Water Alternating Gas Process 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.

Study on SiO2 Nanofluid Alternating CO2 Enhanced Oil Recovery in Low-Permeability Sandstone Reservoirs

Study on SiO2 Nanofluid Alternating CO2 Enhanced Oil Recovery in Low-Permeability Sandstone Reservoirs

Computational fluid dynamic simulation of multi-phase flow in fractured porous media during water-alternating-gas injection process

Naturally fractured reservoirs (NFRs) are among major oil and gas producing reservoirs that are commonly targeted for various enhanced oil recovery (EOR) techniques, particularly water-alternating-gas (WAG) injection. Production from NFRs is complicated due to the flow communication between the matrix and fractures in such porous media. The implementation of WAG injection in NFRs features inherent complexities not only related to the three-phase flow, saturation history, and cycle-dependent hysteresis of the individual phases, but also the fracture-matrix communication, fingering, and early breakthrough of the injected phases particularly during gas injection processes. This paper provides the key results on the computational fluid dynamics (CFD) simulation of WAG injection in a fractured system. We evaluate the impacts of hysteresis, fracture characteristics (aperture, orientation, and fracture density in the network), and the three-phase relative permeability of available phases during the WAG injection. The CFD model simulates an immiscible WAG injection, and the CFD results are compared to the experimental data in a strongly water-wet sand-pack. Similar to the experiments, we simulate Maroon crude as the oil phase, and synthetic brine, and pure CO2 at 100 °C and atmospheric outlet pressure. The CFD results are in excellent agreement with the experimental data. The absolute relative error is less than 12% for predicting the ultimate oil recovery factors (RFs) in water flooding (WF) and gas injection (GI) cycles. Including the three-phase hysteresis significantly increases the accuracy of the WAG process simulation, while excluding hysteresis underestimates the instantaneous RFs at each cycle (especially GI cycles) and the ultimate RF by 4%. We also analyze the fracture pattern and configuration; adding fractures to the system increases the system effective permeability, leading to more contact between the injecting fluid and trapped oil, and consequently higher oil recovery. Connecting a vertical fracture to the horizontal fracture enhances the recovery through strong connections between the vertical and horizontal blocks. An increase in the fracture aperture from 0.5 to 3 mm increases the RF from 50% to 59%. The fracture inclination angle from 30° to 90° increases the ultimate RF by only 2%. Including gravity forces in vertical model orientation results in overall improvement in RF through engaging both matrix and fracture media in all cycles. As the permeability contrast between the matrix and fracture media decreases, the flow communication between the two regions increases, which improves the recovery performance of the WAG process. Our simulation results can help to further understand the effect of various parameters and operational conditions on WAG injection performance in fractured reservoirs.

Impact of proper design of operating parameters on the performance of CO2-Water Alternating Gas (CO2-WAG) injection: a simulation study

Water-alternating-gas (WAG) is one of the enhanced oil recovery (EOR) methods in which both water and gas are injected into the reservoir. Among different WAG processes, CO2-WAG is one the most environmental-friendly and efficient methods. The low minimum miscibility pressure (MMP) of CO2 turns this gas to a special candidate for EOR applications. In this study, impact of anisotropy coefficient and operating parameters including injection rate, pattern size and slug size on performance of this process was investigated through 360 different cases of numerical simulation. Also, a modification to the currently used dimensionless aspect ratio was proposed to enhance the accuracy of predicting oil recovery factor during WAG process. Generally, it was concluded that regardless of anisotropy coefficient, oil recovery factor increases as the ratio of well distance to reservoir thickness increases. For instance, for anisotropy coefficient of 0.1, the average recovery factor for well distance to reservoir thickness of 10 and 100 was 68% and 74%, respectively. In addition, it was concluded that the performance of WAG process is logarithmically correlated with anisotropy coefficient and well distance to reservoir thickness. Finally, it was concluded that the proposed modification for the dimensionless aspect ratio considerably increases its accuracy.

