Water Alternating Gas Flooding Research Articles

Numerical Investigation on Alkaline-Surfactant-Polymer Alternating CO2 Flooding

For over four decades, carbon dioxide (CO2) has been instrumental in enhancing oil extraction through advanced recovery techniques. One such method, water alternating gas (WAG) injection, while effective, grapples with limitations like gas channeling and gravity segregation. To tackle the aforementioned issues, this paper proposes an upgrade coupling method named alkaline-surfactant-polymer alternating gas (ASPAG). ASP flooding and CO2 are injected alternately into the reservoir to enhance the recovery of the WAG process. The uniqueness of this method lies in the fact that polymers could help profile modification, CO2 would miscible mix with oil, and alkaline surfactant would reduce oil–water interfacial tension (IFT). To analyze the feasibility of ASPAG, a couples model considering both gas flooding and ASP flooding processes is established by using the CMG-STARS (Version 2021) to study the performance of ASPAG and compare the recovery among ASPAG, WAG, and ASP flooding. Our research delved into the ASPAG’s adaptability across reservoirs varying in average permeability, interlayer heterogeneity, formation rhythmicity, and fluid properties. Key findings include that ASPAG surpasses the conventional WAG in sweep and displacement efficiency, elevating oil recovery by 12–17%, and in comparison to ASP, ASPAG bolsters displacement efficiency, leading to a 9–11% increase in oil recovery. The primary flooding mechanism of ASPAG stems from the ASP slug’s ability to diminish the interfacial tension, enhancing the oil and water mobility ratio, which is particularly efficient in medium-high permeability layers. Through sensitivity analysis, ASPAG is best suited for mid-high-permeability reservoirs characterized by low crude oil viscosity and a composite reverse sedimentary rhythm. This study offers invaluable insights into the underlying mechanisms and critical parameters that influence the alkaline-surfactant-polymer alternating gas method’s success for enhanced oil recovery. Furthermore, it unveils an innovative strategy to boost oil recovery in medium-to-high-permeability reservoirs.

Optimization of CO2 EOR and geological sequestration in high-water cut oil reservoirs

In terms of the collaborative optimization of CO2 flooding for Enhanced Oil Recovery (EOR) and CO2 sequestration, previous studies have co-optimized both cumulative oil production and CO2 sequestration by various algorithms. However, these solutions fail to optimize the CO2 injection schemes for high-water cut oil reservoirs. This paper presents an optimization methodology for CO2 flooding and sequestration in high-water cut oil reservoirs. The production optimization was carried out by adjusting the injection and production rate. To solve the proposed objective functions, the simultaneous perturbation stochastic approximation (SPSA) algorithm is applied in this paper, and the CMG-GEM module is utilized to simulate the reservoir production performance. A typical high-water cut reservoir in the Shengli oilfield was used to verify the feasibility of the presented methodology. In this paper, the production performance and net present value (NPV) for continuous gas injection under different water cuts were analyzed. The optimal timing of transforming from water flooding to gas displacement for the high-water cut reservoir was optimized. In addition, the optimal water–gas ratios for Water-Alternating-Gas (WAG) flooding were determined. The sensitivity of NPV to gas injection price and carbon subsidy was analyzed. The results show that when the gas price is 0.178 $/m3 and the carbon subsidy is 0.0169 $/m3, the optimal timing of transforming from water flooding to gas injection should be earlier than the time when the water cut is 0.82. Through the combination of NPV, cumulative oil production rate, and CO2 sequestration volume for WAG flooding, the optimal WAG ratio should be 1:2. The presented method in this paper considers various economic indicators and can optimize CO2 flooding and sequestration in high-water cut oil reservoirs efficiently, which can provide some guidance for the design of CO2 flooding schemes in high-water cut oil reservoirs.

