Optimization of acid gas injection to improve solubility and residual trapping

Abstract

In acid gas injection, the solubility and residual trapping of acid gas can be effectively improved by optimizing the acid gas injection, which is important for short-term storage of acid gas and reducing the risk of acid gas leakage. The current study numerically investigates three different acid gas injection schemes, namely continuous acid gas injection, intermittent acid gas injection, and water alternating gas injection. The results suggest that the continuous acid gas injection with higher injection rate is slightly conducive to the solubility and residual trapping of acid gas. In particular, Continuous injection-Case1 with a rate of 19 200 Nm 3 d −1 reduces mobile acid gas by 1.82% and enhances residual trapping by 1.25%. While the intermittent acid gas injection can hardly improve the solubility and residual trapping of acid gas. Water alternating gas injection scheme shows superior behavior over other schemes. Specially, the Water alternating gas injection-Case3 with higher water injection rate is the most effective, which can reduce mobile acid gas by 13.66% and enhance solubility trapping by 23.95%. The acid gas plume is funnel-shaped in the acid gas injection stage. However, in the subsequent water injection stage, the acid gas plume gradually becomes fan shaped. This is because the injected water accelerates the dissolution of the acid gas, causing almost all the rear of the acid gas plume to dissolve in the water. Thus, we conclude that water alternating gas injection scheme can significantly enhance the acid gas trapping and Water alternating gas injection Case 3 is the preferred injection scheme.

Long‐term CO2 sequestration mechanisms and influence of injection mode in Zhujiang Formation of Pearl River Mouth Basin

“…Apart from Case 1, the variable of Cases 2–4 is the temperature of injected CO 2 ; the variable of cases 3, 5, 6 and 7 is CO 2 injection rate; the variable of Cases 6, 7, 8 and 9 is the injection cycle. In the cases 6–9, to amplify the impact of the injection cycle, the intervals were set to be longer, which is a commonly employed treatment mean 50,51 . As the same well head temperature may also lead to different bottom‐hole temperatures due to the different wellbore depths, materials, roughness, flow rates, and so on, 52–54 different bottom‐hole temperatures of injected fluid (which are 323.15K, 343.15 K and 363.15K, respectively) were set for Cases 2–4 to study the influence of injection fluid's temperature on long‐term CO 2 phase evolution.…”

“…In the cases 6-9, to amplify the impact of the injection cycle, the intervals were set to be longer, which is a commonly employed treatment mean. 50,51 As the same well head temperature may also lead to different bottom-hole temperatures due to the different wellbore depths, materials, roughness, flow rates, and so on, [52][53][54] different bottom-hole temperatures of injected fluid (which are 323.15K, 343.15 K and 363.15K, respectively) were set for Cases 2-4 to study the influence of injection fluid's temperature on long-term CO 2 phase evolution. The CO 2 injection rate of continuous injection for 30 years (see Case 1) was set according to actual engineering situation, and the total amount of CO 2 injected in the other cases remained the same as in Case 1.…”