scholarly journals Simulation of Immiscible Water-Alternating-CO2 Flooding in the Liuhua Oilfield Offshore Guangdong, China

Energies ◽  
2020 ◽  
Vol 13 (9) ◽  
pp. 2130 ◽  
Author(s):  
Gang Hu ◽  
Pengchun Li ◽  
Linzi Yi ◽  
Zhongxian Zhao ◽  
Xuanhua Tian ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Full Field ◽  
Water Alternating Gas ◽  
Production History ◽  
And Storage

In this paper, the immiscible water-alternating-CO2 flooding process at the LH11-1 oilfield, offshore Guangdong Province, was firstly evaluated using full-field reservoir simulation models. Based on a 3D geological model and oil production history, 16 scenarios of water-alternating-CO2 injection operations with different water alternating gas (WAG) ratios and slug sizes, as well as continuous CO2 injection (Con-CO2) and primary depletion production (No-CO2) scenarios, have been simulated spanning 20 years. The results represent a significant improvement in oil recovery by CO2 WAG over both Con-CO2 and No-CO2 scenarios. The WAG ratio and slug size of water affect the efficiency of oil recovery and CO2 injection. The optimum operations are those with WAG ratios lower than 1:2, which have the higher ultimate oil recovery factor of 24%. Although WAG reduced the CO2 injection volume, the CO2 storage efficiency is still high, more than 84% of the injected CO2 was sequestered in the reservoir. Results indicate that the immiscible water-alternating-CO2 processes can be optimized to improve significantly the performance of pressure maintenance and oil recovery in offshore reef heavy-oil reservoirs significantly. The simulation results suggest that the LH11-1 field is a good candidate site for immiscible CO2 enhanced oil recovery and storage for the Guangdong carbon capture, utilization and storage (GDCCUS) project.

scholarly journals Why CCS? Milestone on Research and Regulation Coverages

KnE Energy ◽  
2015 ◽  
Vol 1 (1) ◽  
pp. 13
Author(s):  
Aisyah Kusuma ◽  
Eko Widianto ◽  
Rachmat Sule ◽  
Wawan Gunawan A. Kadir ◽  
Mega S. Gemilang
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Carbon Emission ◽  
Fossil Fuels ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Point Sources ◽  
Co2 Injection ◽  
Road Map ◽  
And Storage

<p>Further to Kyoto Protocol, again in 2009 G-20 Pittsburg Summit, Indonesia delivered the commitment on reducing 26% on its emission level. Moreover, as non-annex 1 country, Indonesia shows strong and bold commitment in supporting reduction on increased concentrations of greenhouse gases produced by human activities such as burning the fossil fuels and deforestation. From the energy sector, Carbon Capture and Storage (CCS) is known as a process of capturing waste carbon dioxide (CO2) from large point sources and depositing it normally at an underground geological formation. CCS becomes now as one of the possible supports to the country commitment. In Indonesia, the potential of CCS applications could be conducted in the gas fields with high content of CO2 and in almost depleted oil fields (by applying CO2-Enchanced Oil Recovery (EOR) The CCS approach could also be conducted in order to increase hydrocarbon production, and at the same time the produced CO2 will be injected and storage it back to the earth. Thus, CCS is a mitigation process in enhancing carbon emission reduction caused by green house effect from production hydrocarbon fields.</p><p>This paper will show a proposed milestone on CCS Research roadmap, as steps to be taken in reaching the objective. The milestone consists of the study for identifying potential CO2 sources, evaluating CO2 storage sites, detail study related to CO2 storage selection, CO2 injection, and CO2 injection monitoring. Through these five steps, one can expect to be able to comprehend road map of CCS Research. Through this research milestone, applications of CCS should also be conducted based on the regulatory coverage milestone. From this paper, it is hoped that one can understand the upstream activities starting with research milestone to the very end downstream activities regarding to the regulation coverage bound. </p><p><em><strong>Keywords</strong></em>: CCS, reduction of carbon emission, regulation umbrella </p>

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

SPE Journal ◽  
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.

scholarly journals Chemistry of Reservoir Fluids in the Aspect of CO2 Injection for Selected Oil Reservoirs in Poland

Energies ◽  
2020 ◽  
Vol 13 (23) ◽  
pp. 6456
Author(s):  
Ewa Knapik ◽  
Katarzyna Chruszcz-Lipska
Keyword(s):  
Oil Recovery ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Oil Reservoirs ◽  
Co2 Injection ◽  
Oil Composition ◽  
Co2 Solubility ◽  
Geological Co2 Storage ◽  
Reservoir Conditions