Water alternating gas (WAG) recovery process evaluation through simulation for a giant middle-eastern carbonate reservoir

The objectives of this article it to present a water alternating gas (WAG) process evaluation methodology for a giant middle eastern carbonate reservoir. The methodology involves enhanced oil recovery through an immiscible hydrocarbon water alternating gas (WAG) injection method. Although water alternating gas injection is a proven enhance oil recovery technique and has been around for some time now, only a limited published literature is available on complete evaluation of immiscible WAG process in field application. This article aims to bridge the gap by presenting a detailed study of immiscible water alternating gas evaluation process. In this article a complete methodology for evaluating a water alternating gas injection recovery technique is presented. It includes optimization of WAG cycle length, WAG ratio, production constraints, injected gas compositions, WAG duration, and WAG slug size. The work presented in this article could aid oil field operators to understand the impact of different parameters on immiscible WAG injection process and potentially help them to optimize production from their fields.

Optimization of WAG in real geological field using rigorous soft computing techniques and nature-inspired algorithms

To meet the ever-increasing global energy demands, it is more necessary than ever to ensure increments in the recovery factors (RF) associated with oil reservoirs. Owing to this challenge, enhanced oil recovery (EOR) techniques are increasingly gaining more significance as robust strategies for producing more oil volumes from mature reservoirs. Water alternating gas (WAG) injection is an EOR method intended at improving the microscopic and macroscopic displacement efficiencies. To handle and implement successfully this technique, it is of vital importance to optimize its operating parameters. This study targeted at implementing robust proxy paradigms for investigating the suitable design parameters of a WAG project applied to real field data from “Gullfaks” in the North Sea. The proxy models aimed at reducing significantly the rum-time related to the commercial simulators without scarifying the accuracy. To this end, machine learning (ML) approaches, including multi-layer perceptron (MLP) and radial basis function neural network (RBFNN) were implemented for estimating the needed parameters for the formulated optimization problem. To improve the reliability of these ML methods, they were evolved using optimization algorithms, namely Levenberg–Marquardt (LM) for MLP, and ant colony optimization (ACO) and grey wolf optimization (GWO) for RBFNN. The performance analysis of the proxy models revealed that MLP-LMA has better prediction ability than the other two proxy paradigms. In this context, the highest average absolute relative deviation noticed per runs by MLP-LMA was lower than 3.60%. Besides, the best-implemented proxy was coupled with ACO and GWO for resolving the studied WAG optimization problem. The findings revealed that the suggested proxies are cheap, accurate, and practical in emulating the performance of numerical reservoir model. In addition, the results demonstrated the effectiveness of ACO and GWO in optimizing the parameters of WAG process for the real field data used in this study.

Fast and Cost-Effective Mathematical Models for Hydrocarbon-Immiscible Water Alternating Gas Incremental Recovery Factor Prediction.

Predicting the incremental recovery factor with an enhanced oil recovery (EOR) technique is a very crucial task. It requires a significant investment and expert knowledge to evaluate the EOR incremental recovery factor, design a pilot, and upscale pilot result. Water-alternating-gas (WAG) injection is one of the proven EOR technologies, with an incremental recovery factor typically ranging from 5 to 10%. The current approach of evaluating the WAG process, using reservoir modeling, is a very time-consuming and costly task. The objective of this research is to develop a fast and cost-effective mathematical model for evaluating hydrocarbon-immiscible WAG (HC-IWAG) incremental recovery factor for medium-to-light oil in undersaturated reservoirs, designing WAG pilots, and upscaling pilot results. This integrated research involved WAG literature review, WAG modeling, and selected machine learning techniques. The selected machine learning techniques are stepwise regression and group method of data handling. First, the important parameters for the prediction of the WAG incremental recovery factor were selected. This includes reservoir properties, rock and fluid properties, and WAG injection scheme. Second, an extensive WAG and waterflood modeling was carried out involving more than a thousand reservoir models. Third, WAG incremental recovery factor mathematical predictive models were developed and tested, using the group method of data handling and stepwise regression techniques. HC-IWAG incremental recovery factor mathematical models were developed with a coefficient of determination of about 0.75, using 13 predictors. The developed WAG predictive models are interpretable and user-friendly mathematical formulas. These developed models will help the subsurface teams in a variety of ways. They can be used to identify the best candidates for WAG injection, evaluate and optimize the WAG process, help design successful WAG pilots, and facilitate the upscaling of WAG pilot results to full-field scale. All this can be accomplished in a short time at a low cost and with reasonable accuracy.

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

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 CO2, 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.

