CO2 WAG Research Articles

Study of recovery factor and CO(2) storage behavior in a reservoir using numerical simulation

In this study, the behavior of the recovery factor during the displacement and storage phases of carbon dioxide (CO2) in an Ecuadorian reservoir was investigated by numerical simulation. Continuous injection and CO2 WAG methods were used. The methodology included field data collection, creation of a static reservoir model, configuration of the PVT model with CMG software, construction of a dynamic model in GEM-CMG based on rock-fluid properties, and evaluation of CO2 injection scenarios. After a screening analysis, the optimal scenario was identified and the performance of the recovery factor over time was studied. The results indicated that, during the 8 years of simulation, the recovery factor with continuous injection was 28%, while with the WAG method it reached 31%. It was concluded that WAG was the most efficient method. Regarding storage, it was observed that continuous injection was able to store 83% of the CO2 in the reservoir.

Experimental study of hybrid nanofluid-alternating-CO2 microbubble injection as a novel method for enhancing heavy oil recovery

Water-alternating-CO2 injection (CO2 WAG) is a successful method for enhancing heavy oil recovery and geologic CO2 storage. However, CO2 WAG still has some setbacks, such as water blocking, gravity overriding, and viscous fingering of injected CO2. Therefore, a new method, named hybrid nanofluid-alternating-CO2 microbubble injection, is proposed in this study to improve the effect of CO2 WAG. In this method, the hybrid nanofluid is used to reduce the interfacial tension (IFT) between the heavy oil and brine and alter the sandstone surface wettability. The CO2 microbubbles improve mobility control by minimizing gravity overriding and viscous fingering. In this study, for the first time, hybrid nanofluid and CO2 microbubbles are simultaneously used in WAG processes to enhance heavy oil recovery. Five types of nanoparticles are screened systematically by contact angle and IFT tests to find the best candidate for the hybrid nanofluid in hybrid nanofluid-alternating-CO2 microbubble injection and clarify the enhanced oil recovery mechanisms. Then, oil displacement tests are carried out by using a patented large-scale sandpack to assess the viability of hybrid nanofluid-alternating-CO2 microbubble injection and to analyze the effects of key parameters on the performance of hybrid nanofluid-alternating-CO2 microbubble injection. Our experimental results indicate that Al2O3-SiO2 nanofluid has more influence than TiO2-SiO2 and TiO2-Al2O3 nanofluids on wettability alteration to the water-wet state and IFT reduction. Hybrid nanofluid-alternating-CO2 microbubble injection is a potentially good choice to enhance heavy oil recovery because of the synergistic effect of injecting hybrid nanofluid and CO2 microbubbles. Hybrid nanofluid-alternating-CO2 microbubble injection is suggested to be initiated as early as possible. A smaller slug size is preferred, and the water and gas slugs are suggested to be separately injected from the upper and lower parts of a heavy oil reservoir. The optimum WGR and slug size (1:1 and 0.05PV in this study) should be prudently considered when designing hybrid nanofluid-alternating-CO2 microbubble injection.

ASPHALTENE PRECIPITATION FOR CO2WAG FLOODING PROCESS: EFFECTS OF OPERATIONAL PARAMETERS ON OIL RECOVERY FACTOR AND PHYSICAL PROPERTIES

CO2-water alternating injection (CO2 WAG) is an advanced recovery strategy widely used in many oil fields. Asphaltenes may precipitate and eventually deposit on the rock surface in CO2 WAG injection, reducing permeability and porosity and thus affecting oil production. This work aims to determine under which operating conditions the highest recovery factor (RF) is reached in a WAG injection process and analyze the behavior of the physical properties of oil and rock, in addition to precipitation and deposition of asphaltenes. The results show that the higher the WAG ratio is, the higher the pressures achieved will be, reducing the amount of precipitated asphaltenes and its deposition. However, as the WAG ratio increases, the water breakthrough occurs earlier, causing the macroscopic displacement efficiency to decrease, impairing oil production. Furthermore, in most cases, higher RFs are reached for intermediate WAG ratios in a given injection cycle.

Data-driven modeling for forecasting oil recovery: A timeseries neural network approach for tertiary CO2 WAG EOR

Attaining reliable forecasts in the petroleum industry is a constant challenge, prompting ongoing research into models that empower engineers to make informed decisions. The conventional approach suffers from high uncertainties with complex input parameters resulting in convergence issues and high computational costs. The emergence of timeseries machine-learning models has shown to leverage trends and pattern recognition to achieve tractable, robust and cost-effective solutions. While previous research primarily focused on predicting existing production trends, this study uses timeseries analysis to forecast oil recovery in a CO2-EOR reservoir, focusing on an inverted five-spot pattern. Dynamic data encompassing pressures, WAG cycles, and injection volumes undergo preprocessing and chronological division to facilitate training and testing of an LSTM model. The analysis of field history calibration through the loss iteration of the training dataset shows promising results reflected in low mean-squared-error of 6.65. Model validation, including the test and blind datasets, demonstrates an approximate R-squared value of 0.88. The forecasted results unveil mounting uncertainty over time, and sensitivity analysis shows the significance of WAG cycle adjustments. This study introduces an economical oil recovery forecasting approach, devoid of complex physical models, offering a versatile framework applicable across disciplines, especially for scenarios influenced by past decisions.

