The effect of light gas on miscible CO2 flooding to enhance oil recovery from sandstone and chalk reservoirs

Hamouda, Aly A.; Tabrizy, Vahid Alipour

doi:10.1016/j.petrol.2013.04.013

Cited by 23 publications

(8 citation statements)

References 30 publications

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“…Their results show that CO 2 injection increases asphaltene deposition in all of the pressure ranges, in comparison with the tests without CO 2 injection. Besides the studies of the physical properties for CO 2 –crude oil systems, many laboratory experiments are conducted to evaluate the performance of CO 2 injection in carbonate reservoirs, thin heavy oil reservoirs, naturally fractured reservoirs, and tight oil formations. , Li and Gu recommended that the optimum timing for starting miscible CO 2 tertiary flooding is when water flooding reaches half of its maximum secondary oil recovery factor in tight sandstone formation. Han and Gu evaluated the WAG slug size for CO 2 WAG injection and found that the optimum WAG slug ratio is ∼1:1 for the Bakken tight formation.…”

Section: Introductionmentioning

confidence: 99%

“…15 Field and laboratory data confirm that the asphaltene solubility is lower in the light oil and asphaltene has a tendency to precipitate more easily from light oil than heavy oil. 16 Zanganeh et al 17 properties for CO 2 −crude oil systems, many laboratory experiments are conducted to evaluate the performance of CO 2 injection in carbonate reservoirs, 18 thin heavy oil reservoirs, 19 naturally fractured reservoirs, 20 and tight oil formations. 21,22 Li and Gu 8 recommended that the optimum timing for starting miscible CO 2 tertiary flooding is when water flooding reaches half of its maximum secondary oil recovery factor in tight sandstone formation.…”

Section: Introductionmentioning

confidence: 99%

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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: Introductionmentioning

confidence: 99%

Section: Introductionmentioning

confidence: 99%

Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Wang

Chen

2015

Energy Fuels

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“…It was supplied by Chiron AS (Trondheim, Norway) in high performance liquid chromatography (HPLC) grade (purity > 99%). N,N-dimethyldodecylamine (NN-DMDA, purity > 99%, Fluka, St. Gallen, Switzerland) was used as an oil soluble additive with the concentration of 0.01 M in n-C 10 to represent natural base in the crude oil [21].…”

Section: Methodsmentioning

confidence: 99%

Sodium Silicate Behavior in Porous Media Applied for In-Depth Profile Modifications

2014

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This paper addresses alkaline sodium silicate (Na-silicate) behavior in porous media. One of the advantages of the Na-silicate system is its water-like injectivity during the placement stage. Mixing Na-silicate with saline water results in metal silicate precipitation as well as immediate gelation. This work demonstrated that low salinity water (LSW, sea water diluted 25 times) could be used as a pre-flush in flooding operations. A water override phenomenon was observed during gel formation which is caused by gravity segregation. Dynamic adsorption tests in the sand-packed tubes showed inconsiderable adsorbed silicon density (about 8.5 × 10 −10 kg/cm 3 for a solution with 33 mg/L silicon content), which is less than the estimated mono-layer adsorption density of 1.4 × 10 −8 kg/cm 3 . Na-silicate enhanced water sweep efficiency after application in a dual-permeability sand-pack system, without leak off into the oil-bearing low permeability (LP) zone. Field-scale numerical sensitivity studies in a layered reservoir demonstrated that higher permeability and viscosity contrasts and lower vertical/horizontal permeability ratio result in lower Na-silicate leakoff into the matrix. The length of the mixing zone between reservoir water and the injected Na-silicate solution, which is formed by low salinity pre-flush, acts as a buffer zone.

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“…According to several literature studies, stability of the foam can be significantly affected when it comes in contact with the remaining oil in the formation (Li et al, 2021;Chuaicham and Maneeintr, 2017;Hamouda and Tabrizy, 2013). Therefore, besides screening high foaming performance and half-life, low interfacial tension should also be used as the selection criterion to facilitate the stripping of the remaining oil to achieve higher recovery (Zhang et al, 2019).…”

Section: Evaluation Of Heat-resistant Foaming Agentmentioning

confidence: 99%

Heat-Resistant CO2 Foam for Promoting Carbon Capture and Enhanced Oil Recovery

et al. 2022

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Investigation of methods to effectively block the high-permeability channel and displace the residual oil in the small pores in the old oilfields is an urgent research hotspot. The heat-resistant carbon dioxide (CO2) foam with high viscoelasticity and low interfacial tension, which is suitable for improving the oil recovery of old oilfields, and at the same time aids in carbon sequestration. In this study, a suitable heat-resistant foaming agent was selected by considering the temperature resistance, plugging, and profile control as the evaluation indicators, and the heat-resistant CO2 foam was prepared. Then, the two-dimensional (2D) plate model experiment was designed to verify the feasibility of the heat-resistant CO2 foam profile control process in order to solve the problems of small sweep range and uneven sweep degree in the reservoir. The results show that the selected foaming agent (RSB-IV) still maintained a foaming volume of 375 ml at 300°C, and the interfacial tension was only 0.008 mNm−1. The prepared heat-resistant CO2 foam exhibited the best profile control effect when the gas and liquid mixed injection, the gas-liquid ratio was 1:1, and the injection volume was 4.5–5.5 PV. In the 2D plate experiment, heat-resistant CO2 foam flooding promoted the recovery of the remaining oil in the matrix, and the oil recovery was increased to 61.01%. Furthermore, by designing the CO2 gas cap, it was verified that when the volume of the gas cap was large (above 1.5 PV), the injection of the CO2 gas cap could not only effectively improve the recovery rate, but also achieve effective CO2 capture.

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The effect of light gas on miscible CO2 flooding to enhance oil recovery from sandstone and chalk reservoirs

Cited by 23 publications

References 30 publications

Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Characterization of Produced and Residual Oils in the CO₂ Flooding Process

Sodium Silicate Behavior in Porous Media Applied for In-Depth Profile Modifications

Heat-Resistant CO2 Foam for Promoting Carbon Capture and Enhanced Oil Recovery

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The effect of light gas on miscible CO2 flooding to enhance oil recovery from sandstone and chalk reservoirs

Cited by 23 publications

References 30 publications

Characterization of Produced and Residual Oils in the CO2 Flooding Process

Characterization of Produced and Residual Oils in the CO2 Flooding Process

Sodium Silicate Behavior in Porous Media Applied for In-Depth Profile Modifications

Heat-Resistant CO2 Foam for Promoting Carbon Capture and Enhanced 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