Miscible Flooding Research Articles

Effects of miscible degree and pore scale on seepage characteristics of unconventional reservoirs fluids due to supercritical CO2 injection

Supercritical CO2 (ScCO2) injection is a potential way to enhance oil recovery (EOR). The displacement effect varies significantly with the difference of miscible degree and pore scale. However, studies in this field are rarely reported. In this paper, relative permeability curves of three miscible types are firstly measured. Interestingly, the ultimate oil recovery of near-miscible flooding is found to be comparative with that of miscible flooding due to the obvious decrease of gas relative permeability under higher residual oil saturation. On this basis, four main zones in the vicinity of oil-ScCO2 contact are divided in view of the multiple contact miscibility mechanism. A new threshold pressure gradient (TPG) considering both pressure sensitivity and oil properties, is proposed as the indicator of the seepage capacity for the reservoir fluids. The seepage resistance of different cores is greatly reduced due to the ScCO2 injection, especially for the permeabilities less than 5 × 10−3 μm2. The modified TPGs decreased exponentially with the increase of mobility indicating that the seepage capacity of reservoir fluids can be enhanced significantly by strong and sufficient interactions of ScCO2 and oil. Thus, CO2 soaking-alternating-gas (CO2-SAG) flooding is proposed and evaluated to verify the importance of contact time and mass transfer.

The Effect of Formation Water Salinity on the Minimum Miscibility Pressure of CO2-Crude Oil for Y Oilfield

CO2 miscible flooding is an important technology for enhancing oil recovery and greenhouse gas storage in the world. As a tertiary recovery technology, it is usually applied after water flooding. Therefore, the actual reservoirs usually contain a lot of injected water in addition to connate water. The salinity of these formation waters varies from place to place. CO2 is an acid gas. After it is injected into the reservoir, it easily reacts with formation water and rock and affects the physical properties of the reservoir. However, no research results have been reported whether this reaction affects the minimum miscibility pressure (MMP) of CO2-crude oil, a key parameter determining miscible flooding in formation water. Based on CO2-formation water–rock interaction experiments, this paper uses the core flooding method to measure the CO2-crude oil MMP under different salinity in formation water. Results show that CO2 causes a formation water pH decrease from 7.4 to 6.5 due to its dissolution in formation water. At the same time, CO2 reacts with formation water, albite, potassium feldspar, and carbonate minerals in the cores to generate silicate and carbonate precipitates, which could migrate to the pore throat together with the released clay particles. Overall, CO2 increased core porosity by 5.63% and reduced core permeability by 7.43%. In addition, when the salinity of formation water in cores was 0, 4,767, and 6,778 mg/L, the MMP of CO2-crude oil was 20.58, 19.85, and 19.32 MPa, respectively. In other words, the MMP of CO2-crude oil decreased with the increase of salinity of formation water.

Carbon Dioxide Flooding Technology for Ultra-Low Permeability Reservoirs to Greatly Enhance oil Recovery

Low-permeability reservoir pressure is difficult to maintain, CO2 miscible flooding is difficult to achieve for low-permeability reservoirs, and near-miscible flooding is a promising technology for enhancing oil recovery for low-permeability reservoirs. Aiming at the complex geological and development characteristics of China’s continental low-permeability reservoirs, the system elaborated Sinopec’s CO2 flooding theory, reservoir engineering optimization design, injection and production engineering and anti-corrosion technology, production CO2 recovery and utilization, and other technical developments and field tests. Happening. Based on the research of CO2 flooding mechanism, this paper takes a well-known oil field H 28 reservoir as the target, and conducts an indoor evaluation of CO2 flooding methods through core physical simulation experiments. The pilot test of CO2 flooding field shows that CO2 flooding can significantly increase the productivity of ultra-low permeability oil wells, improve the development effect of oil wells, and meet the needs of ultra-low permeability reservoir development, and has broad application prospects.

Migration behavior of CO2-crude oil miscible zone

The CO2-crude oil miscible zone is the key factor to improve the recovery of miscible flooding, and the migration behavior of CO2-crude oil miscible zone has an significant influence on the development effect of CO2 miscible flooding. At present, the research on the characteristics of CO2-crude oil miscibility mainly focus on the miscible mechanism and the migration behavior of the miscible front edge, but there still remain many gaps in the systematic studies on the migration behavior of miscible zones. This paper defines four characteristic parameters of the miscible zone and presents the migration behavior of the miscible zone through theoretical analysis and numerical simulation. The results demonstrate that before the miscible zone's front edge breaks through, the front and rear edges' sweep coefficient and the dimensionless miscible zone's area increase linearly.Then, the dimensionless miscible zone's width decreases gradually after reaching the local maximum, while the front and rear edges' fingering coefficient increase more and more rapidly. After the miscible zone's rear edge breaks through, the miscible zone sweep coefficient's increase rate dropped significantly. The dimensionless miscible zone's area, the dimensionless miscible zone's width and the fingering coefficient gradually decrease and then stabilize. Based on the accurate characterization of miscible zone, it can provide a basis for the miscible zone regulation to improve the development effect of CO2 flooding.

