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Michael L Johns - One of the best experts on this subject based on the ideXlab platform.
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quantitative dependence of ch4 co2 dispersion on immobile water fraction
Aiche Journal, 2017Co-Authors: Marco Zecca, Sarah J. Vogt, Abdolvahab Honari, Gongkui Xiao, Einar O. Fridjonsson, Eric F. May, Michael L JohnsAbstract:Enhanced Gas Recovery (EGR) involves CO2 injection into natural Gas reservoirs to both increase Gas Recovery and trap CO2. EGR viability can be determined by reservoir simulations; however these require a description of fluid dispersion (mixing) between the supercritical CO2 and natural Gas. Here we quantify this dispersivity (α) in sandstone rock plugs as a function of residual water fraction. To ensure the accuracy of such data, we designed a novel core flooding experimental protocol that ensured an even spatial distribution of water, minimised erroneous entry/exit contributions to mixing, and minimised dissolution of the CO2 into the water phase. Dispersivity was found to increase significantly with water content, although the differences in α between sandstones were eliminated upon the inclusion of residual water. This enabled development of a correlation between α and water content and, hence, between the dispersion coefficient and Peclet number that is readily incorporable into reservoir simulations. This article is protected by copyright. All rights reserved.
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Inclusion of Connate Water in Enhanced Gas Recovery Reservoir Simulations
Energy, 2017Co-Authors: M.j. Patel, Eric F. May, Michael L JohnsAbstract:Abstract Enhanced natural Gas Recovery (EGR) with supercritical (sc)CO2 sequestration offers the prospect of increased natural Gas Recovery. High-fidelity reservoir simulations offer a method to quantify the risk of contamination of produced Gas by the injected scCO2. Simulations of scCO2 mixing with the reservoir Gas have been reported; however the effects of connate water on EGR have not been effectively explored. We extend a prior EGR simulation tool (Patel, May and Johns, 2016; Ref. [1]) to incorporate connate water accounting for its effect on dispersivity and permeability; chemical equilibrium is modelled using a novel, computationally efficient Lagrange multiplier-based approach. The code is applied to a ‘quarter five-spot’ benchmark scenario. The inclusion of connate water generally resulted in a reduction in breakthrough time and a decrease in methane Recovery. The connate water's largest effect was to change the scCO2 flow field, which sank towards the reservoir floor, flooded the lowermost accessible layers and entered the production well via a high throughput channel (‘coning’). The magnitude of these effects were, however, sensitive to well perforation depth, the influence of which was subsequently studied systematically. Well perforation depth was found to determine the duration of these sinking and coning events in a non-linear manner.
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enhanced Gas Recovery with co2 sequestration the effect of medium heterogeneity on the dispersion of supercritical co2 ch4
International Journal of Greenhouse Gas Control, 2015Co-Authors: Abdolvahab Honari, Michael L Johns, Branko Bijeljic, Eric F. MayAbstract:Abstract Reinjection of CO 2 into producing natural Gas reservoirs is considered as a promising technology to improve Gas Recovery, mitigate atmospheric emissions and control climate change. However, natural Gas and CO 2 are miscible at reservoir conditions and could result in CO 2 contamination of produced natural Gas. This mixing process and consequently the viability of Enhanced Gas Recovery (EGR) projects can be quantitatively determined by reservoir simulations – such simulations require a description of Gas dispersion. Here we conduct fluid transport experiments through carbonate and sandstone rock cores at various reservoir conditions to evaluate the effect of medium heterogeneity on the dispersion between supercritical CO 2 and CH 4 , accounting for erroneous contributions from entrance/exit and gravitational effects. Early breakthrough and long-tailed profiles are observed for one of the carbonate cores (Ketton) which is attributed to the existence of intra-grain micro-pores, which results in a persistent pre-asymptotic transport regime. Thus a revised model (Mobile-Immobile Model) was successfully used for this core to obtain dispersion coefficients characteristic of the eventual asymptotic regime. Both heterogeneous carbonate rocks considered exhibit higher dispersion than that observed in previously-measured homogeneous sandstone cores (Honari et al., 2013). The power law describing the dependency of dispersion coefficient on Peclet number at comparatively high interstitial displacement velocities gave an exponent of 1.2 for sandstones and 1.4 for carbonates, consistent with literature predictions (Bijeljic and Blunt, 2006; Bijeljic et al., 2011) based on pore-scale simulations.
