CO2 Enhanced Oil Recovery Process Research Articles

Application of smart proxy model for multi-optimization of CO2-EOR design in farnsworth unit with production-injection well conversion

CO2-Enhanced Oil Recovery (CO2-EOR) is an effective development strategy and an economically viable CO2 storage method for a mature oil field. In this study, a smart proxy model (SPM) was constructed to establish the optimal development strategies in Farnsworth Unit (FWU) considering CO2 storage and oil production with the production-injection well conversion. An SPM was constructed with the results of 16 reservoir simulations and was validated with an R2 values of 96.3 % and 97.5 % for the CO2 storage and oil production, respectively. The obtained Pareto front indicates a range of the optimized CO2 storage and oil production. In addition, the maximum CO2 storage case shows 260 % and 61.1 % of the CO2 storage and oil production of the base case, respectively. When the maximum oil production is targeted, the CO2 storage and oil production are respectively 66.5 % and 111.3 % of the base case. It was concluded that the SPM is effectively applicable for multi-objective optimization with fewer simulation runs and shorter time. In addition, the well conversion is a viable method to improve both the CO2 storage and oil production in the FWU during CO2-EOR process.

Multi-objective optimization of CO2 enhanced oil recovery and storage processes in low permeability reservoirs

CO2 enhanced oil recovery (CO2-EOR) is a mature technology to improve production from low permeability reservoirs. The CO2-EOR process has the potential of both improving oil recovery and sequestering large volumes of injected CO2. The performance of CO2 flooding can be affected significantly by CO2 injection modes (continuous gas injection, CGI, or water alternating gas, WAG); types of optimizations (co-optimization or synergy optimization); and several operational parameters, e.g., injection rates, etc. This paper presented an integrated numerical framework for co-optimization and synergy-optimization of CO2-EOR performance and CO2 storage performance in low permeability reservoirs and provided a comparison of CGI and WAG injection modes. In co-optimization, we maximized cumulative oil production (COP) and CO2 storage capacity (CO2SC) simultaneously (i.e., bi-objective optimization) using multi-objective particle swarm optimization (MOPSO). In synergy-optimization, we maximized a weighted sum of COP and CO2SC (i.e., single objective optimization) using PSO. The optimization results provide significant insight to the decision-making process of coupled CO2-EOR and storage projects when multiple objective functions are considered. We also compared the influence of dimensionless objective functions on the optimization results for different types of optimizations, and the results proved dimensionless objective functions had no impact on the results of co-optimization, but had great influence on the results of synergy-optimization. Considering the tax credit of CO2 stored can obtain higher NPV due to balance out some of the operating cost. Synergy-optimization can approximately obtain partial optimization results of co-optimization when different weight of index is considered.

CO2 Sequestration and Enhanced Oil Recovery via the Water Alternating Gas Scheme in a Mixed Transgressive Sandstone-Carbonate Reservoir: Case Study of a Large Middle East Oilfield

The knowledge on CO2 sequestration and CO2 enhanced oil recovery (CO2-EOR) in mature mixed and interbedded hydrocarbon reservoirs are limited. In this vein, the feasibility of CO2-water alternating gas (CO2-WAG) for coupling CO2 sequestration and CO2-EOR in a mature mixed sandstone-carbonate reservoir was investigated using the S1A reservoir. First, core sample analysis and scanning electron microscopy (SEM) were conducted to evaluate the reservoir characterization. Next, a geological model with dual porosity and permeability was developed and transferred to a reservoir simulation model, and 21-year field production data were utilized for history matching and constraining of the reservoir model. Then, continuous CO2 and CO2-WAG injection methods were simulated using newly developed and history-matched geo-models and compared to assess their CO2-EOR and CO2 storage mechanisms and determine their potential in a mixed sandstone-carbonate reservoir. The effect of the anisotropic permeability ratio and hysteresis on CO2 storage mechanisms was addressed in this work. The results indicate that the CO2-WAG scheme can yield a +3% oil recovery factor than the continuous CO2 injection method, and CO2-WAG injection can utilize up to 14 and 12% of the total CO2 injected for residual and solubility trappings, respectively, while a minimal 2.9 and 0.03% was utilized from continuous CO2 injection for residual and solubility trappings, respectively. The WAG ratio of 2:1 could yield a higher recovery factor and greater CO2 utilization for solubility and residual trappings in a mixed reservoir. In mixed and interbedded reservoirs, geological anisotropy can also strongly influence reservoir performance during the CO2-EOR process, in which higher values of the anisotropy ratio (Kv/Kh) in CO2-WAG can yield greater oil recovery and more CO2 storage; also, hysteresis has great impact on residual trapping. This study provides valuable insights into the potential of CO2-WAG for CO2 sequestration and CO2-EOR in mature mixed and interbedded reservoirs.

