Feasibility study of CO2 huff 'n' puff process to enhance heavy oil recovery via long core experiments

Zhou, Xiang; Yuan, Qingwang; Rui, Zhenhua; Wang, Hanyi; Feng, Jie; Zhang, Liehui; Zeng, Fanhua

doi:10.1016/j.apenergy.2018.12.007

Cited by 90 publications

(37 citation statements)

References 49 publications

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“…Foamy oil‐rich pressure decline range is defined as the pressure range where the foamy oil flow flourishes during the pressure depletion process. Pressure gradient is one of the main factors that affects the critical gas saturation of solution gas drive within the foamy oil flow . One previous CSI experimental study indicates that the oil recovery peaks within certain pressure ranges during pressure depletion process .…”

Section: Resultsmentioning

confidence: 99%

“…Pressure gradient is one of the main factors that affects the critical gas saturation of solution gas drive within the foamy oil flow. 37,38 One previous CSI experimental study indicates that the oil recovery peaks within certain pressure ranges during pressure depletion process. 39 Therefore, it is reasonable to introduce the difference in foamy oil-rich pressure range between CHSI and CSI methods to determine the injection temperature influence.…”

Section: Effect Of Injection Condition On Foamy Oil Strength and Lomentioning

confidence: 97%

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Solvent temperature: An injection condition to bring multiple changes in the heavy oil exploitation process based on the cyclic solvent injection (CSI) recovery method

Zhang

Zhou

et al. 2019

Energy Science & Engineering

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Heavy oil is a major fossil fuel resource to fulfill global growing fuel consumption. Hot solvent injection is an effective heavy oil production method. Hot solvent application feasibility has been previously compared between cyclic solvent injection (CSI) method and vapor solvent extraction (VAPEX) method where CSI method is advantageous in terms of oil recovery. However, previous studies have focused on the solvent temperature sensitivity analysis only in the VAPEX method. In this study, the solvent temperature study has been conducted discussing the multiple effects of temperature on both foamy oil and production performance in CSI method. A conventional CSI experiment (20°C) and two hot solvent‐based CSI experiments (55 and 70°C) are conducted. The results demonstrate that, although the oil recovery of three tests is close to each other, oil rate and foamy oil strength will increase with the solvent injection temperature during the high oil rate phase. However, at a high injection temperature level, the maintenance of foamy oil is difficult due to high‐temperature effect on foamy oil stability. Medium‐high temperature level (55°C) is considered optimal temperature regarding the solvent extraction efficiency based on the gross utilization factor data.

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Section: Resultsmentioning

confidence: 99%

Section: Effect Of Injection Condition On Foamy Oil Strength and Lomentioning

confidence: 97%

Solvent temperature: An injection condition to bring multiple changes in the heavy oil exploitation process based on the cyclic solvent injection (CSI) recovery method

Zhang

Zhou

et al. 2019

Energy Science & Engineering

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“…The mode is conducted by a cyclical operation with three distinct procedures: (1) Inject gas into the inclined reservoir; (2) shut-in wells and sufficient time is allowed for gas to migrate up-dip by gravity segregation; (3) the gas injection well is converted to produce until the production well is gas flooded. The production mode is similar to the Huff 'n' Puff process [27][28][29][30]. Based on the production mode, Kimbrell et al [31] designed a sand pack model with the gas injection (oil production) well in the middle to conduct an attic oil development experiment.…”

Section: Introductionmentioning

confidence: 99%

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

Jiang

et al. 2020

Energies

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As the mature oil fields have stepped into the high water cut stage, the remaining oil is considered as potential reserves, especially the attic oil in the inclined fault-block reservoirs. A novel assisted gas–oil countercurrent technique utilizing gas oil countercurrent (GOC) and water flooding assistance (WFA) is proposed in this study to enhance the remaining oil recovery in sealed fault-block reservoirs. WFA is applied in our model to accelerate the countercurrent process and inhibit the gas channeling during the production process. Four comparative experiments are conducted to illustrate enhanced oil recovery (EOR) mechanisms and compare the production efficiency of assisted GOC under different assistance conditions. The results show that WFA has different functions at different stages of the development process. In the gas injection process, WFA forces the injected gas to migrate upward and shortens the shut-in time by approximately 50% and the production efficiency improves accordingly. Compared with the basic GOC process, the attic oil swept area is extended 60% at the same shut-in time condition and secondary gas cap forms under the influence of WFA. At the production stage, the WFA and secondary gas cap expansion form the bi-directional flooding. The bi-directional flooding also displaces the bypassed oil and replaced attic oil located below the production well, which cannot be swept by the gas cap expansion. WFA inhibits the gas channeling effectively and increases the sweep factor by 26.14% in the production stage. The oil production increases nearly nine times compared with the basic GOC production process. The proposed technique is significant for the development of attic oil in the mature oil field at the high water cut stage.