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co2 sequestration for enhanced Gas Recovery new measurements of supercritical co2 ch4 dispersion in porous media and a review of recent research
International Journal of Greenhouse Gas Control, 2012Co-Authors: Thomas J Hughes, Abdolvahab Honari, Brendan F Graham, Aman S Chauhan, Michael L JohnsAbstract:Abstract The enhanced Recovery of natural Gas by the injection and sequestration of CO 2 is an attractive scenario for certain prospective field developments if the risks of Gas contamination or early CO 2 breakthrough can be assessed reliably. Simulations of enhanced Gas Recovery (EGR) scenarios require accurate dispersion parameters at reservoir conditions to quantify the size of the miscible CO 2 –CH 4 displacement front; several experimental studies using core-flooding equipment aimed at measuring such parameters have been reported over the last decade. However, such measurements are particularly challenging and the data produced are generally afflicted in their repeatability by limited experimental control and in their accuracy by systematic errors such as gravitational and core-entrance/exit effects. We review here the existing experimental data pertaining to EGR by CO 2 sequestration and also report new measurements of longitudinal CO 2 –CH 4 dispersion coefficients at temperatures of 40–80 °C, pressures of 8–12 MPa and interstitial velocities of 0.05–1.13 mm s −1 [14.2–320 ft day −1 ] in 5–10 cm long sandstone cores with permeabilities of 12 and 460 mD. The core-floods were conducted in both a horizontal and vertical orientation, with significant gravitational effects observed for low velocity floods in horizontal cores with high permeabilities. We also analyzed the effects of tubing and core entrance/exit effects on the measurements and found that the latter resulted in apparent dispersion coefficients up to 63% larger than would be due to the core alone. Our results indicate that dispersivities for CO 2 –CH 4 at these supercritical conditions are less than 0.001 m, which indicates that excessive mixing will not occur in EGR scenarios in the absence of conformance effects such as heterogeneity coupled with injection well pattern. Inclusion of such conformance effects is essential for detailed reservoir simulation.
Guan Qin - One of the best experts on this subject based on the ideXlab platform.
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utilization of zeolite as a potential multi functional proppant for co2 enhanced shale Gas Recovery and co2 sequestration a molecular simulation study of the impact of water on adsorption in zeolite and organic matter
Fuel, 2021Co-Authors: Kaiyi Zhang, Hao Jiang, Guan QinAbstract:Abstract We proposed to use zeolites as multi-functional proppants for enhanced shale Gas Recovery and CO2 sequestration in our previous paper and studied the competitive adsorption of CO2 and CH4 in silicalite-1 and kerogen organic matter. It is proved that CO2 released from proppants can be preferentially adsorbed by kerogen and replace the adsorbed CH4. In the present paper, we aim at studying the impact of water on the Gas adsorption capacity and selectivity of CO2 over CH4 since water can significantly alter Gas adsorption behaviors in zeolites and organic matter. We carry out grand canonical Monte Carlo simulations of water adsorption and the competitive adsorption of a CO2, CH4, and water mixture in silicalite-1 and in kerogen. It is found that water is less favored in both adsorbents but could suppress the adsorption of CO2 and CH4 when the water content is high, it can also enhance CO2/CH4 selectivity under some circumstances. Kerogen shows a stronger preference for adsorbing CO2 over CH4 under most conditions; thus, the replacement process of CO2 and CH4 with water present can still happen in the positive direction.