Worldwide experiences related to geological CO2 storage show that the process of the injection of carbon dioxide into depleted oil reservoirs (CCS-EOR, Carbon Capture and Storage—Enhanced Oil Recovery) is highly profitable. The injection of CO2 will allow an increasing recovery factor (thus increasing CCS process profitability) and revitalize mature reservoirs, which may lead to oil spills due to pressure buildups. In Poland, such a solution has not yet been implemented in the industry. This work provides additional data for analysis of the possibility of the CCS-EOR method’s implementation for three potential clusters of Polish oil reservoirs located at a short distance one from another. The aim of the work was to examine the properties of reservoir fluids for these selected oil reservoirs in order to assure a better understanding of the physicochemical phenomena that accompany the gas injection process. The chemical composition of oils was determined by gas chromatography. All tested oils represent a medium black oil type with the density ranging from 795 to 843 g/L and the viscosity at 313 K, varying from 1.95 to 5.04 mm/s. The content of heavier components C25+ is up to 17 wt. %. CO2–oil MMP (Minimum Miscibility Pressure) was calculated in a CHEMCAD simulator using the Soave–Redlich–Kwong equation of state (SRK EoS). The oil composition was defined as a mixture of n-alkanes. Relatively low MMP values (ca. 8.3 MPa for all tested oils at 313 K) indicate a high potential of the EOR method, and make this geological CO2 storage form more attractive to the industry. For reservoir brines, the content of the main ions was experimentally measured and CO2 solubility under reservoir conditions was calculated. The reservoir brines showed a significant variation in properties with total dissolved solids contents varying from 17.5 to 378 g/L. CO2 solubility in brines depends on reservoir conditions and brine chemistry. The highest calculated CO2 solubility is 1.79 mol/kg, which suggest possible CO2 storage in aquifers.

Effective Prediction and Management of a CO2 Flooding Process for Enhancing Oil Recovery Using Artificial Neural Networks

2017 ◽  
Vol 140 (3) ◽  
Author(s):  
Si Le Van ◽  
Bo Hyun Chon
Keyword(s):  
Oil Recovery ◽  
Water Saturation ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Environmental Benefits ◽  
Co2 Production ◽  
Co2 Injection ◽  
Co2 Flooding ◽  
Injection Process ◽  
Artificial Neural

The injection of CO2 has been in global use for enhanced oil recovery (EOR) as it can improve oil production in mature fields. It also has environmental benefits for reducing greenhouse carbon by permanently sequestrating CO2 (carbon capture and storage (CCS)) in reservoirs. As a part of numerical studies, this work proposed a novel application of an artificial neural network (ANN) to forecast the performance of a water-alternating-CO2 process and effectively manage the injected CO2 in a combined CCS–EOR project. Three targets including oil recovery, net CO2 storage, and cumulative gaseous CO2 production were quantitatively simulated by three separate ANN models for a series of injection frames of 5, 15, 25, and 35 cycles. The concurrent estimations of a sequence of outputs have shown a relevant application in scheduling the injection process based on the progressive profile of the targets. For a specific surface design, an increment of 5.8% oil recovery and 4% net CO2 storage was achieved from 25 cycles to 35 cycles, suggesting ending the injection at 25 cycles. Using the models, distinct optimizations were also computed for oil recovery and net CO2 sequestration in various reservoir conditions. The results expressed a maximum oil recovery from 22% to 30% oil in place (OIP) and around 21,000–29,000 tons of CO2 trapped underground after 35 cycles if the injection began at 60% water saturation. The new approach presented in this study of applying an ANN is obviously effective in forecasting and managing the entire CO2 injection process instead of a single output as presented in previous studies.

A Screening Model for CO2 Flooding and Storage in Gulf Coast Reservoirs Based on Dimensionless Groups

2008 ◽  
Vol 11 (03) ◽  
pp. 513-520 ◽  
Author(s):  
Derek J. Wood ◽  
Larry W. Lake ◽  
Russell T. Johns ◽  
Vanessa Nunez
Keyword(s):  
Oil Recovery ◽  
Gulf Coast ◽  
Co2 Storage ◽  
Co2 Flooding ◽  
Large Databases ◽  
Dimensionless Groups ◽  
Quantitative Results ◽  
Storage Potential ◽  
Dip Angle ◽  
And Storage

