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Liquid CO2 Behaviour during Water Displacement in a Sandstone Core Sample
Gas Science and Engineering ( IF 5.285 ) Pub Date : 2019-02-01 , DOI: 10.1016/j.jngse.2018.12.005
Ebraheam Al-Zaidi , Xianfeng Fan

Abstract CO2 sequestration in saline aquifers and hydrocarbon reservoirs is a potential strategy to reduce CO2 concentration in the atmosphere, enhance hydrocarbon production, or extract geothermal heat. CO2 injection is considerably influenced by the interfacial interactions, capillary forces and viscous forces. Any change in the subsurface conditions of pressure, temperature, and salinity is likely to have an impact on the interfacial interactions, capillary forces and viscous forces, which, in turn, will have an influence on the injection, migration, displacement, and CO2 storage capacity. In this study, unsteady-state immiscible experimental investigations have been performed to explore the impact of fluid pressure, temperature, salinity (brine concentration and valency) and injection rate on the dynamic pressure evolution and displacement efficiency when CO2 as a liquid phase is injected into a water-saturated sandstone core sample. This study also highlights the impact of capillary forces and viscous forces on the two-phase flow properties and shows when capillary forces or viscous forces are dominant. The results reveal a moderate to considerable impact for the fluid pressure, temperature, injection rate, and salinity on the differential pressure profile, water recovery (WR), endpoint CO2 relative permeability (KrCO2), and cumulative produced volumes. Overall, increasing fluid pressure, CO2 injection rate and salinity (brine concentration and valency) cause an increase in the differential pressure profile; the highest increase occurred with the injection rate. In general, increasing temperature caused a reduction in the differential pressure profile. The WR is in range of around 61.6–69.3% while the KrCO2 is in range of 0.112–0.203, depending on the parameters investigated. Increasing fluid pressure and injection rate caused an increase in the WR; the highest increase occurred with the injection rate. On the other hand, increasing temperature and salinity caused a decrease in the WR; the highest reduction occurred with salinity. Nevertheless, the increase in fluid pressure, temperature, injection rate and salinity led to a reduction in the KrCO2; the highest reduction occurred with increasing temperature whilst the lowest occurred with increasing fluid pressure. The cumulative produced volumes decreased with fluid pressure and salinity but showed no noticeable change with temperature and injection rate. The capillary forces have less impact on the differential pressure profiles than viscous forces when fluid pressure, temperature and injection rate increase but the capillary forces show more impact as salinity increase.

中文翻译:

砂岩岩心样品中水驱替过程中的液态 CO2 行为

摘要 咸水层和油气藏中的 CO2 封存是降低大气中 CO2 浓度、提高油气产量或提取地热的潜在策略。CO2 注入受界面相互作用、毛细管力和粘性力的影响很大。压力、温度和盐度等地下条件的任何变化都可能对界面相互作用、毛细管力和粘性力产生影响,进而对注入、运移、置换和 CO2 储存产生影响容量。在这项研究中,进行了非稳态不混溶实验研究,以探讨流体压力、温度、当 CO2 作为液相注入含水饱和砂岩岩心样品时,盐度(盐水浓度和化合价)和注入速率对动态压力演变和驱替效率的影响。这项研究还强调了毛细力和粘性力对两相流动特性的影响,并显示了毛细力或粘性力何时占主导地位。结果表明,流体压力、温度、注入速率和盐度对压差剖面、水回收率 (WR)、终点 CO2 相对渗透率 (KrCO2) 和累积产量有中等至相当大的影响。总体而言,增加流体压力、CO2 注入速率和盐度(盐水浓度和化合价)会导致压差分布增加;最大的增加发生在注射速率。一般而言,升高温度会导致压差分布减小。WR 大约在 61.6-69.3% 的范围内,而 KrCO2 的范围在 0.112-0.203 之间,这取决于所研究的参数。增加流体压力和注入速率导致 WR 增加;最大的增加发生在注射速率。另一方面,温度和盐度的增加导致 WR 的降低;最大的减少发生在盐度上。尽管如此,流体压力、温度、注入速率和盐度的增加导致 KrCO2 的减少;温度升高时降低幅度最大,流体压力升高时降低幅度最低。累积产量随流体压力和盐度而降低,但随着温度和注入速度的变化没有明显变化。
更新日期:2019-02-01
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