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utilization of zeolite as a potential multi functional proppant for co2 enhanced shale Gas Recovery and co2 sequestration a molecular simulation study on the competitive adsorption of ch4 and co2 in zeolite and organic matter
Fuel, 2019Co-Authors: Kaiyi Zhang, Hao Jiang, Guan QinAbstract:Abstract It is well known that CO2 is one of the most effective enhanced hydrocarbon Recovery agents due to its thermodynamic characteristics, and extensive research and pilot studies have been conducted in recent years on how to utilize CO2 for enhanced Gas Recovery in shales. The common delivery method involves injecting CO2 in its liquid or supercritial form into a shale formation. In this paper, we propose a novel approach to shale Gas Recovery that uses zeolite as a multi-functional proppant and carrier of adsorbed CO2 to enhance shale Gas Recovery as well as CO2 sequestration and storage. This process involves complex thermodynamic and transport processes, among which the competitive adsorption behaviors of CO2 and CH4 into organic matter and zeolite is the most critical to the success of the proposed approach. In this paper, we carry out a systematic molecular simulation study to investigate the adsorption behaviors of methane and CO2 into organic matter (kerogen) and silica zeolite (silicalite-1). We use grand canonical Monte Carlo simulations to measure single-component adsorption isotherms and calculate the isosteric heat of adsorption at surface temperature and at elevated temperatures of up to 425 K. Moreover, we simulate the competitive adsorption of binary mixtures of CH4 and CO2 with various compositions and investigate the competition between the two Gas components in kerogen and silicalite-1. Both silicalite and kerogen show a stronger affinity for CO2 than for CH4. While the adsorption capacity of kerogen is about two times that of silicalite, the isosteric heat of adsorption demonstrates that the kerogen/CO2 interaction is the strongest among all four single-component adsorption systems. These findings demonstrate the great potential of using zeolite as a proppant and CO2 carrier to displace CH4 in shale organic matter under subsurface conditions. This observation is also validated via a competitive adsorption study, in which kerogen preferentially adsorbs CO2 over CH4 under all conditions and silicalite exhibits weaker CO2/CH4 selectivity, especially when the CO2 fraction is very low in the bulk phase. These results suggest the potential applicability of using zeolite as a proppant and CO2 carrier to enhance shale Gas Recovery. In reservoir conditions, the CO2 desorbed from zeolite can be favorably adsorbed by kerogen due to the increase in temperature and decrease in pressure; in the meantime, it can displace the adsorbed CH4 to enhance Gas production.
Reinhard Gaupp - One of the best experts on this subject based on the ideXlab platform.
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experimental and numerical investigations on co2 injection and enhanced Gas Recovery effects in altmark Gas field central germany
Acta Geotechnica, 2014Co-Authors: Leonhard Ganzer, Viktor Reitenbach, Dieter Pudlo, Daniel Albrecht, Arron Tchouka Singhe, Kilian Nhungong Awemo, Joachim Wienand, Reinhard GauppAbstract:The feasibility of CO2 storage and enhanced Gas Recovery (EGR) effects in the mature Altmark natural Gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO2 as well as reservoir simulation studies to evaluate the CO2 wellbore injectivity and displacement efficiency of the residual Gas by the injected CO2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO2 Gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO2 will be maximized. The migration/extension of CO2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO2 extension and pressure propagation suggested no breakthrough of CO2 at the prospective production well during the 3-year injection period studied.
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Experimental and numerical investigations on CO_2 injection and enhanced Gas Recovery effects in Altmark Gas field (Central Germany)
Acta Geotechnica, 2014Co-Authors: Leonhard Ganzer, Viktor Reitenbach, Dieter Pudlo, Daniel Albrecht, Arron Tchouka Singhe, Kilian Nhungong Awemo, Joachim Wienand, Reinhard GauppAbstract:The feasibility of CO_2 storage and enhanced Gas Recovery (EGR) effects in the mature Altmark natural Gas field in Central Germany has been studied in this paper. The investigations were comprehensive and comprise the characterization of the litho- and diagenetic facies, mineral content, geochemical composition, the petrophysical properties of the reservoir rocks with respect to their potential reactivity to CO_2 as well as reservoir simulation studies to evaluate the CO_2 wellbore injectivity and displacement efficiency of the residual Gas by the injected CO_2. The Rotliegend sediments of the Altmark pilot injection area exhibit distinct mineralogical, geochemical, and petrophysical features related to litho- and diagenetic facies types. The reservoir rock reactivity to CO_2 has been studied in autoclave experiments and associated effects on two-phase transport properties have been examined by means of routine and special core analysis before and after the laboratory runs. Dissolution of calcite and anhydrite during the short-term treatments leading to the enhancements of permeability and porosity as well as stabilization of the water saturation relevant for CO_2 injection have been observed. Numerical simulation of the injection process and EGR effects in a sector of the Altmark field coupled with a wellbore model revealed the possibility of injecting the CO_2 Gas at temperatures as low as 10 °C and pressures around 40 bar achieving effective inflow in the reservoir without phase transition in the wellbore. The small ratio of injected CO_2 volume versus reservoir volume indicated no significant EGR effects. However, the retention and storage capacity of CO_2 will be maximized. The migration/extension of CO_2 varies as a function of heterogeneity both in the layers and in the reservoir. The investigation of CO_2 extension and pressure propagation suggested no breakthrough of CO_2 at the prospective production well during the 3-year injection period studied.
