PB
Pavel Bedrikovetsky
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5 records found
1
The injection of humid (or wet) CO2 into geological aquifers offers a practical means of mitigating near-wellbore impairment caused by connate-water evaporation and the consequent formation damage induced by salt-precipitation in the dry zone. This study aims to develop a novel analytical model for this process. We extend the traditional Vertical Equilibrium (VE) formulation for immiscible displacement of brine by CO2 in layer-cake reservoirs to incorporate partial brine-CO2 miscibility, and formation damage due to fines migration and salt precipitation in the dry zone. The depth-averaging of the quasi-2D VE model yields explicit expressions for upscaled phase permeabilities and effective capillary pressure. The resulting 1D model allows for an exact self-similar solution, which provides explicit expressions for determining sweep efficiency and injectivity decline. The analysis of the model reveals the emergence of two distinct displacement fronts—a CO2 dissolution-displacement front (advanced front) and a full-evaporation front (receded front)—which delineate the two-phase flow region. The explicit analytical expressions derived enable rapid multivariate sensitivity studies on how CO2 humidity, reservoir heterogeneity, viscosity ratio and formation damage parameters influence overall sweep efficiency and well injectivity.
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The injection of humid (or wet) CO2 into geological aquifers offers a practical means of mitigating near-wellbore impairment caused by connate-water evaporation and the consequent formation damage induced by salt-precipitation in the dry zone. This study aims to develop a novel analytical model for this process. We extend the traditional Vertical Equilibrium (VE) formulation for immiscible displacement of brine by CO2 in layer-cake reservoirs to incorporate partial brine-CO2 miscibility, and formation damage due to fines migration and salt precipitation in the dry zone. The depth-averaging of the quasi-2D VE model yields explicit expressions for upscaled phase permeabilities and effective capillary pressure. The resulting 1D model allows for an exact self-similar solution, which provides explicit expressions for determining sweep efficiency and injectivity decline. The analysis of the model reveals the emergence of two distinct displacement fronts—a CO2 dissolution-displacement front (advanced front) and a full-evaporation front (receded front)—which delineate the two-phase flow region. The explicit analytical expressions derived enable rapid multivariate sensitivity studies on how CO2 humidity, reservoir heterogeneity, viscosity ratio and formation damage parameters influence overall sweep efficiency and well injectivity.
Heat exchange with surrounding formations and Joule–Thomson cooling during CO2 injection into deep saline aquifers and depleted hydrocarbon reservoirs can lead to substantial declines in well injectivity. This work addresses these challenges by introducing an analytical model for non-isothermal CO2 injection that accounts for both JT cooling and inter-formation heat exchange, assuming that heat transfer begins upon arrival of the temperature front rather than the gas–water front, as adopted in earlier models. An exact 1D solution is derived, providing closed-form expressions for temperature and pressure profiles. Model performance is evaluated through comparison with an exact 2D solution obtained from reservoir energy conservation. The new formulation demonstrates markedly improved accuracy over the previous model. The solution predicts a temperature drop from the injection temperature at the wellbore to a minimum at the temperature front, followed by a rapid rise back to the initial reservoir temperature. Mapping the evolving temperature and pressure profiles onto a (T, p) phase diagram enables assessment of hydrate-formation risk and identification of the distance from the injection well where hydrates may form.
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Heat exchange with surrounding formations and Joule–Thomson cooling during CO2 injection into deep saline aquifers and depleted hydrocarbon reservoirs can lead to substantial declines in well injectivity. This work addresses these challenges by introducing an analytical model for non-isothermal CO2 injection that accounts for both JT cooling and inter-formation heat exchange, assuming that heat transfer begins upon arrival of the temperature front rather than the gas–water front, as adopted in earlier models. An exact 1D solution is derived, providing closed-form expressions for temperature and pressure profiles. Model performance is evaluated through comparison with an exact 2D solution obtained from reservoir energy conservation. The new formulation demonstrates markedly improved accuracy over the previous model. The solution predicts a temperature drop from the injection temperature at the wellbore to a minimum at the temperature front, followed by a rapid rise back to the initial reservoir temperature. Mapping the evolving temperature and pressure profiles onto a (T, p) phase diagram enables assessment of hydrate-formation risk and identification of the distance from the injection well where hydrates may form.
Journal article
(2025)
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Christina Chesnokov, Kofi Ohemeng Kyei Prempeh, Rouhi Farajzadeh, Pavel Bedrikovetsky
Joule-Thomson cooling during CO2 injection into low-pressure fields can lead to injectivity impairment due to hydrate formation. This paper presents axial-symmetric flow model, which can be used to predict propagation of temperature and CO2 fronts during CO2 injection into porous formations accounting for Joule-Thomson cooling and unsteady-state delayed heat exchange between the reservoir and the adjacent formations. The solution of the 1D flow is validated by comparing with the quasi 2D analytical heat-conductivity solution. The non-steady state heat exchange results in a temperature front that propagates without limit into the reservoir with time. The temperature profiles exhibit a temperature decrease from the injected temperature to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The solution allows plotting temperature-pressure (T-P) profiles at fixed moments in the CO2-water phase diagram. By changing injection parameters such as injection rate, the T-P trajectories allow for assessment of hydrate formation.
