Solubility trapping as a potential secondary mechanism for CO2 sequestration during enhanced gas recovery by CO2 injection in conventional natural gas reservoirs: An experimental approach

Most natural gas reservoirs of Ukraine are depleted to some extent; still they contain significant tail gas reserves. A promising direction for increasing gas recovery from depleted gas reservoirs is the displacement of tail gas from the porous medium with nitrogen which is easily accessible and does not cause corrosion of the down-hole equipment. This article characterizes the technologies for increasing gas recovery from depleted gas reser-voirs by injecting nitrogen into them. The technology of replacing tail gas with nitrogen is tested on the example of the depleted reservoir of ND-9 horizon of Lyubeshivskyy gas field, the productive deposits of which are composed mainly of sandstones with interlayers of limestone and clay. The authors consider fifteen options of injecting ni-trogen into the reservoir, including options of treating the bottom-hole of low-production wells at the beginning of the process of further reservoir development and at the beginning of the injection of nitrogen into the reservoir. In all cases, the reservoir is first redeveloped in the depletion mode until the reservoir pressure decreases to 0,1 from the initial value. After that, nitrogen is injected into one of the producing wells which is transferred to the injection well. The injection of nitrogen into the reservoir continues until the nitrogen content in the last produc-ing well is less than 5 % vol. All options are characterized by high values of the gas recovery coefficient and close values of the dura-tion of the reservoir further development. The positions of the front of the displacement of natural gas by nitrogen at various time points are given. According to the research results, the gas recovery coefficient for tail gas for var-ious options varies from 14,12 to 34,58 %. With the introduction of the technology of injecting nitrogen into the reservoir, the overall gas recovery coefficient increases from 72,25 % (at present development system) to 80,28 % when the residual gas is displaced by nitrogen.

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Numerical Simulation and Modeling of Enhanced Gas Recovery and CO2 Sequestration in Shale Gas Reservoirs: A Feasibility Study

10.2118/139701-ms ◽

2010 ◽

Cited By ~ 25

Author(s):

Amirmasoud Kalantari Dahaghi

Keyword(s):

Numerical Simulation ◽

Feasibility Study ◽

Shale Gas ◽

Co2 Sequestration ◽

Simulation And Modeling ◽

Gas Reservoirs ◽

Enhanced Gas Recovery ◽

Gas Recovery ◽

Shale Gas Reservoirs

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Co-Optimization of CO2 Storage and Enhanced Gas Recovery Using Carbonated Water and Supercritical CO2

Energies ◽

10.3390/en14227495 ◽

2021 ◽

Vol 14 (22) ◽

pp. 7495

Author(s):

Abdirizak Omar ◽

Mouadh Addassi ◽

Volker Vahrenkamp ◽

Hussein Hoteit

Keyword(s):

Co2 Storage ◽

Uncertainty Assessment ◽

Co2 Injection ◽

Gas Reservoirs ◽

Enhanced Gas Recovery ◽

Gas Recovery ◽

Structured Design ◽

Perform Sensitivity Analysis ◽

Carbonated Water

CO2-based enhanced gas recovery (EGR) is an appealing method with the dual benefit of improving recovery from mature gas reservoirs and storing CO2 in the subsurface, thereby reducing net emissions. However, CO2 injection for EGR has the drawback of excessive mixing with the methane gas, therefore, reducing the quality of gas produced and leading to an early breakthrough of CO2. Although this issue has been identified as a major obstacle in CO2-based EGR, few strategies have been suggested to mitigate this problem. We propose a novel hybrid EGR method that involves the injection of a slug of carbonated water before beginning CO2 injection. While still ensuring CO2 storage, carbonated water hinders CO2-methane mixing and reduces CO2 mobility, therefore delaying breakthrough. We use reservoir simulation to assess the feasibility and benefit of the proposed method. Through a structured design of experiments (DoE) framework, we perform sensitivity analysis, uncertainty assessment, and optimization to identify the ideal operation and transition conditions. Results show that the proposed method only requires a small amount of carbonated water injected up to 3% pore volumes. This EGR scheme is mainly influenced by the heterogeneity of the reservoir, slug volume injected, and production rates. Through Monte Carlo simulations, we demonstrate that high recovery factors and storage ratios can be achieved while keeping recycled CO2 ratios low.

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Numerical Simulation and Modeling on CO2 Sequestration Coupled with Enhanced Gas Recovery in Shale Gas Reservoirs

Geofluids ◽

10.1155/2021/9975296 ◽

2021 ◽

Vol 2021 ◽

pp. 1-15

Author(s):

Jie Zhan ◽

Zhihao Niu ◽

Mengmeng Li ◽

Ying Zhang ◽

Xianlin Ma ◽

...

Keyword(s):

Numerical Model ◽

Shale Gas ◽

Co2 Sequestration ◽

The United States ◽

Hydraulic Fractures ◽

Competitive Sorption ◽

Gas Reservoirs ◽

Enhanced Gas Recovery ◽

Gas Recovery ◽

Shale Gas Reservoirs

CO2 geological sequestration in shale is a promising method to mitigate global warming caused by greenhouse gas emissions as well as to enhance the gas recovery to some degree, which effectively addresses the problems related to energy demand and climate change. With the data from the New Albany Shale in the Illinois Basin in the United States, the CMG-GEM simulator is applied to establish a numerical model to evaluate the feasibility of CO2 sequestration in shale gas reservoirs with potential enhanced gas recovery (EGR). To represent the matrix, natural fractures, and hydraulic fractures in shale gas reservoirs, a multicontinua porous medium model will be developed. Darcy’s and Forchheimer’s models and desorption-adsorption models with a mixing rule will be incorporated into the multicontinua numerical model to depict the three-stage flow mechanism, including convective gas flow mainly in fractures, dispersive gas transport in macropores, and CH4-CO2 competitive sorption phenomenon in micropores. With the established shale reservoir model, different CO2 injection schemes (continuous injection vs. pulse injection) for CO2 sequestration in shale gas reservoirs are investigated. Meanwhile, a sensitivity analysis of the reservoir permeability between the hydraulic fractures of production and injection wells is conducted to quantify its influence on reservoir performance. The permeability multipliers are 10, 100, and 1,000 for the sensitivity study. The results indicate that CO2 can be effectively sequestered in shale reservoirs. But the EGR of both injection schemes does not perform well as expected. In the field application, it is necessary to take the efficiency of supplemental energy utilization, the CO2 sequestration ratio, and the effect of injected CO2 on the purity of produced methane into consideration to design an optimal execution plan. The case with a permeability multiplier of 1,000 meets the demand for both CO2 sequestration and EGR, which indicates that a moderate secondary stimulation zone needs to be formed between the primary hydraulic fractures of injection and production wells to facilitate the efficient energy transfer between interwell as well as to prevent CO2 from channeling. To meet the demand for CO2 sequestration in shale gas reservoirs with EGR, advanced and effective fracking is essential.

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