Sally M Benson - One of the best experts on this subject based on the ideXlab platform.
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economic feasibility of carbon sequestration with enhanced Gas Recovery csegr
Energy, 2004Co-Authors: Curtis M. Oldenburg, S H Stevens, Sally M BensonAbstract:Abstract Prior reservoir simulation and laboratory studies have suggested that injecting carbon dioxide into mature natural Gas reservoirs for carbon sequestration with enhanced Gas Recovery (CSEGR) is technically feasible. Reservoir simulations show that the high density of carbon dioxide can be exploited to favor displacement of methane with limited Gas mixing by injecting carbon dioxide in low regions of a reservoir while producing from higher regions in the reservoir. Economic sensitivity analysis of a prototypical CSEGR application at a large depleting Gas field in California shows that the largest expense will be for carbon dioxide capture, purification, compression, and transport to the field. Other incremental costs for CSEGR include: (1) new or reconditioned wells for carbon dioxide injection, methane production, and monitoring; (2) carbon dioxide distribution within the field; and, (3) separation facilities to handle eventual carbon dioxide contamination of the methane. Economic feasibility is most sensitive to wellhead methane price, carbon dioxide supply costs, and the ratio of carbon dioxide injected to incremental methane produced. Our analysis suggests that CSEGR may be economically feasible at carbon dioxide supply costs of up to US$ 4–12/t (US$ 0.20–0.63/Mcf). Although this analysis is based on a particular Gas field, the approach is general and can be applied to other Gas fields. This economic analysis, along with reservoir simulation and laboratory studies that suggest the technical feasibility of CSEGR, demonstrates that CSEGR can be feasible and that a field pilot study of the process should be undertaken to test the concept further.
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process modeling of co2 injection into natural Gas reservoirs for carbon sequestration and enhanced Gas Recovery
Energy & Fuels, 2001Co-Authors: Curtis M. Oldenburg, Karsten Pruess, Sally M BensonAbstract:Injection of CO2 into depleted natural Gas reservoirs offers the potential to sequester carbon while simultaneously enhancing CH4 Recovery. Enhanced CH4 Recovery can partially offset the costs of CO2 injection. With the goal of analyzing the feasibility of carbon sequestration with enhanced Gas Recovery (CSEGR), we are investigating the physical processes associated with injecting CO2 into natural Gas reservoirs. The properties of natural Gas reservoirs and CO2 and CH4 appear to favor CSEGR. To simulate the processes of CSEGR, a module for the TOUGH2 reservoir simulator that includes water, brine, CO2, tracer, and CH4 in nonisothermal conditions has been developed. Simulations based on the Rio Vista Gas Field in the Central Valley of California are used to test the feasibility of CSEGR using CO2 separated from flue Gas generated by the 680 MW Antioch Gas-fired power plant. Model results show that CO2 injection allows additional CH4 to be produced during and after CO2 injection.
Eric F. May - One of the best experts on this subject based on the ideXlab platform.
