Summary 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 interwell 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.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWaterflood 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 of a trial of this in-depth diversion system, resulting in commercially significant incremental oil from a BP Alaskan field are presented. 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 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 1500 to 3500 ppm active particles in sand of 560 to 670 mD permeability at 149°F. 15,587 gallons of particulate product was dispersed, using 8,060 gallons of dispersing surfactant, into 38,000 barrels of injected water and pumped over 3 weeks at a concentration of 3300 ppm active particles.Placement deep in the reservoir between injector and producer was confirmed by pressure fall off analysis and injectivity tests. The incremental oil predicted from the simulation was 50,000 to 250,000 bbl over 10 years. In fact over 60,000 barrels of oil was recovered in the first 4 years at a cost comparable with traditional well work and less than sidetracking. Bright Water injectionMixing surfactant : EC 9360A

Maintaining proper waterflood conformance is a critical component of waterflood management. Most methods used to control waterflood conformance have proven to be only marginally effective. A unique technique has been developed for creating a durable reservoir flow restriction that diverts injected water into unswept reservoir sections. Placement of the restriction is based in the location of the thermal front between the injector and producers. The performance of this thermally activated particulate system for waterflood conformance control has been evaluated in a three injection well trial in the Prudhoe Bay oilfield, Alaska. The aim of the trial was to determine the incremental oil produced and improvement of sweep efficiencies for three interior water injection patterns in the east waterflood area of Greater Prudhoe Bay Unit.

Maintaining proper waterflood conformance is a critical component of waterflood management. Most methods used to control waterflood conformance have proven to be only marginally effective. A unique technique has been developed for creating a durable reservoir flow restriction that diverts injected water into unswept reservoir sections. Placement of the restriction is based in the location of the thermal front between the injector and producers. The performance of this thermally activated particulate system for waterflood conformance control has been evaluated in a three injection well trial in the Prudhoe Bay oilfield, Alaska. The aim of the trial was to determine the incremental oil produced and improvement of sweep efficiencies for three interior water injection patterns in the east waterflood area of Greater Prudhoe Bay Unit.

We have made substantial improvements to the previously published methods for geochemical allocation of commingled oil production and/or commingled gas production. This new method has allowed allocation of commingled production from wells at less than 2-5% of the cost of production logging. Four case studies are shown here. In the first two studies, commingling of the wells was subject to approval of the Alaska Oil and Gas Conservation Commission (AOGCC). Before agreeing to the use of geochemical allocation, the AOGCC required the well operator to perform multi-month trial studies in which the wells were monitored both by geochemical allocation and by production logging. The individuals performing the geochemical allocation were kept blind from the results of the production logging until the studies were completed. Close agreement between the geochemistry-based allocation values and the production-logging-based allocation values resulted in AOGCC approval of continued use of the geochemical method for oil production monitoring of these two wells. Two additional case studies presented here illustrate how geochemical allocation can be used to monitor the effects on production of (1) changes in water injection into nearby wells, and (2) closing or opening perforations within a well.