Research on the Timing of WAG Intervention in Low Permeability Reservoir CO2 Flooding Process to Improve CO2 Performance and Enhance Recovery

In low permeability reservoirs, CO2 flooding usually leads to gas channeling, whereby a significant amount of CO2 bypasses the oil-bearing formation and fails to effectively displace oil. Introducing water-alternating-gas (WAG) flooding, utilizing water phase stability-driven processes, serves to suppress gas channeling and enhance oil recovery rates. Implementing WAG flooding, which utilizes water phase stability-driven processes, helps suppress gas channeling and improve oil recovery rates. The timing of implementing WAG flooding is crucial. Initiating WAG flooding prematurely can limit the efficiency of CO2 displacement, while initiating it with delays may result in severe gas channeling, resulting in decreased production and increased environmental risks. Finding the balance point is the challenge. The balance point can effectively control gas channeling without reducing the efficiency of CO2 flooding. In this paper, the timing of WAG flooding in low permeability reservoirs is studied in detail. Firstly, this study conducted experimental research to investigate the CO2 displacement process in both homogeneous and heterogeneous cores. Furthermore, it validated the correlation between the timing of WAG injection and the heterogeneity of the cores. The experimental results indicated the existence of an optimal timing for WAG injection, which is correlated with the degree of heterogeneity. Numerical simulation studies were performed to simulate the characteristics of the light oil–CO2 system using the Peng–Robinson (PR) equation. Furthermore, a history matching analysis was performed to validate the experimental results and investigate the correlation between WAG injection and the degree of heterogeneity. The study concluded that as the degree of heterogeneity increases, initiating WAG injection earlier leads to a more significant suppression of gas channeling, increased water–gas interaction, improved gas–oil contact, and enhanced the synergistic effect of increasing the resistance and pressure of WAG flooding and controlling gas channeling. This finding has significant practical implications, as the optimization of WAG injection timing can enhance oilfield production efficiency.

Pore-Scale Characterization of CO2 Trapping and Oil Displacement in Three-Phase Flow in a Heterogeneous Layered Sandstone

Summary Permeability variation in the vertical direction, a typical sandstone reservoir heterogeneity, can trap a large amount of oil in the low-permeability layer. We performed water-alternating-gas (WAG) injection and CO2 foam flooding on a specially constructed millimeter-sized layered sandstone and investigated fluid distribution using high-resolution X-ray microtomography. Based on the segmented images, CO2 capillary-trapping capacity, oil recovery, Euler number, shaper factor, capillary pressure, and fluid flow conductivity were calculated. Our results show that increasing the number of WAG cycles favored CO2 capillary trapping, and oil recovery was enhanced by the WAG strategy. However, there was still a significant amount of oil trapped in the low-permeability layer. After the WAG injection, the connectivity of the residual oil clusters decreased, the capillary pressure of the oil clusters increased, and oil flow conductivity decreased. This was not conducive to further oil recovery. The subsequent injection of CO2 foam effectively recovered the oil in the low-permeability layer. During the no-injection period, we observed a crossflow phenomenon caused by gravity segregation (the high-permeability layer was located below the low-permeability layer), i.e., oil in the low-permeability layer decreased while oil in the high-permeability layer increased, which is beneficial for subsequent oil production. Furthermore, CO2 moved upward driven by gravity, and although capillary barriers could prevent CO2 from escaping, subsequent water injection was essential to improve the stability of CO2 capillary trapping. This work accurately quantifies the distribution of oil and gas in high- and low-permeability layers, thus providing fundamental data for oil recovery and CO2 trapping in reservoirs with vertical heterogeneity. Although the sample used in the experiment was not natural reservoir rock, our results imply that when the permeability ratio between the two layers is greater than 2, sufficient attention must be paid to the fluid distribution differences caused by this layered heterogeneity. Different displacement strategies, such as WAG and CO2 foam flooding, or gravity differences between oil and gas can be used to enhance oil recovery.

