Numerical simulation of Water-alternating-gas Process for Optimizing EOR and Carbon Storage

Zhi, Zhao; Liu, Siyan; Carr, Timothy R.; Takbiri-Borujeni, Ali; Kazemi, Mohammad; Fu, Qinwen

doi:10.1016/j.egypro.2019.01.507

Cited by 13 publications

(9 citation statements)

References 2 publications

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“…Their simulation results showed the significance of molecular diffusion in a gas injection on EOR for the studied reservoirs. Zhong et al 24 studied a numerical simulation of the WAG process for optimizing carbon storage and EOR. Their results showed that injection of WAG caused the mobility ratio of water and oil to decrease and swept coefficient to increase, the total recovery of the reservoir after WAG injection increased.…”

Section: Introductionmentioning

confidence: 99%

Modeling of the movement of rich gas in a porous medium in immiscible, near miscible and miscible conditions

Mehrjoo

Safaei

Kazemzadeh

et al. 2023

Sci Rep

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Gas injection is one of the most common enhanced oil recovery techniques in oil reservoirs. In this regard, pure gas, such as carbon dioxide (CO2), nitrogen (N2), and methane (CH4) was employed in EOR process. The performance of pure gases in EOR have been investigated numerically, but till now, numerical simulation of injection of rich gases has been scared. As rich gases are more economical and can result in acceptable oil recovery, numerical study of the performance of rich gases in EOR can be an interesting subject. Accordingly, in the present work the performance of rich gases in the gas injection process was investigated. Methane has been riched in liquefied petroleum gas (LPG), natural gas liquid (NGL), and Naphtha. Afterwards, the process of gas injection was simulated and the effect of injection fluids on the relative permeability, saturation profile of gas, and fractional flow of gas was studied. Our results showed that as naphtha is a heavier gas than the two other ones, IFT of oil-rich gas with naphtha is lower than other two systems. Based our results, gas oil ratio (GOR) and injection pressure did not affect the final performance of injection gas that has been riched in NGL and LPG. However, when GOR was 1.25 MSCF/STB, rich gas with naphtha moved with a higher speed in the domain and the relative permeability of each fluid and fractional flow of gas were affected. The same result was achieved at higher injection pressure. When injection pressure was 2000 psi, movement of gas with higher speed in the domain, alteration of relative permeability and changes in the fractional flow of gas were obvious. Therefore, based on our result, injection of naphtha with low pressure and high GOR was suggested for considered oil.

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Section: Introductionmentioning

confidence: 99%

Modeling of the movement of rich gas in a porous medium in immiscible, near miscible and miscible conditions

Mehrjoo

Safaei

Kazemzadeh

et al. 2023

Sci Rep

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“…The study of hydrate formation problem in the technological lines of downhole wells and bottomhole zone is of the highest relevance. The search for strategies and methods of eliminating excess hydrate formation, for different regime and technological conditions of oil field development, increases in depletion conditions of explored oil reserves in the world [4][5][6][7][8][9][10][11][12][13][14][15][16][17][18][19][20]. This is due, in particular, to the increasing need for flooding and injection of various gases compositions into depleted deposits to intensify oil production.…”

Section: Introductionmentioning

confidence: 99%

Geothermal heat use to eliminate hydrate formations in oil deposit injection wells

et al. 2021

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The article is devoted to an actual issue: the development of internal downhole heat exchangers technology to combat hydration in injection wells. Purpose: development of conceptual solutions for the use of geothermal coolant in the internal well heat exchanger of the injection well. A scheme of an internal downhole heat exchanger with a geothermal heat carrier has been developed, and includes a supply line of a geothermal carrier through the heat exchange surface of the injection well into the productive reservoir of the oil field. The scheme provides targeted utilization of thermobaric energy of a geothermal source to combat hydration in the injection well. A mathematical apparatus for describing the process of heat utilization and heat exchange in injection well is proposed. It is established that the capacity of one geothermal well discovered at the oil depths in the Dnipro-Donetsk basin is sufficient to eliminate hydration in 1-3 injection wells, and determines the feasibility of their joint work.

