Nanoparticle-Stabilized Carbon Dioxide Foam Used In Enhanced Oil Recovery: Effect of Different Ions and Temperatures

Summary This paper reports the study of the effect of different ions (monovalent, bivalent, and multiple ions) on nanosilica-stabilized carbon dioxide (CO2) foam generation. CO2 foam was generated by coinjecting CO2/5,000 ppm nanosilica dispersion (dispersed in different concentrations of brine) into a sandstone core under 1,500 psi and at different temperatures. A sapphire observation cell was used to determine the foam texture and foam stability. Pressure drop across the core was measured to estimate the foam mobility. The results indicated that more CO2 foam was generated as the sodium chloride (NaCl) concentration increased from 1.0 to 10%. In addition, the foam bubble became smaller and foam stability improved with the increase in NaCl concentration. The CO2-foam mobility decreased from 13.1 to 2.6 md/cp when the NaCl concentration increased from 1 to 10%. For the bivalent ions, the generated CO2-foam mobility decreased from 19.7 to 4.8 md/cp when CaCl2 concentration increased from 0.1 to 1.0%. Synthetic produced water with total dissolved solids (TDS) of 18,583 ppm was prepared to investigate the effect of multiple ions on foam generation. The results showed that stable CO2 foam was generated as the synthetic produced water and nanosilica dispersion/CO2 flowed through a porous medium. The lifetime of the foam was observed to be more than 2 days as the foam stood at room temperature. Mobility of the foam was calculated as 5.2 md/cp.

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Surfactant Prefloods During Carbon Dioxide Foam Injection for Integrated Enhanced Oil Recovery in Fractured Oil-Wet Carbonates

SPE Journal ◽

10.2118/190168-pa ◽

2019 ◽

Vol 24 (03) ◽

pp. 1139-1153 ◽

Cited By ~ 1

Author(s):

S. B. Fredriksen ◽

Z. P. Alcorn ◽

A.. Frøland ◽

A.. Viken ◽

A. U. Rognmo ◽

...

Keyword(s):

Carbon Dioxide ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Surfactant Solution ◽

Mobility Control ◽

Threshold Pressure ◽

Oil Saturation ◽

Co2 Foam ◽

Matrix Blocks ◽

Carbon Dioxide Co2

Summary An integrated enhanced-oil-recovery (EOR) (IEOR) approach is used in fractured oil-wet carbonate core plugs where surfactant prefloods reduce interfacial tension (IFT), alter wettability, and establish conditions for capillary continuity to improve tertiary carbon dioxide (CO2) foam injections. Surfactant prefloods can alter the wettability of oil-wet fractures toward neutral/weakly-water-wet conditions that in turn reduce the capillary threshold pressure for foam generation in matrix and create capillary contact between matrix blocks. The capillary connectivity can transmit differential pressure across fractures and increase both mobility control and viscous displacement during CO2-foam injections. Outcrop core plugs were aged to reflect conditions of an ongoing CO2-foam injection field pilot in west Texas. Surfactants were screened for their ability to change the wetting state from oil-wet using the Darcy-scale Amott-Harvey index. A cationic surfactant was the most effective in shifting wettability from an Amott-Harvey index of –0.56 to 0.09. Second waterfloods after surfactant treatments and before tertiary CO2-foam injections recovered an additional 4 to 11% of original oil in place (OIP) (OOIP), verifying the favorable effects of a surfactant preflood to mobilize oil. Tertiary CO2-foam injections revealed the significance of a critical oil-saturation value below which CO2 and surfactant solution were able to enter the oil-wet matrix and generate foam for EOR. The results reveal that a surfactant preflood can reverse the wettability of oil-wet fracture surfaces, lower IFT, and lower capillary threshold pressure to reduce oil saturation to less than a critical value to generate stable CO2 foam.

