Oil CO2 Research Articles

Analysis of CO2 storage mechanisms at a CO2‐EOR site, Cranfield, Mississippi

AbstractCarbon dioxide injected for enhanced oil recovery will partition into several phases in the target geological formation. The distribution into free or residually trapped oil, gas, and brine phases depends on many factors such as reservoir temperature and pressure, initial fluid saturations, brine salinity, and relative permeability parameters, and evolves through time including in the post‐injection period, during which it will tend to stabilize. Our numerical simulations, based on Cranfield, MS CO2‐EOR project data, demonstrate that these variations are significant and mostly dependent on the operator's selected field‐development strategy: continuous gas (CO2) injection, water alternating gas (WAG) injection, water curtain injection, or combinations thereof. In summary, our work shows that the field development strategy selected by the operator has a major impact on the relative importance of the different trapping mechanisms and that WAG seems to be a promising operational approach to balance both CO2 storage and oil production. © 2018 Society of Chemical Industry and John Wiley & Sons, Ltd.

How do metal oxide nanoparticles influence on interfacial tension of asphaltic oil-Supercritical CO2 systems?

Often, supercritical CO2 is injected into oil reservoirs as a miscible gas. CO2 injection might force asphaltene particles to precipitate. To reduce asphaltene precipitation, it might be a good solution to use asphaltene adsorbents like metal oxide nanoparticles. Diffusion of supercritical CO2, containing suspended nanoparticles, into oil slugs would decrease asphaltene precipitation as a result of nanoparticles high adsorption capacity. In this research, IFT values between the supercritical CO2 and different crude oil types, which are saturated with NiO, Co3O4, and Fe3O4 nanoparticles, have been measured. Furthermore, effects of different crude oil properties such as API gravity, asphaltene content, and sulfur content on the nanoparticles performance are also investigated. Accordingly, nanoparticles performances order is NiO > Co3O4> Fe3O4. In addition, it is found that oil properties effects on IFT reduction are not synergistic; so, the overall effect must be evaluated quantitatively to understand IFT reduction of the system.

Enhanced effects of large-scale CO 2 transportation on oil accumulation in oil-gas-bearing basins — Implications from supercritical CO 2 extraction of source rocks and a typical case study

Abstract Large-scale mantle-derived CO2 emplacement and co-accumulation of CO2 and crude oil have been discovered in oil-gas bearing basins in eastern China and many other areas worldwide. To investigate the effect of the natural supercritical CO2 on the migration of crude oil as well as on the formation of oil reservoirs, experiments on supercritical CO2 extraction (SCE) and traditional chloroform extraction (CE) of hydrocarbon source rocks were carried out and the geochemical characteristics of the Huangqiao CO2-oil reservoir in the Subei Basin, eastern China were investigated. The SCE yielded a large proportion of the hydrocarbons in the Permian mudstone source rocks at 110 °C under 30 MPa. Compared with the traditional chloroform extraction (CE), the SCE-retrieved organic compounds are dominated by saturated hydrocarbons and contain a relatively higher concentration of small molecular mass compounds. Many wells in the Huangqiao reservoir yielded large amounts of CO2 from several formations, such as the Triassic Qinglong Formation (T1q) and the Permian Longtang Formation (P2l). Accompanying the CO2 flow, a certain amount of oil is commonly recovered. The oil is mainly light oil or condensate oil with a relative density of 0.7933–0.8308, and it contains 90.06–97.37% saturated hydrocarbons. Compared with hydrocarbons in the Permian source rocks, the oil accompanying the CO2 in the Huangqiao reservoir contains more C20- hydrocarbons and less C21+ hydrocarbons. The oil accompanying the CO2 has a similar composition to the SCE extracts from the source rocks, namely, both contain a relatively high concentration of low molecular mass hydrocarbons. Therefore, it can be concluded that, in the Huangqiao area, during movement upward along deep faults and fractures or flow through source rocks, the deep supercritical CO2 naturally extracted hydrocarbons, especially small molecular hydrocarbons, from the source rocks, and then brought them to the shallow strata to form the CO2-oil coupling reservoirs.

