Design Of Carbon Dioxide Injection In Wangchang Oilfield-Jianghan Basin, China

Carbon Capture and Storage of CO2 gas into deep saline aquifers is one of the ways of reducing CO2 emissions from the atmosphere thereby mitigating the Green House Effect and the resultant climate change. However, large scale injection of CO2 into the saline aquifers such as those found in Wangchang Oilfield-Jianghan Basin, China will induce a variety of coupled physiochemical processes that are still not well known and need to be well understood in order for this technology to be widely feasible. These physicochemical changes will result from multiphase fluid flow, solute transport and chemical reactions between CO2 and the formation waters and source rocks. Therefore this study is the first investigation on the design CO2 injection into Wangchang Oilfield using the fluid and property module EC02N of the general purpose numerical simulator, TOUGH2 version 2. In our study, a model concept has been designed taking into account the effect of four parameters namely: (1) salinity; (2) residual gas saturation; (3) vertical to horizontal permeability ratio; (4) CO2 injection rate. In addition, another model is designed to simulate CO2 storage in a layered formation consisting of three sandstone aquifers separated by two low permeability caprocks of mudstone and salt. In all simulations, CO2 injection is done for (ten) 10 years and the models are run to a maximum simulation time of 500 years. A risk assessment on CO2 leakage via a fault in the caprock is also modeled using a 1-dimensional model. The main conclusions of this research can be summarized as follows:-Effect of salinity·Increase in salinity (from 12wt.% to 21wt.% and 30wt.%) the amount of CO2 dissolved in the formation brine. For base-case, 42.7% of CO2 is stored in dissolved form, for case 2,26.6%. The least amount of 20.3% is stored in case 3. A larger volume of CO2 is held as a free gas phase for high salinity brine.·With increased injection time and at higher salinity, more CO2 is held as a free gas in the formation due to greater buoyancy forces. This in turn means that if the gas migrates towards areas of discontinuities in the formation such as faults, fractures or abandoned oil wells in Wangchang, the likelihood of CO2 leakage is heightened with higher salinity.·Higher salinity causes greater pressure buildup in the formation hence chances of leakage are increased, threatening caprock integrity and thwarting the goal of CO2 geological storage. This is especially so if longer injection periods are maintained at higher injection rates.·Higher salinity causes more formation of dry out zones near the injection well due to precipitation of salt. Due to higher salinity at Wangchang, there may be greater halite formation at the injection zone with longer injection times (greater than 10 years for our case) hence the likelihood of overall reduction in injectivity due to clogging of the wellbore is probable.Effect of residual gas saturation (Sgr) ·Increase in Sgr from 0.05 to 0.25 leads to reduced solubility trapping and increase in gas trapping. At the end of 500 years simulation time, only 24% of total CO2 injected is stored in solution form in case 4a compared to base-case's 42.7%. In case 4b, the gas saturation value was reduced to 0.025 and 43.3% of the gas was trapped by solubility trapping. For the layered formation (case 7), Sgr was increased to Sgr 0.30 (case 8) and only 15.3% of the injected CO2 is stored in solution form compared to 31.1% in case 7. This means that in at higher Sgr values, a larger percentage of CO2 is immobilized structurally through hydrodynamic and residual trapping in the formation. Sgr is therefore a significant parameter to be considered in CO2 injection and storage projects where at smaller Sgr values, a greater amount of the gas would remain mobile leading to increased contact between CO2 and fresh brine which in turn increases dissolution of CO2 in brine, and the reverse is true.Effect of vertical to horizontal permeability ratio (Kv/Kh)·Increase in the Kv/Kh ratio decreases the amount of CO2 that is trapped by solubility trapping from 42.7.7% (base-case) to 32.4% (case 5). In this case, horizontal permeability was reduced while the vertical permeability remained unchanged. This in turn leads to greater vertical gas migration which limits horizontal spread of the CO2 plume in turn minimizing its contact with fresh brine along the flow of the formation brine. Consequently, there is reduced CO2 dissolution in the formation brine.Effect of CO2 injection rate·Increase in CO2 injection rate results in increased gas dissolution in the formation brine hence more CO2 stored with longer injection periods. However, although higher CO2 injection rates lead to greater CO2 dissolution, it may threaten the integrity of the caprock through increase in formation pressure especially near the injection zone. This in turn may lead to opening up of pre-existing fractures or faults or poorly sealed abandoned oil wells through which CO2 leakage could occur.Leakage of CO2 through a fault in the caprock·When anthropogenic CO2 is injected and stored in DSAs, it will migrate in the formation to extensive distances over time where it may encounter caprock imperfections such as faults, fractures or improperly sealed abandoned wells. From the 1-D model used in our study to assess the risk of CO2 leakage via a fault in the caprock, the escaping plume moving to lower overlying strata undergoes various phase changes from liquid to gas due to pressure reduction and or permeability effects and this may be a self-enhancing process which may lead to leakage of the gas to shallower strata which may contain portable groundwater.The results of this study may be useful to judge the feasibility of CO2 storage in deep saline aquifers of Wangchang Oilfield and Jianghan Basin and will also act as a base for future extensive numerical, experimental and field testing studies in China and to fill existing gaps in knowledge.