Application of X-Ray CT for Investigation of CO&lt;sub&gt;2&lt;/sub&gt; and WAG Injection in Fractured Reservoirs

Chakravarthy, Deepak; Muralidharan, Vivek; Putra, Erwinsyah; Schechter, David S.

doi:10.2118/2004-232

Cited by 24 publications

(11 citation statements)

References 8 publications

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“…Although the sandpacks are approximately homogeneous, results show that slightly uneven residual oil distribution is still observed in this experiment. Such uneven residual oil distribution can be attributed to the coupled effect of viscous fingering and properties changes of the oil during CO 2 flooding process . CO 2 viscosity is estimated to be 0.063, while the oil phase viscosity is 4.22 mPa s for Test No.…”

Section: Resultsmentioning

confidence: 98%

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Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Wang

Chen

2015

Energy Fuels

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In immiscible CO 2 flooding processes, the injected CO 2 extracts light and intermediate components from reservoir hydrocarbons, changing the properties of both the produced and residual oils. CO 2 injection also increases asphaltene precipitation, which further causes adverse effects on the oil effective permeability, operational facilities, and the oil recovery. In this study, six CO 2 flooding followed by blowdown processes are carried out in the laboratory under four CO 2 injection pressures and two temperatures, and the properties of produced and residual oils are further characterized. It is found that uneven residual oil distribution occurred due to the coupled effects of viscous fingering and oil properties changes during CO 2 flooding process. Characterization of the produced oil shows that both the produced oil density and viscosity decrease when CO 2 injection pressure increases. The asphaltenes content of the oil produced after CO 2 breakthrough is found to be relatively lower than that of the oil samples collected before CO 2 breakthrough. In addition, the produced oil becomes lighter as the CO 2 injected volume increases. The saturates content in the residual oil decrease considerably in comparison with original crude oil in the CO 2 miscible flooding process. Furthermore, this study discovers that asphaltene component in produced oils is more stable than that in residual oils based on asphaltene-to-resin ratio (ATR) analysis. Finally, incremental oil recoveries of 2.78%−11.72% can be experimentally achieved through blowdown processes that are carried out after a 30 min soaking period. The laboratory study not only shows that blowdown processes can be successfully applied to improve the performance of CO 2 flooding processes, but also provides a deep understanding of properties changes of produced and residual oils in CO 2 -enhanced oil recovery processes.

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Section: Resultsmentioning

confidence: 98%

“…Such uneven residual oil distribution can be attributed to the coupled effect of viscous fingering and properties changes of the oil during CO 2 flooding process. 27 CO 2 viscosity is estimated to be 0.063, while the oil phase viscosity is 4.22 mPa s for Test No. 1.…”

Section: Distribution Of Residual Oilmentioning

confidence: 92%

Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Wang

Chen

2015

Energy Fuels

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“…However, there are some obstacles to achieving these conditions in petroleum reservoirs. Gas flooding has very poor volumetric sweep efficiency, and this is attributed to three main causes: the gravity override which is caused by the density differences between injected gas and the reservoir fluids; the gas fingering caused by the lower viscosity of injected gas compared with the reservoir fluid; and the reservoir heterogeneity which includes high permeability and heavily fractured zones. − Several methods have been tested in attempting to solve this issue. The use of foam is one of the most promising techniques to overcome gas mobility challenges in petroleum reservoirs and to improve the volumetric sweep efficiency. , Foam can reduce the gas mobility in a petroleum reservoir by increasing the apparent gas viscosity and reducing the gas relative permeability .…”

Section: Introductionmentioning

confidence: 99%

Enhancing the Stability of Foam by the Use of Nanoparticles

2017

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Foam generation is one of the most promising techniques to overcome gas mobility challenges and improve the sweep efficiency of reservoir fluids. The synergistic effect of surfactant and nanoparticles can help produce a stronger and more stable foam in reservoir porous media. The objective of this work is to assess the ability of anionic surfactant and a mixture of the surfactant and nanoparticles to produce foam for gas mobility control and the enhancement of oil recovery. Static, dynamic, and core flood tests were conducted to evaluate foam strength. Static foam tests in the presence of crude oil showed a clear trend on foam behavior when solid nanoparticles were added to surfactant. As the concentration of nanoparticles increases, the foam half-life increases, too. Foamability tests in Bentheimer sandstone showed better foam generation and stabilization when nanoparticles were used. The addition of nanoaprticles to surfactant solutions resulted in higher pressure drop and, therefore, higher reduction of gas mobility compared to surfactant. The rise in temperature from 25 to 50 °C reduces the measured pressure drop across the core samples in the absence and presence of nanoparticles, which can be attributed to the reduction in foam stability and strength. Both surfactant and a mixture of surfactant and nanoparticles were able to enhance oil recovery. The surfactant was able to bring the oil recovery to 41.45% of the original oil in place (OOIP). In contrast, the presence of nanoparticles resulted in higher oil recovery, 49.05%, of the OOIP.