Determination of Minimum Miscibility Pressure of CO2-Oil System: A Molecular Dynamics Study.

CO2 enhanced oil recovery (CO2-EOR) has become significantly crucial to the petroleum industry, in particular, CO2 miscible flooding can greatly improve the efficiency of EOR. Minimum miscibility pressure (MMP) is a vital factor affecting CO2 flooding, which determines the yield and economic benefit of oil recovery. Therefore, it is important to predict this property for a successful field development plan. In this study, a novel model based on molecular dynamics to determine MMP was developed. The model characterized a miscible state by calculating the ratio of CO2 and crude oil atoms that pass through the initial interface. The whole process was not affected by other external objective factors. We compared our model with several famous empirical correlations, and obtained satisfactory results—the relative errors were 8.53% and 13.71% for the two equations derived from our model. Furthermore, we found the MMPs predicted by different reference materials (i.e., CO2/crude oil) were approximately linear (R2 = 0.955). We also confirmed the linear relationship between MMP and reservoir temperature (TR). The correlation coefficient was about 0.15 MPa/K in the present study.

Monitoring oil displacement and CO2 trapping in low-permeability media using NMR: A comparison of miscible and immiscible flooding

Dynamic monitoring of the internal fluid distribution during CO2 immiscible/miscible flooding provides a crucial window for illuminating key processes controlling displacement and transport. We used online low-field nuclear magnetic resonance (NMR) imaging to monitor CO2 flooding under different reservoir pressures in low-permeability siltstone core plugs pre-saturated with stock tank oil from the Chang72 Formation in China. Immiscible and miscible styles of fluid displacement were triggered by flooding at pressures of 8 and 16 MPa, respectively. To visualize the oil distribution, NMR T2 and T1–T2 spectra and one-dimensional frequency (1D-FQ), and magnetic resonance imaging (MRI) were conducted to obtain the overall and spatially distributed saturations. The results show that recovery by miscible flooding (69.4%) was twice more than that by immiscible flooding (32.6%). The effect of the extraction of lighter components on oil viscosity and density after CO2 injection was negligible compared to the changes in miscibility. CO2 concentrations at the leading edge of the miscible zone (0.526) were higher than in the immediately adjacent transition zone (0.1); the dimensionless widths were 0.76 and 0.44, respectively. The CO2 retention rate following miscible flooding was 10.59% higher than that due to immiscible flooding, primarily due to remnant dissolved CO2 in the oil. In contrast, immiscible flooding limited the solubility of CO2 and led to solubility and residual trapping. These observations have a significant impact on defining oil and CO2 budgets, modes of transport, and storage for enhanced oil recovery and CO2 sequestration.