Conformance control by a microgel in a multi-layered heterogeneous reservoir during CO2 enhanced oil recovery process

Injecting CO2 into the underground for oil displacement and shortage is an important technique for carbon capture, utilization and storage (CCUS). One of the main problems during the CO2 injection is the channeling plugging. Finding an effective method for the gas channeling plugging is a critical issue in the CO2 EOR process. In this work, an acid-resistance microgel named dispersed particle gel (DPG) was characterized and its stability was tested in the CO2 environment. The microgel size selection strategies for the homogeneous and heterogeneous reservoirs were respectively investigated using the single core flooding and three parallel core flooding experiments. Moreover, the comparison of microgel alternate CO2 (MAC) injection and water alternate CO2 (WAC) injection in the dual core flooding experiments were presented for the investigation of the role of microgel on the conformance control in CO2 flooding process. The results have shown that the microgel featured with NH and CN groups can keep its morphology after aging 7 days in the CO2 environment. Where, the small microgel with unobstructed migration and large microgel with good plugging efficiency for the high permeability zone were respectively featured with the higher recovery factor in homogeneous and heterogeneous conditions, which indicate they are preferred used for the oil displacement and conformance control. Compared to WAC injection, MAC injection had a higher incremental recovery factor of 12.4%. It suggests the acid-resistance microgel would be a good candidate for the conformance control during CO2 flooding process.

Effect of permeability and fractures on oil mobilization of unconventional resources during CO2 EOR using nuclear magnetic resonance

CO2 EOR (enhanced oil recovery) will be one of main technologies of enhanced unconventional resources recovery. Understanding effect of permeability and fractures on the oil mobilization of unconventional resources, i.e. tight oil, is crucial during CO2 EOR process. Exposure experiments based on nuclear magnetic resonance (NMR) were used to study the interaction between CO2 and tight oil reservoirs in Chang 8 layer of Ordos Basin at 40 °C and 12 MPa. Effect of permeability and fractures on oil mobilization of exposure experiments were investigated for the different exposure time. The oil was mobilized from matrix to the surface of matrix and the oil recovery increased as the exposure time increased. The final oil recovery increased as the core permeability increased in these exposure experiments. Exposure area increased to 1.75 times by fractures resulting in that oil was mobilized faster in the initial stage of exposure experiment and the final oil recovery increased to 1.19 times from 28.8 to 34.2%. This study shows the quantitative results of effect of permeability and fractures on oil mobilization of unconventional resources during CO2 EOR, which will support CO2 EOR design in Chang 8 layer of Ordos Basin.

Joint Optimization of Well Completions and Controls for CO2 Use and Storage

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200316, “Joint Optimization of Well Completions and Controls for CO2 Enhanced Oil Recovery and Storage,” by Bailian Chen, SPE, and Rajesh Pawar, Los Alamos National Laboratory, 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. Carbon dioxide (CO2) storage through CO2 enhanced oil recovery (EOR) has been considered an option for larger-scale deployment of CO2 storage because of the economic benefits of oil recovery, 45Q tax credits, and the use of existing infrastructure. The complete paper investigates how optimal reservoir management and operation strategies can be used to optimize both CO2 storage and oil recovery. Results of the authors’ study showed that joint optimization of well completions and well controls can achieve a higher final net present value (NPV) than that obtained from the optimization of well controls only. Introduction In CO2 EOR associated with storage processes, poorly designed well-operating conditions or completions can lead to low oil recovery factors and suboptimal CO2 storage. Co-optimization of oil production and CO2 storage has been recognized as a feasible technique to maximize benefit in terms of oil production and CO2 storage tax credit. To the best of the authors’ knowledge, settings for well completions have not been considered as optimization variables in a CO2 EOR and storage co-optimization process. The objective of this study is to conduct joint optimization of well completions and controls [well rates or bottomhole pressures (BHP)] that maximize life-cycle NPV in CO2 EOR and storage processes and demonstrate the superiority of joint optimization over well-control-only optimization. Optimization Problem In this study, the optimization problem considered is the joint optimization of well completions and well controls for a CO2 EOR and storage process. The mathematical process behind this determination is detailed in the complete paper. The optimization problem was focused on jointly estimating the well completions (i.e., fraction of injection/production well perforations in each reservoir layer) and CO2 injection and oil-production controls that maximize NPV in a CO2 EOR and storage operation. The authors used a newly developed stochastic simplex approximate gradient algorithm to solve the optimization problem. The performance of the joint optimization approach was compared with the performance of the well-control-only optimization approach. In addition, the performance of the co-optimization of CO2 storage and oil-recovery approach was compared with that of the maximization of only-CO2-storage and only-oil-recovery approaches.

