Experimental Investigation on the CO 2 Effective Distance and CO 2 -EOR Storage for Tight Oil Reservoir

Carbon neutrality has become the long-term development strategy of many countries worldwide, and the widespread implementation of CCUS (carbon capture, utilization, and storage) is critical for achieving this goal. Ultralow permeability reservoirs have good storage and shielding properties, making them ideal for CO2 geological storage. CO2 into these reservoirs has the dual purpose of improving crude oil recovery and protecting the environment. However, the physical properties of ultralow permeability reservoirs are poor. Furthermore, the distribution of fractures is often complex. The mechanism and influencing factors of the CO2 storage are still unclear. Here, the CO2 storage in ultralow permeability reservoirs is analyzed through core displacement experiments and numerical simulation. The main influencing factors of cumulative oil production and CO2 storage capacity were calculated through gray correlation theory, including CO2 injection rate, permeability, porosity, the solubility of CO2 in water, and the bottom hole flow pressure of production wells. The research results show that the geological storage of CO2 in ultralow permeability reservoirs mainly consists of structural trapping and dissolution into the residual fluids; in the short term, mineralization is relatively small and can be ignored. Within the 15 years predicted by numerical simulation, the injected CO2 into the Y28–102 well group in the Huang3 district was structurally trapped, with a total capacity of 6.59 × 104t. The burial ratio was 63.4%, of which structural burial accounted for 82%, oil dissolution accounted for 9%, water dissolution accounted for 8%, and mineral burial accounted for approximately 1%. The research results reference CO2 flooding and geological storage in ultralow permeability reservoirs.

Section: Sensitivity Analysismentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Experimental and Numerical Simulation Analysis of Factors Affecting CO₂ Geological Storage and Enhanced Oil Recovery in Extra-Low Permeability

Liu,

Shen,

Yue

et al. 2023

“…The first diffusion stage refers to the process in which CO 2 diffusion front does not reach the interface between two oil phases, and CO 2 6) There is no mixing, and components exchange between the light oil and the heavy oil. (7) The swelling of the oil phases is considered, but the swelling of the water phase is neglected.…”

Section: Mathematical Modelmentioning

confidence: 99%

“…Global warming and insufficient energy supply have aroused interest in enhanced oil recovery (EOR) with CO 2 and CO 2 capture, utilization and storage (CCUS). − Injection of CO 2 into oil reservoirs known as CO 2 -enhanced oil recovery (EOR) can not only help to store the CO 2 but also improve the recovery of crude oil. − Hence, this process is considered to be the most cost-effective CCUS technique and has been widely used in the development of oilfields. , In CO 2 injection EOR projects, CO 2 diffuses into the formation and helps improve oil recovery by reducing the crude oil viscosity, supplementing the formation energy, swelling oil volume, and reducing the interfacial tension. , Studies have shown that the in situ mass transfer between CO 2 and heavy oil under reservoir conditions is dominated by molecular diffusion and dispersion. , The magnitude of molecular-diffusion coefficients affects the time for the heavy oil to achieve desirable viscosity reduction and swelling effect, thus influencing the oil-production response. , Therefore, the determination of CO 2 diffusion coefficient has extremely important guidance on CO 2 -EOR risk assessment, engineering design, and economic evaluation. , …”

Section: Introductionmentioning

confidence: 99%

Numerical Simulation of CO₂ Diffusion in a Multiliquid-Phase System Using Moving Mesh Technology

Chen

Liu

et al. 2023

CO2 diffusion plays an important role in many CO2 injection techniques. But CO2 diffusion in multiliquid-phase systems has not been thoroughly investigated. Here multiliquid-phase system refers to the liquid system coexisting water, light oil, and heavy oil phases. This study investigates the CO2 concentration and the induced oil expansions when CO2 diffuses in a multiliquid-phase system. First, the mathematical model is developed based on the location of the CO2 diffusion front in the multiliquid-phase system. Second, the corresponding numerical model is established for different diffusion stages. To accurately describe the swelling of two oils, we employ the moving mesh technology to monitor the movement of two interfaces. Finally, CO2 concentration profiles, the induced oil swelling, and the movement of the CO2 front are studied by coding the developed numerical model. The results demonstrate that the CO2 concentration distribution and the induced oil swelling exhibit different performances in various phases at different diffusion stages. So it is necessary to divide the diffusion stage when studying the CO2 diffusion in a multiliquid-system. CO2 diffusion results in 19.52% and 17.21% expansion for light and heavy oil, respectively.

“…Tight rocks have complex pore systems, including micro-and macropores, due to depositional and diagenetic processes. 26 Macropores are voids between detrital grains, which form during the depositional process, while micropores originate before the depositional process and commonly exist between grains and authigenic clay minerals. 27 Compaction, the presence of quartz overgrowth, and small grain size can reduce the contribution of macropores in tight sandstones.…”

Section: Introductionmentioning

confidence: 99%

Microscopic CO₂ Injection in Tight Rocks: Implications for Enhanced Oil Recovery and Carbon Geo-Storage

AlKharraa,

Wolf,

AlQuraishi

et al. 2023

Carbon dioxide (CO2) injection has been widely used in conventional reservoirs for enhanced oil recovery and CO2 sequestration. Nevertheless, the effectiveness of CO2 injection in tight reservoirs is limited due to diagenetic processes that impact displacement efficiency. This research work assesses the performance of CO2 injection in tight reservoirs and evaluates oil mobilization and fluid distribution within the rock pore systems. A set of experiments, including routine core analysis, X-ray diffraction (XRD), scanning electron microscopy (SEM), and mercury injection capillary pressure (MICP), was performed on Scioto sandstone. Three core-flooding runs were conducted to evaluate oil recovery of different injection schemes, including tertiary miscible CO2 injection, secondary immiscible CO2 injection, and secondary miscible CO2 injection. A nuclear magnetic resonance (NMR) spectrometer was utilized to evaluate the fluid distribution in pre- and postflooding schemes. Results show that secondary miscible CO2 injection provided the highest displacement efficiency (E d) of 88%, with oil mobilized from both micro- and macropore systems, leading to the highest oil recovery of 93% original oil in place (OOIP). Tertiary miscible CO2 injection had E d of 67%, providing an ultimate oil recovery of 79% OOIP mostly from the macropore system. Limited contribution of micropores during the tertiary miscible CO2 injection is attributed to the increased water content as a result of previously conducted secondary water flooding. Secondary immiscible CO2 injection showed the least oil recovery among the injection schemes of 68% OOIP, which is attributed to the unstable displacement, as indicated by E d of 52%. The efficiency of pore fluid displacement was determined through NMR analyses, and the findings are in line with the displacement efficiency values obtained from core-flood experiments, with a strong positive correlation. This finding is a promising strategy for determining a suitable CO2 injection scheme in tight rocks for oil recovery and CO2 storage.