Advances in Midland Basin Expand Boundaries of CO2 EOR in Marginal Pay Areas

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 200460, “A Case Study of SACROC CO2 Flooding in Marginal Pay Regions: Improving Asset Performance,” by John Kalteyer, SPE, Kinder Morgan, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. As one of the first fields in the world to use carbon dioxide (CO2) in enhanced oil recovery (EOR), the Scurry Area Canyon Reef Operators Committee (SACROC) unit of the Kelly-Snyder field in the Midland Basin of Texas provides a unique opportunity to study, learn from, and improve upon the development of CO2 flood technology. The complete paper reviews the history of EOR at SACROC, discusses changes in theory over time, and provides a look at the field’s future. Field Overview and Development History The first six pages of the paper discuss the field’s location, geology, and development before June 2000, when Kinder Morgan acquired the SACROC unit and took over as operator. Between initial gas injection in 1972 and 2000, approximately 1 TCF of CO2 had been injected into the Canyon Reef reservoir. Since 2000, cumulative CO2 injection has sur-passed 7 TCF and yielded cumulative EOR of over 180 million bbl. The reservoir is a primarily limestone reef complex containing an estimated original oil in place (OOIP) of just under 3 billion bbl. The reservoir ranges from 200 ft gross thickness in the south to 900 ft in the north, where the limestone matrix averages 8% porosity and 20-md permeability. The Canyon Reef structure is divided into four major intervals, of which the Upper Canyon zone provides the highest-quality pay. The field was discovered in 1948 at a pressure of 3,122 psi. By late 1950, 1,600 production wells had been drilled and the reservoir pressure plummeted, settling as low as 1,700 psi. Waterflooding begun in 1954 enabled the field to continue producing for nearly 20 years, at which time the operators deter-mined that another recovery mechanism would be needed to maximize recovery and reach additional areas of the field. The complete paper discusses various CO2 injection programs that were developed and applied—including a true tertiary response from a miscible CO2 flood in 1981—along with their outcomes. Acquisition and CO2-Injection Redevelopment In June 2000 Kinder Morgan acquired the SACROC Unit and took over as operator. Approximately 6.7 billion bbl of water and 1.3 TCF of CO2 had been injected across the unit to that date, but the daily oil rate of 8,700 B/D was approaching the field’s economic limit. An estimated 40% of the OOIP had been produced through the combination of recovery methods that each previous operator had used. Expanding on the conclusions of its immediate predecessor, the operator initiated large-scale CO2-flood redevelopment in a selection of project areas. These redevelopments were based on several key distinctions differentiating them from previous injection operations.

The experimental research for reducing the minimum miscibility pressure of carbon dioxide miscible flooding

As the minimum miscibility pressure in the research area is higher than the formation fracture pressure, it is impossible to form the miscible flooding. To address this problem, the effect of two chemical reagents (citric acid isobutyl ester, citric acid isopentyl ester) on reducing the minimum miscibility pressure (MMP) of carbon dioxide and the crude oil was determined through the long slim tube displacement experiment. The experimental results show that the minimum miscibility pressure could decrease significantly with increasing the injected slug size of the chemical reagents, but the decrease became smaller and smaller. The chemical reagents had an optimal injected slug size of 0.003 PV (pore volume). At such slug size, the minimum miscibility pressure for citric acid isobutyl ester was reduced by 6.1 MPa and for citric acid isopentyl ester the reduction was 5.5 MPa. The minimum miscibility pressure was reduced by 20.61% and 18.58%. The addition of citric acid isobutyl ester slug could greatly reduce the minimum miscibility pressure, with a better effect. The recovery of the miscible flooding experiment scheme after injection of citric acid isobutyl ester slug was higher by 6.5%–11.6% than that of the scheme without citric acid isobutyl ester injection. Therefore, the citric acid isobutyl ester was recommended as the best chemical reagent to reduce the minimum miscibility pressure. The research results are of certain guiding significance for the overall realization of miscible flooding to enhance oil recovery in the research area.

Geomechanical analysis of formation deformation and permeability enhancement due to low-temperature CO2 injection in subsurface oil reservoirs

Several benefits of CO2 injection are reported in the literature such as its ability to mitigate greenhouse gas emissions and the increase in oil recovery at a low cost. However, the correlated reservoir-engineering problems with low-temperature CO2 injection including formation damage and leakage risk are still uncertain and has not been comprehensively investigated. This research examines the effect of low-temperature CO2 on lowering of formation breakdown pressure, and the associated formation damage from a geomechanical prospective. This study presents the coupling of the equilibrium stress equation, the system energy balance equation, continuity equation, and saturation equation to develop thermoporoelastic model for the reservoir rock. We determined the cooling-induced formation damage due to decrease in temperature and thermal stresses, formation contraction and tensile stresses, and examine its effects on formation properties, stresses, joint and fracture stability. We observed that low-temperature CO2 would create a low thermal stress region and thus the formation could fail in tension. This process might increase formation permeability but it would decrease the stability of reservoir, basement and caprock. We analyzed several factors affecting formation deformation such as injection rate for both miscible and immiscible CO2 flooding, formation porosity, depth, temperature, and formation breakdown pressure. We also compared our results and findings with experimental data, finding excellent match and similar consequences. Furthermore, as a sequence of low-temperature CO2 injection, the initial formation breakdown pressure was initially at 2560 psi and it reduced to 1928 for immiscible case and 1270 psi for miscible case in the selected case study. We also propose that shallow reservoirs should be avoided for CO2 capture and storage because of stability issues.

