Carbon Dioxide Injection Pressure and Reservoir Temperature Impact on Oil Recovery from Unconventional Shale Reservoirs During Cyclic CO2 Injection: An Experimental Study

The fault roots of Liuzan north block in Jidong oilfield of China have been long-term explored by solution gas drive. Recently, oil production declined rapidly because of shortage of formation energy and needing high water injection pressure. Carbon dioxide injection pressure is found to be generally low, and CO 2 has good solubility in crude oil to supply formation energy and achieve high oil recovery efficiency. In this work, a pilot program of CO 2 EOR technology was carried out. The slim tube test results showed that the minimal miscible pressure of Liuzan north block was 28.28 MPa. The injection parameters were optimized by numerical simulation method: the injection method was continuous, the slug size was 0.2 HCPV and the EOR efficiency was 7.23%. After two months of gas injection field test, the formation pressure of two gas injectors just increased by 14.02 MPa and 2.98 MPa, respectively, indicating that carbon dioxide could supply the formation energy effectively. 16 months after gas injection, the CO 2 injection amount was 14640 t, and the oil increment was 16424 t. The present work demonstrates the potential applicability of CO 2 flooding technology from high water injection reservoirs.

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Improving oil recovery from shale oil reservoirs using cyclic cold carbon dioxide injection – An experimental study

Fuel ◽

10.1016/j.fuel.2019.05.169 ◽

2019 ◽

Vol 254 ◽

pp. 115586 ◽

Cited By ~ 6

Author(s):

Khalid Elwegaa ◽

Hossein Emadi ◽

Mohamed Soliman ◽

Talal Gamadi ◽

Mahmoud Elsharafi

Keyword(s):

Carbon Dioxide ◽

Experimental Study ◽

Oil Recovery ◽

Oil Reservoirs ◽

Shale Oil ◽

Carbon Dioxide Injection ◽

Shale Oil Reservoirs

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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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Laboratory Studies of Carboniferous Reservoirs of High-Viscosity Oil Fields Using Carbondioxide

Вестник Пермского национального исследовательского политехнического университета Геология Нефтегазовое и горное дело ◽

10.15593/2712-8008/2020.4.6 ◽

2020 ◽

Vol 20 (4) ◽

pp. 369-385

Author(s):

Stanislav A. Kalinin ◽

◽

Oleg A. Morozyuk ◽

Keyword(s):

Carbon Dioxide ◽

Heat Carrier ◽

Oil Recovery ◽

High Mobility ◽

High Viscosity ◽

Laboratory Studies ◽

Carbon Dioxide Injection ◽

Recovery Method ◽

Matrix Blocks ◽

High Viscosity Oil

It is of current concern for the Permian-Carboniferous reservior of the Usinskoye field to develop low-permeable matrix blocks of carboniferous reservoirs, which contain major reserves of high-viscosity oil. To increase effectiveness of the currently used thermal oil recovery methods, the authors suggest using carbon dioxide as a reservoir stimulation agent. Due to a high mobility in its supercritical condition, СО2 is, theoretically, able to penetrate matrix blocks, dissolve in oil and, additionally, decrease its viscosity. Thus, СО2 applications together with a heat carrier could increase effectiveness of the high-viscosity oil recoveries and improve production parameters of the Permian-Carboniferous reservior of the Usinskoye field. During carbon dioxide injections, including combinations with various agents, some additional oil production is possible due to certain factors. Determination of the influencing factors and detection of the most critical ones is possible in laboratory tests. So, laboratory studies entail the key stage in justification of the technology effectiveness. The paper deals with describing the laboratory facilities and methodologies based on reviews of the best world practice and previous laboratory researches. These aim at evaluating effectiveness of thermal, gas and combined oil recovery enhancement methods. In particular, the authors explore experimental facilities and propose methodology to perform integrated researches of the combined heat carrier and carbon dioxide injection technology to justify the effective super-viscous oil recovery method.

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Molecular-Scale Considerations of Enhanced Oil Recovery in Shale

Energies ◽

10.3390/en13246619 ◽

2020 ◽

Vol 13 (24) ◽

pp. 6619

Author(s):

Mohamed Mehana ◽

Qinjun Kang ◽

Hari Viswanathan

Keyword(s):

Carbon Dioxide ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Energy Equation ◽

Simulation Approach ◽

Production Region ◽

The World ◽

Fluid Properties ◽

Shale Reservoirs ◽

Different Gases

With only less than 10% recovery, the primary production of hydrocarbon from shale reservoirs has redefined the energy equation in the world. Similar to conventional reservoirs, Enhanced Oil Recovery (EOR) techniques could be devised to enhance the current recovery factors. However, shale reservoirs possess unique characteristics that significantly affect the fluid properties. Therefore, we are adopting a molecular simulation approach that is well-suited to account for these effects to evaluate the performance of three different gases, methane, carbon dioxide and nitrogen, to recover the hydrocarbons from rough pore surfaces. Our hydrocarbon systems consists of either a single component (decane) or more than one component (decane and pentane). We simulated cases where concurrent and countercurrent displacement is studied. For concurrent displacement (injected fluids displace hydrocarbons towards the production region), we found that nitrogen and methane yielded similar recovery; however nitrogen exhibited a faster breakthrough. On the other hand, carbon dioxide was more effective in extracting the hydrocarbons when sufficient pressure was maintained. For countercurrent displacement (gases are injected and hydrocarbons are produced from the same direction), methane was found to be more effective, followed by carbon dioxide and nitrogen. In all cases, confinement reduced the recovery factor of all gases. This work provides insights to devise strategies to improve the current recovery factors observed in shale reservoirs.

