A critical review of carbon dioxide enhanced oil recovery in carbonate reservoirs

Tan, Yamin; Li, Qi; Li, Xu; Ghaffar, Abdul; Zhou, Xiang; Li, Pengchun

doi:10.1016/j.fuel.2022.125256

Cited by 31 publications

(18 citation statements)

References 117 publications

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“…In the Rocky Mountain Basin, injected CO 2 can be separated as the byproduct during natural gas production . Until 2020, over 1 Gt of CO 2 has been injected for EOR in the U.S., whereas ∼83% of injected CO 2 is mined natural CO 2 . , However, in China, only a few natural CO 2 reservoirs have been identified . Most of these natural CO 2 reservoirs are far from shale/tight reservoirs, except for the Songliao Basin, which provides convenient natural CO 2 for the Jilin oilfield.…”

Section: Challenges and Perspectivesmentioning

confidence: 99%

“…102,103 However, in China, only a few natural CO 2 reservoirs have been identified. 104 Most of these natural CO 2 reservoirs are far from shale/tight reservoirs, except for the Songliao Basin, which provides convenient natural CO 2 for the Jilin oilfield. The CO 2 source of CO 2 injection in Jilin's Daqingzi oilfield is supplied by CO 2 separated at the Changling gas field (CO 2 content at 22.5%).…”

Section: Pilot Field Testmentioning

confidence: 99%

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Minireview of Microscopic CO₂ Interactions with Fluids and Minerals in Shale: Advances and Outlook

et al. 2023

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Shale is featured by nanometer pores and ultralow permeability. Enhancing shale oil recovery after primary production is challenging as a result of the low injectivity of water. CO 2 could be a promising injection fluid to enhance shale oil recovery for its high mobility in porous media and mixability with hydrocarbons. Fluid behaviors in the nanometer pores of shale reservoirs deviate from those in the micrometer pores of conventional reservoirs. The previous understanding of CO 2 displacement and sequestration in conventional reservoirs is not completely applicable to shale reservoirs. In this review, we analyzed research advances in CO 2 interactions with reservoir fluids and shale rocks at the microscopic level. We delineated recent progress in interpreting phase behavior, mass transfer of the CO 2 −oil system confined in nanometer pores, and reshaping of CO 2 -induced mineralization in shale porous media. We also discussed limitations and future directions for studying CO 2 injection in shale reservoirs, from the experimental scope, theoretical analysis, and field application.

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Section: Challenges and Perspectivesmentioning

confidence: 99%

Section: Pilot Field Testmentioning

confidence: 99%

Minireview of Microscopic CO₂ Interactions with Fluids and Minerals in Shale: Advances and Outlook

et al. 2023

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“…Enhanced oil recovery (EOR) techniques are utilized to increase the recovery of oil even further . Accurately predicting water saturation and areal sweep efficiency, along with conducting thorough reservoir characterization, is crucial for the success of enhanced oil recovery techniques, as they have the potential to increase production rates and ultimately improve oil recovery rates. − EOR techniques encompass chemical flooding, which involves the utilization of polymers, surfactants, alkalis, or a combination of these chemicals, − gas flooding, which utilizes carbon dioxide, , and thermal injection that involves the application of steam or in situ combustion. − Alkalis and surfactants are commonly utilized in chemical-based oil recovery techniques to enhance both the microscopic and macroscopic sweep efficiency of oil. , …”

Section: Introductionmentioning

confidence: 99%

Sulfonamide Derivatives as Novel Surfactant/Alkaline Flooding Processes for Improving Oil Recovery