An experimental assessment of seawater alternating near-miscible CO2 for EOR in pre-salt carbonate reservoirs

Enhanced oil recovery (EOR) methods considering the injection of seawater and CO2 have been widely investigated and applied in the Brazilian pre-salt fields. The high availability of these fluids in offshore facilities makes seawater alternating CO2 (CO2WAG) a viable and environmentally friendly EOR method. It combines the advantages of seawater injection and CO2 injection to improve fluid mobility control and viscous fingering attenuation. In this study, in addition to the core flooding test of secondary seawater flooding and the tertiary CO2WAG, different experimental determinations provided a better understanding of the mechanisms related to the EOR methods applied to a carbonate core composed mainly of dolomite, and their interactions with pre-salt oil, brines and CO2. A 13.30% incremental oil recovery was achieved by alternating seawater with CO2. Considering formation brine, non-carbonated seawater, or seawater saturated with CO2, contact angle measurements revealed that the wettability alteration is not significant when dolomite is slightly water-wet, even in the presence of CO2. On the other hand, measures of brine/oil, brine/CO2/oil and CO2/oil interfacial tension emphasize the beneficial effects of this gas for EOR, in near-miscible conditions. This is achieved by the reduction of capillary and interfacial forces that act by trapping the oil in the pores of the medium. The brine salinity, the presence of magnesium in dolomite and the oil's low TAN/TBN ratio proved to be essential factors in determining the slightly water-wet wettability of the dolomitic rock and the interfacial tension between the phases. Furthermore, for the experiments carried out in the presence of brine with solubilized CO2, a considerable variation in the oil drop volume was observed due to the mass transfer of CO2 between the phases. Finally, experimental results showed that the additional oil recovery was mainly associated with oil swelling, viscosity reduction, and mobility increase, which occur even in near-miscible conditions during CO2WAG.

Techno-economical optimization of water-alternating-CO2/dimethyl ether process for enhanced oil recovery

The use of CO2 to improve oil recovery has the disadvantage of reduced sweep efficiency due to the large difference in density and viscosity between oil and CO2. Overcoming these drawbacks, the use of dimethyl ether (DME) is known to be more effective than CO2 in improving oil recovery. In this study, a CO2-DME mixed solvent, is thoroughly investigated by developing a compositional model. The oil recovery of a CO2-DME mixed solvent has been examined in terms of sweep efficiency and displacement efficiency by comparing CO2-water-alternating-gas (WAG) and CO2-DME WAG. According to the results from compositional simulation, the highest DME content investigated resulted in a 66.4% lower viscous gravity number and a 26.6% increase in sweep efficiency compared to CO2 WAG. Minimum miscible pressure (MMP) and interfacial tension (IFT) were reduced by 30.1 and 97.5%, respectively, significantly improving the mobility of the oil. As a result, the amount of oil remaining in the reservoir decreased by 40.7%, and oil recovery increased by 31%. An economic evaluation considering optimized injection design and reuse of recovered DME showed a 13% improvement in net present value (NPV) of CO2-DME WAG over CO2 WAG.

Experimental investigation of CO2 storage and oil production of different CO2 injection methods at pore-scale and core-scale

The CO2 storage and oil production of different CO2 injection schemes via laboratory experiments was investigated in this study. Microfluidic equipment was upgraded to increase its working pressure above the miscible pressure of the CO2/oil system. Microfluidic experiments of immiscible CO2 injection, miscible CO2 injection, water injection, and water alternating CO2 (WAG) injection were conducted. Affected by buoyancy subject to gas phase, apparent gas overriding and flow stratification were observed under immiscible conditions in porous media. Miscible CO2 injection eliminated the influence of buoyancy, thereby expanding the CO2 storage area and enhancing oil production. Non-uniform miscibility was observed during miscible CO2 injection, caused by connate water, tiny pores, and differential pressure. Water flooded most areas in the porous media, but small dispersed oil such as droplet oil and film oil remained in the water-flooded pores, resulting in low oil washing efficiency. The strong Jamin effect in the water-flooded area, caused by the dispersion of the remaining oil, inhibited the gas overriding and expanded the scope of CO2 flow in WAG, thereby increasing the oil production. However, the water slug occupied a large pore volume and drove out the CO2 stored at the beginning stage, resulting in low CO2 storage. The core flooding experiments were conducted to quantitatively evaluate the CO2 storage and oil recovery of different CO2 injection methods. Miscible injection produced 20.5%, 12.2%, and 2.9% more oil than immiscible CO2 injection, water flooding, and WAG. Besides, the produced gas by miscible CO2 injection was 46.5% and 47.6% lower than that of immiscible CO2 injection and WAG, respectively.