Study on the optimization of injection modes and injection parameters for natural gas in ultra-low permeability reservoir

The heavy gas breakthrough is a serious problem when developing the ultra-low permeability reservoir by natural gas, one available way to deal with this difficulty is to adjust the injection mode, such as the water alternating gas (WAG) injection and the intermittent gas (IG) injection. In order to slow down the gas breakthrough and to enhance oil displacement efficiency in ultra-low permeability reservoir better, the injection modes are compared and the injection parameters are optimized. Based on the ultra-low permeability core experiments, the WAG flooding and the IG flooding after gas fingering are simulated. The displacement efficiencies and the injection differential pressures of these two injection modes are compared. And the suitable injection mode in ultra-low permeability reservoir is confirmed. Furthermore, the experiments with the selected injection mode for several flooding rounds and different flooding periods are made, and the optimized injection parameters are achieved. The results show that both the WAG injection and the IG injection can slow down the gas breakthrough and improve the oil displacement efficiency. The oil displacement efficiency improvement of WAG injection and the IG injection is close, but the pressure of WAG injection is much higher than the one of IG injection. The IG injection can be confirmed as the optimized injection mode in the ultra-low permeability reservoir after gas fingering as the pressure requirement. The economic IG flooding round is 7 at most as the oil displacement efficiency stops improving till the flooding round increases to 7. The optimized IG flooding period after gas breakthrough in ultra-low permeability reservoir is 6 h under the differential pressure of 2MPa limited by the dissolving ability of natural gas.

Evaluation of CO2 storage of water alternating gas flooding using experimental and numerical simulation methods

The potential of water alternating gas (WAG) flooding in CO2 storage was exploited using experimental and numerical simulation methods in this study. Through comparing experiments results of WAG flooding and continuous CO2 flooding, WAG flooding after water flooding enhanced oil recovery by 39.0%, 2.2% higher than that of continuous CO2 flooding. However, the water slugs in WAG displaced part of the previously stored CO2 out the core. Only 13.1% of the injected CO2 was stored through WAG, 13.4% lower than that of continuous CO2 flooding. Then, numerical simulations of WAG and continuous CO2 flooding were conducted at a water flooded oil reservoir. The field-scale case study showed that the number of rounds of alteration from CO2 slug to water slug in WAG, the duration time of each round, and the CO2 injection time in each round were the main factors influencing CO2 storage. Improper design of influencing parameters led to 118,986 tons lower CO2 storage through WAG than continuous CO2 flooding. Finally, to obtain the maximum CO2 storage, surrogate optimization was applied to adjust the proposed influencing factors. The optimization results showed less rounds of alteration and a pure CO2 slug size at the end improved the CO2 swept area in the reservoir for CO2 storage and inhibited the displacement of CO2 by water slug. After optimization of the proposed factors, 391,000 tons of CO2 were stored in the water flooded oil reservoir through WAG flooding, 65,764 tons more than continuous CO2 flooding. This study provides valuable experimental data and theoretical guidance for CO2 storage in water flooded oil reservoirs.

Application of Gene Expression Programming (GEP) in Modeling Hydrocarbon Recovery in WAG Injection Process