Experimental investigation of CO2 in continuous and water alternating gas injection

CO2 injection and water-alternating-gas injection are EOR methods for improving oil recovery. This paper shows Water alternating gas (WAG) and continuous gas injection experiments with CO2 in secondary recovery. Experiments were performed in sand-packed-model. The continuous gas injection experiments were conducted at 3800, 4200, 4600 and 5000 psi, then two WAG experiments was completed at 3800 psi. Also temperature was 190 °F (the reservoir temperature) in all experiments. Six tests were conducted to investigate continuous CO2 and WAG injection under the reservoir condition. In the first test, 1.2 PV (pore volume) of CO2 was injected into sand-packed-model at pressure of 3800 psi and temperature of 190 °F. Amount 1.2 PV of CO2 was injected into sand-packed-model at 4200 psi in the test 2. In third one, 1.2 PV of CO2 was injected at 4600 psi and 1.2 of PV CO2 was injected at 5000 psi in forth one. Water alternating gas injection experiments with CO2 were including two tests. In the first one, 0.3 PV of CO2 and 0.9 PV of brine were injected consecutively into model. In the second one, 0.3 PV of CO2 and 0.3 PV of brine were injected respectively into model and this test was completed in two cycles. The results indicate that increase of injection pressure enhances oil recovery in continuous CO2 injection and increase of injected CO2 increases oil recovery in WAG process. Also WAG injection increases oil recovery more than CO2 continuous injection.

Evaluation of the economic efficiency of the WAG process based on experimental data for one of the domestic oil fields

The challenge related to the need for an increase of the recovery factor concerns numerous mature, also domestic oilfields, including the most important ones – located in Main Dolomite formation. Satisfactory recovery factor can be ensured only through applying an effective enhanced oil recovery method (EOR). Water Alternating Gas (WAG), as one of the most effective EOR methods, has been tested in conditions characteristic for domestic deposits in carbonate formations. The results of experimental and simulation works carried out at the Oil and Gas Institute (INiG – PIB) indicate significant potential for the application of the WAG method in domestic conditions. An unquestionable advantage of the WAG method is the opportunity to utilize various types of gases, including flue/waste gas or low-energy natural gas. This issue deserves special attention because, as we know, the reduction in the emissions of gases involved in global warming is critical for the future of our planet. Their utilization in EOR methods, coupled with their safe storage in geological structures, constitute measures that reduce the environmental footprint of produced oil. In the article, based on the of experimental results, a simplified economic analysis of the utilization of four gas types in the form of acidic gases (carbon dioxide and its mixture with hydrogen sulfide) and natural gases (high and very high nitrogen content) in the WAG method was carried out. That allowed to identify the most economically optimal variants of the WAG method. The results showed that despite significantly lower effectiveness of nitrogen-rich natural gases in enhancing oil recovery (in the context of recovery factor), their application might be justified in economic terms. The selection of the optimal variant for enhancing recovery is strongly influenced by the assumed (current) cost of acquiring the injected media, and of course by the current (and forecasted) crude oil price.

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

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.

Impact of Low Salinity Water Injection on CO2 Storage and Oil Recovery for Improved CO2 Utilization

CO2 utilization for oil recovery applications is often impacted by the challenges such as viscous fingering and its premature breakthrough. Injection of slugs of water-alternating-gas (WAG) generally aims to overcome these challenges though the control of CO2 mobility. Moreover, the oil recovery potential of WAG is largely dependent on the injection water salinity and the subsequent CO2 dissolution and storage. Therefore, the effect of varying salinity (0–4 wt% NaCl) on CO2 loading capacity of water is investigated in this study, at two test temperatures of 323 K and 363 K and three confining pressures of 4, 8, and 12 bar, and subsequently, the flooding experiments were performed to find the low salinity (LS)-WAG process suitability in oil recovery applications from porous sandstone rocks. The inclusion of salt was found to significantly affect CO2 loading capacity of water. At higher NaCl concentration (4 wt%), CO2 loading decreased by 50% as demonstrated by absorption kinetic study. LS-WAG suggested maximum oil recovery 55–58% of original oil in place for water salinity of 2 wt% NaCl at both the test temperatures. Increment in pressure had a positive impact on CO2 loading while increasing temperature showed reverse behavior. As a result of LS in WAG and kinetic adsorption study, it is anticipated that the reduction in water salinity is a favorable factor in the CO2 storage and oil recovery performance of CO2 injection. The instance of CO2 injection was also varied for LS-WAG process and its effect on oil recovery from sand-packs was reported. Oil recovery results demonstrated that WAG was similarly effective in all the stages of the injection cycle as long as water salinity remained lower than 2 wt% NaCl. Based on the findings in this study, it is recommended to implement the WAG in conjunction with low salinity water (LSW) in moderate saline conditions, which is of key importance for various applications where water salinity differs on a large scale.