Soliman,

ElSahaa,

Elsaeed

et al. 2023

ACS Omega

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Over time, oil consumption has increased along with a continuous demand for petroleum products that require finding ways to increase hydrocarbon production more economically and effectively. So, enhanced oil recovery technologies are believed to be very promising and will serve as a key to meeting the future energy demand. This paper aims to introduce an innovative method to boost the EOR by using two novel types of surfactants synthesized from sulfonamide derivatives. Types I and II surfactants were analyzed using Fourier transform infrared spectroscopy, and their characterization was further performed using 1H NMR and 13C NMR spectroscopy. Additionally, the evaluation of these surfactants included interfacial tension measurements at concentrations up to 0.9 wt %. The combination of types I and II surfactants with alkaline (NaOH) was also investigated by the measurements of interfacial tension. A series of coreflood and sandpack tests under high-salinity conditions were carried out to assess the effects of a surfactant alone and alkaline–surfactant as a combination on improving oil recovery. The rock wettability was evaluated using relative permeability saturation curves, and the oil displacement efficiency was determined using fractional flow curves. The coreflood results demonstrated that alkaline–surfactant flooding with the chemical formula 0.2 wt % surfactant type II plus 0.5 wt % NaOH achieved a higher oil recovery of 74% OOIP compared to surfactant flooding with the chemical formula 0.5 wt % surfactant type II (64% OOIP) and waterflooding (saline solution with a 35,000 ppm salinity: 48% OOIP). Moreover, the experimental results showed that under both core and sandpack flood conditions, there was a noticeable reduction in oil–water interfacial tension, a change in rock wettability to more water-wet, and higher efficiency of oil displacement when alkaline was added to the surfactant. Based on current research, the alkaline–surfactant formulation is strongly recommended for chemical flooding because of its high efficacy and relatively low cost.

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“…Among the global oil and gas resources, carbonate reservoirs account for 70% of the total petroleum reserves, 50% of the demonstrated reserves, and 63% of production . However, carbonate oil and gas reservoirs are characterized by high heterogeneity, strong anisotropy, and well-developed natural fractures. − Since the flow resistances of gas and drilling mud are smaller in fractures, in carbonate reservoirs, oil and gas mainly flow in the fractures, and the apparent permeability of fractured carbonate formation is much larger than that of normal formation. As a result, carbonate formations are quite sensitive to wellbore pressure.…”

Section: Introductionmentioning

confidence: 99%

Numerical Simulation of Gas–Liquid Gravity Displacement in Vertical Fractures during Drilling of Carbonate Formations

Peng

Deng

et al. 2023

ACS Omega

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In petroleum drilling, carbonate formations characterized by natural fractures can result in troublesome gas–liquid gravity displacement, which refers to the phenomenon that the drilling mud leakage and gas kick are simultaneously triggered. This work focuses on clarifying the mechanism of gas–liquid displacement in vertical fractures during the drilling of carbonate formations and investigating the characteristics of gas–liquid displacement under various conditions. First, the bottom hole pressure allowing for gas–liquid gravity displacement is analyzed, which determines the coexistence condition of leakage and kick in vertical fractures. Then, a theoretical model of gas–liquid displacement flow in a vertical fracture is established. To verify the reliability and accuracy of the model, the results of numerical simulation are compared with those of a visualization experiment. The development process and flow characteristics of gas–liquid displacement in the fracture under different conditions are numerically simulated. The effects of pressure difference, drilling mud property, and fracture geometry on the gas–liquid displacement rate are analyzed. It is found that the drilling mud leakage rate increases with the increase of fracture width, fracture height, and drilling mud density, while it decreases with the increase of pressure difference and fracture length. The gas invasion rate increases with the increase of fracture width, fracture height, and pressure difference, while it decreases with the increase of drilling mud density and fracture length. The equations for leakage rate and gas invasion rate are derived by the response surface method, and the methods for mitigating gas–liquid gravity displacement are discussed. It is expected that the present work provides a better understanding of the gas–liquid gravity displacement in carbonate formations.

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A critical review of carbon dioxide enhanced oil recovery in carbonate reservoirs

Cited by 31 publications

References 117 publications

Minireview of Microscopic CO₂ Interactions with Fluids and Minerals in Shale: Advances and Outlook

Minireview of Microscopic CO₂ Interactions with Fluids and Minerals in Shale: Advances and Outlook

Sulfonamide Derivatives as Novel Surfactant/Alkaline Flooding Processes for Improving Oil Recovery

Numerical Simulation of Gas–Liquid Gravity Displacement in Vertical Fractures during Drilling of Carbonate Formations

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A critical review of carbon dioxide enhanced oil recovery in carbonate reservoirs

Cited by 31 publications

References 117 publications

Minireview of Microscopic CO2 Interactions with Fluids and Minerals in Shale: Advances and Outlook

Minireview of Microscopic CO2 Interactions with Fluids and Minerals in Shale: Advances and Outlook

Sulfonamide Derivatives as Novel Surfactant/Alkaline Flooding Processes for Improving Oil Recovery

Numerical Simulation of Gas–Liquid Gravity Displacement in Vertical Fractures during Drilling of Carbonate Formations

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Minireview of Microscopic CO₂ Interactions with Fluids and Minerals in Shale: Advances and Outlook

Minireview of Microscopic CO₂ Interactions with Fluids and Minerals in Shale: Advances and Outlook