Water alternating gas (WAG) injection has been successfully applied as a tertiary recovery technique. Forecasting WAG flooding performance using fast and robust models is of great importance to attain a better understanding of the process, optimize the operational conditions, and avoid high-cost blind tests in laboratory or pilot scales. In this study, we introduce a novel correlation to determine the performance of the near-miscible WAG flooding in strongly water-wet sandstones. We conduct dimensional analysis with Buckingham’s π theorem technique to generate dimensionless numbers using eight key parameters. Seven dimensionless numbers are employed as the input variables of the desired correlation for predicting the recovery factor of a near-miscible WAG injection. A verified mathematical model is used to generate the required training and testing data for the development of the correlation using a gene expression programming (GEP) algorithm. The provided data points are then separated into two subsets: training (67%) to develop the model and testing (33%) to assess the models’ capability. Conducting error analysis, statistical measures and graphical illustrations are provided to assess the effectiveness of the introduced model. The statistical analysis shows that the developed GEP-based correlation can generate target data with high precision such that the training phase leads to R2 = 92.85% and MSE = 1.38 × 10−3 and R2 = 91.93% and MSE = 4.30 × 10−3 are attained for the testing phase. The relative importance of the input dimensionless groups is also determined. According to the sensitivity analysis, decreasing the oil–water capillary number results in a significant reduction in RF in all cycles. Increasing the magnitudes of oil to gas viscosity ratio and oil to water viscosity ratio lowers the RF of each cycle. It is found that oil to gas viscosity ratio has a higher impact on RF value compared to oil to water viscosity ratio due to a higher viscosity gap between the gas and oil phases. It is expected that the GEP, as a fast and reliable tool, will be useful to find vital variables including relative permeability in complex transport phenomena such as three-phase flow in porous media.

Production Characteristics, Evaluation, and Prediction of CO2 Water-Alternating-Gas Flooding in Tight Oil Reservoir

Abstract It is complex and obviously different for the production characteristics of CO2 water-alternating-gas (WAG) flooding in tight reservoir and influenced by quite a few factors. Therefore, the prediction of oil production is a key matter of efficient development of CO2 WAG to be solved in tight reservoirs. In order to cope with this issue, in this paper, the production characteristics of CO2 WAG flooding are analyzed and classified in tight oil reservoir of block A as an example. On this basis, properties of reservoir, fracture factors, and operational factors are taken into account and the sensitivity of the influencing factors is carried out. Subsequently, the gray relation analysis is used to confirm the primary influencing factors. Finally, the evaluated model is established to predict oil production rapidly. The results illustrate that the wells of CO2 WAG flooding in tight reservoirs can be divided into four types of fluid production characteristics. The production is affected by permeability, reservoir thickness, amount of sand entering the ground, amount of liquid entering the ground, gas/water ratio, the injection rate, injection pressure, permeability variation coefficient, water sensitive index, acid sensitive index, and expulsion pressure. And the primary influencing factors are the amount of sand entering the ground, reservoir thickness, and amount of liquid entering the ground. The oil production can be predicted quickly based on the relation between production and comprehensive evaluation factor of production. The average relative error between the predicted results and the actual production is 8%, which proves the reliability and accuracy of this method.

Numerical simulation of water alternating gas flooding (WAG) using CO2 for high-salt argillaceous dolomite reservoir considering the impact of stress sensitivity and threshold pressure gradient

Numerical simulation of water alternating gas flooding (WAG) using CO2 for high-salt argillaceous dolomite reservoir considering the impact of stress sensitivity and threshold pressure gradient

Experimental investigation of immiscible water-alternating-gas injection in ultra-high water-cut stage reservoir

Water-alternating-gas (WAG) injection is recommended as a means of improving gas mobility control. This paper describes a series of coreflood tests conducted to investigate the potential for continuous gas injection and WAG injection in ultra-high water-cut saline reservoirs. The mechanisms of immiscible water-alternating-nitrogen injection on residual oil distribution are analyzed, and pore-scale analysis is conducted. The effect of injection parameters on residual oil distribution and recovery efficiency is also evaluated. Coreflood results show that tertiary oil recovery efficiency is significantly higher using WAG injection than continuous gas injection during the ultra-high water-cut period. Pore-scale visualization illustrates the movement of gas through the waterflooded channels into the pore space previously occupied by water and residual oil, which then becomes trapped. Injected gas breaks the force balance of microscopic residual oil and reduces residual oil saturation. This mobilizes the displaced/collected residual oil into large waterfilled pores and blocks several water channels. WAG flooding can decrease free-gas saturation and increase trapped-gas saturation significantly, resulting in decreased relative permeabilities of gas and water. The experimental results indicate that appropriate WAG design parameters could enhance recovery by 15.62% when the injected pore volume of water and gas in the cycle is 0.3 PV at a gas/water injection ratio of 2:1. The results from this study will allow researchers and reservoir engineers to understand and implement immiscible WAG injection as an enhanced oil recovery method in ultra-high water-cut stage reservoirs. Cited as: Kong, D., Gao, Y., Sarma, H., Li, Y., Guo, H., Zhu, W. Experimental investigation of immiscible water-alternating-gas injection in ultra-high water-cut stage reservoir. Advances in Geo-Energy Research, 2021, 5(2): 139-152, doi: 10.46690/ager.2021.02.04

