CO2 Injection for Improved Recovery in Tight Gas Condensate Reservoirs

Morsy, Mahmoud El; Ali, Samad; Giddins, Marie Ann; Fitch, Peter

doi:10.2118/202363-ms

Cited by 6 publications

(3 citation statements)

References 9 publications

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“…Different gas injection methods have different effects on EGR in condensate gas reservoirs with different permeability capacity. El Morsy et al [76] constructed an ideal reservoir model, focusing on tight condensate gas reservoirs, and set 0.1 mD and 1 mD permeability reservoirs for continuous gas injection, and huff and puff gas injection, respectively, for comparison. The analysis concluded that CO 2 huff and puff gas injection is better for tight condensate gas reservoirs and continuous gas injection is better for condensate gas reservoirs with better permeability.…”

Section: Condensate Gas Reservoirsmentioning

confidence: 99%

“…This shows that in conventional gas reservoirs, gas injection is mainly used to drive and sweep natural gas, and there are also errors that do not take into account mixing and solubility. El Morsy et al [76] studied the effect of mixed gas on enhanced gas recovery and revealed that the effect of mixture gas injection in tight condensate gas reservoirs was not much different from that of pure CO 2 , which would be more economical but would have an impact on condensate gas production, because N 2 would reduce the minimum miscible pressure of CO 2 .…”

Section: Research On the Influence Of Reservoir Physical Properties A...mentioning

confidence: 99%

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Current Progress and Development Trend of Gas Injection to Enhance Gas Recovery in Gas Reservoirs

Lin,

Wei,

Gao

et al. 2024

Energies

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Conventional recovery enhancement techniques are aimed at reducing the abandonment pressure, but there is an upper limit for recovery enhancement due to the energy limitation of reservoirs. Gas injection for energy supplementation has become an effective way to enhance gas recovery by reducing hydrocarbon saturation in gas reservoirs. This review systematically investigates progress in gas injection for enhanced gas recovery in three aspects: experiments, numerical simulations and field examples. It summarizes and analyzes the current research results on gas injection for EGR and explores further prospects for future research. The research results show the following: (1) Based on the differences in the physical properties of CO2, N2 and natural gas, effective cushion gas can be formed in bottom reservoirs after gas injection to achieve the effects of pressurization, energy replenishment and gravity differentiation water resistance. However, further experimental evaluation is needed for the degree of increase in penetration ability. (2) It is more beneficial to inject N2 before CO2 or the mixture of N2 and CO2 in terms of EGR effect and cost. (3) According to numerical simulation studies, water drive and condensate gas reservoirs exhibit significant recovery effects, while CO2-EGR in depleted gas reservoirs is more advantageous for burial and storage; current numerical simulations only focus on mobility mass and saturation changes and lack a mixed-phase percolation model, which leads to insufficient analysis of injection strategies and a lack of distinction among different gas extraction effects. Therefore, a mixed-phase-driven percolation model that can characterize the fluid flow path is worth studying in depth. (4) The De Wijk and Budafa Szinfelleti projects have shown that gas injection into water drive and depleted reservoirs has a large advantage for EGR, as it can enhance recovery by more than 10%. More experiments, simulation studies and demonstration projects are needed to promote the development of gas injection technology for enhanced recovery in the future.

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Section: Condensate Gas Reservoirsmentioning

confidence: 99%

Section: Research On the Influence Of Reservoir Physical Properties A...mentioning

confidence: 99%

Current Progress and Development Trend of Gas Injection to Enhance Gas Recovery in Gas Reservoirs

Lin,

Wei,

Gao

et al. 2024

Energies

View full text Add to dashboard Cite

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“…But the experiments are all at the core scale and have certain limitations. Some scholars have also conducted numerical simulations of CO 2 injection into condensate gas reservoirs [59]. The results show that compared to continuous injection of CO 2 , CO 2 -HnP can improve condensate oil recovery to 25%, which is much higher than with the continuous injection of CO 2 [60].…”

Section: Introductionmentioning

confidence: 99%

Compositional Simulation of CO2 Huff-n-Puff Processes in Tight Oil Reservoirs with Complex Fractures Based on EDFM Technology Considering the Threshold Pressure Gradient

