• Energy Research

AbstractNew advancements in unconventional oil reservoirs to enhance cumulative oil production are essential for petroleum industries to develop new oilfields. Carbon dioxide injection (CO2) is considered one of the most functional enhanced oil recovery (EOR) methods, especially in shale reservoirs, regarding their low permeability of pores and cracks. This paper aims to experimentally investigate the crucial factors such as shale particle size, pressure, and temperature on the CO2 adsorption that can be used as a useful guideline for developing unconventional hydrocarbon reservoirs. Thereby, pressure increase would be an essential parameter to increase CO2 storage capacity; however, temperature increase has a reverse pattern and has caused to decrease the CO2 storage capacity. The essence of the oil recovery factor from shale reservoirs is another crucial factor that depends on the pressure, temperature, and soaking time factors. CO2 injection would be a proper (EOR) method to increase the oil recovery factor for higher pressures and temperatures. Therefore, the applicability of CO2 injection in shale reservoirs could provide efficient results rather than other EOR techniques.

AbstractNew advancements in unconventional oil reservoirs to enhance cumulative oil production are essential for petroleum industries to develop new oilfields. Carbon dioxide injection (CO2) is considered one of the most functional enhanced oil recovery (EOR) methods, especially in shale reservoirs, regarding their low permeability of pores and cracks. This paper aims to experimentally investigate the crucial factors such as shale particle size, pressure, and temperature on the CO2 adsorption that can be used as a useful guideline for developing unconventional hydrocarbon reservoirs. Thereby, pressure increase would be an essential parameter to increase CO2 storage capacity; however, temperature increase has a reverse pattern and has caused to decrease the CO2 storage capacity. The essence of the oil recovery factor from shale reservoirs is another crucial factor that depends on the pressure, temperature, and soaking time factors. CO2 injection would be a proper (EOR) method to increase the oil recovery factor for higher pressures and temperatures. Therefore, the applicability of CO2 injection in shale reservoirs could provide efficient results rather than other EOR techniques.

Abstract Due to the increasing demand for gas consumption during cold seasons, it is a sense of urgency to provide a reliable resource for gas supply during these periods. The objectives of this comprehensive research entail reservoir core analysis, reservoir fluid study, investigation and optimization of improved condensate recovery during gas storage processes in one of Iranian-depleted fractured gas condensate reservoir. We have attempted to make a balance among reservoir petrophysical and operational characteristics such as production rate, ultimate reservoir pressure after production, cumulative condensate production, number of wells and the required time periods for the reservoir depletion, to obtain an optimum condition for the gas storage process. It’s a foregone conclusion that the quality of management decision-making regarding reservoir depletion, maximum gas recovery and natural gas condensate production subsequently optimize at the minimum pressure drop. Furthermore, according to the simulation analysis, pipeline gas injection may lead to condensate recovery improvement.

Abstract Due to the increasing demand for gas consumption during cold seasons, it is a sense of urgency to provide a reliable resource for gas supply during these periods. The objectives of this comprehensive research entail reservoir core analysis, reservoir fluid study, investigation and optimization of improved condensate recovery during gas storage processes in one of Iranian-depleted fractured gas condensate reservoir. We have attempted to make a balance among reservoir petrophysical and operational characteristics such as production rate, ultimate reservoir pressure after production, cumulative condensate production, number of wells and the required time periods for the reservoir depletion, to obtain an optimum condition for the gas storage process. It’s a foregone conclusion that the quality of management decision-making regarding reservoir depletion, maximum gas recovery and natural gas condensate production subsequently optimize at the minimum pressure drop. Furthermore, according to the simulation analysis, pipeline gas injection may lead to condensate recovery improvement.

Alternative injection of gas as slugs with water slugs, or alternative water gas injection, is the conventional technique for improving the recovery factor due to its high potential for mobilizing the residual oil in place in the reservoirs and to control gas mobility. The water alternating gas methodology is a combination of two oil recovery procedures: gas injection and waterflooding. The principal parameters that must be evaluated in water alternating gas injection in laboratory scale are reservoir heterogeneity, rock type, and fluid properties. In the current investigation, a feasibility study has been performed to analyze the five various scenarios of enhanced oil recovery techniques and compare them experimentally. The laboratory experiments are done for one of the Iranian reservoirs which have been subjected to waterflooding for several years, and the amount of recovery factor for water flooding is about 42%. The results of this study illustrate that water alternating gas injection and hot water alternating gas injection exert a profound impact on the amount of recovery factor. Moreover, the primary purpose of this study is to assess the application of alternative hot water and hot carbon dioxide gas injections in the conventional and fractured reservoir model.