Summary Concerns over global warming have led to interest in removing greenhouse gases, specifically CO2, from the atmosphere. Sequestration of CO2 in oil reservoirs as part of enhanced oil recovery (EOR) projects is one method that is being considered. This paper first presents the scaling groups necessary to describe CO2 flooding for a typical line-drive pattern and then uses these groups in a Box-Behnken experimental design to create a screening model most applicable to candidate Gulf Coast reservoirs (Box and Behnken 1960). By generating oil recovery and CO2 storage curves, the model estimates the cumulative oil recovery and CO2 storage potential for a given reservoir. Past screening models—Rivas et al. (1992) and Diaz et al. (1996)—focused only on oil recovery and simply assigned qualitative rankings to reservoirs. Models that did include quantitative results, including CO2 Prophet (Dobitz and Prieditis 1994) and the CO2 Predictive Model (Paul et al. 1984), did not include the effects of dip. This model focuses on both oil recovery and CO2 storage potential, produces quantitative results for each, and includes the effects of dip. This model quickly estimates the oil recovery and CO2 storage potential for a reservoir. Operators can quickly screen large databases of reservoirs to identify the best candidates for CO2 flooding and storage. The scaling groups also provide the basis for future models that may be more specific to other regions. The results show that continuous CO2 flooding can be fully described using 10 dimensionless groups: aspect ratio, dip angle group, water and CO2 mobility ratios, buoyancy number, dimensionless injection and producing pressures, residual oil saturation to water and gas, and initial oil saturation. The effects of capillary forces and dispersion were secondary effects in this model and were not included in the scaling. Dimensionless oil recovery was effectively modeled with the dimensionless oil breakthrough time and the dimensionless recovery at three different dimensionless times, while CO2 storage potential was calculated only at the final dimensionless time. The reservoir-specific parameters discussed above were calculated from response surface fits. The scaling does not work as well at small buoyancy numbers; however, it is effective in the range of values typical of Gulf Coast reservoirs. Introduction CO2 flooding is a popular EOR technique; however, it has not heretofore been scaled for dipping reservoirs. Scaling is done using a process called inspectional analysis. In this process, the equations governing fluid flow in a reservoir are described and then converted into dimensionless equations. For example, the variable z (distance in the vertical direction) can be transformed into a dimensionless variable by dividing by a scalar parameter z1*, which can be set equal to H, the height of the reservoir. This new group z/z1* is dimensionless. These transformations are made until the equations are entirely in dimensionless form. Then, through various assumptions and mathematical manipulations of the equations, dimensionless terms are canceled out and removed until a final group of independent dimensionless groups is extracted from the equations. Using inspectional analysis, Shook et al. (1992) scaled waterfloods for a homogeneous, 2D, cartesian, dipping reservoir with two phases (oleic and aqueous) present and found five necessary dimensionless groups. They are:RL = [Equation] effective aspect ratioMow = [Equation] mobility ratio (water)Na = [Equation] dip angle groupNog = [Equation] buoyancy numberNPc = [Equation] capillary number These groups served as the initial basis for the scaling of CO2 flooding; however, they proved insufficient. This paper presents the additional groups necessary to scale CO2 flooding. The desire to undertake CO2 flooding begets the need to identify economically attractive candidate reservoirs. Comprehensive simulations may be too costly and time-consuming when large databases of reservoirs must be evaluated. This paper presents a model based on the aforementioned dimensionless groups that quickly estimates the oil recovery and CO2 storage potential for candidate reservoirs.

scholarly journals Modeling of CO2-LPG WAG with asphaltene deposition to predict coupled enhanced oil recovery and storage performance

2021 ◽  
Vol 11 (1) ◽  
Author(s):  
Jinhyung Cho ◽  
Baehyun Min ◽  
Moon Sik Jeong ◽  
Young Woo Lee ◽  
Kun Sang Lee
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Water Injection ◽  
Carbon Capture And Storage ◽  
Liquefied Petroleum Gas ◽  
Water Alternating Gas ◽  
Asphaltene Deposition ◽  
Trapping Performance ◽  
And Storage

AbstractCombined carbon capture and storage and CO2-enhanced oil recovery (CCS-EOR) can reconcile the demands of business with the need to mitigate the effects of climate change. To improve the performance of CCS-EOR, liquefied petroleum gas (LPG) can be co-injected with CO2, leading to a reduction in the minimum miscibility pressure. However, gas injection can cause asphaltene problems, which undermines EOR and CCS performances simultaneously. Here, we systematically examine the mechanisms of asphaltene deposition using compositional simulations during CO2-LPG–comprehensive water–alternating-gas (WAG) injection. The LPG accelerates asphaltene deposition, reducing gas mobility, and increases the performance of residual trapping by 9.2% compared with CO2 WAG. In contrast, solubility trapping performance declines by only 3.7% because of the greater reservoir pressure caused by the increased formation damage. Adding LPG enhances oil recovery by 11% and improves total CCS performance by 9.1% compared with CO2 WAG. Based on reservoir simulations performed with different LPG concentrations and WAG ratios, we confirmed that the performance improvement of CCS-EOR associated with increasing LPG and water injection reaches a plateau. An economic evaluation based on the price of LPG should be carried out to ensure practical success.