A pore-scale study of foam-microemulsion interaction during low tension gas flooding using microfluidics - Tertiary recovery

The emerging EOR technology of Low-Tension-Gas (LTG) flooding has been proven to be successful for tertiary oil recovery in laboratory scale coreflooding experiments. However, there has not been a detailed study of the pore-scale phenomena which occur during LTG flooding. In the current study, alternate injection of a suitable surfactant formulation and air has been used to simulate the mechanism of LTG flooding in a borosilicate water-wet micromodel. The main phenomenon that was investigated was the interaction between different microemulsion types (Winsor I and III) and foam. Results show that presence of foam facilitates faster and better oil displacement. Microemulsion equilibration time was improved in the presence of foam, due to increased mixing of the liquid phases. Presence of trapped gas helped to divert the flowing surfactant/microemulsion to regions with trapped remaining oil and thus improved oil recovery. For equilibrated Type III microemulsion, completely miscible flooding (or ultralow tension displacement) was observed. For Type I systems, oil-in-water macroemulsions were observed. For equilibrated Type III microemulsion, the presence of foam mainly improved the oil recovery rate. In case of Type III surfactant solution injection, the presence of foam improved both the oil recovery rate and the overall oil recovery. For Type I systems, the presence of foam enabled the transition of oil-in water macroemulsions to water-entrained macroemulsions, thus improving both the oil recovery rate and the overall oil recovery.

Enhanced oil recovery application in low permeability formations by the injections of CO2, N2 and CO2/N2 mixture gases

Low oil recovery which is very predominant in shale oil reservoirs has stimulated petroleum engineers to investigate the applications of enhanced oil recovery methods in these formations. One such application is the injection of gases into the formation to stimulate increased oil recovery. In many gas flooding projects performed in the field, the miscibility of the gas injected is usually the most desired displacement mechanism, and carbon dioxide (CO2) gas has been recognized to be the best performing gas for injection due to its ability to be miscible with oil in the reservoir at low pressures compared to other gases such as nitrogen. This minimum miscibility pressure (MMP) is of very crucial importance because it is the primary limiting factor in the feasibility of a miscible gas flooding project. However, there are other limiting factors such as cost and availability and, in these instances, nitrogen (N2) and lean gas are the more preferred candidate as opposed to carbon dioxide gas. Mixing carbon dioxide gas with lean gas or with nitrogen in a required ratio can allow us to design an injection gas that will be suitable enough to satisfy both the availability and cost constraints and at the same time allow us to achieve a reachable and reasonable miscibility pressure. The objective of this paper is to investigate the effect of mixing nitrogen gas and carbon dioxide gas in a 50:50 ratio on oil recovery in tight oil formations. The experiment was performed with controlled constraints such as the same core sample, same crude oil and same core cleaning and saturation process which was repeated for each trial. The oil used was live oil from Eagle ford formation, and the gases used were nitrogen (99.9% purity), carbon dioxide and a mixture of nitrogen and carbon dioxide in a 50:50 ratio. The injection pressure ranged from 1000 to 5000 psi with pressure increments of 1000 psi, and the same flooding time was 6 h. The potential of the N2, CO2 and N2–CO2 mixture for improving oil recovery was assessed along with the breakthrough time. The results showed that CO2 gas had the highest recovery followed by the N2–CO2 mixture and N2 gas had the lowest recovery. The gas breakthrough time results showed that the N2–CO2 mixture had the longest breakthrough time, N2 had the shortest breakthrough time, and CO2 had a significantly longer breakthrough time than pure N2 gas. The RF increased with increasing pressure, but the gas breakthrough time decreased with increasing pressure. However, the incremental RF decreased in all three cases when the injection pressure was above 3000 psi.

Effect of gravity segregation on CO2 flooding under various pressure conditions: Application to CO2 sequestration and oil production

This research evaluates the effect of gravity segregation on CO2 sequestration and oil production during CO2 flooding under immiscible, near-miscible, and miscible conditions. The core experiment results show that CO2 flooding recovery was seriously affected by gravity under immiscible conditions, while under miscible conditions, this influence was not apparent. Visual experiments show when immiscible, gravity restricts the oil and gas front’s stability, and different gas injection strategies have evident differences in the swept region; when miscible, gravity has almost no effect on the swept region. These results indicate that when CO2 immiscible flooding is implemented, the reservoir thickness affects the choice of gas injection direction. However, for miscible flooding, the reservoir thickness and gas injection direction are not essential for developing CO2 flooding. In immiscible conditions, gas injection velocity greatly restricts the CO2 gravity flooding recovery; in miscible conditions, the velocity is no longer the main influencing index of CO2 gravity flooding recovery. For CO2 sequestration, gravity segregation is conducive to increasing CO2 sequestration potential. As the pressure increases, the influence of gravity on CO2 sequestration weakens. Regardless of whether there is gravity effect, the best oil recovery and gas sequestration potential of CO2 flooding is obtained under miscible conditions.