Experimental analysis of hybrid low salinity water alternating gas injection and the underlying mechanisms in carbonates

Abstract Enhanced oil recovery methods have been widely used around the world to improve ultimate hydrocarbon recovery. Among them, low salinity water flooding has gained attention as a practical enhanced oil recovery method which modifies the rock wettability to a more hydrophilic state. Besides, gas, mainly C O 2 , injection by means of water alternating gas process is proved to improve un-swept oil recovery due to the mobility control of displacing fluids. Hence, the mutual application of these two enhanced oil recovery techniques, as low salinity water alternating gas) injection, benefits the driving mechanisms subjected by both methods resulting in higher oil production. In this study, a series of experiments including contact angle measurements, gas solubility in brine, emulsion formation, and coreflooding were conducted. Wettability alteration of the carbonate samples towards the more water wet state was observed by the contact angle measurements for diluted sea waters which shows salinity of the injected water can play a significant role in the enhancement of ultimate oil recovery. 10 times diluted brine was found to be the optimum one which changed the contact angle for 52°. It shows that there is an optimum concentration for different CBR systems under which the available PDIs are not sufficient to alter the rock wettability to a greater extent. The presence of gas phases favorably improved the wettability modification. The successful performance of 10 times diluted brine was also confirmed by emulsion formation tests. For this case, the number of the generated water in oil emulsion droplets was 1.54 times that of SW. Stable emulsions enhance the oil displacement through provoking wettability alteration by low salinity water and mobilizing the residual oil via the osmotic effect. Finally, a 10.8% incremental oil recovery by low salinity water alternating gas flooding verified the synergistic effects of this method regarding enhanced oil recovery.

Monitoring of Flooding Characteristics with Different Methane Gas Injection Methods in Low-Permeability Heterogeneous Cores

Methane gas injected into reservoirs can greatly enhance oil recovery and has been widely used. However, continuous methane gas flooding has a deleterious effect on oil recovery enhancement and easily causes gas channeling in low-permeability heterogeneous reservoirs because of the low viscosity and high mobility of methane gas. This study consists of comprehensive experimental research that combines physical simulation and saturation dynamic monitoring technologies with a component analysis of produced oil to investigate the oil recovery and mobility control effects in low-permeability heterogeneous cores. First, solubility, foaming ability, and stability are used as evaluation indicators. The results show that an alcohol ethoxylate foaming agent at 1.5 wt % is suitable for reservoirs, based on the Waring blender and Ross–Miles methods combined with microscopic observation. Second, methods of methane gas with water alternating gas (WAG) injection, advanced cyclic water alternating gas (ACWAG) injection, and methane nonionic foam injection are performed on three kinds of low-permeability heterogeneous cores under reservoir conditions. The experimental results show that methane nonionic foam flooding can significantly improve oil recovery by 11–18%. Third, the residual oil saturation in the core is tested by saturation dynamic monitoring. This finding indicates that methane nonionic foam flooding reduces mobility control, effectively restrains gas channeling, increases sweep efficiency, and has the highest permeability plugging rate (82–90%) for high-permeability channels. In the stage of methane WAG and ACWAG flooding, methane gas can increase the C12–C24 components in the produced oil by 0.3–0.9%. ACWAG injection can improve the stage of no water-cut oil recovery compared with conventional WAG injection.