Influence factors on CO2 solubility in cycloalkanes and cycloalkane volume expansion: Temperature, pressure and molecular structure

In CO2 enhanced oil recovery process, the interactions between CO2 and oil components are complex since crude oil is a mixture of n-alkanes, cycloalkanes, aromatics, resin, asphaltene and other compounds. To investigate the effects of temperature, pressure and molecular structure on CO2 solubility in cycloalkanes and the resulting cycloalkane volume expansion, the solubility of near critical and supercritical CO2 in cyclopentane (CP), cyclohexane (CH), methylcyclohexane (MCH), methylcyclopentane (MCP) and ethylcyclohexane (ECH) and the volume expansion factor of cycloalkanes at diverse temperature and pressure were measured. It was observed that increasing temperature decreases CO2 solubility, while CO2 solubility increases with pressure increasing. Compared with CP and CH, it's harder for CO2 to dissolve in their methyl or ethyl substituents. For homologues, CO2 solubility decreases with carbon number increasing. The volume expansion factor and solubility have a same variation tendency with temperature, pressure and molecular structure. The experimental results of solubility were correlated with Fornari's model and PR equation of state with the maximum average absolute relative deviation (AARD) of 2.8% and 6.8%, respectively. The excess molar volume of CO2 + cycloalkane mixtures was calculated to be negative and increases with pressure.

Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance

CO2 enhanced oil recovery (EOR) has been carried out in the Bell Creek oil field since 2013. Together with the encouraging oil production results, a considerable quantity of CO2 has also been trapped in the reservoir as a normal part of the EOR process, also referred to as associated storage. Because of the complex geologic conditions in the field, a series of experimental and modeling work have been conducted to better understand the CO2 EOR and associated storage performance in the reservoir. Effects of gas relative permeability hysteresis and solubility on associated CO2 storage performance are thoroughly investigated in this study.A proportion of injected CO2 remains behind through residual and solubility trapping mechanisms when CO2 flows through a reservoir during a CO2 EOR process. Over 50 core plugs were collected from the reservoir to characterize the rock properties. Mineralogical analysis and capillary pressure measurements showed that the mineral composition and pore-size distribution in the reservoir are favorable for residual trapping of CO2. The hysteresis of gas relative permeability was measured to assess the effect of residual trapping on associated CO2 storage using steady-state relative permeability tests and reservoir simulation. The reservoir oil was characterized based on pressure–volume–temperature experiments and Peng–Robinson equation of state modeling, which showed that CO2 solubility in oil is much greater (≥5 times) than in water. Results indicated that depleted oil reservoirs have great potential to store a huge quantity of CO2 associated with EOR operations, as residual oil saturation is 0.3 or greater in most conventional oil reservoirs after water flooding.

