Moon Sik Jeong

Simulation Study on Miscibility Effect of CO2/Solvent Injection for Enhanced Oil Recovery at Nonisothermal Conditions

The minimum miscibility pressure (MMP) determines the main mechanism of CO2 flooding, which is either an immiscible or miscible process. This paper examines the recovery improvements of CO2 flooding in terms of both the injection temperature and solvent composition. The results show that a lower temperature injection and LPG (liquefied petroleum gas) mixture can considerably improve oil recovery due to the reduced MMP in the swept area caused by the injected solvent. For the pure CO2 injection at the reservoir temperature, oil recovery is 59% after 1.0 PV CO2 injection. The oil recoveries by CO2-LPG mixtures are improved to 73% with 0.1 mole fractions of LPG and 81% with 0.2 mole fractions of LPG. The recovery factor from low-temperature CO2 injection is 78%, which is 32% higher compared to the isothermal case. The recoveries obtained by low-temperature CO2-LPG injection increase up to 87% of the initial oil. Heat transfer between the reservoir and the formation of over/underburden should be considered in order to describe the process more accurately. Additionally, the recovery factors from the heat transfer models are decreased by 4–12% in comparison with the original nonisothermal models.

Optimized well configuration of gas-assisted gravity drainage process

CO2 flooding has been widespread as one of the effective enhanced oil recovery methods by oil swelling and viscosity reduction. In spite of the efficiencies, the improvement of oil recovery falls short of expectation, especially for immiscible flooding because unswept zone by injected CO2 still exists at the bottom of the reservoir owing to gravity overriding phenomenon. Gas-assisted gravity drainage (GAGD) has been applied to use CO2 gravity overriding conversely and improve carbon capture sequestration efficiency. During GAGD, the area of swept zone by injected CO2 is affected greatly by injector length and producer well perforation design. The producer well perforation just below the injectors inhales CO2 downwardly, which interrupts gas spread from the top. Moreover, CO2 out of the injector far away from the top is affected by the downward pull of the producer more than buoyancy to the top; so, gas does not spread throughout the wide range of the area. The unswept zone existed below the injectors at the end of production can be solved by new perforations in the producer under the injectors. Results obtained would give not only the strength of GAGD but also a suggestion for an effective well length and perforation design of GAGD process.

Compositional Modeling for Optimum Design of Water-Alternating CO2-LPG EOR under Complicated Wettability Conditions

The addition of LPG to the CO2 stream leads to minimum miscible pressure (MMP) reduction that causes more oil swelling and interfacial tension reduction compared to CO2 EOR, resulting in improved oil recovery. Numerical study based on compositional simulation has been performed to examine the injectivity efficiency and transport behavior of water-alternating CO2-LPG EOR. Based on oil, CO2, and LPG prices, optimum LPG concentration and composition were designed for different wettability conditions. Results from this study indicate how injected LPG mole fraction and butane content in LPG affect lowering of interfacial tension. Interfacial tension reduction by supplement of LPG components leads to miscible condition causing more enhanced oil recovery. The maximum enhancement of oil recovery for oil-wet reservoir is 50% which is greater than 22% for water-wet reservoir. According to the result of net present value (NPV) analysis at designated oil, CO2, propane, and butane prices, the optimal injected LPG mole fraction and composition exist for maximum NPV. At the case of maximum NPV for oil-wet reservoir, the LPG fraction is about 25% in which compositions of propane and butane are 37% and 63%, respectively. For water-wet reservoir, the LPG fraction is 20% and compositions of propane and butane are 0% and 100%.

Thermo-Mechanistic EOR Process Modelling in Deploying Low Salinity Hot Water Injection Under Carbonate Reservoirs

This work was financially supported by the Energy Efficiency & Resources of the Korea Institute of Energy Technology Evaluation and Planning (KETEP) grant funded by the Korea government Ministry of Knowledge Economy (No.20152510101980).

Compositional Simulation on the Flow of Polymeric Solution Alternating CO2 through Heavy Oil Reservoir

Water-alternating-gas (WAG) method provides superior mobility control of CO2 and improves sweep efficiency. However, WAG process has some problems in highly viscous oil reservoir such as gravity overriding and poor mobility ratio. To examine the applicability of carbon dioxide to recover viscous oil from highly heterogeneous reservoirs, this study suggests polymer-alternating-gas (PAG) process. The process involves a combination of polymer flooding and CO2 injection. In this numerical model, high viscosity of oil and high heterogeneity of reservoir are the main challenges. To confirm the effectiveness of PAG process in the model, four processes (waterflooding, continuous CO2 injection, WAG process, and PAG process) are implemented and recovery factor, WOR, and GOR are compared. Simulation results show that PAG method would increase oil recovery over 45% compared with WAG process. The WAG ratio of 2 is found to be the optimum value for maximum oil recovery. The additional oil recovery of 3% through the 2 WAG ratio is achieved over the base case of 1: 1 PAG ratio and 180 days cycle period.

Effects of Bottom Aquifer on the Productivity of Chemical Flooding Applied to Multi-Layered Heterogeneous Reservoirs

Complex geological properties of oil reservoirs affect productivity of chemical flooding. Presence of bottom-water aquifer combined with heterogeneous reservoirs has been regarded as a problem which brings out reduction of recovery factor and high water-cut. A numerical reservoir simulator is used to investigate effects of aquifer on the performance of chemical flooding. By including the effects of bottom-water aquifer, productivity decreases significantly compared with that from non-aquifer case. Results from this study emphasize the importance of an accurate assessment of performance before implementing chemical flooding, especially in unfavorable condition such as bottom-water aquifer.

Assessment on the Transport of Polymeric Solution through High-Salinity Reservoirs Containing Divalent Cations

Water salinity and hardness have been regarded as main limitation for field application of polymer floods. It causes not only reduction of polymer concentration, but also injectivity loss in the near wellbore. Based on the mathematical and chemical theory, extensive numerical simulations were conducted to investigate performance of polymer floods in the high-salinity reservoirs. According to results from simulations, the high salinity reduces the viscosity of polymer in contacting area. That causes a poor sweep efficiency of polymer flooding. Moreover, the presence of divalent cations makes the project of polymer flooding worse. That is because of excessively increased bottom-hole pressure in injection well by the precipitation of polymer. The quantitative assessment of polymer floods needs to be required before field application. Therefore, the results in this paper are helpful for optimal polymer flooding design under harsh reservoir conditions.