Przegląd kierunków rozwoju biochemicznych metod wspomagania wydobycia ropy naftowej ze złóż ropnych

Crude oil, a major source of energy, is being exploited as a driver of the economy throughout the world. Being a limited resource, the price of crude oil increases constantly and the exploitation of mature reservoirs becomes essential in order to meet the ever-increasing energy demands. As conventional recovery methods are not sufficient to fulfil the growing needs, there is an incessant demand for developing new technologies which can help in efficient tertiary recovery in old reservoirs. Petroleum biotechnology has been emerging as a branch that can provide solutions to major problems in the oil industry, including increasing oil production from marginal oil wells. The enhanced oil recovery (EOR) method comprises four methods – chemical, thermal, miscible, and immiscible gas flooding – as well as microbial interference to increase recovery of the remaining hydrocarbons trapped in reservoir rocks. Biochemically enhanced oil recovery comprises an array of blooming technologies for tertiary oil recovery methods which is eco-friendly, cost-effective, and efficient in extracting the residual oil trapped in reservoir rocks. Biochemical enhanced oil recovery (BcEOR) is based on the principle of using biochemical by-products produced by microbial species to enhance oil recovery, etc. All these technologies work on the principles of reducing viscosity, increasing permeability, modifying solid surfaces, emulsifying through adherence to hydrocarbons, and lowering interfacial tension. BcEOR technologies either employ the beneficial microorganism itself or the biochemical by-products produced by the microbial species to enhance tertiary oil recovery. This review paper discusses the chronological development of biologically enhanced oil recovery and its various mechanisms.

Use of hybrid-ANFIS and ensemble methods to calculate minimum miscibility pressure of CO2 - reservoir oil system in miscible flooding process

CO2 injection is believed to be a reliable carbon dioxide sequestration and enhanced hydrocarbon recovery technique. Accurate calculation of minimum miscibility pressure (MMP) is of great importance for the design and implementation of CO2 injection processes. This study involves an innovative machine learning-based algorithm called AdaBoost integrated with the classification and regression tree (AdaBoost-CART) to accurately calculate the CO2-reservoir oil MMP for streams with various compositions. Furthermore, another model is presented on the basis of hybrid-adaptive neuro-fuzzy inference system (ANFIS). The reservoir temperature, composition of injection gas, critical temperature of the drive gas (in average), molecular weight of C5+ fraction in crude oil (MW C5+), and ratio of volatile to intermediate components in crude oil (Vol./Int.) are the independent input parameters considered for the modeling. A large number of data available in technical papers related to intelligent models were selected for comparison purpose. The results reveal the accuracy of the presented Hybrid-ANFIS and AdaBoost-CART models over models selected from the literature. It was also found that the most precise results can be obtained using the developed AdaBoost-CART model as the average absolute relative deviation percent is 0.40. The proposed models can be incorporated in various chemical and petroleum engineering simulators for more accurate and reliable MMP calculations.

Pore-Scale Simulations of CO2/Oil Flow Behavior in Heterogeneous Porous Media under Various Conditions

Miscible and near-miscible flooding are used to improve the performance of carbon-dioxide-enhanced oil recovery in heterogeneous porous media. However, knowledge of the effects of heterogeneous pore structure on CO2/oil flow behavior under these two flooding conditions is insufficient. In this study, we construct pore-scale CO2/oil flooding models for various flooding methods and comparatively analyze CO2/oil flow behavior and oil recovery efficiency in heterogeneous porous media. The simulation results indicate that compared to immiscible flooding, near-miscible flooding can increase the CO2 sweep area to some extent, but it is still inefficient to displace oil in small pore throats. For miscible flooding, although CO2 still preferentially displaces oil through big throats, it may subsequently invade small pore throats. In order to substantially increase oil recovery efficiency, miscible flooding is the priority choice; however, the increase of CO2 diffusivity has little effect on oil recovery enhancement. For immiscible and near-miscible flooding, CO2 injection velocity needs to be optimized. High CO2 injection velocity can speed up the oil recovery process while maintaining equivalent oil recovery efficiency for immiscible flooding, and low CO2 injection velocity may be beneficial to further enhancing oil recovery efficiency under near-miscible conditions.