Natural enhancement and mobility of oil reservoirs by supercritical CO2 and implication for vertical multi-trap CO2 geological storage

The accumulation and production of both deep mantle-derived CO2 and light oil were discovered in the Huangqiao reservoir, which is located in the Subei Basin, East China. The Huangqiao reservoir shows that both CO2 and oil are entrapped in and produced from vertical multi-traps. The effects of deep CO2 on the accumulation and production of oil under natural conditions and the implications for CO2 geological storage are investigated in detail. The fluid inclusions in quartz or calcite veins from the Silurian Fentou Formation (S2-3f), Permian Longtan Formation (P2l) and Triassic Qinglong Formation (T1q) have homogenization temperatures (Ths) that display peak ranges of 180°C–190 °C, 170°C–180 °C and 150°C–160 °C, respectively. The Ths are higher than the formation temperatures. The calcite veins have light carbon and oxygen isotope compositions and have high 87Sr/86Sr ratios and positive Eu anomalies. These characteristics reveal the activities of deep CO2-rich hydrothermal fluids in the basin strata. The feldspar in the S2-3f and P2l sandstone reservoirs underwent significant dissolution because of the presence of CO2-rich fluids, forming of a large amount of secondary pores in the sandstone reservoirs and enhancing the reservoirs’ physical properties. The measured porosity reaches 12.3%. CO2 in a supercritical state extracted or dissolved light petroleum components out of sedimentary rocks and then carried them towards reservoirs. Thus, CO2 and oil co-accumulated in the enhanced reservoirs, e.g. S2-3f, P2l and T1q. During drilling development, this supercritical CO2 naturally increased the mobility of oil, resulting in the co-production of highly pure CO2 and light oil. Based on the unique features of the Huangqiao CO2-oil reservoir, we propose a new CO2 geological storage model, namely, a vertical multi-trap geological storage model, which can either entrap large volumes of CO2 or lower the risk of long-term storage.

Predictions of In-Tube Cooling Heat Transfer Coefficients and Pressure Drops of CO2 and Lubricating Oil Mixture at Supercritical Pressures

ABSTRACTThe in-tube cooling heat transfer and flow characteristics of supercritical pressure CO2 mixed with small amounts of lubricating oil differ from those for pure CO2 due to the entrainment of the lubricating oil as well as the sharp property variations of the supercritical CO2 working fluid. In-tube gas cooling flow and heat transfer models were developed in this study for CO2 with entrained polyol ester type lubricating oil in a CO2 gas cooler at supercritical pressures. A “thermodynamic approach,” which treats the CO2–oil mixture as a homogenous mixture was used with the heat transfer coefficients and frictional pressure drops evaluated based on the thermophysical properties of the CO2–oil mixture. Thermophysical property variation correction terms as a function of the wall temperature and the oil concentration were included in the models. The frictional pressure drop correlation predicts more than 90% of the experimentally measured data within ±10%, while the heat transfer coefficient correlation predicts more than 90% of the experimentally measured data within ±20%.

Electrokinetic nanoparticle injection for remediating leaks in oil well cement

This paper presents experimental results on injecting nanoparticles into a hardened oil well cement with electromigration technique. Oil well cement is a special cement type used in underground constructions to protect steel casing of oil wells, CO2 storage wells or oil and gas platforms. Due to the technological reasons, the hardened cement is characterized with a high initial porosity. Further distressing and fracturing occurs in the hardened cement originating from the harsh underground environment which includes elevated pressure and temperature. This leads to severe leakages of the stored media and puts the steel casing to the risk of corrosion.The paper proposes to use a non-destructive remediation technique for the cement repair based on the electrokinetic injection of nanoparticles into the pore and crack space in the material. It shows the efficiency of the technique and presents results from injections with a variety of differently sized nanosilica, microsilica and nanoalumina particles. Characterization of the treated samples was based on microscopy observations, electrical measurements, the change in their open porosity and nanopore surface area assessed by the BET technique. It was found that the electrokinetic process and driving of particles in samples is very efficient and reduces the sample porosity by about 4–7% with respect to the initial porosity of intact specimens and 5–8% on aged samples. The BET analysis confirmed reduction of the inner pore surface area in the treated samples. Increasing level of agglomeration of particles on the surface as well as in the inner pores was observed during electrokinetic treatment and documented with the electric current measurements.