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A Laboratory Investigation of the Effect of Ethanol-Treated Carbon Dioxide Injection on Oil Recovery and Carbon Dioxide Storage

SPE Journal ◽

10.2118/205503-pa ◽

2021 ◽

pp. 1-17

Author(s):

Saira ◽

Emmanuel Ajoma ◽

Furqan Le-Hussain

Keyword(s):

Carbon Dioxide ◽

Oil Recovery ◽

Carbon Capture ◽

Molar Fraction ◽

Co2 Injection ◽

Carbon Dioxide Injection ◽

Treated Carbon ◽

Carbon Dioxide Co2 ◽

And Storage ◽

Experimental Runs

Summary Carbon dioxide (CO2) enhanced oil recovery is the most economical technique for carbon capture, usage, and storage. In depleted reservoirs, full or near-miscibility of injected CO2 with oil is difficult to achieve, and immiscible CO2 injection leaves a large volume of oil behind and limits available pore volume (PV) for storing CO2. In this paper, we present an experimental study to delineate the effect of ethanol-treated CO2 injection on oil recovery, net CO2 stored, and amount of ethanol left in the reservoir. We inject CO2 and ethanol-treated CO2 into Bentheimer Sandstone cores representing reservoirs. The oil phase consists of a mixture of 0.65 hexane and 0.35 decane (C6-C10 mixture) by molar fraction in one set of experimental runs, and pure decane (C10) in the other set of experimental runs. All experimental runs are conducted at constant temperature 70°C and various pressures to exhibit immiscibility (9.0 MPa for the C6-C10 mixture and 9.6 MPa for pure C10) or near-miscibility (11.7 MPa for the C6-C10 mixture and 12.1 MPa for pure C10). Pressure differences across the core, oil recovery, and compositions and rates of the produced fluids are recorded during the experimental runs. Ultimate oil recovery under immiscibility is found to be 9 to 15% greater using ethanol-treated CO2 injection than that using pure CO2 injection. Net CO2 stored for pure C10 under immiscibility is found to be 0.134 PV greater during ethanol-treated CO2 injection than during pure CO2 injection. For the C6-C10 mixture under immiscibility, both ethanol-treated CO2 injection and CO2 injection yield the same net CO2 stored. However, for the C6-C10 mixture under near-miscibility,ethanol-treated CO2 injection is found to yield 0.161 PV less net CO2 stored than does pure CO2 injection. These results suggest potential improvement in oil recovery and net CO2 stored using ethanol-treated CO2 injection instead of pure CO2 injection. If economically viable, ethanol-treated CO2 injection could be used as a carbon capture, usage, and storage method in low-pressure reservoirs, for which pure CO2 injection would be infeasible.

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Enabling Large-Scale Carbon Capture, Utilisation, and Storage (CCUS) Using Offshore Carbon Dioxide (CO2) Infrastructure Developments—A Review

Energies ◽

10.3390/en12101945 ◽

2019 ◽

Vol 12 (10) ◽

pp. 1945 ◽

Cited By ~ 8

Author(s):

Lars Ingolf Eide ◽

Melissa Batum ◽

Tim Dixon ◽

Zabia Elamin ◽

Arne Graue ◽

...

Keyword(s):

Carbon Dioxide ◽

Oil Recovery ◽

Carbon Capture ◽

Large Scale ◽

Business Models ◽

Reservoir Performance ◽

High Investment ◽

Co2 Eor ◽

Carbon Dioxide Co2 ◽

And Storage

Presently, the only offshore project for enhanced oil recovery using carbon dioxide, known as CO2-EOR, is in Brazil. Several desk studies have been undertaken, without any projects being implemented. The objective of this review is to investigate barriers to the implementation of large-scale offshore CO2-EOR projects, to identify recent technology developments, and to suggest non-technological incentives that may enable implementation. We examine differences between onshore and offshore CO2-EOR, emerging technologies that could enable projects, as well as approaches and regulatory requirements that may help overcome barriers. Our review shows that there are few, if any, technical barriers to offshore CO2-EOR. However, there are many other barriers to the implementation of offshore CO2-EOR, including: High investment and operation costs, uncertainties about reservoir performance, limited access of CO2 supply, lack of business models, and uncertainties about regulations. This review describes recent technology developments that may remove such barriers and concludes with recommendations for overcoming non-technical barriers. The review is based on a report by the Carbon Sequestration Leadership Forum (CSLF).