Experimental and simulation studies for optimization of water–alternating-gas (CO2) flooding for enhanced oil recovery

The paper deals with the screening of injection of water-alternating-gas (WAG) to tap the residual oil saturation left in the reservoir by over and above the water flooding. The detailed mineralogical composition has been studied by X-ray diffraction (XRD) method along with the petrophysical parameters to see their impacts of flow on Himmatnagar (India) sandstone. Saturates, aromatics, resins, and asphaltenes present in the crude oil were determined by ASTM procedure. Minimum miscibility pressure of CO2 with the crude oil was determined and it has been found at 1254 psi based on thermodynamic software. Different WAG ratios of 1:1, 1.5:1 and 2:1 have been applied for EOR during studies. Simulation on water injection followed by CO2 has been performed for investigation of the WAG process efficiency. A total 2 cycles of WAG injection was done with water flow rate of 1 ml/min and gas injection pressure around 1250 psi to achieve the better contact miscibility. The experimental data has been generated, compiled and interpreted during different cycles of WAG process. It was observed that WAG ratio 2:1 exhibits highest additional oil recovery around 34% of original oil in place. Increasing WAG ratio yields more additional oil recovery.

Robust optimization of CO2 sequestration through a water alternating gas process under geological uncertainties in Cuu Long Basin, Vietnam

This study presents a robust optimization workflow to determine the optimal water alternating gas (WAG) process for CO2 sequestration in a heterogeneous fluvial sandstone reservoir. As depicted in this study, WAG injection could enhance CO2 residual and solubility trapping based on an integrated modeling workflow. First, continuous CO2 injection and WAG were compared to demonstrate the efficiency of the WAG process for CO2 trapping enhancement. To achieve this while highlighting the impact of reservoir heterogeneity, 200 geological realizations were generated considering a wide range of plausible geological conditions. The ranking of these realizations was performed by quantifying the CO2 cumulative injection (P10, P50, and P90 realizations) that represent the overall geological uncertainties. Then, an innovative robust workflow was used Artificial Intelligence optimizer to determine the optimal solution for CO2 trapping. For comparison, a nominal optimization workflow of P50 realization was also conducted. The proposed robust optimization workflow resulted in higher CO2 trapping than the nominal optimization workflow. Thus, this study demonstrates a fast and reliable workflow that can accurately represent for optimization the cycle length injection in the WAG process under geological uncertainties.

Experimental investigation on precipitation damage during water alternating flue gas injection

Water Alternating Gas (WAG) approach can improve the efficiency of gas flooding. However, the precipitation damage that is induced by the gas injection may be inevitable. The precipitation pressure point test of gas injection, and the WAG parallel double-tube long-core flooding experiment under different injection conditions were systematically performed to obtain the optimum injection parameters. The variations of petrophysical properties were caused by precipitation, and its morphology was also determined by centrifugal capillary force and environmental scanning electron microscope. The precipitation pressure rised with the increase of the amount of gas injection, generally 2.0 MPa ~ 3.0 MPa higher than the bubble point pressure (Pb), and it was confirmed by X-ray energy spectrum and scanning electron microscope that the precipitation was mainly asphaltene. The optimum injection parameters for WAG were Gas–Water Ratio (GWR) of 1:1 and slug size of 0.1 HydroCarbon Pore Volume (HCPV), which benefited the recovery of low-permeability and high-permeability pipe by additional recovery of 28.5% and 17.4% respectively, while WAG process enhanced the total oil recovery by 23.4%. The pore volume and median radius of capillary pressure of all cores were both reduced with more obvious effects on conglomerate. Combined with the results of sediment saturation, it also showed the poorer the physical properties of the cores, the severer the influence of the precipitation. Overall, the WAG could greatly improve the recovery but the influence of precipitation must be considered.

