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Steam Assisted Gravity Drainage (SAGD) is a widely used thermal recovery method for heavy oil and bitumen. S-13832 reservoir in Liaohe oil field in China is reaching economical limit after several cycles of cyclic steam stimulation (CSS). To improve the recovery, toe-to-heel air injection (THAI) had been field tested, however with unfavorable results. In this study, we analyze the alternative SAGD process and show it as most promising follow-up for CSS in S1-3832 reservoir. We first conduct comprehensive summary of reasons for the previous THAI trial failure, including lack of knowledge for shale layer distributions, difficulties in control spreading of combustion front and blockage of wellbore. Then, numerical simulation has been performed to investigate the feasibility and advantage of using SAGD process in S1-3832. A fine-grid reservoir model with shale layers carefully characterized for reservoir heterogeneity and oil-water distributions modeled. Finally, history match of the field is carried out and dominant influencing factors for SAGD recovery were determined in order to establish an optimum reservoir development strategy. Vertical injector-horizontal producer and vertical injector-vertical producer hybrid well configuration is adopted in the type pattern simulation model. Key parameters such as perforation locations, steam quality, production-injection ratio, injection rate and SAGD transition time are optimized. It is observed that steam chamber shape is irregular due to the presence of shale layers in some locations. Based on shale layer characteristics of the reservoir, perforation positions together with injection and production rates are adjusted to improve the conformance in these areas. According to these findings, a practical development strategy is designed. Ultimately, the simulation results show the production rate, accumulative oil-steam ratio and other indicators satisfy the requirement of economic development, with incremental recovery factor of 39%in the SAGD stage. The optimum development plan has been successfully implemented for more than 1 year now, with monitored temperature showing steam chamber growth in favorable manner in the entire reservoir, even in area above shale barriers. With thermal communication achieved, production rate increases progressively, indicating a smooth transition to SAGD mode. This work has demonstrated SAGD as effective recovery process in S1-3832. It also provides technical guidance for designing follow-up processes to CSS for similar reservoirs.
Steam Assisted Gravity Drainage (SAGD) is a widely used thermal recovery method for heavy oil and bitumen. S-13832 reservoir in Liaohe oil field in China is reaching economical limit after several cycles of cyclic steam stimulation (CSS). To improve the recovery, toe-to-heel air injection (THAI) had been field tested, however with unfavorable results. In this study, we analyze the alternative SAGD process and show it as most promising follow-up for CSS in S1-3832 reservoir. We first conduct comprehensive summary of reasons for the previous THAI trial failure, including lack of knowledge for shale layer distributions, difficulties in control spreading of combustion front and blockage of wellbore. Then, numerical simulation has been performed to investigate the feasibility and advantage of using SAGD process in S1-3832. A fine-grid reservoir model with shale layers carefully characterized for reservoir heterogeneity and oil-water distributions modeled. Finally, history match of the field is carried out and dominant influencing factors for SAGD recovery were determined in order to establish an optimum reservoir development strategy. Vertical injector-horizontal producer and vertical injector-vertical producer hybrid well configuration is adopted in the type pattern simulation model. Key parameters such as perforation locations, steam quality, production-injection ratio, injection rate and SAGD transition time are optimized. It is observed that steam chamber shape is irregular due to the presence of shale layers in some locations. Based on shale layer characteristics of the reservoir, perforation positions together with injection and production rates are adjusted to improve the conformance in these areas. According to these findings, a practical development strategy is designed. Ultimately, the simulation results show the production rate, accumulative oil-steam ratio and other indicators satisfy the requirement of economic development, with incremental recovery factor of 39%in the SAGD stage. The optimum development plan has been successfully implemented for more than 1 year now, with monitored temperature showing steam chamber growth in favorable manner in the entire reservoir, even in area above shale barriers. With thermal communication achieved, production rate increases progressively, indicating a smooth transition to SAGD mode. This work has demonstrated SAGD as effective recovery process in S1-3832. It also provides technical guidance for designing follow-up processes to CSS for similar reservoirs.
This paper presents the key aspects of nitrogen-assisted cyclic steam stimulation field trial at Post-CHOPS wells in FNE field, Sudan. FNE field is a heavy-oil asset with compositional gradient (13.87 to 18.1°API, in-situ viscosity of 226 to 255 cp) in massive unconsolidated sandstones at depths of 1,500 to 1,900 ft, with a permeability of 2 to 9 Darcies and strong bottom-water drive. Initially, cold heavy oil production with sand (CHOPS) was applied to exploit easy oil at upper zones of entire play. When flow rates of CHOPS wells declined to economic limits, or producers were too cool (reservoir temperature 111°F) to pump efficiently, nitrogen-assisted cyclic steam stimulation was to increase reservoir pressure, decrease heavy-oil viscosity, and boost well production. The specific technical points are highlighted below: In-house studies, including viscosity reduction test and numerical simulations, recommended that steam volume (cold-water equivalent) of 11,442 bbl per cycle based on 268 bbl/ft, with 70 to 75% quality, will be injected into the reservoir at rate of 1,260 bbl/d, nitrogen injection volume per cycle is 4.75 MMscf, soak time is for 5 to 7 days to allow the heat and pressure to distribute more uniform through the reservoir, then go to puff process. Pump is set 30-60 ft below the lowermost perforations to maximize fluids production through keeping fluid-level well below bottom perforations. By the end of pumping, bottomhole flowing pressure can declined to 70 psi. Steam and nitrogen injection sequence at updip wells is to inject steam first, followed by nitrogen injection. For downdip wells, nitrogen injection is the first and steam injection comes later to mitigate water influx. Re-completion strategy: squeeze cement into CHOPS producing zones because they contain wormholes, some communicating with aquifer, and perforate the lower pay interval to extract more viscous heavy oil. Failure risk assessment of production casings: pre-tensioning and full cementing of the casing with thermal cement is adopted in CHOPS wells for post-CHOPS thermal operation. Initial flowback flow rate is limited to less than the level of 500 bbl/d to reduce sanding risk and does not unduly de-pressure the formation at initial production. During pumping process, all fluids are exploited up the tubing string and the annulus is vented the flow-line. Pump works at optimal rate to ensure pressure drawdown less than critical drawdown threshold for sanding and water coning. Field data confirmed that this trial is successful, with 2 to 3-fold production gain, relatively low water cut and no sanding issue. This technology is a useful option for post-CHOPS wells in the similar heavy-oil assets.
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