Research for reducing the Minimum Miscible Pressure of crude oil and carbon dioxide by injecting citric acid isobutyl ester

Carbon dioxide miscible flooding has become one of the important technologies for improving oil recovery. The Minimum Miscible Pressure (MMP) is the key parameter to realize miscible flooding. As the MMP in the research area is higher than the formation fracture pressure, miscible flooding cannot be formed. To address this problem, it is necessary to find a way to reduce the MMP. Citric acid isobutyl ester is chosen to reduce the MMP of carbon dioxide and crude oil in this research. The effect of citric acid isobutyl ester on reducing the MMP was measured by the method of long-slim-tube displacement experiment. The experiment results show that the MMP is 29.6 MPa and can be obviously reduced by injecting the slug of citric acid isobutyl ester. The MMP could decrease gradually with constantly adding the injected slug of citric acid isobutyl ester, but the decrease becomes smaller and smaller. The optimum injected slug size of the chemical reagent is 0.003 PV. Under the condition of the slug size, the MMP is reduced to 23.5 MPa and the reduction is 6.1 MPa.

Proxy modelling for rapid optimisation of miscible CO<SUB align="right">2-WAG injection in heterogeneous clastic reservoirs: a case study from Southern Iraqi oil fields

Multiple simulation runs are required to optimise and quantify uncertainty and sensitivity analysis to determine and rank the impact of reservoir and operating parameters on the incremental oil recovery (ΔRF) under miscible CO2-WAG flooding. The central composite design (CCD) was employed to create a statistical proxy model for ΔRF as a function of seven reservoir and operating parameters. Statistical analysis was employed to check the model adequacy. The importance and effect of variables that result to higher predicted ΔRF were investigated. As an analogue of the Nahr Umr reservoir, the reservoir understudy, the proxy model can be roughly applied to predict the ΔRF during the miscible CO2-WAG injection at depending on uncertainty. The reliability of the proxy model has been demonstrated based on many statistical tools. [Received: 29 July 2019; Accepted: 24 November 2019]

Proxy modelling for rapid optimisation of miscible CO<SUB align="right">2-WAG injection in heterogeneous clastic reservoirs: a case study from Southern Iraqi oil fields

Multiple simulation runs are required to optimise and quantify uncertainty and sensitivity analysis to determine and rank the impact of reservoir and operating parameters on the incremental oil recovery (ΔRF) under miscible CO2-WAG flooding. The central composite design (CCD) was employed to create a statistical proxy model for ΔRF as a function of seven reservoir and operating parameters. Statistical analysis was employed to check the model adequacy. The importance and effect of variables that result to higher predicted ΔRF were investigated. As an analogue of the Nahr Umr reservoir, the reservoir understudy, the proxy model can be roughly applied to predict the ΔRF during the miscible CO2-WAG injection at depending on uncertainty. The reliability of the proxy model has been demonstrated based on many statistical tools. [Received: 29 July 2019; Accepted: 24 November 2019]

Application and Mechanism of a Novel CO<sub>2</sub>-Oil Miscible Flooding Agent, CAA8-X

Application and Mechanism of a Novel CO<sub>2</sub>-Oil Miscible Flooding Agent, CAA8-X

The Effect of Carbonyl and Hydroxyl Compounds Addition on CO2 Injection through Hydrocarbon Extraction Processes

CO2 miscible flooding occurs when injection pressure is higher than the minimum miscibility pressure (MMP) which can exceed the fracture pressure. Co-solvents are expected to reduce the MMP by interacting with various hydrocarbons that depend on the polarity and intermolecular forces of solvent and oil. However, there are limited studies that have investigated co-solvent performance in CO2 injection through an extraction process based on oil compositional analysis. This paper is aimed at studying the effects of carbonyl and hydroxyl compounds on oil extraction and also the mutual interactions of CO2-oil-carbonyl and -hydroxyl. The experiment is conducted by using VIPS (viscosity, interfacial tension, pressure-volume, and swelling) and gas chromatography (GC) apparatuses. The compositional results from GC are utilized to analyze the performance of co-solvents, which are further classified based on the carbon number and molecular structure of oil. Acetone is a non-associated polar compound which reacts easily with and assists CO2 to extract polar-aromatic heavy and slightly polar components such as alkenes and straight-chain alkanes, due to high polarizability and low cohesive forces. Ethanol is a self-associated polar compound which has the capability of extracting high-boiling fractions and slightly polar-aromatic components. Moreover, both co-solvents also assist CO2 to extract non-polar components because they have non-polar end in the alkyl group.