Enhancing photosynthetic biomass productivity of industrial oleaginous microalgae by overexpression of RuBisCO activase

Eukaryotic microalgae are promising cell factories for photosynthesis-driven CO2 sequestration and oil production, however one key challenge has been to genetically enhance their biomass productivity. Here we showed that the biomass productivity of a model industrial oleaginous microalga Nannochloropsis oceanica can be elevated by overexpression of a nuclear-encoded, cbbX-homologous, candidate RuBisCO activase (g1915 or ‘nNoRca-like’) that is transcriptionally induced under air-level CO2 (i.e., 0.04% v/v) as compared to 5% CO2 in wild-type cells. In the mutants, under air-level CO2, growth rate was enhanced by ~32%, biomass accumulation by ~46% and lipid productivity by ~41%, which were also accompanied by ~28% elevation in photosynthesis; furthermore, abundance of RuBisCO large subunit protein increased by ~45%, suggesting nNoRca-like overexpression enhanced microalgal photosynthesis by upregulating the level and activity of RuBisCO. Interestingly, under 5% CO2, no significant enhancement of RuBisCO protein expression was observed. Thus a genetic strategy that activates RuBisCO by augmenting its functional partners was proposed to increase biomass production of industrial microalgae. Our work expands the reservoir of potential photosynthetic gene targets for plant biotechnology and provides a basis for constructing advanced microalgal cell factories for carbon sequestration and biofuel production.

Synergy of CO2 Storage and Oil Recovery in Different Geological Formations: Case Study in the Baltic Sea

Pilot project for CO2 storage and CO2-EOR/EOR+ in different geological formations including two scenarios is proposed for Latvian offshore structure E6. The first “two wells and possible fault-leakage” scenario proposed CO2 storage in the Cambrian Deimena Formation and oil recovery from the Upper Ordovician Saldus Formation. One common injection well and possible fault leakage to the oil reservoir are considered as a profit. The second “three wells and no leakage” scenario, includes additional CO2 injection well to oil reservoir. A surplus for both scenarios is increased CO2 storage capacity. The new pilot project idea supports exploitation of small oil deposits in the Baltic Region.

Laboratory Characterization and Modeling to Examine CO2 Storage and Enhanced Oil Recovery in an Unconventional Tight Oil Formation

The Bakken Formation is a major unconventional tight oil play in North America. The potential for the Bakken to serve as a target for CO2 storage and CO2-based enhanced oil recovery was examined using advanced characterization techniques, laboratory experiments, and modeling. Bakken rocks are dominated by nanoscale pore throats, and although porosity is low, much of the nanoscale porosity is connected. Collectively, the characterization, experimental, and modeling results suggest the nanoscale pore throats make important contributions as transport pathways for CO2 storage and oil mobilization in the Bakken.

Influence of Sedimentation Heterogeneity on CO2 Flooding

To study CO2 flow characteristics in heterogeneous rock, we designed a laboratory experimental system that visualizes the CO2 movements in rock specimens by using X-ray computed tomography (CT). We carried out laboratory experiments of CO2 flooding in porous sandstones, together with porosity calculation, fluid saturation monitoring based on the CT images and mass flow measurements for ejected fluids. We used Berea sandstone and Sarukawa sandstone as homogeneous and heterogeneous rock in this study. The CO2 flooding tests were carried out until the CO2 injection reaches about 2 PV (pore volume) for the Berea sandstone and about 3 PV for the Sarukawa sandstone. When injected CO2 reached 1.0 PV in both specimens, The CO2 saturations were 34.15% and 15.21% in Berea sandstone and Sarukawa sandstone, respectively. We increased the differential pressure only for the Sarukawa sandstone to confirm the influence of differential pressure on CO2 saturation and oil recovery in heterogeneous media. The oil recoveries were 74.80% and 71.93% for Berea sandstone and Sarukawa sandstone, respectively when injected CO2 reached about 2.0 PV. CO2 was spreading evenly from the injection part through the Berea sandstone. In the case of Sarukawa sandstone, almost all of the CO2 preferentially moved through the upper part of specimen. This represents that the sedimentation heterogeneity is one of the main factors that affects the CO2 flooding pattern.

Measurement of the Rheology of Crude Oil in Equilibrium with CO2 at Reservoir Conditions.

A rheometer system to measure the rheology of crude oil in equilibrium with carbon dioxide (CO2) at high temperatures and pressures is described. The system comprises a high-pressure rheometer which is connected to a circulation loop. The rheometer has a rotational flow-through measurement cell with two alternative geometries: coaxial cylinder and double gap. The circulation loop contains a mixer, to bring the crude oil sample into equilibrium with CO2, and a gear pump that transports the mixture from the mixer to the rheometer and recycles it back to the mixer. The CO2 and crude oil are brought to equilibrium by stirring and circulation and the rheology of the saturated mixture is measured by the rheometer. The system is used to measure the rheological properties of Zuata crude oil (and its toluene dilution) in equilibrium with CO2 at elevated pressures up to 220 bar and a temperature of 50 °C. The results show that CO2 addition changes the oil rheology significantly, initially reducing the viscosity as the CO2 pressure is increased and then increasing the viscosity above a threshold pressure. The non-Newtonian response of the crude is also seen to change with the addition of CO2.

