Numerical study on the impact of reservoir heterogeneity on utilization of CO2 and optimization strategies in low-Permeability Reservoirs

The worsening global climate crisis underscores the urgent need to reduce greenhouse gas emissions, capturing the attention of individuals, industries, and nations. Carbon Capture, Utilization, and Storage (CCUS) technology, particularly Enhanced Oil Recovery (EOR), is gaining prominence as a transformative solution to combat rising emissions. EOR is being widely adopted globally, with success stories in North America and China using CO2 injection for enhanced oil recovery. Enhanced Gas Resources (EGR) is also emerging as a negative carbon technology. However, deploying CO2 injection faces challenges, especially in China's unique sedimentary environment characterized by low permeability, tight formations, and strong reservoir heterogeneity. These challenges include premature CO2 breakthrough, preferential CO2 flow pathways, and reduced sweep efficiency. To gain a deeper and more precise understanding of how reservoir heterogeneity affects the geological utilization of CO2, this study employs an integrated approach. It begins by utilizing Flac3D and the "gast" tool in R language to generate comprehensive data fields that quantitatively characterize heterogeneity in terms of porosity standard deviation and correlation length. Subsequently, the research conducts a systematic and thorough analysis of how heterogeneity impacts CO2 gas displacement. This effort leverages TOUGH2MP-TMVOC's capabilities as the foundational tool to dissect the nuanced implications of heterogeneity on CO2 oil recovery. The pursuit of precision leads to enhancements in the numerical simulation program TOUGH2MP-TMVOC, including the development of new models for CO2 solubility and crude oil viscosity through meticulous data fitting experiments. These enhancements enhance the reliability and fidelity of the simulation process. Furthermore, the study explores a variety of displacement methods designed to mitigate the adverse effects of strong reservoir heterogeneity. Notably, it introduces a groundbreaking CO2 foam model, addressing critical aspects like CO2 foam properties and parameter flow characteristics, previously uncharted within the framework of TOUGH2MP-TMVOC. The research culminates in a comprehensive comparative analysis of the effectiveness of various injection methods, including CO2 gas, CO2 foam, CO2 alternating nitrogen injection, and CO2 alternating water injection. The study has yielded practical results and provides guiding principles for oil and gas reservoir development. In the realm of CO2 gas displacement, the influence of heterogeneity on final recovery is relatively limited. In contrast, CO2 oil displacement is significantly affected by porosity heterogeneity, with the most pronounced effects observed when the standard deviation is set at 0.1. Under these conditions, cumulative oil recovery experiences a marked reduction compared to scenarios with standard deviations of 0.025 and 0.05, regardless of the correlation length (12.5, 25, or 50 meters). Furthermore, the comparative analysis of various injection methods underscores the substantial positive impact of CO2 foam injection, closely followed by CO2 alternating nitrogen injection. The potency of increased injection rates and augmented reservoir pressure surpasses the efficacy of CO2 alternating water injection. The research extends to numerical simulations based on data from the Jilin oilfield in China, demonstrating the merits of CO2 foam injection. These simulations indicate that, under these conditions, a tenyear cumulative recovery rate of 27.6% is achievable, representing an approximately 5.5% improvement over CO2 gas injection. This underscores the superiority of CO2 foam and provides valuable insights for CO2-EOR in low permeability and tight reservoirs, offering a roadmap for more effective CCUS strategies.