Mobility control in carbon dioxide-enhanced oil recovery process using nanoparticle-stabilized foam for carbonate reservoirs

Recent developments in the subject of using silica-nanoparticles (SiNPs) for stabilizing carbon dioxide (CO2)-foam have led to a renewed interest in the enhanced oil recovery (EOR) in oilfields. This study investigates the mobility control in the process of CO2 EOR through unfractured and fractured limestone cores. Toward this aim, laboratory tests were performed by co-injection of CO2 and 12 nm methyl-coated SiNPs solution to generate stable CO2 foam in the cores. In addition, sodium chloride (NaCl) and decane were used to examine the sensitivity of foam generation to salinity and to signify hydrocarbon (HC) phase in the experiments, respectively. The results revealed that SiNPs were able to generate stabilized CO2 foam in both unfractured and fractured limestone cores. A critical shear rate was established in the generation of foam with different conditions in the core-flood experiments. The cores with lower matrix permeability had a lower value of critical shear rate for foam generation. Moreover, the magnitude of apparent viscosity was found to be a crucial factor for mobility control and to obtain an optimum quality of foam. The results indicated that increasing NaCl concentration to 3 wt.% causes a decrease in the value of critical shear rate at applied temperatures. Furthermore, the findings revealed that a real mobility control in CO2 EOR process can only be reached when the generated foam still interacts with HC in the reservoir.

Fluid–fluid interactions in a system of CO 2 , oil, surfactant solution, and brine at high pressures and temperatures – A Malaysian reservoir case

In this study, the interactions of fluids involved in foam assisted CO2 enhanced oil recovery process are studied at the prevailing conditions of a shallow Malaysian (sandstone) oil reservoir (pressure of 70–200 bar, and temperature of 102 °C). The equilibrium CO2 solubility into the reservoir brine, and crude oil, and the effect of foaming agent surfactants on the CO2 solubility into the aqueous phase are measured by using an equilibrium high pressure cell. The interfacial tension (IFT) measurements of gas–liquid and liquid–liquid systems are accomplished by utilizing the axisymmetric drop shape analysis (ADSA) adapted in a pendant drop tensiometer. Two in-house developed surfactants (FomaxII and FomaxVII) are compared with the industrial bench-mark surfactant, alpha olefin sulfonate (AOS), for the structure–property analysis. FomaxVII is a blend of anionic and amphoteric surfactants, with a short-branched chain structure which contains CO2-philic groups. FomaxII is a blend of anionic surfactants, with long, straight-tail hydrocarbon structure. The results show that the dissolution of CO2 into the aqueous phase increased significantly in the presence of 1 wt% surfactants at the reservoir prevailing conditions. A relationship was also observed between the surfactant molecular structure and its effect on the CO2/aqueous phase interface. The results of this study are useful to evaluate the mechanisms of immiscible CO2 flooding as well as to design the foam assisted CO2-EOR applications for the case Malaysian or similar oil reservoir.

An Integrated Framework for Optimizing CO2 Sequestration and Enhanced Oil Recovery

CO2-enhanced oil recovery (CO2-EOR) is a technique for commercially producing oil from depleted reservoirs by injecting CO2 along with water. Because a large portion of the injected CO2 remains in place, CO2-EOR is an option for permanently sequestering CO2. This study develops a generic integrated framework for optimizing CO2 sequestration and enhanced oil recovery based on known parameter distributions for a depleted oil reservoir in Texas. The framework consists of a multiphase reservoir simulator coupled with geologic and statistical models. An integrated simulation of CO2–water–oil flow and reactive transport is conducted, followed by a global sensitivity and response surface analysis, for optimizing the CO2-EOR process. The results indicate that the reservoir permeability, porosity, thickness, and depth are the major intrinsic reservoir parameters that control net CO2 injection/storage and oil/gas recovery rates. The distance between injection and production wells and the sequence of alternating CO2 and water injection are the significant operational parameters for designing a five-spot CO2-EOR pattern that efficiently produces oil while storing CO2. The results from this study provide useful insights for understanding the potential and uncertainty of commercial-scale CO2 sequestrations with a utilization component.

Simulation of CO2-Oil Minimum Miscibility Pressure (MMP) for CO2 Enhanced Oil Recovery (EOR) using Neural Networks

CO2-oil minimum miscibility pressure (MMP) is a key parameter in CO2 enhanced oil recovery (CO2-EOR) process. This work developed a fast and vigorous mathematical method using artificial neural network (ANN) model based on genetic algorithm to predict the CO2-oil MMP which was affected by several factors (i.e. reservoir temperature, the composition of reservoir oil, and the composition of injected gas). The study evaluated the performance of the newly developed ANN-based model by the errors between the predicted values and the target values. It was found that the developed ANN model provided a reliable theoretical basis for CO2 flooding, as well as offered a guidance to the successful implementation of CO2-EOR process.