Measurement of the Rheology of Crude Oil in Equilibrium with CO<sub>2</sub> at Reservoir Conditions

A rheometer system to measure the rheology of crude oil in equilibrium with carbon dioxide (CO2) at high temperatures and pressures is described. The system comprises a high-pressure rheometer which is connected to a circulation loop. The rheometer has a rotational flow-through measurement cell with two alternative geometries: coaxial cylinder and double gap. The circulation loop contains a mixer, to bring the crude oil sample into equilibrium with CO2, and a gear pump that transports the mixture from the mixer to the rheometer and recycles it back to the mixer. The CO2 and crude oil are brought to equilibrium by stirring and circulation and the rheology of the saturated mixture is measured by the rheometer. The system is used to measure the rheological properties of Zuata crude oil (and its toluene dilution) in equilibrium with CO2 at elevated pressures up to 220 bar and a temperature of 50 °C. The results show that CO2 addition changes the oil rheology significantly, initially reducing the viscosity as the CO2 pressure is increased and then increasing the viscosity above a threshold pressure. The non-Newtonian response of the crude is also seen to change with the addition of CO2.

Visualization observation of formation of a new oil phase during immiscible dense CO2 injection in porous media

Miscibility is not a target nor achievable for CO2 injection in heavy oil reservoirs but immiscible CO2 injection has shown significant potential in enhancing heavy oil recovery mainly through a substantial reduction in the oil viscosity. Another major benefit of CO2 for enhanced heavy oil recovery is a favorable improvement in the composition of the oil which results in the production of higher quality oil compared to the original oil. To identify the actual mechanisms that affect the physical properties of heavy oil during various CO2 injection strategies, the behavior of CO2 and heavy oil was visually investigated under reservoir conditions. For this purpose, a setup was designed to visually observe the contact between injected CO2 and heavy oil under reservoir conditions. In addition, several flow experiments were performed using a transparent micromodel setup.It was observed that as soon as CO2 contacts the oil, the extraction of hydrocarbons, mostly methane at the beginning, from the oil starts. The extraction of hydrocarbons by CO2 initially led to a sudden swelling of the oil mainly because of the liberation of dissolved methane from oil. Because of the extraction strength of CO2, an accumulation of light and intermediate compounds of the oil takes place in the oil phase, near the interface of oil and CO2. The results of direct visualization of the flow of CO2 and heavy oil reveal that the contact of CO2 and heavy oil results in the formation of a light and less viscous oil-rich phase. This oil-rich phase has a relatively lighter color than the oil in contact with CO2 and it is very mobile in pore spaces.

Application of adaptive neuro fuzzy interface system optimized with evolutionary algorithms for modeling CO2-crude oil minimum miscibility pressure

CO2 injection is known as one of the most reliable enhanced oil recovery techniques. The success of every gas injection process depends highly on the minimum miscibility pressure (MMP) needed for the injected gas and the oil to reach miscibility. Therefore, determination of the MMP between the two fluids is of great importance. In this study, a novel intelligent model based on adaptive neuro fuzzy interface system (ANFIS) was developed for predicting MMP values between pure/impure CO2 and reservoir oil at different reservoir conditions based on 270 experimental data points for pure and impure CO2, dead and live oils, reservoir temperature ranges from 293.72K to 388.73K, and experimental MMP values range from 6.54MPa to 31.30MPa. The ANFIS model was optimized by five different approaches; including Back Propagation (BP), Genetic Algorithm (GA), Particle Swarm Optimization (PSO), Ant Colony Optimization (ACO) and Differential Evolution (DE). A large number of data points from various sources of literature were gathered for model development and verification. In addition, various statistical and graphical error analyses were employed to evaluate the performance of the developed models as well as to compare them with major literature models for MMP prediction. The results showed that the ANFIS model optimized by PSO has the highest accuracy among all the models developed in this study as well as literature models, with an average absolute percent relative error of only 7.53%. In addition, all models developed in this study are more accurate than the existing models and their accuracy are as follows: ANFIS-PSO>ANFIS-GA>ANFIS-ACO>ANFIS-BP>ANFIS-DE. Lastly, the ANFIS models developed here can be inserted in any simulator to increase the accuracy of predicting pure and impure CO2-crude oil MMP.