Alternative injection of gas as slugs with water slugs, or alternative water gas injection, is the conventional technique for improving the recovery factor due to its high potential for mobilizing the residual oil in place in the reservoirs and to control gas mobility. The water alternating gas methodology is a combination of two oil recovery procedures: gas injection and waterflooding. The principal parameters that must be evaluated in water alternating gas injection in laboratory scale are reservoir heterogeneity, rock type, and fluid properties. In the current investigation, a feasibility study has been performed to analyze the five various scenarios of enhanced oil recovery techniques and compare them experimentally. The laboratory experiments are done for one of the Iranian reservoirs which have been subjected to waterflooding for several years, and the amount of recovery factor for water flooding is about 42%. The results of this study illustrate that water alternating gas injection and hot water alternating gas injection exert a profound impact on the amount of recovery factor. Moreover, the primary purpose of this study is to assess the application of alternative hot water and hot carbon dioxide gas injections in the conventional and fractured reservoir model.

The sufficient energy to transfer the crude oil to the surficial wellbore facilities would be reduced dramatically which was done by CO2, especially for heavy and super-heavy oil reservoirs. The objective of this comprehensive study is to measure the considerable influence of CO2 solubility on the recovery factor, density, viscosity at different pressures and temperatures. According to the results of this study, recovery factor at the pressure of 0.2 MPa and 0.5 MPa experienced the lowest recovery factor among other pressures. They were about 38.37% and 43.81% after the injection of about 15 pore volumes of CO2. For the pressures of 1 MPa, 2 MPa, 3 MPa, and 4 MPa, at the first stages of CO2 injection (up to 3 pore volumes of CO2 injection), the recovery factor experienced the same value. Since then, by the increase in pressure from 1 to 4 MPa, the recovery factor was increased slightly. Moreover, recovery factor at the temperature of 333 K was measured about 34.5%. The measured recovery factor for other temperatures was 40.17%, 47.68%, 51.97%, 58.42%, and 63.54% at the temperature of 363 K, 393 K, 423 K, 453 K, and 483 K, respectively. On the other hand, the density of heavy oil which was saturated with CO2 was decreased with the increase in pressure and temperature and the higher temperatures caused the lower effect on the viscosity and density of heavy oil. Consequently, the dissolution of CO2 had decreased the heavy oil viscosity in the higher temperatures and pressures, and due to the increase in pressure and temperature, the heavy oil recovery factor was increased. Furthermore, the recovery factor for the 70 mL min−1 of CO2 injection was lower than the 700 mL min−1 of CO2 injection.

The sufficient energy to transfer the crude oil to the surficial wellbore facilities would be reduced dramatically which was done by CO2, especially for heavy and super-heavy oil reservoirs. The objective of this comprehensive study is to measure the considerable influence of CO2 solubility on the recovery factor, density, viscosity at different pressures and temperatures. According to the results of this study, recovery factor at the pressure of 0.2 MPa and 0.5 MPa experienced the lowest recovery factor among other pressures. They were about 38.37% and 43.81% after the injection of about 15 pore volumes of CO2. For the pressures of 1 MPa, 2 MPa, 3 MPa, and 4 MPa, at the first stages of CO2 injection (up to 3 pore volumes of CO2 injection), the recovery factor experienced the same value. Since then, by the increase in pressure from 1 to 4 MPa, the recovery factor was increased slightly. Moreover, recovery factor at the temperature of 333 K was measured about 34.5%. The measured recovery factor for other temperatures was 40.17%, 47.68%, 51.97%, 58.42%, and 63.54% at the temperature of 363 K, 393 K, 423 K, 453 K, and 483 K, respectively. On the other hand, the density of heavy oil which was saturated with CO2 was decreased with the increase in pressure and temperature and the higher temperatures caused the lower effect on the viscosity and density of heavy oil. Consequently, the dissolution of CO2 had decreased the heavy oil viscosity in the higher temperatures and pressures, and due to the increase in pressure and temperature, the heavy oil recovery factor was increased. Furthermore, the recovery factor for the 70 mL min−1 of CO2 injection was lower than the 700 mL min−1 of CO2 injection.