Residual Oil Saturation Determination for EOR Projects in Means Field, a Mature West Texas Carbonate Field

Summary The technical success of an enhanced oil recovery (EOR) project depends on two main factors: first, the reservoir remaining oil saturation (ROS) after primary and secondary operations, and second, the recovery efficiency of the EOR process in mobilizing the ROS. These two interrelated parameters must be estimated before embarking on a time-consuming and costly process for designing and implementing an EOR process. The oil saturation can vary areally and vertically within the reservoir, and the distribution of the ROS will determine the success of the EOR injectants in mobilizing the remaining oil. There are many methods for determining the oil saturation (Chang et al. 1988; Pathak et al. 1989), and these include core analysis, well-log analysis, log/inject/log (LIL) procedures (Richardson et al. 1973; Reedy 1984), and single-well chemical tracer tests (SWCTT) (Deans and Carlisle 1986). These methods have different depths of investigation and different accuracies, and they all provide valuable information about the distribution of ROS. No single method achieves the best estimate of ROS, and a combination of all these methods is essential in developing a holistic picture of oil saturation and in assessing whether the oil in place (OIP) is large enough to justify the application of an EOR process. As Teletzke et al. (2010) have shown, EOR implementation is a complex process, and a staged, disciplined approach to identifying the key uncertainties and acquiring data for alleviating the uncertainties is essential. The largest uncertainty in some cases is the ROS in the reservoir. This paper presents the results from a fieldwide data acquisition program conducted in a west Texas carbonate reservoir to estimate ROS as part of an EOR project assessment. The Means field in west Texas has been producing for more than the past 75 years, and the producing mechanisms have included primary recovery, secondary waterflooding, and the application of a CO2 EOR process. The Means field is an excellent example of how the productive life and oil recovery can be increased by the application of new technology. The Means story is one of judicious application of appropriate EOR technology to the sustained development of a mature asset. The Means field is currently being evaluated for further expansion of the EOR process, and it was imperative to evaluate the oil saturation in the lower, previously undeveloped zones. This paper briefly outlines the production history, reservoir description, and reservoir management of the Means field, but this paper concentrates on the residual oil zone (ROZ) that underlies the main producing zone (MPZ) and describes a recent data acquisition program to evaluate the oil saturation in the ROZ. We discuss three major methods for evaluating the ROS: core analysis, LIL tests, and SWCTT tests.

CO2 EOR: Nanotechnology for Mobility Control Studied

Technology Update Most domestic conventional oil resources have been produced using primary and secondary recovery techniques, with an average recovery factor estimated at 35%. Additional recovery is possible by using innovative enhanced oil recovery (EOR) techniques. One of these, carbon dioxide (CO2) miscible flooding, is the fastest growing EOR technique in the United States because of the many reservoirs amenable to the process. Current production is almost 310,000 B/D (EOR Survey, Oil and Gas Journal, April 2012), representing approximately 5% of total US oil output. A revised national resource assessment for CO2 EOR conducted by the National Energy Technology Laboratory (NETL) of the United States Department of Energy (DOE) in 2011 indicated that “next generation” CO2 EOR can provide 137 billion bbl of additional, technically recoverable domestic oil, with about half (67 billion bbl) economically recoverable at an oil price of USD 85 per bbl. CO2 EOR has the benefit of sequestering CO2 in oil producing formations and is seen as a critical component of future greenhouse gas management programs. This facet of CO2 EOR produces valuable synergies with the carbon capture, utilization, and storage research program with the DOE’s Office of Fossil Energy. The CO2 EOR process is limited by technology, cost, and the geographic availability of CO2. Technology improvements are needed to increase the displacement efficiency of the process. Not only would advances in displacement efficiency increase oil recovery, it would also lead to the sequestration of additional CO2 volumes. Background The Office of Fossil Energy has historically supported a large number of laboratory and field tests in an effort to improve oil recovery processes. A majority of the projects were related to advanced reservoir characterization, mobility control, and conformance of CO2 flooding. In September 2010, the NETL awarded a number of new research projects to further development of the next generation of CO2 EOR, encouraging applicants to pursue small field or pilot testing. Two of the awarded research projects are related to mobility control in CO2 flooding using nanoparticle technologies. The University of Texas at Austin (UT) is evaluating inexpensive alternative nanoparticles (microscopic particles with at least one dimension less than 100 nm) to provide the large volumes needed for foam stabilization in field-scale CO2 floods. The study entails using low-cost, commercially available “bare” nanoparticles (e.g., silica, fly ash, and iron oxide) and applying a polyethylene glycol (PEG) or other in-house coating to produce low-cost alternatives to develop CO2 foam.

