喇南聚驱后羧酸铬流动凝胶驱油试验研究

Analysis of Flowing Gel Flood Pilot After Polymer Flood in South Lamadian Oil Field

大庆喇嘛甸油田聚驱后葡I1～2层采收率约50%.1999.9～2001.9在喇南一区进行了聚驱后流动凝胶驱油试验,本文报道试验结果及结果分析.试验区为五点法面积井网,注入井6口,采出井12口,其中两口中心井采收率为53.96%和51.99%.新钻井资料表明未水淹、低水淹层多分布于单元顶部低渗层,数模分析表明平面上剩余油多分布在试验区边部,中心区含水饱和度62.5%.注入聚合物/羧酸铬流动凝胶后,①吸水剖面改善;②4口采出井含水下降,产油量增加,中心区采收率提高0.8%;③后续注水时含水上升慢,每注水0.01 PV,9口采出井含水平均上升0.04%,对比水驱井为0.14%.注入过程中注入井口取样成胶率为91.7%,3～5天成胶粘度超过2×103mPa·s的占82.0%,最高粘度达2×104mPa·s;返排深度～3 m,20 h返排液地面粘度超过2×104 mPa·s,这些数据说明注入体系在地面条件下成胶性能良好.注入压力上升幅度小,视吸水指数下降幅度小;注入体系阻力系数和残余阻力系数小;有一口井产出少量Cr3+,产出液在地面能形成凝胶;初始粘度24 mPa·s的注入体系在30～50℃下常压静置2天后粘度为610 mPa·s,在高压条件下流动7天后粘度仅为9.1 mPa·s;这些现象说明注入体系在油层条件下成胶性能较差.图2表2.

About 50% oil was reoovered from pay layers P Ⅰ 1-2 in Lamadian oil field, Daqing, after polymer flood completed. In Sept 1999--Sept 2001, a flowing gel flood pilot was conducted in block S-1, Lamadian. The results of the pilot are presented and analyzed in this paper. The experimental area （EA） of five spot well pattern consisted of 6 injection and 12 production wells and 53.96% and 51.99% oil had been recovered from two central production wells after polymer flood. The water unflooded and less flooded zones were located mostly at the low permeable top sublayers as shown by newly drilled well data and planarly the residual oil was placed mostly in the periphery of the EA and the water saturation in the central part of the EA was of 62.5 % as shown by a digital simulation. Injecting polymer/chromium earbxylate flowing gel resulted in ① notable improvement in the watertake profile; ② decrease in water cut and increase in oil productivity in four wells and enhancement in oil recovery by 0.8 % in the central part of the EA; ③ lowering down of water cut ascending rate （WCAR） in the course of successive water flooding： WCAR being of 0.04% per 0.01 PV water injected against 0.14% for water flooding areas. The gelation behavior of the polymer/Cr^3＋ gelling fluid was good at surfaces as evidenced by the following data： 91.7% fluid samples taken at the injection well heads was gelled and 82.0%- developed their viscosity up to 〉2.0 Pa·s in 3--5 days with highest gel viscosity 〉20 Pa·s; the fluid injected could he flown back from the reservoir formations --3 m far from the borehole and the fluid flown hack in 20 hrs developed at surfaces viscosity 〉20 Pa · s. The gelation behavior of the fluid in reservoir formations was rather poorer as demostrated by the following phenomena： small amplitude of injection pressure ascending and of apparent water injeetivity index descending; small values of resistance and residual resistance factors; proper gel formation from water samples produced from one well and containing a little amount of Cr^3 ＋ ; that the gelling fluid of initial viscosity 24 mPa＇s get high viscosity of 610 mPa·s at atmospheric pressure in 2 days standing but low viscosity of 9.1 mPa·s in 7 day flowing at high pressure at temperatures 30--50℃.