Mathematical modeling and simulation of water-alternating-gas (WAG) process by incorporating capillary pressure and hysteresis effects

Mathematical modeling and simulation of three-phase flow in porous media involves complexities related to the three-phase relative permeability, capillary pressure, and hysteresis effects that are cycle-dependent. Extensive theoretical studies are available in the literature, simulating immiscible and miscible water-alternating-gas (WAG) processes; however, the simulation of recovery behaviors and mechanisms of near-miscible WAG is overlooked. Also, a majority of WAG simulation studies lack the cycle-dependent three-phase hysteresis that appears in the relative permeability and capillary pressure models. In this paper, we study a three-phase flow modeling of near-miscible WAG process for EOR implication, using implicit pressure explicit saturation (IMPES) method. The mathematical model simulates a WAG case study in a strongly water-wet Berea sandstone core, using synthetic oil and brine at 38 °C and 12.7 MPa. Three cycles of water flooding (WF) and gas injection (GI) are used in the WAG operation. The recovery data from our mathematical model is in excellent agreement with the corresponding experimental data. The absolute relative error is less than 1.7%, while estimating the ultimate oil recovery factor in the WF and GI stages of all three cycles. We also study the effects of influential variables such as injection rate, WAG ratio, slug size, crude oil viscosity, and core absolute permeability on the WAG performance. The WAG ratio of 1 is found to be better than 0.5 and 2 cases. Although the absolute permeability changes the breakthrough recovery performance of the individual stages, it does not significantly affect the ultimate recovery of near-miscible WAG. Increasing the injection rate decreases the recovery factor. This effect is more pronounced in the GI cycles. Also, the ultimate recovery factor is reduced by 20% upon an increase in the viscosity of the in-situ oil. The findings of this research work can help to better understand the near-miscible WAG injection at various scenarios/conditions in terms of operational conditions and rock and fluid characteristics for the purposes of WAG design, operation, and optimization.

Experimental Study of Oil Recovery by Water Alternating Gas (WAG) process in Microporous media

Water alternating gas injection process (WAG) is a tertiary oil recovery technique commonly used to enhance the displacement efficiency of the residual oil which cannot be recovered during the primary and secondary recovery processes. In this study, experimental tests were conducted in a transparent water wet microporous model packed with glass beads and initially filled with crude oil. Alternate cycles of gas and water were injected to characterize the dynamics of three-phase flows and its associated oil recovery. The displacement of the residual oil at the end of each WAG injection cycles were studied in detail using the state of the art image processing techniques. It was observed that, the continuous cycles of WAG injection have helped the saturated residual oil to spread across the porous region and effectively displaced the residual oil that remained inside the water wet porous media after the initial water flooding. Obtained experimental results helps to understand the WAG process in detail and further it helps to validate future numerical models related to this process.

Model calibration and optimization of a post-combustion CO2 WAG pilot in a mature oil field

A carbon dioxide (CO2) water-alternating-gas (WAG) pilot was conducted to gain insights into tertiary oil recovery potential via CO2 flood in the West Ranch Field as part of the Petra Nova project, the world's largest post-combustion CO2 capture and utilization initiative. With a fluvial formation geology, this is a challenging and novel application of CO2 enhanced oil recovery. The aim of this study is two-fold. First, to build a predictive dynamic model that incorporates the data acquired during the pilot operation. Second, to utilize this model to provide guidance for optimal design for a field-wide CO2 EOR operation.This study began with an initialization of the pilot sector model extracted from a calibrated full-field model. The pilot model calibration follows a two-step hierarchical workflow. First, we performed a large-scale update of the permeability distribution by integrating available bottomhole pressure and multiphase production data. Next, local permeability field is fine-tuned using a streamline-based method to match CO2 breakthrough times at the producers. The predictive capability of the calibrated model was verified through two blind validation tests: (1) the model showed good agreement with saturation logs acquired at two observation wells; and (2) the model reproduced the CO2 recovery as a fraction of the injected CO2.Sensitivity studies were conducted using the calibrated pilot model to evaluate the effects of various operational parameters. Finally, we performed a Design of Experiment based multi-objective optimization of the CO2 WAG processes using the influential operational parameters identified from the sensitivity analysis.

Experimental investigation of effect of asphaltene deposition on oil relative permeability, rock wettability alteration, and recovery in WAG process

Asphaltene deposition is considered to be one of the most problems during oil productions. This work describes the effect of asphaltene precipitation and deposition on relative permeability of reservoir rock during water alternating gas (WAG) injection process. The main objective of this work is experimental investigating of relative permeability change of reservoir fluid due to asphaltene deposition on application of WAG process by use of core flood setup. Result of this paper investigate the relative permeability change during WAG process with different asphaltene content that help to make better development decisions for a reservoir with fluid with specific asphaltene content.

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.