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Pore-to-Core EOR Upscaling for CO2 Foam for CCUS

SPE Journal ◽

10.2118/190869-pa ◽

2019 ◽

Vol 24 (06) ◽

pp. 2793-2803 ◽

Cited By ~ 1

Author(s):

Arthur Uno Rognmo ◽

Sunniva Brudvik Fredriksen ◽

Zachary Paul Alcorn ◽

Mohan Sharma ◽

Tore Føyen ◽

...

Keyword(s):

Oil Recovery ◽

Apparent Viscosity ◽

Shear Thinning ◽

Liquid Films ◽

Carbonate Reservoir ◽

Sweep Efficiency ◽

Reference Case ◽

Foam Generation ◽

Co2 Foam ◽

Gas Fractions

Summary This paper presents an ongoing CO2–foam upscaling research project that aims to advance CO2–foam technology for accelerating and increasing oil recovery, while reducing operational costs and lessening the carbon footprint left during CO2 enhanced oil recovery (EOR). Laboratory CO2–foam behavior was upscaled to pilot scale in an onshore carbonate reservoir in Texas, USA. Important CO2–foam properties, such as local foam generation, bubble texture, apparent viscosity, and shear–thinning behavior with a nonionic surfactant, were evaluated using pore–to–core upscaling to develop accurate numerical tools for a field–pilot prediction of increased sweep efficiency and CO2 utilization. At pore–scale, high–pressure silicon–wafer micromodels showed in–situ foam generation and stable liquid films over time during no–flow conditions. Intrapore foam bubbles corroborated high apparent foam viscosities measured at core scale. CO2–foam apparent viscosity was measured at different rates (foam–rate scans) and different gas fractions (foam–quality scans) at core scale. The highest mobility reduction (foam apparent viscosity) was observed between 0.60 and 0.70 gas fractions. The maximum foam apparent viscosity was 44.3 (±0.5) mPa·s, 600 times higher than that of pure CO2, compared with the baseline viscosity (reference case, without surfactant), which was 1.7 (±0.6) mPa·s, measured at identical conditions. The CO2–foam showed shear–thinning behavior with approximately 50% reduction in apparent viscosity when the superficial velocity was increased from 1 to 8 ft/D. Strong foam was generated in EOR corefloods at a gas fraction of 0.70, resulting in an apparent viscosity of 39.1 mPa·s. Foam parameters derived from core–scale foam floods were used for numerical upscaling and field–pilot performance assessment.

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Effects of carbon dioxide (CO2) at different temperatures on physiological parameters and growth in striped catfish (Pangasianodon hypophthalmus) juveniles

Aquaculture ◽

10.1016/j.aquaculture.2020.736279 ◽

2021 ◽

Vol 534 ◽

pp. 736279

Author(s):

Do Thi Thanh Huong ◽

Chau Huynh Thuy Tram ◽

Nguyen Thi Kim Ha ◽

Le Thi Hong Gam ◽

Atsushi Ishimatsu ◽

...

Keyword(s):

Carbon Dioxide ◽

Physiological Parameters ◽

Pangasianodon Hypophthalmus ◽

Different Temperatures ◽

Striped Catfish ◽

Carbon Dioxide Co2

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Mobility of Ethomeen C12 and Carbon Dioxide (CO2) Foam at High Temperature/High Salinity and in Carbonate Cores

SPE Journal ◽

10.2118/179726-pa ◽

2016 ◽

Vol 21 (04) ◽

pp. 1151-1163 ◽

Cited By ~ 44

Author(s):

Leyu Cui ◽

Kun Ma ◽

Maura Puerto ◽

Ahmed A. Abdala ◽

Ivan Tanakov ◽

...