Experimental and simulation investigations of carbon storage associated with CO2 EOR in low-permeability reservoir

Abstract CO2 based water-alternating-gas (WAG) injection and surfactant-alternating-gas (SAG) injection have shown to be two effective and practical methods to enhance oil recovery, which, also achieves carbon sequestration as well. In this study, a combination of experiment and numerical simulation was used to evaluate the performances of WAG and SAG flooding in low-permeability reservoir. Core drainage experiments were conducted, and NMR equipment was used to reveal the microscopic fluid distribution and explain the macroscale drainage results for each of the enhancing oil recovery (EOR) technique. In addition, the two EOR techniques were further evaluated in a realistic low-permeability reservoir, Yushulin oil field from Songliao Basin, China. The results show that, gas phase can lower gas-oil interfacial tension (IFT) in WAG process which contributes the oil displacement from smaller pores. Besides that, the surfactant in SAG process can also improve the oil displacement efficiency in larger pores due to the generation of foams. The optimal WAG and SAG ratios (1.25–1.5) in the realistic reservoir are all higher than the typical ratio (equal to 1) from the core experimental results and that in the most conventional oilfields due to the higher heterogeneity in low-permeability reservoir with easier gas breakthrough. Furthermore, the CO2 utilization efficiency for SAG is higher than WAG.

Experimental Study on Gas Breakthrough Prevention by Flue Gas Drive

The heterogeneity of glutenite reservoir is serious, and breakthrough is easy to occur in the process of water drive and gas drive, which reduces the sweep efficiency. The serious vertical heterogeneity in the H well area of Xinjiang oilfield led to the rapid gas breakthrough during gas injection test. Water alternating gas flooding and foam profile control are often used to seal breakthrough. In this paper, based on the actual reservoir characteristics, vertical heterogeneous planar model is made for flooding experiment. The experimental results show that after gas breakthrough caused by water alternating gas flooding, the flue gas foam can effectively block the high permeability layer and develop the low permeability layer, improve the sweep efficiency and recovery percent, and provide reference for the development adjustment of actual reservoir after gas breakthrough.

Simulation Optimization of Water Alternating Gas (WAG) Process under Operational Constraints: A Case Study in the Persian Gulf

Optimizing the efficiency of WAG flooding projects can guarantee the success of these projects. Many operational constraints can indirectly affect the flooding efficiency. Their effects is not normally considered during routine optimizations. The main aim of this study is to find the influence of these constraints (e.g., maximum water-cut, maximum GOR, and minimum BHP during WAG process). Implementing a reservoir simulator coupled with a simulating-annealing (SA) enables us to discover the effects of these constraints during simulation optimizations. The developed optimizer is applied into a case study from an Iranian formation located in the Persian Gulf. The recovery factor of WAG flooding is compared with that of the conventional waterflooding and gas injection. Moreover, the optimization of individual and simultaneous WAG parameters are analyzed. Results indicate that a) operational constraints not also can alter the production mechanism but also they directly affect the ultimate recovery factor; b) the recovery factor of simultaneous optimization of all WAG parameters is higher than that of individual parameter optimization; c) irrespective to the manner of parameter optimization, WAG ratio (or the volume fraction of injected water to gas) remains almost constant during all optimizations, showing the influence of this parameter during WAG flooding scenarios.

Insight investigation of miscible SCCO2 Water Alternating Gas (WAG) injection performance in heterogeneous sandstone reservoirs