Minimum miscibility pressure of CO2 and crude oil during CO2 injection in the reservoir

Recently, carbon dioxide (CO2) flooding into depleted reservoirs regardless of miscible or immiscible displacement is widely investigated not only to improve oil recovery but also to reduce the greenhouse effect of this gas produced by numbers of industries in the globe. In the light of this fact, in the first stage of this investigation, the minimum miscibility pressure (MMP) of CO2 and light crude oil (API°=35) with low asphaltene content was determined at temperatures of 30, 50 and 80°C using vanishing interfacial tension (VIT) method. The obtained results demonstrated that the MMP of the studied system is almost linear function of temperature with slope of 0.15MPa/K. The interesting point is that the results revealed a reduction in slope as the composition of light components of crude oil increases.

Optimum design of CO2 storage and oil recovery under geological uncertainty

This paper presents an integrated numerical framework to co-optimize EOR and CO2 storage performance under uncertainty in the Farnsworth Unit (FWU) oil field in Ochiltree County, Texas. The framework includes a field-scale compositional reservoir multiphase flow model, an uncertainty quantification model and a neural network optimization process. The reservoir flow model has been constructed based on the field geophysical, geological, and engineering data. Equation of state parameters were tuned to achieve field measured fluid properties and subsequently used to predict the minimum miscible pressure (MMP).A history match of primary and secondary recovery processes was conducted to estimate the reservoir and multiphase flow parameters as the base case for analyzing the effect of recycling produced gas, infill drilling and water alternating gas (WAG) cycles on oil recovery and CO2 storage. A multi-objective optimization model was defined for maximizing both oil recovery and CO2 storage. The uncertainty quantification model comprising the Latin Hypercube sampling, Monte Carlo simulation, and sensitivity analysis, was used to study the effects of uncertain variables on the defined objective functions. Uncertain variables include bottom hole injection pressure, WAG cycle, injection and production group rates, and gas-oil ratio. The most significant variables were chosen as control variables to be used for the optimization process. A neural network optimization algorithm was utilized to optimize the objective function both with and without geological uncertainty. The vertical permeability anisotropy (Kv/Kh) was selected as one of the uncertain parameters in the optimization process.The simulation results were compared to a scenario baseline case that predicted CO2 storage of 74%. The results showed an improved approach for optimizing oil recovery and CO2 storage in the FWU. The optimization model predicted that about 94% of CO2 would be stored and most importantly, that this increased storage could result in about 25% of incremental oil recovery. The sensitivity analysis reduced the number of control variables to decrease computational time. A risk aversion factor was used to represent results at various confidence levels to assist management in the decision-making process. The defined objective functions were shown to be a robust approach to co-optimize oil recovery and CO2 storage.

Interactions and phase behaviors between oleic phase and CO2 from swelling to miscibility in CO2-based enhanced oil recovery (EOR) process: A comprehensive visualization study

In this work, a comprehensive study of interactions and phase behaviors between CO2 and oleic phase, including CO2 dissolution, oil swelling (So), hydrocarbon extraction, and miscible process, was conducted using a high-pressure-temperature visualization cell. The experimental data indicated that the magnitude of CO2 solubility decreased with temperature and oil density; while at a given temperature, this parameter increased steadily with pressure until the oleic phase was CO2-saturated. The value of So remained increasing up to the first threshold extraction pressure, Pext,1, from which the hydrocarbons began to be extracted into the CO2 phase. Furthermore, the extracted portion became heavier (C10–C19) with the rise in pressure, which thus caused the oil volume to shrink and led to the value of So below 1.0 from the second threshold extraction pressure, Pext,2. Further increasing pressure resulted in more heavy hydrocarbons (C20–C29) participating in CO2-oleic phase interchanges until the miscibility was finally achieved. At the miscible stage, the composition of the gas phase was found to be fairly close to the oleic phase except some heavy fraction (i.e. asphaltene). Based on the results, the dominant oil recovery mechanisms contributing to CO2 cyclic injection EOR were qualitatively defined.