Experimental Investigation of Immiscible Gas Process Performance for Medium Oil

Abstract Immiscible CO2 injection is a potentially viable method of enhanced oil recovery (EOR) for medium oil reservoirs in southwestern Saskatchewan. The relatively high reservoir pressures could result in a large extent of CO2 dissolution, significant oil viscosity reduction and oil swelling. Laboratory corefloods were used to compare the performance of different modes of CO2 injection into a medium-gravity oil system. The following methods were compared: injection of a single CO2 slug chased by water, simultaneous injection of water/CO2, and different water-alternating-gas (WAG) cycles. The results indicate that both a single CO2 slug and the first WAG cycle in a series produced oil very efficiently, possibly owing to good gas/oil contact at the relatively high residual oil saturation at this stage. The simultaneous injection of water/CO2 was not as effective as a single CO2 slug, possibly because the co-injected water shielded the oil from being contacted by the gas. Among the four runs, a coreflood with four WAG cycles recovered the most incremental oil—20.58% initial oil in place (IOIP)—while the co-injection process produced the least (8.91% IOIP). This experimental study suggests that the immiscible CO2 EOR process is viable for medium oil reservoirs with relatively high pressures, and that proper process application is important for maximizing additional oil production. Introduction Miscible/immiscible CO2 flooding is an increasingly popular EOR technique. So far, most of the CO2 miscible/immiscible processes have been applied in light oil reservoirs, and there has been little application in medium oil reservoirs. The in-place resources of medium oils, defined as 20 - 30°API, in Saskatchewan are estimated at up to 1,338 × 106 m3 (8.42 billion barrels)(1). Most of these reservoirs are characterized by thin pay (2 to 10 metres in thickness) and shaly sand, and they have been under production for over four to five decades. The estimated average recovery by conventional waterflood, as listed in Table 1, is only approximately 23% IOIP because this method has generally exhibited early water breakthrough and high water cuts owing to the unfavourably high water-to-oil mobility ratio. By adapting miscible/immiscible CO2 flooding technologies that have matured in light oil applications, the immiscible CO2 process is potentially viable for recovering additional oil from these medium oil reservoirs if we can improve its displacement and sweep efficiency(2).

Effects of Viscous and Capillary Forces on CO2Enhanced Oil Recovery under Reservoir Conditions

Carbon dioxide flooding has been proven to be one of the most effective and viable enhanced oil recovery (EOR) processes for light and medium oil reservoirs. In the past, an extremely large number of laboratory experiments and numerical simulations have been conducted to study the CO2 EOR process. However, the specific effects of viscous and capillary forces on this tertiary oil recovery process are neither thoroughly studied nor well understood yet. In this paper, an experimental study is carried out to examine the detailed effects of viscous and capillary forces on the CO2 EOR under the actual reservoir conditions. First, the equilibrium interfacial tensions between a light crude oil and CO2 are measured at different equilibrium pressures. Second, a series of CO2 coreflood tests are performed to measure the CO2 EOR at different CO2 injection pore volumes, pressures, and rates. Each CO2 coreflood test is terminated after a total of 1.5 pore volume of CO2 is injected. The detailed experimental results show that, in general, the measured equilibrium interfacial tension is reduced with the equilibrium pressure but the measured CO2 EOR at 1.5 pore volume of CO2 is increased with the CO2 injection pressure and rate. Finally, the measured CO2 EOR at 1.5 pore volume versus injection pressure data at different CO2 injection rates are related to the measured equilibrium interfacial tension versus equilibrium pressure data in terms of the complete capillary number, which is defined as the ratio of the viscous force to the capillary force for each CO2 coreflood test. This study shows that if the complete capillary number is in an intermediate range, the CO2 EOR increases quickly with the complete capillary number. Otherwise, the CO2 EOR is lower and remains almost constant for a smaller complete capillary number, or it is higher and remains unchanged for a larger complete capillary number.