Abstract In this manuscript, we present the results of a systematic approach to investigate the impact of core scale heterogeneity on the efficiency of miscible CO2 water-alternating-gas (WAG) flooding performance. Both vertical (by layering two axially-cut half plugs with differing permeability) and horizontal (stacking two smaller core samples with differing permeability in series) heterogeneities are explored. In the layered or vertically heterogeneous sample, the permeability ratio (PR) defines the ratio between the permeability values of each half plug. Our special sample construction technique using either a thin impermeable Teflon sheet to prevent flow communication or a thin tissue to promote flow communication has enabled us to investigate the effect of crossflow between half plug on the performance of the WAG flood. For the stacked composite or the horizontally heterogeneous core samples, short cylindrical core segments were used each with a different permeability value. We have also investigated the effect of the EOR injection mode (i.e. secondary vs. tertiary) on our results. For this study, core flooding experiments were performed using n-C10, brine and CO2 at a temperature of 343 K and a pressure of 12.4 MPa. The results obtained for homogeneous, layered and composite samples indicate that CO2 WAG flood performs better in all cases and achieves the highest recovery factor (RF) when conducted under the secondary mode (e.g. homogeneous: 93.4%, layered: 74.0%, and composite: 90.9%) compared with the tertiary mode (e.g. homogeneous: 74.2%, layered: 64.1%, and composite: 71.3%). For the layered samples, it was found that the oil recovery decreases noticeably with an increase in the permeability ratio (PR). For instance, RFs of 93.4%, 90.1%, 78.8%, and 74.0% correspond to PRs of 1, 2.5, 5, and 12.5, respectively. In contrast to our previous findings with continuous CO2 flooding which showed that crossflow enhances recovery in layered samples, for this study using WAG, crossflow was found to negatively affect the RF. Such an outcome may be attributed to the conformance control achieved by WAG flooding which would be more pronounced in the case of non-communication layers (i.e. no cross flow). In other words, the higher oil recovery of WAG flooding in a non-communicating system may be due to the dominance of viscous forces and, to a lesser extent, the vanishing effect of gravity forces that tend to reduce sweep efficiency. The effect of composite heterogeneity on the RF was also investigated with the results showing that the permeability sequence along the length of a composite sample has a noticeable but more subtle impact on RF.

A new experimental method for measuring the three-phase relative permeability of oil, gas, and water

Abstract For tertiary oil recovery, the gas drive is often implemented after water flooding. The three-phase flow phenomenon of oil, gas, and water exists during the process of gas injection. The three-phase relative permeability should be measured to further study the flow characteristics of oil, gas, and water in porous media. In this work, the steady-state flow method is adopted to establish a combined experimental method based on the principle of relationship between resistivity and water saturation, and the principle of on-line CT scanning is used to measure the three-phase relative permeability. The relative permeability of oil, gas, and water is measured under different saturation histories, including the water alternating gas flooding, in which water saturation decreases, oil saturation decreases, and gas saturation increases, as well as gas alternating water flooding, in which water saturation increases, oil saturation decreases, and gas saturation decreases. The experimental results show that in a water-wet core, the relative permeability of water is a function of its own saturation, and its isoperms are straight lines. The relative permeability of oil and gas phase is affected by their saturation and other phase saturations. In an oil-wet core, the isoperms of oil, water, and gas are convex to the point of 100% their own saturation, which means the relative permeability of oil, gas and water depend on all the three phase saturations. The saturation histories influence the isoperms of the three phases differently. Compared with the two-phase flow, the three-phase flow is more complex. This new experiment provides an approach and theory for the study of three-phase seepage laws in the gas drive.

Evaluation of recycle gas injection on CO2 enhanced oil recovery and associated storage performance