scholarly journals Simulasi difusi dan adsorpsi matriks pada proses enhanced coalbed methane

2018 ◽  
Vol 12 (1) ◽  
pp. 173
Author(s):  
Ade Nurisman ◽  
Retno Gumilang Dewi ◽  
Ucok W.R. Siagian
Keyword(s):  
Mathematical Model ◽  
Co2 Emissions ◽  
Coalbed Methane ◽  
Carbon Capture ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
The Matrix ◽  
Enhanced Coalbed Methane ◽  
And Storage

Diffusion and matrix adsorption simulations in enhanced coalbed methane process. Carbon capture and storage (CCS) can be considered as one of climate change mitigation efforts, through capturing and injecting of CO2 in underground formations for reducing CO2 emissions. CO2 injection in coalbed methane (CBM) reservoir has potentially attracted for reducing CO2 emissions and enhancing coalbed methane (ECBM) recovery. Diffusion and sorption are phenomenon of gas in the matrix on CO2 injection in CBM reservoir. The objectives of the research are focused on understanding of diffusion and sorption of gas in the coal matrix with mathematical model and estimating of CO2 storage in coalbed and CH4 recovery. In this research, mathematical model is developed to describe the mechanism in the matrix on ECBM process. Mathematical model, which have been valid, is simulated in various variables, i.e. macroprosity (0.001, 0.005, and 0,01), pressure (1, 3, and 6 MPa), temperature (305, 423, and 573 K), and initial fraction of CO2 (0.05, 0.1, 0.3, and 0.5). The results of this research show that preferential sequestration of CO2 and preferential recovery of CH4 in the surface of micropore on macroporosity 0.001, pressure 1 MPa, temperature 305 K, and inital fraction CO2 0,5 conditions are 0.9936 and 0.0064.Keywords: carbon capture and storage (CCS), coalbed methane (CBM), ECBM, diffusion, adsorption Abstrak Carbon capture and storage (CCS) dapat dipertimbangkan sebagai salah satu upaya mitigasi perubahan iklim, yaitu dengan menangkap CO2 dan menginjeksikannya ke dalam formasi bawah permukaan. Injeksi CO2 pada lapangan coalbed methane (CBM) berpotensi mengurangi emisi CO2 dan meningkatkan produksi CBM (ECBM). Pada proses injeksi CO2 di lapangan CBM, fenomena yang terjadi di dalam matriks lapisan batubara (coalbed) adalah difusi dan adsorpsi. Penelitian ini bertujuan memahami fenomena difusi dan adsorpsi pada proses injeksi CO2 untuk ECBM melalui model matematika, dan memperkirakan potensi penyimpanan CO2 di dalam lapangan CBM dan potensi recovery CH4. Pada penelitian dilakukan pengembangan model matematika untuk menjelaskan fenomena di dalam matriks pada proses ECBM. Model matematika, yang telah valid, disimulasikan dengan memvariasikan beberapa variabel, yaitu makroporositas (0,001, 0,005, dan 0,01), tekanan (1, 3, dan 6 MPa), suhu (305, 423, dan 573 K), dan fraksi CO2 awal (0,05, 0,1, 0,3, dan 0,5). Hasil penelitian menunjukkan pada makroporositas 0,001, tekanan 1 Pa, suhu 305 K, dan fraksi CO2 awal 0,5, fraksi CO2 yang teradsorpsi pada permukaan mikropori bernilai 0,9936 dan sisa fraksi CH4 yang teradsorpsi pada permukaan mikropori bernilai 0,0064. Kata kunci: carbon capture and storage (CCS), coalbed methane (CBM), ECBM, difusi, adsorpsi

Technology Focus: EOR Operations (June 2021)

2021 ◽  
Vol 73 (06) ◽  
pp. 62-62
Author(s):  
Sunil Kokal
Keyword(s):  
Climate Change ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Oil Production ◽  
Water Flooding ◽  
Co2 Injection ◽  
Full Potential ◽  
The World ◽  
And Storage