Zheng,

Jiang,

Chen

et al. 2023

Energies

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Although tight oil reservoirs have abundant resources, their recovery efficiency is generally low. In recent years, CO2 injection huff-n-puff has become an effective method for improving oil recovery on the basis of depleted production of volume-fracturing horizontal wells in tight oil reservoirs. In order to study the effects of CO2 huff-n-puff (CO2-HnP) on production, a compositional numerical simulation study of CO2 huff-n-puff (CO2-HnP) was conducted in tight oil reservoirs with complex fractures. Embedded discrete fracture model technology was used in the simulations to characterize complex fractures. The process of CO2 huff-n-puff (CO2-HnP) was simulated, which consists of CO2 injection, CO2 soaking, and CO2 production. Taking into account the threshold pressure gradient and stress sensitivity in the model, we conducted a series of numerical simulations with different production condition parameters, such as bottom-hole pressure, CO2 injection rate, injection time, soaking time, and the number of cycles of CO2 huff-n-puff (CO2-HnP). Then, the effects of these sensitivity parameters on the cumulative oil production (COP) were studied. The results indicate that the threshold pressure gradient and rock stress sensitivity factors greatly affect the pressure field of tight reservoirs and the cumulative oil production (COP) of multistage-fracturing horizontal wells. The production parameters all have an impact on the COP. The injection rate and circulation number both have optimal values, and the injection time and soak time tend to have less significant effects on the growth of cumulative oil production over time. According to the numerical simulation, the optimal solution is 5 × 104 m3/day injection rate per cycle, 25 days of injection time, 35 days of soaking time, three cycles, and production for 5 years, which can obtain the optimal cumulative oil production.

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An Experimental Study of the Effects of CO2 Injection on Gas/Condensate Recovery and CO2 Storage in Gas-Condensate Reservoirs

Seteyeobot¹,

Jamiolahmady²,

Jaeger

et al. 2021

Day 1 Tue, September 21, 2021

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The application of non-hydrocarbon gas injection for enhanced gas and condensate recovery (EGCR) is still in a developmental stage as the mixing/interaction between the injected gas and resident reservoir fluid is yet to be extensively understood and the inability to optimize the recovery process has led to limited pilot trials. Carbon dioxide (CO2) injection into gas-condensate reservoirs for improved recovery and CO2 storage provides additional and favorable changes in phase and fluid flow behaviour making it economically more attractive compared to other injection gases. However, to make an informed decision, adequate phase and flow behaviour analysis are required to better forecast the reservoir performance under CO2 injection. In this research, appropriate experimental phase behaviour, EOS modeling, and unsteady-state flow tests have been conducted to determine the level of CO2/gas-condensate interaction including condensing/vaporizing mechanisms during CO2 Huff-n-Puff (HnP) injection. A CO2 HnP injection technique was followed to identify the best CO2 flooding conditions. A total of four HnP injection cycles with incremental CO2 volumes of 20, 40, 60, and 80 % of the initial resident fluid volume prior to depletion was considered. CO2 injection pressure and volume are optimized below the saturation pressure. The analysis is based on evaluating the level of interaction between CO2 and resident fluid at the maximum condensate saturation of the corresponding CO2-gas-condensate fluid mixture as determined in a phase equilibria cell. Appropriate experimental phase behaviour and core flood data were generated and analyzed to identify and quantify the level of condensing/vaporizing mechanisms which are vital for adequate optimization of the injection pressure and amount of injected CO2 for both enhanced gas and condensate recovery and CO2 storage purposes. The amount of gas, condensate, and CO2 produced at each core flood stage was recorded. These data allow bridging the gap between conflicting reports on the trend and level of CO2/gas-condensate fluid interactions at pressures below the dew point pressure (Pdew). They also provide a better knowledge of the governing mechanisms during CO2 flooding, which are required for designing appropriate CO2 HnP injection for reservoir engineering applications.

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CO2 Injection for Improved Recovery in Tight Gas Condensate Reservoirs

Cited by 6 publications

References 9 publications

Current Progress and Development Trend of Gas Injection to Enhance Gas Recovery in Gas Reservoirs

Current Progress and Development Trend of Gas Injection to Enhance Gas Recovery in Gas Reservoirs

Compositional Simulation of CO2 Huff-n-Puff Processes in Tight Oil Reservoirs with Complex Fractures Based on EDFM Technology Considering the Threshold Pressure Gradient

An Experimental Study of the Effects of CO2 Injection on Gas/Condensate Recovery and CO2 Storage in Gas-Condensate Reservoirs

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