An Alkaline/Surfactant/Polymer Field Test in a Reservoir with a Long-Term 100% Water Cut
Authors: Demin Wang , Jiecheng Cheng , Junzheng Wu , Fenglan Wang , Huabin Li , Xiaohong Gong 
Published: December 2007

Daqing Oil Field has already successfully implemented two alkaline/surfactant/polymer (ASP) floods with dense well spacing. To further confirm the feasibility of ASP flooding at industrial well spacing, confirm "absolute incremental oil" (incremental oil after the pay zone reaches 100% water cut by water flooding, and not incremental oil over 98% water cut as is normally calculated in China) and to further confirm the magnitude of chromatographic separation of the injected chemicals on condition of large well spacing, two ASP field tests with a larger well spacing (200m to 250m) are in progress in Daqing now, the results of one of the field tests in a more advanced stage (i.e. a larger portion of chemicals have been injected) is presented in the this paper.

This larger well spacing field test consists of 4 injectors and 9 producers forming 4 inverted five spot patterns. The distance between producers (or injectors) is 28Om and between producer and injector 200m. By the end of 1995, 7 new wells were drilled. The data from these wells showed that, on the average, 92.5% of the pay zone (PI33) were already water flooded. In these 7 new wells, 5 producers (including the center well) had a water cut of 100% for 9 months from the start of production to the time the ASP flood lowered the water cut. The average water cut of the 9 producers was 98.4%. Single well tracer logging at the center well obtained a residual oil saturation of 18+3%. By numerical simulation, the water flood recovery was already 67.2% before the ASP flood.

Core tests were performed to optimize the sequence and quantity of chemicals to be injected. The results showed that, on condition of constant quantity of polymer and surfactant injected, injecting a polymer slug before the ASP slug and injecting a tapered ASP slug can increase the recovery of the flood; increasing the viscosity of the ASP slug can offset the effect of the heterogeneity of the pay zone.

The injection scheme was optimized according to the above tests, the characteristics of the pilot area and by numerical simulation. According to the optimized program, it was predicted that the ultimate recovery of the ASP field test would be 77.2% OOIP, about 10% higher than the 100% water cut recovery and 25% OOIP higher than the 98% water cut recovery.

The polymer slug was injected during the period Sept. 18 to Nov. 2, 1996. After that, the ASP slug started to be injected. After injecting 0.09 PV of ASP, the surrounding wells started to respond by lower water cuts. The water cut of the center well dropped from 100% to 46.9%. now the cumulative incremental oil production of the center well is 7,494 t, equivalent to 12.8% OOIP increase in recovery, much better than that predicted. It is estimated that the ultimate incremental recovery will be 16 to 17% OOIP over that of 100% water cut by water flooding.

Preliminary economic analyses show the chemical cost per barrel of incremental oil is around $6.5

When the water cut dropped to 50%, the produced fluid was completely emulsified, this condition was maintained for a long period of time (0.123 PV). At reservoir temperature, the viscosity of the emulsion was 140 mPa S, and it could further emulsify oil and water. The emulsion was very stable, but it could be broken easily by a de-emulsifier developed in Daqing.

The field test shows that by optimized designing, ASP flooding of ultra-high pay zones can obtain very good technical and economical results. Large amount of emulsified fluids is an important factor for good results of ASP flooding. The results of this field test should be of important reference for ASP flooding of 100% water cut pay zones. P. 305