Techno-economic evaluation of CO2 enhanced oil recovery (EOR) with the optimization of CO2 supply

Enhanced oil recovery (EOR) by the injection of CO2 into the oil reservoir is widely practiced for stimulating oil production, which is also favorable for CCS (carbon capture and storage) due to the effect of sequestrating CO2 into the empty space of the reservoir along with oil production. Although economic and environmental benefits can be obtained through CO2 EOR, it requires considerable capital investment and expenditure for the operation. Therefore, it is helpful to assess systematically the life-time effect of CO2 EOR by evaluating the capital and energy flow.Rather considering collectively overall mass flows of CO2 purchase, recycling, sequestration and oil production throughout the whole life-cycle, this study presents the assessment of CO2 EOR in a multi-period manner in which CO2 supply is systematically scheduled, subject to the availability of external CO2 sources and time-dependent relationship between CO2 injection, CO2 supply and CO2 recycle. The methodological procedure for the proposed economical assessment is presented with the case study, in which CO2 supply schedule is optimized to maximize net present value (NPV), considering the constraints imposed by time-dependent availability of CO2 supply sources. Sensitivity analysis of key design parameters is performed to gain conceptual insights for the design and operation of CO2 EOR.

CO2 flooding strategy to enhance heavy oil recovery

Abstract CO2 flooding is one of the most promising techniques to enhance both light and heavy oil recovery. In light oil recovery, the production pressure in CO2 flooding in general keeps constant in order to maintain the miscibility of injected CO2 and crude oil; while in heavy oil recovery, a depleting pressure scheme may be able to induce foamy oil flow, thus the oil recovery could be further enhanced. In this study, different pressure control schemes were tested by 1-D core-flooding experiments to obtain an optimized one. Numerical simulations were conducted to history match all experimental data to understand the mechanisms and characteristics of different CO2 flooding strategies. For the core-flooding experiments, 1500 mD sandstone cores, formation brine and a heavy oil sample with a viscosity of about 869.3 cp at reservoir condition (55 °C and 11 MPa) were used. Before each CO2 flooding test, early stage water-flooding was conducted until the water cut reached 90%. Different CO2 injection rates and production pressure control strategies were tested through core-flooding experiments. Experimental results indicated that a slower CO2 injection rate (2 ml/min) led to a higher recovery factor from 31.1% to 36.7%, compared with a high CO2 injection rate of 7 ml/min; for the effects of different production strategies, a constant production pressure at the production port yielded a recovery factor of 31.1%; while a pressure depletion with 47.2 kPa/min at the production port yielded 7% more oil recovery; and the best pressure control scheme in which the production pressure keeping constant during CO2 injection period, then depleting the model pressure with the injector shut-in yielded a recovery factor of 42.5% of the initial OOIP. For the numerical simulations study, the same oil relative permeability curve was applied to match the experimental results to all tests. Different gas relative permeability curves were obtained when the production pressure schemes are different. A much lower gas relative permeability curve and a higher critical gas saturation were achieved in the best pressure control scheme case compared to other cases. The lower gas relative permeability curve indicates that foamy oil was formed in the pressure depletion processes. Through this study, it is suggested that the pressure control scheme can be optimized in order to maximize the CO2 injection performance for enhanced heavy oil recovery.

Experimental identification of CO2–oil–brine–rock interactions: Implications for CO2 sequestration after termination of a CO2-EOR project

Carbon dioxide enhanced oil recovery (CO2-EOR) has been widely applied to the process of carbon capture, utilization, and storage (CCUS). Here, we investigate CO2–oil–water–rock interactions under reservoir conditions (100 °C and 24 MPa) in order to understand the fluid–rock interactions following termination of a CO2-EOR project. Our experimental results show that CO2-rich fluid remained the active fluid controlling the dissolution–precipitation processes in an oil-undersaturated sandstone reservoir; e.g., the dissolution of feldspar and calcite, and the precipitation of kaolinite as well as solid phases comprising O, Si, Al, Na, C, and Ti. Mineral dissolution rates were reduced in the case that mineral surfaces were coated by oil. Mineral wettability and composition, and oil saturation were the main controls on the exposed surface area of grains, and mineral wettability in particular led to selective dissolution. In addition, the permeability of the reservoir decreased substantially due to the precipitation of kaolinite and solid-phase particles, and due to the clogging of less soluble mineral particles released by the dissolution of K-feldspar and carbonate cement, whereas porosity increased. The results provide insight into potential formation damage resulting from CO2-EOR projects.