Numerical simulation and feasibility assessment of acid gas injection in a carbonate formation of the Tarim Basin, China

Xiaoyan Zhang,Liange Zheng,Qi Li,Xiaying Li,Liang Xu

doi:10.2516/ogst/2020019

Abstract

An enormous amount of acid gas, containing carbon dioxide (CO2) and hydrogen sulfide (H2S), is generated in the exploitation of oil and gas reservoirs in the Tarim Basin, China. An appropriate management plan is required to safely dispose of the acid gas, and common strategy considered for the safe disposal of acid gas is the injection of it into deep formations – this strategy mitigates greenhouse gas emissions and avoids costs associated with desulfurization. A feasibility assessment of acid gas injection requires a detailed investigation of the potential physical and geochemical impacts. Reactive transport simulations based on the mineralogical composition and the hydrochemical characteristics of a carbonate formation in the Tarim Basin were conducted to identify the physical and geochemical interactions of acid gas with the mineral matrix and formation water. Acid gas (59% CO2 and 41% H2S) was injected at a constant rate of 19 200 Nm3/d for 25 years, and the simulation was run by the TMVR_EOSG module of the TOUGHREACT code for a period of 10 000 years. The results indicate that the minimum liquid saturation is much larger than the residual water saturation, and the pressure buildup is below the allowable pressure increase. Additionally, the porosity change is found to be negligible due to the small changes in calcite and quartz in the volume fraction. From this perspective, acid gas injection in the carbonate formation of the Tarim Basin seems feasible. Furthermore, the fast breakthrough of CO2 can provide an advanced warning of a potential breakthrough of acid gas. Last, the injection rate can be increased to accelerate acid gas trapping, and the results could be used as guidance for future acid gas injection operations.

Highlights

With the increasing exploitation of sour hydrocarbon reservoirs, a growing volume of acid gas, consisting primarily of carbon dioxide (CO2) and hydrogen sulfide (H2S), is generated
Pressure buildup occurs on a large scale when massive acid gas is injected into the formation, and the effect occurring in the two-phase zone is more pronounced than in the singlephase zone
As investigated in the literature (Meng et al, 2015; Pruess and García, 2002; Pruess and Müller, 2009; Zhao and Cheng, 2017), salt precipitation is caused at the dry-out region near the injection well where liquid saturation is lower than the residual water saturation

Summary

Introduction

With the increasing exploitation of sour hydrocarbon reservoirs, a growing volume of acid gas, consisting primarily of carbon dioxide (CO2) and hydrogen sulfide (H2S), is generated. The conventional sulfur recovery method, which converts sulfur compounds to elemental sulfur and directly emits residual CO2 into the atmosphere, can be adopted to dispose of acid gas. Acid Gas Injection (AGI) into depleted oil and gas reservoirs is gaining increasing attention as an alternative to mitigate greenhouse gas emissions and to avoid the costs of desulfurization. Acid gas injection operations have been approved worldwide (British Columbia Geological Survey, 2003; Carroll et al, 2009; Khan et al, 2013; Li et al, 2017; Miwa et al, 2002), and feasibility of AGI operations in China has been analyzed (Li et al, 2013; Liu et al, 2012). The implementation of acid gas injection requires a proper assessment of the effects induced by the presence of acid gas

Results

Discussion

Conclusion