A long time ago, my mentor, Farooq Ali, wrote a thought-provoking paper on the unfulfilled promises of enhanced oil recovery (EOR). His essential summary: EOR had not lived up to its hype and full potential. There were more than a hundred methods and techniques proposed, but only a few had succeeded commercially. Fast-forward a few decades and into the new century, and the message and conclusions have not changed. EOR has definitely not lived up to its promise, especially from the big-picture perspective of daily oil production rates. Before the COVID-19 pandemic, the world was producing close to 100 million BOPD. Of this, only approximately 4 million BOPD was coming from EOR, and the bulk of this was from thermal. The numbers pale even when compared with shale oil, which has dominated US oil production during the past decade. So why has EOR failed so spectacularly? The answer is complex—mostly economic, less technical. It is difficult to compete against water (flooding), where the cost of the injectant is practically free. Compare this with EOR, where you have to inject something other than water—either heat, a gas or solvent, polymer, surfactant, or something exotic such as microbes. These techniques cost money and make EOR inherently expensive. They have become the Achilles’ heel of EOR. So, what is the message for those of us working in EOR? Make EOR cost-competitive, improve waterflooding, or join the sustainability bandwagon that is sweeping the world? That is the call of the hour, and for decades to come. While other EOR methods such as thermal and chemical will have a limited future, injection of carbon dioxide (CO2) for EOR will be a win/win proposition. It provides a way to sequester CO2 and produce additional oil at the same time. The oil revenues provide the “U” in “CCUS” (carbon capture, utilization, and storage) that will play a vital role in the removal of CO2. CCUS is considered by most to be an essential part of the climate-change portfolio of solutions. The papers in this feature are examples of CO2 sequestration either with EOR or in saline aquifers. One provides the EOR and storage potential in the Norwegian continental shelf. Another is a case study of improving asset performance in marginal pay regions. The third is an example that capitalizes on the US government’s 45Q tax credits for incentivizing CO2 injection. Our industry has been the custodian of subterranean reservoirs. We are the experts in managing and developing them. Why not use that expertise to find solutions for climate change by capturing and removing carbon and being part of the solution? Recommended additional reading at OnePetro: www.onepetro.org. SPE 200363 Economic Assessment of Strategies for CO2 EOR and Storage in Brownfield Residual Oil Zones: A Case Study From the Seminole San Andres Unit by Bo Ren, The University of Texas at Austin, et al. OTC 30157 Effects of CO2/Rock/Formation Brine Parameters on CO2 Injectivity for Sequestration by Muhammad Aslam Md Yusof, Universiti Teknologi Petronas, et al. SPE 202276 Is Chemical EOR Finally Coming of Age? by Eric Delamaide, IFP Technologies

scholarly journals Compositional Modeling of Impure CO2 Injection for Enhanced Oil Recovery and CO2 Storage

2021 ◽  
Vol 11 (17) ◽  
pp. 7907
Author(s):  
Hye-Seung Lee ◽  
Jinhyung Cho ◽  
Young-Woo Lee ◽  
Kun-Sang Lee
Keyword(s):  
Enhanced Oil Recovery ◽  
Oil Recovery ◽  
Carbon Capture ◽  
Oil And Gas ◽  
Co2 Storage ◽  
Carbon Capture And Storage ◽  
Co2 Injection ◽  
Displacement Efficiency ◽  
Compositional Simulation ◽  
Sweep Efficiency

Injecting CO2, a greenhouse gas, into the reservoir could be beneficial economically, by extracting remaining oil, and environmentally, by storing CO2 in the reservoir. CO2 captured from various sources always contains various impurities that affect the gas–oil system in the reservoir, changing oil productivity and CO2 geological storage performance. Therefore, it is necessary to examine the effect of impurities on both enhanced oil recovery (EOR) and carbon capture and storage (CCS) performance. For Canada Weyburn W3 fluid, a 2D compositional simulation of water-alternating-gas (WAG) injection was conducted to analyze the effect of impure CO2 on EOR and CCS performance. Most components in the CO2 stream such as CH4, H2, N2, O2, and Ar can unfavorably increase the MMP between the oil and gas mixture, while H2S decreased the MMP. MMP changed according to the type and concentration of impurity in the CO2 stream. Impurities in the CO2 stream also decreased both sweep efficiency and displacement efficiency, increased the IFT between gas and reservoir fluid, and hindered oil density reduction. The viscous gravity number increased by 59.6%, resulting in a decrease in vertical sweep efficiency. In the case of carbon storage, impurities decreased the performance of residual trapping by 4.1% and solubility trapping by 5.6% compared with pure CO2 WAG. As a result, impurities in CO2 reduced oil recovery by 9.2% and total CCS performance by 4.3%.

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