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quantitative dependence of ch4 co2 dispersion on immobile water fraction
Aiche Journal, 2017Co-Authors: Marco Zecca, Sarah J. Vogt, Abdolvahab Honari, Gongkui Xiao, Einar O. Fridjonsson, Eric F. May, Michael L JohnsAbstract:Enhanced Gas Recovery (EGR) involves CO2 injection into natural Gas reservoirs to both increase Gas Recovery and trap CO2. EGR viability can be determined by reservoir simulations; however these require a description of fluid dispersion (mixing) between the supercritical CO2 and natural Gas. Here we quantify this dispersivity (α) in sandstone rock plugs as a function of residual water fraction. To ensure the accuracy of such data, we designed a novel core flooding experimental protocol that ensured an even spatial distribution of water, minimised erroneous entry/exit contributions to mixing, and minimised dissolution of the CO2 into the water phase. Dispersivity was found to increase significantly with water content, although the differences in α between sandstones were eliminated upon the inclusion of residual water. This enabled development of a correlation between α and water content and, hence, between the dispersion coefficient and Peclet number that is readily incorporable into reservoir simulations. This article is protected by copyright. All rights reserved.
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Inclusion of Connate Water in Enhanced Gas Recovery Reservoir Simulations
Energy, 2017Co-Authors: M.j. Patel, Eric F. May, Michael L JohnsAbstract:Abstract Enhanced natural Gas Recovery (EGR) with supercritical (sc)CO2 sequestration offers the prospect of increased natural Gas Recovery. High-fidelity reservoir simulations offer a method to quantify the risk of contamination of produced Gas by the injected scCO2. Simulations of scCO2 mixing with the reservoir Gas have been reported; however the effects of connate water on EGR have not been effectively explored. We extend a prior EGR simulation tool (Patel, May and Johns, 2016; Ref. [1]) to incorporate connate water accounting for its effect on dispersivity and permeability; chemical equilibrium is modelled using a novel, computationally efficient Lagrange multiplier-based approach. The code is applied to a ‘quarter five-spot’ benchmark scenario. The inclusion of connate water generally resulted in a reduction in breakthrough time and a decrease in methane Recovery. The connate water's largest effect was to change the scCO2 flow field, which sank towards the reservoir floor, flooded the lowermost accessible layers and entered the production well via a high throughput channel (‘coning’). The magnitude of these effects were, however, sensitive to well perforation depth, the influence of which was subsequently studied systematically. Well perforation depth was found to determine the duration of these sinking and coning events in a non-linear manner.
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enhanced Gas Recovery with co2 sequestration the effect of medium heterogeneity on the dispersion of supercritical co2 ch4
International Journal of Greenhouse Gas Control, 2015Co-Authors: Abdolvahab Honari, Michael L Johns, Branko Bijeljic, Eric F. MayAbstract:Abstract Reinjection of CO 2 into producing natural Gas reservoirs is considered as a promising technology to improve Gas Recovery, mitigate atmospheric emissions and control climate change. However, natural Gas and CO 2 are miscible at reservoir conditions and could result in CO 2 contamination of produced natural Gas. This mixing process and consequently the viability of Enhanced Gas Recovery (EGR) projects can be quantitatively determined by reservoir simulations – such simulations require a description of Gas dispersion. Here we conduct fluid transport experiments through carbonate and sandstone rock cores at various reservoir conditions to evaluate the effect of medium heterogeneity on the dispersion between supercritical CO 2 and CH 4 , accounting for erroneous contributions from entrance/exit and gravitational effects. Early breakthrough and long-tailed profiles are observed for one of the carbonate cores (Ketton) which is attributed to the existence of intra-grain micro-pores, which results in a persistent pre-asymptotic transport regime. Thus a revised model (Mobile-Immobile Model) was successfully used for this core to obtain dispersion coefficients characteristic of the eventual asymptotic regime. Both heterogeneous carbonate rocks considered exhibit higher dispersion than that observed in previously-measured homogeneous sandstone cores (Honari et al., 2013). The power law describing the dependency of dispersion coefficient on Peclet number at comparatively high interstitial displacement velocities gave an exponent of 1.2 for sandstones and 1.4 for carbonates, consistent with literature predictions (Bijeljic and Blunt, 2006; Bijeljic et al., 2011) based on pore-scale simulations.
