reservoir are a severe and previously challenging problem. This paper gives an introduction to the nature of a novel, heat-activated polymer particulate. Details are presented of a trial of this in-depth diversion system, resulting in commercially significant incremental oil from a BP Alaskan field. The system of one injector and two producers was selected because of a high water/oil ratio and low recovery factor, which was recognized as an indicator of the presence of an injection-water thief zone and was confirmed by study of a previous injection survey. The area around the wells is bounded by faults, so the system can be considered to be isolated from surrounding wells and operations. The position of the thermal front in the reservoir, tracer transit times, injection rates, and inter-well separations indicated that the slowest reacting of the three commercial grades available was most appropriate for the trial.
The treatment was designed using laboratory tests and numerical simulation informed by pressure and chemical-tracer tests. Long-sandpack tests indicated permeability-reduction factors of 11 to 350 for concentrations of 1,500 to 3,500 ppm active particles in sand of 560- to 670-md permeability at 149°F. 15,587 gal of particulate product was dispersed using 8,060 gallons of dispersing surfactant, into 38,000 bbl of injected water, and was pumped over a period of 3 weeks at a concentration of 3,300 ppm active particles.
Placement deep in the reservoir between injector and producer was confirmed by pressure-falloff analysis and injectivity tests. The incremental oil predicted from the simulation was 50,000 to 250,000 bbl over 10 years. In fact, more than 60,000 bbl of oil was recovered in the first 4 years at a cost comparable with that of traditional well work and less than that of sidetracking.
|File Size||1 MB||Number of Pages||8|
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