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“…As a consequence, more oil can be produced and oil recovery can be enhanced by reducing oil viscosity, expanding oil volume, and extracting the light components of crude oil. [18][19][20][21][22][23] Mohammed-Singh et al 24 summarized the cases of CO 2 huff and puff in oil fields over the past two decades. Among above methods, CO 2 huff and puff has attracted more attention as an efficient and important technique.…”

Section: Introductionmentioning

confidence: 99%

“…[13][14][15][16][17] Both soaking time and CO 2 injection volume are important operation parameters to improve the performance of CO 2 huff and puff. [18][19][20][21][22][23] Mohammed-Singh et al 24 summarized the cases of CO 2 huff and puff in oil fields over the past two decades. They found that the best soaking time was 2-4 weeks and massive CO 2 injection enhanced the oil recovery of CO 2 huff and puff.…”

Section: Introductionmentioning

confidence: 99%

Experimental investigation on influencing factors of CO₂huff and puff under fractured low‐permeability conditions

Bai

et al. 2019

Energy Science & Engineering

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The fracture system is a vital component of fractured low‐permeability reservoirs. The presence of fractures can improve reservoir flow capacity and injected carbon dioxide (CO2) utilization, thus leading to higher oil recovery. In this study, the effects of the presence of fracture, fracture morphology, soaking time, and CO2 injection volume on CO2 huff and puff were investigated through 11 low‐permeability cores with different properties. The experimental results indicated that the presence of fractures enhanced cyclic oil recovery and increased the effective cycle numbers during CO2 huff and puff in low‐permeability cores. Moreover, compared with low‐permeability cores without fractures, ultimate oil recovery of CO2 huff and puff was risen up by ~11% in fractured cores. Longer soaking time was conducive to enhancing ultimate oil recovery of CO2 huff and puff in fractured low‐permeability cores, but the excessive soaking time had little effect on ultimate oil recovery. Meanwhile, excessive CO2 injection volume did not significantly improve the performance of CO2 huff and puff, but it did reduce the CO2 utilization. Moreover, gravity caused the produced oil to deposit on the bottom surface of the blowout end of the fracture, which made oil recovery of the core with a horizontal fracture slightly higher (~7%) than that of the core with a vertical fracture. In addition, variation in the intersection angle of fractures had little effect on ultimate oil recovery of CO2 huff and puff in fractured low‐permeability cores. It, however, did change the conductivity of the entire core, thus affecting oil recovery during the first two cycles remarkably.

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Feasibility study of CO2 huff 'n' puff process to enhance heavy oil recovery via long core experiments

Cited by 90 publications

References 49 publications

Solvent temperature: An injection condition to bring multiple changes in the heavy oil exploitation process based on the cyclic solvent injection (CSI) recovery method

Solvent temperature: An injection condition to bring multiple changes in the heavy oil exploitation process based on the cyclic solvent injection (CSI) recovery method

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

Experimental investigation on influencing factors of CO₂huff and puff under fractured low‐permeability conditions

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Feasibility study of CO2 huff 'n' puff process to enhance heavy oil recovery via long core experiments

Cited by 90 publications

References 49 publications

Solvent temperature: An injection condition to bring multiple changes in the heavy oil exploitation process based on the cyclic solvent injection (CSI) recovery method

Solvent temperature: An injection condition to bring multiple changes in the heavy oil exploitation process based on the cyclic solvent injection (CSI) recovery method

A Novel Assisted Gas–Oil Countercurrent EOR Technique for Attic Oil in Fault-Block Reservoirs

Experimental investigation on influencing factors of CO2huff and puff under fractured low‐permeability conditions

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Experimental investigation on influencing factors of CO₂huff and puff under fractured low‐permeability conditions