Abstract An enhanced oil recovery (EOR) technique comprising the alternate injection of gas (CO2) and water, commonly referred to as water alternating gas (WAG) flooding, is currently ongoing at an oil field in the northeastern Powder River Basin (PRB), where 4 million barrels (MMbbl) of oil were produced between May 2013 and September 2017. During WAG flooding, a large amount of CO2, which contains some impurities, is produced at the surface with the recovered oil and reinjected into the reservoir to minimize the amount of purchased CO2. The concentration of these impurities in the CO2, which are dominated by CH4, is a key parameter in the design of miscible CO2 flooding of an oil reservoir and in the quantitative assessment of the associated storage of CO2 that occurs in the reservoir. For a given oil and reservoir temperature, the CO2–oil minimum miscibility pressure (MMP) is strongly and adversely affected by the presence of CH4, the concentration of which varies with time and operational conditions, such as injection pressure, flooding pattern, and injection scheme (i.e., continuous CO2 injection or WAG). To capture the full range of potential variation in the MMP caused by the presence of CH4, a series of laboratory experiments were conducted to determine CO2–oil MMP with different mole percentages of CH4 in the CO2. All of the experiments were performed at reservoir temperature (108 °F) using the VIT (vanishing interfacial tension) method. Results showed that MMP increases from 1403 to 4085 psi as the mole percentage of CH4 in the CO2 increases from 0% to 100%. To assess the impact of this variation in MMP on the oil recovery performance in the field, a history-matched, compositional reservoir simulation model was used to predict the oil production performance for a WAG flood using CO2 that contained a range of CH4 concentrations. The reservoir simulations examined the effects of permeability heterogeneity, fluid crossflow, and phase behavior on the oil displacement performance in three-dimensional space over time. Simulation results indicated that CO2 floods using a limited range of CO2–CH4 mixtures could still maintain multiple-contact miscibility and result in effective EOR. In addition, the ability to reinject produced CO2–CH4 mixtures as is, without removal of the CH4, ensured that this approach to EOR would continue to be cost-effective.

Using Polymer Alternating Gas to Enhance Oil Recovery in Heavy Oil

CO2 has been used to recover oil for more than 40 years. Currently, about 43% of EOR production in U.S. is from CO2 flooding. CO2 flooding is a well-established EOR technique, but its density and viscosity nature are challenges for CO2 projects. Low density (0.5 to 0.8 g/cm3) causes gas to rise upward in reservoirs and bypass many lower portions of the reservoir. Low viscosity (0.02 to 0.08 cp) leads to poor volumetric sweep efficiency. So water-alternating-gas (WAG) method was used to control the mobility of CO2 and improve sweep efficiency. However, WAG process has some other problems in heavy oil reservoir, such as poor mobility ratio and gravity overriding. To examine the applicability of carbon dioxide to recover viscous oil from highly heterogeneous reservoirs, this study suggests a new EOR method--polymer-alternating gas (PAG) process. The process involves a combination of polymer flooding and CO2 injection. To confirm the effectiveness of PAG process in heavy oils, a reservoir model from Liaohe Oilfield is used to compare the technical and economic performance among PAG, WAG and polymer flooding. Simulation results show that PAG method would increase oil recovery over 10% compared with other EOR methods and PAG would be economically success based on assumption in this study. This study is the first to apply PAG to enhance oil recovery in heavy oil reservoir with highly heterogeneous. Besides, this paper provides detailed discussions and comparison about PAG with other EOR methods in this heavy oil reservoir.

Long-core experimental study of different displacement modes on fractured-vuggy carbonate reservoirs

It is difficult to utilize real fractured–vuggy carbonate cores to conduct long-core displacement experiments due to the special structures of fractured and vuggy. Aiming to not affect the porosity and permeability of the original core structure, a special filling method on the sunken space of the core surface was created to meet the requirements of long-core experiments. Long-core experiments of depletion drive, water flooding, gas drive, and water alternating gas (WAG) drive were performed to simulate the actual conditions of one-dimension oil reservoir and systematically study the influence of different development approaches on the recovery of vuggy carbonate reservoirs. Results show that the optimal conversion pressure of water flooding is between 80% bubble point and bubble point pressure. In the high-pressure and high water-cut stage, the development effect of gas–water alternative drive becomes significant, it can effectively reduce water cut and improve oil recovery. The most suitable and effective displacement mode is adopted depletion drive first and converts water flooding when the pressure decreases between 80% bubble point and bubble point pressure. When the water cut approximately reaches 80%, then WAG flooding is performed. The experiments provide data and technical support for the rational development of vuggy carbonate reservoirs.