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“…Despite the reported successes of CO 2 injection, a major challenge faced by this technique is poor volumetric sweep efficiency. Major factors that contribute to this problem are the low density and viscosity of CO 2 relative to reservoir fluids, as well as reservoir heterogeneity such as high permeability and heavily fractured zones (Campbell and Orr 1985;Chakravarthy et al 2004;Masalmeh et al 2010). To solve this issue, either conformance control or mobility control techniques might be applied (Seright 1997;Choi et al 2010;Pu et al 2018;Torrealba and Hoteit 2018;Enick et al 2012).…”

Section: Introductionmentioning

confidence: 99%

“…To solve the CO 2 injection issues, several approaches have been tested. The most reported and applied approaches are: water alternating gas (WAG), generation of foams, and increasing gas viscosity by adding thickening agents (Christensen et al 1998;Chakravarthy et al 2004;Enick 1998;Dalland andHanssen 1997, Enick et al 2012;Dandge and Heller 1987;Heller 1994). The use of foam has the potential to reduce the gas mobility in a petroleum reservoir by increasing the gas apparent viscosity and reducing the gas relative permeability and, hence, improve the volumetric sweep efficiency (Falls et al 1988;Kovscek and Radke 1994).…”

Section: Introductionmentioning

confidence: 99%

Surfactant and a mixture of surfactant and nanoparticles to stabilize CO2/brine foam, control gas mobility, and enhance oil recovery

Yousef

Almobarky

Schechter

2019

J Petrol Explor Prod Technol

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Injecting carbon dioxide into oil reservoirs has the potential to serve as an enhanced oil recovery (EOR) technique, mitigating climate change by storing CO 2 underground. Despite the successful achievements reported of CO 2 to enhance oil recovery, mobility control is one of the major challenges faced by CO 2 injection projects. The objective of this work is to investigate the potential of using surfactant and a mixture of surfactant and nanoparticles to generate foam to reduce gas mobility and enhance oil recovery. A newly developed anionic surfactant and a mixture of the surfactant and surface-modified silica nanoparticles were used to assess the ability of generating a stable foam at harsh reservoir conditions: sc-CO 2 and high temperature. Dynamic foam tests and coreflood experiments were conducted to evaluate foam stability and strength. To measure the mobility of injected fluids in sandstone rocks, the foam was generated by co-injection of sc-CO 2 and surfactant, as well as a mixture of surfactant and nanoparticles at 90% quality. The coreflood experiments were conducted using non-fractured and fractured sandstone cores at 1550 psi and 50 °C. The use of surfactant and mixture was able to generate foam in porous media and reduce the CO 2 mobility. The mobility reduction factor (MRF) for both cases was about 3.5 times higher than that of injecting CO 2 and brine at the same conditions. The coreflood experiments in non-fractured sandstone rocks showed that both surfactant and a mixture of surfactant and nanoparticles were able to enhance oil recovery. The baseline experiment in the absence of surfactant resulted in a total recovery of 71.50% of the original oil in place. However, the use of surfactant was able to bring oil recovery to 76% of the OOIP. The addition of nanoparticles to surfactant, though, resulted in higher oil recovery, 80% of the OOIP. In fractured rocks, oil recoveries during secondary production mechanisms for the mixture, the surfactant alone, and sc-CO 2 alone were 12.62, 8.41, and 7.21% of the OOIP, respectively. Huge amount of oil remains underground following the primary and secondary oil production schemes. CO 2 has been widely used to enhance oil recovery. However, its high mobility might result in unfavorable and unsuccessful projects. The use of specially designed surfactants and the synergistic effect of surfactant and nanoparticles may provide a solution to stabilize CO 2 /brine foam at harsh reservoir conditions and, therefore, reduce the gas mobility and, consequently, enhance oil recovery.

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Application of X-Ray CT for Investigation of CO<sub>2</sub> and WAG Injection in Fractured Reservoirs

Cited by 24 publications

References 8 publications

Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Enhancing the Stability of Foam by the Use of Nanoparticles

Surfactant and a mixture of surfactant and nanoparticles to stabilize CO2/brine foam, control gas mobility, and enhance oil recovery

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Application of X-Ray CT for Investigation of CO<sub>2</sub> and WAG Injection in Fractured Reservoirs

Cited by 24 publications

References 8 publications

Characterization of Produced and Residual Oils in the CO2 Flooding Process

Characterization of Produced and Residual Oils in the CO2 Flooding Process

Enhancing the Stability of Foam by the Use of Nanoparticles

Surfactant and a mixture of surfactant and nanoparticles to stabilize CO2/brine foam, control gas mobility, and enhance oil recovery

Contact Info

Product

Resources

About

Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Characterization of Produced and Residual Oils in the CO₂ Flooding Process