Keyword(s):

Carbon Dioxide ◽

High Temperature ◽

High Salinity ◽

Local Equilibrium ◽

Co2 Flooding ◽

Sweep Efficiency ◽

Co2 Foam ◽

Foam Model ◽

Wide Range ◽

Carbon Dioxide Co2

Summary The low viscosity and density of carbon dioxide (CO2) usually result in the poor sweep efficiency in CO2-flooding processes, especially in heterogeneous formations. Foam is a promising method to control the mobility and thus reduce the CO2 bypass because of the gravity override and heterogeneity of formations. A switchable surfactant, Ethomeen C12, has been reported as an effective CO2-foaming agent in a sandpack with low adsorption on pure-carbonate minerals. Here, the low mobility of Ethomeen C12/CO2 foam at high temperature (120 °C), high pressure (3,400 psi), and high salinity [22 wt% of total dissolved solids (TDS)] was demonstrated in Silurian dolomite cores and in a wide range of foam qualities. The influence of various parameters, including aqueous solubility, thermal and chemical stability, flow rate, foam quality, salinity, temperature, and minimum-pressure gradient (MPG), on CO2 foam was discussed. A local-equilibrium foam model, the dry-out foam model, was used to fit the experimental data for reservoir simulation.

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Visualizing and Quantifying Generation, Propagation, and Sweep of Nanocellulose-Strengthened Carbon Dioxide Foam in a Complex 2D Heterogeneous Fracture Network Model

SPE Journal ◽

10.2118/206011-pa ◽

2021 ◽

pp. 1-14

Author(s):

Bing Wei ◽

Qingtao Tian ◽

Shengen Chen ◽

Xingguang Xu ◽

Dianlin Wang ◽

...

Keyword(s):

Carbon Dioxide ◽

Network Model ◽

Gravitational Effect ◽

Fracture Network ◽

Sweep Efficiency ◽

Co2 Foam ◽

Reservoir Conditions ◽

Foam Film ◽

Carbon Dioxide Co2

Summary There exist two main issues hampering the wide application and development of carbon dioxide (CO2) foam in conformance improvement and CO2 mobility reduction in fractured systems: (1) instability of foam film under reservoir conditions and (2) uncertainties of foam flow in complex fractures. To address these two issues, we previously developed a series of nanocellulose-strengthened CO2 foam (referred to as NCF-st-CO2 foam), while the primary goal of this work is to thoroughly elucidate generation, propagation, and sweep of NCF-st-CO2 foam in a visual 2D heterogeneous fracture network model. NCF-st-CO2 foam outperformed CO2 foam in reducing gas mobility during either coinjection (COI) or surfactant-alternating-gas (SAG) injection, and the threshold foam quality was approximately 0.67. Foam creation was increased with the total superficial velocity for CO2 foam and almost stayed constant for NCF-st-CO2 foam in fractures during COI. For SAG, large surfactant slug could prevent CO2 from early breakthrough and facilitate foaming in situ. The improved sweep efficiency induced by NCF-st-CO2 foam occurred near the producer for both COI and SAG. Film division and behind mainly led to foam generation in the fracture model. Gravity segregation and override was insignificant during COI but became noticeable during SAG, which caused the sweep efficiency decrease by 3 to 9%. Owing to the enhanced film, NCF-st-CO2 foam enabled mitigation of the gravitational effect, especially around the producer.

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New metal complexes with inhibiting and biocide properties

Azerbaijan Oil Industry ◽

10.37474/0365-8554/2020-8-46-52 ◽

2020 ◽

pp. 46-52

Author(s):

F.F. Veliyev ◽

Keyword(s):

Carbon Dioxide ◽

Carbon Steel ◽

Hydrogen Sulphide ◽

Copper Complex ◽

Produced Water ◽

Methanol Solutions ◽

Production Wells ◽

Carbon Dioxide Co2 ◽

Water Saturated ◽

Reducing Bacteria

Methanol solutions of various concentrations have been developed based on synthesized N, Nʹ- (pirazin-2-il) pyridine - 2,6-diamine ligand (N5-2pz), its linear pentanuclear of nickel string (II) [Ni5(μ5-dpzpda)4Cl2] (Ni5-N5-2pz) and tetracyclic copper complex (II) [Cu4(Hdpzpda)2(CH3COO)6] (Cu4-N5-2pz). Anticorrosion impact of these solutions on carbon steel Сt20 was studied on the model of produced water saturated with carbon dioxide (CO2) in the medium of hydrogen sulphide with different concentrations (H2S). Biocide properties of developed solutions against corrosion bacteria (sulphate-reducing bacteria, Tionand hydrocarbon oxidizing bacteria) have been studied on the samples of produced water taken from flooded production wells of “Bibiheybat” OGPD as well and good results obtained.

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