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“…A geological formation must have the properties, for instance, injectivity, capacity, and restriction in terms of long-term CO2 storage and safety. CO2 can be stored in a geological formation by diverse methods through a variety of chemical and physical trapping mechanisms (Zhong et al, 2018). Physical trapping of CO2 takes place when CO2 is stationary as a free gas or supercritical fluid and as a process, it depends on the storage volume availability.…”

Section: Co2 Trapping Mechanismmentioning

confidence: 99%

“…Whereas chemical trapping of CO2 happens when CO2 contact with any materials in underground storage sites or reservoir. The cap-rock integrity is vital to prevent the upward movement of supercritical CO2 towards the surface (Zhong et al, 2018).…”

Section: Co2 Trapping Mechanismmentioning

confidence: 99%

“…This trapping mechanisms are the essential parts in the storage of CO2 in a depleted hydrocarbon reservoir. The cap-rock integrity is vital to prevent the upward movement of supercritical CO2 towards the surface (Zhong et al, 2018). Once CO2 is injected, supercritical CO2 can be more buoyant than other liquids that might be presented in the pore space.…”

Section: Structural or Stratigraphic Trappingmentioning

confidence: 99%

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Simulation study on co2 enhanced oil recovery for offshore area in Thailand

Wongsriraksa

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Fossil fuels are widely used all over the world. It generates carbon dioxide (CO2) which is one of the main causes for climate change and global warming. One practical technology to reduce CO2 emission is carbon capture, utilization, and storage (CCUS) which includes the use of CO2 for enhanced oil recovery (CO2EOR) and storage in the geological reservoir. In Thailand, there are some potential geological reservoirs for CO2EOR due to crude properties, depth of the reservoir and oil saturation, especially in the Gulf of Thailand. However, the high temperatures gradient in the Gulf of Thailand can lead to higher minimum miscibility pressure (MMP). Consequently, this study becomes partial CO2 miscible process. Previous studies on this issue in Thailand are rarely available and it becomes more difficult to determine appropriates parameters including injection rate and operating pressure for the CO2EOR processes. This study aims to evaluate the possibility of CO2EOR in the presuming light oil reservoir in the offshore area by applying the real data from the area, a 3-D heterogeneous reservoir model is created and used in the CO2EOR simulations. This study uses two CO2EOR technologies which are CO2 flooding and water alternating gas (WAG) within 24 years of production. The fracture pressure is calculated and considered to prevent the reservoir fracture whilst injecting displacing fluid. The two main parameters studied are the injection rate and operating pressure. The results present that WAG method with the highest injection rate of both CO2 at 0.8 MMSCF/day and water at 500 STB/day as well as operating pressure at 90% of fracture pressure can produce oil with the highest recovery factor at 48.1% and total oil production at 550,497 STB. However, the highest total oil production comes with the high amount of produced water. On the other hands, CO2 flooding with the highest CO2 injection rate at 0.8 MMSCF/day and the highest operating pressure at 90% of fracture pressure produces oil with lower recovery factor at 43.1% and total oil production at 492,893 STB but the produced water declines along with the production rate. Lastly, although this study area has high temperature which causes the process to be partially CO2 miscible, the results of the study can contribute to utilize CO2 from the source for more oil production and to store carbon for the potential site to reach Thailand's carbon neutrality in the future. �

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Numerical simulation of Water-alternating-gas Process for Optimizing EOR and Carbon Storage

Cited by 13 publications

References 2 publications

Modeling of the movement of rich gas in a porous medium in immiscible, near miscible and miscible conditions

Modeling of the movement of rich gas in a porous medium in immiscible, near miscible and miscible conditions

Geothermal heat use to eliminate hydrate formations in oil deposit injection wells

Simulation study on co2 enhanced oil recovery for offshore area in Thailand

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