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Joule-Thomson cooling during CO2 injection into low-pressure fields can lead to injectivity impairment due to hydrate formation. This paper presents axial-symmetric flow model, which can be used to predict propagation of temperature and CO2 fronts during CO2 injection into porous formations accounting for Joule-Thomson cooling and unsteady-state delayed heat exchange between the reservoir and the adjacent formations. The solution of the 1D flow is validated by comparing with the quasi 2D analytical heat-conductivity solution. The non-steady state heat exchange results in a temperature front that propagates without limit into the reservoir with time. The temperature profiles exhibit a temperature decrease from the injected temperature to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The solution allows plotting temperature-pressure (T-P) profiles at fixed moments in the CO2-water phase diagram. By changing injection parameters such as injection rate, the T-P trajectories allow for assessment of hydrate formation.
CO2 Storage in Subsurface Formations
Impact of Formation Damage
Journal article
(2024)
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Amin Shokrollahi, Syeda Sara Mobasher, Kofi Ohemeng Kyei Prempeh, Parker William George, Abbas Zeinijahromi, Rouhi Farajzadeh, Nazliah Nazma Zulkifli, Mohammad Iqbal Mahammad Amir, Pavel Bedrikovetsky
The success of CO2 storage projects largely depends on addressing formation damage, such as salt precipitation, hydrate formation, and fines migration. While analytical models for reservoir behaviour during CO2 storage in aquifers and depleted gas fields are widely available, models addressing formation damage and injectivity decline are scarce. This work aims to develop an analytical model for CO2 injection in a layer-cake reservoir, considering permeability damage. We extend Dietz’s model for gravity-dominant flows by incorporating an abrupt permeability decrease upon the gas-water interface arrival in each layer. The exact Buckley-Leverett solution of the averaged quasi-2D (x, z) problem provides explicit formulae for sweep efficiency, well impedance, and skin factor of the injection well. Our findings reveal that despite the induced permeability decline and subsequent well impedance increase, reservoir sweep efficiency improves, enhancing storage capacity by involving a larger rock volume in CO2 sequestration. The formation damage factor d, representing the ratio between damaged and initial permeabilities, varies from 0.016 in highly damaged rock to 1 in undamaged rock, resulting in a sweep efficiency enhancement from 1–3% to 50–53%. The developed analytical model was applied to predict CO2 injection into a depleted gas field.
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The success of CO2 storage projects largely depends on addressing formation damage, such as salt precipitation, hydrate formation, and fines migration. While analytical models for reservoir behaviour during CO2 storage in aquifers and depleted gas fields are widely available, models addressing formation damage and injectivity decline are scarce. This work aims to develop an analytical model for CO2 injection in a layer-cake reservoir, considering permeability damage. We extend Dietz’s model for gravity-dominant flows by incorporating an abrupt permeability decrease upon the gas-water interface arrival in each layer. The exact Buckley-Leverett solution of the averaged quasi-2D (x, z) problem provides explicit formulae for sweep efficiency, well impedance, and skin factor of the injection well. Our findings reveal that despite the induced permeability decline and subsequent well impedance increase, reservoir sweep efficiency improves, enhancing storage capacity by involving a larger rock volume in CO2 sequestration. The formation damage factor d, representing the ratio between damaged and initial permeabilities, varies from 0.016 in highly damaged rock to 1 in undamaged rock, resulting in a sweep efficiency enhancement from 1–3% to 50–53%. The developed analytical model was applied to predict CO2 injection into a depleted gas field.
Journal article
(2024)
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Christina Chesnokov, Rouhi Farajzadeh, Kofi Ohemeng Kyei Prempeh, Siavash Kahrobaei, Jeroen Snippe, Pavel Bedrikovetsky
This paper discusses axi-symmetric flow during CO2 injection into a non-adiabatic reservoir accounting for Joule-Thomson cooling and steady-state heat exchange between the reservoir and the adjacent layers by Newton's law. An exact solution for this 1D problem is derived and a new method for model validation by comparison with quasi 2D analytical heat-conductivity solution is developed. The temperature profile obtained by the analytical solution shows a temperature decrease to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The temperature distribution head of the front is determined by the initial reservoir temperature, while the solution behind the front is determined by the temperature of injected CO2. The analytical model exhibits stabilisation of the temperature profile and the cooled zone. The explicit formula for temperature distributions allows determining the maximum injection rate that avoids hydrate formation.
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This paper discusses axi-symmetric flow during CO2 injection into a non-adiabatic reservoir accounting for Joule-Thomson cooling and steady-state heat exchange between the reservoir and the adjacent layers by Newton's law. An exact solution for this 1D problem is derived and a new method for model validation by comparison with quasi 2D analytical heat-conductivity solution is developed. The temperature profile obtained by the analytical solution shows a temperature decrease to a minimum value, followed by a sharp increase to initial reservoir temperature on the temperature front. The temperature distribution head of the front is determined by the initial reservoir temperature, while the solution behind the front is determined by the temperature of injected CO2. The analytical model exhibits stabilisation of the temperature profile and the cooled zone. The explicit formula for temperature distributions allows determining the maximum injection rate that avoids hydrate formation.