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An experimental investigation of asphaltene stability in heavy crude oil during carbon dioxide injection

Journal of Petroleum Exploration and Production Technology ◽

10.1007/s13202-019-00782-7 ◽

2019 ◽

Vol 10 (3) ◽

pp. 919-931 ◽

Cited By ~ 5

Author(s):

Sherif Fakher ◽

Mohamed Ahdaya ◽

Mukhtar Elturki ◽

Abdulmohsin Imqam

Keyword(s):

Carbon Dioxide ◽

Crude Oil ◽

Pore Size ◽

Oil Recovery ◽

Asphaltene Precipitation ◽

Carbon Dioxide Injection ◽

Oil Viscosity ◽

Membrane Pore ◽

Pore Sizes ◽

Filter Membrane

Abstract Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen–Mullins asphaltene model and were used to select the proper chemical to alter the oil’s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen–Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO2 injection in different pore sizes, and correlates the results to the principle of the Yen–Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO2 injection in hydrocarbon reservoirs.

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Carbon Sequestration: an Answer to the World’s Carbon Dioxide Emission Problem

Inquiry@Queen's Undergraduate Research Conference Proceedings ◽

10.24908/iqurcp.7653 ◽

2017 ◽

Author(s):

Curtis Wettstein

Keyword(s):

Carbon Dioxide ◽

Carbon Sequestration ◽

Oil Recovery ◽

Carbon Dioxide Emissions ◽

Carbon Dioxide Emission ◽

The United States ◽

Oil Well ◽

Carbon Dioxide Injection ◽

Oil Companies ◽

Reduce Emissions

As of November 2007, 174 parties had ratified the Kyoto protocol signifying a large part of the solution to one of the worlds primary environmental problems; carbon dioxide emissions. Although the United States refused to sign the protocol, their neighbours in Canada were eager to address the issue and sign. However with oil being a major Canadian export, carbon dioxide emission reduction was arguably improbable and unprofitable. With the pressure of reducing carbon dioxide emissions an imminent, carbon sequestration may be the symbiotic solution in satisfying Kyoto, saving the environment and even increasing profitability. Carbon sequestration is the process where carbon dioxide is injected into an oil well in order to increase recovery. With tertiary oil recoveries driving much of the oil business, cheap and efficient recovery methods are invaluable. Presently there is a Canadian operation in Wayburn, Saskatchewan which employs the technique. In addition, Texas and Scandinavian oil companies are using Carbon dioxide injection. If carbon sequestration increases oil recovery it has to be the preferred method. By purchasing carbon dioxide from external sources and recycling their own, companies can reduce emissions while increasing profits. Finally it may be profitable to save the environment.

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Scope for converting an existing natural gas enhanced oil recovery project to carbon dioxide injection

Greenhouse Gas Control Technologies 7 ◽

10.1016/b978-008044704-9/50321-9 ◽

2005 ◽

pp. 2299-2302

Author(s):

H CHALMERS ◽

J GIBBINS

Keyword(s):

Carbon Dioxide ◽

Natural Gas ◽

Enhanced Oil Recovery ◽

Oil Recovery ◽

Carbon Dioxide Injection

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Will Carbon Dioxide Injection in Shale Reservoirs Produce from the Shale Matrix, Natural Fractures, or Hydraulic Fractures?

10.2118/200773-ms ◽

2021 ◽

Author(s):

Sherif Fakher ◽

Youssef Elgahawy ◽

Hesham Abdelaal ◽

Abdulmohsin Imqam

Keyword(s):

Carbon Dioxide ◽

Oil Recovery ◽

Oil And Gas ◽

Fractured Reservoirs ◽

Co2 Injection ◽

Hydraulic Fractures ◽

Natural Fractures ◽

Recovery Potential ◽

Shale Reservoirs ◽

The Impact

Abstract Enhanced oil recovery (EOR) in shale reservoirs has been recently shown to increase oil recovery significantly from this unconventional oil and gas source. One of the most studied EOR methods in shale reservoirs is gas injection, with a focus on carbon Dioxide (CO2) mainly due to the ability to both enhance oil recovery and store the CO2 in the formation. Even though several shale plays have reported an increase in oil recovery using CO2 injection, in some cases this method failed severely. This research attempts to investigate the ability of the CO2 to mobilize crude oil from the three most prominent features in the shale reservoirs, including shale matrix, natural fractures, and hydraulically induced fracture. Shale cores with dimensions of 1 inch in diameter and approximately 1.5 inch in length were used in all experiments. The impact of CO2 soaking time and soaking pressure on the oil recovery were studied. The cores were analyzed to understand how and where the CO2 flowed inside the cores and which prominent feature resulted in the increase in oil recovery. Also, a pre-fractured core was used to run an experiment in order to understand the oil recovery potential from fractured reservoirs. Results showed that oil recovery occurred from the shale matrix, stimulation of natural fractures by the CO2, and from the hydraulic fractures with a large volume coming from the stimulated natural fractures. By understanding where the CO2 will most likely be most productive, proper design of the CO2 EOR in shale can be done in order to maximize recovery and avoid complications during injection and production which may lead to severe operational problems.

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