An Experimental Investigation of WAG Injection in a Carbonate Reservoir and Prediction of the Recovery Factor Using Genetic Programming

Production from mature oil fields is gradually declining, and new discoveries are not sufficient to meet the growing demand for oil products. Hence, enhanced oil recovery is emerging as an essential link in the global oil industry. This paper aims to recognize the possibility of increasing oil recovery from Polish carbonate reservoirs by the water alternating gas injection process (WAG) using various types of gases, including CO2, acid gas (a mixture of CO2 and H2S of 70/30% vol/vol) and high-nitrogen natural gases occurring in the Polish Lowlands. A series of 17 core flooding experiments were performed under the temperature of 126 °C, and at pressures of 270 and 170 bar on composite carbonate cores consisting of four dolomite core plugs. Original reservoir rock and fluids were used. A set of slim tube tests was conducted to determine the miscibility conditions of the injected fluids with reservoir oil. The WAG process was compared to continuous gas injection (CGI) and continuous water injection (CWI) and was proven to be more effective. CO2 WAG injection resulted in a recovery factor (RF) of up to 82%, where the high nitrogen natural gas WAG injection was less effective with the highest recovery of 70%. Based on the core flooding results and through implementing a genetic programming algorithm, a mathematical model was developed to estimate recovery factors using variables specific to a given WAG scheme.

A comprehensive techno-eco-assessment of CO2 enhanced oil recovery projects using a machine-learning assisted workflow

Carbon dioxide enhanced oil recovery (CO2-EOR) projects not only extract residual oil but also sequestrate CO2 in the depleted reservoirs. This study develops a machine-learning-based workflow to co-optimize the hydrocarbon recovery, CO2 sequestration volume and project net present value (NPV) simultaneously. Considering the trade-off relationships among the objective functions, support vector regression with Gaussian kernel (Gaussian- SVR) proxies are coupled with multi-objective particle swarm optimization (PSO) protocol and generate Pareto optimal solutions. Taking advantage of the high computational efficacy of the proxy model, economic uncertainties introduced by tax credits, capital costs and oil price are investigated by this study. The results indicate that the tax incentive policy (Section 45Q) plays a vital role in enhancing the economic returns of CO2-EOR projects, especially under the depression of crude oil market. The proposed workflow has been successfully implemented to optimize a water alternative CO2 (CO2-WAG) injection project in a depleted oil sand in the US. The optimization results yield an incremental oil production of 15.8 MM STB and 1.37 MM metric tons of CO2 storage in a 20-year development strategy, with the highest project NPV to be 205.6 MM US dollars.

Remaining oil distribution in models with different heterogeneities after CO2 WAG injection: Visual research by nuclear magnetic resonance technique

Remaining oil distribution in models with different heterogeneities after CO2 WAG injection: Visual research by nuclear magnetic resonance technique

Assessing the Feasibility of Improving the Performance of CO2 and CO2–WAG Injection Scenarios by CWI

In water-wet systems, the oil recovery performance of CO2 and CO2–WAG injection scenarios is negatively affected when the injection pressure is below the minimum miscibility pressure and the spread...

Simulation Study of CO2 EOR and Storage Potential in a North Sea Reservoir

A simulation study has been carried out using realistic model of a North Sea oil reservoir to assess the performance of CO2 flood in oil recovery compared to the base case water injection. The development strategy for this reservoir is based on one injector and a single producer. Various CO2 injection strategies were studied to define injection schemes that would outperform water injection. Pure CO2 injection, water flooding followed by CO2 injection, CO2 Water-Alternating-Gas (CO2 WAG) injection, and CO2 Simultaneous-Water-And-Gas (CO2 SWAG) injection are strategies that were studied. The latter one was chosen to study the mitigation of gravity segregation between water and gas. Various well locations and well configurations were also evaluated to determine the optimal arrangement. Simulation results showed that the increased recovery factors by the CO2 flooding varies in the range between 3 to 8 percent and is to a considerable extent dependent on well configuration and injection scheme. The flooding with SWAG (water above gas) shows very promising results due to the increased mobility control achieved. Regarding the storage potential, the analysis indicates that this method would result in highest CO2 retention in the reservoir.

Experimental investigation on CO2 injection in the Daqing extra/ultra-low permeability reservoir

This paper aims to study the effect of four kinds of CO2 injection schemes, namely water–alternating-gas (CO2/water), immiscible flooding, miscible flooding, and cyclic CO2 injection, in Daqing peripheral extra/ultra-low permeability reservoirs. Physical simulation experiments and nuclear magnetic resonance (NMR) measurements were conducted to investigate how crude oil residing in different sized pores are recovered by different gas injection schemes in extra/ultra-low permeability cores and to quantify the recovery factors and residual oil distribution in different sized pores. Experimental results indicate that the residual oil is mainly found in the <10msT2 spectrum (clay micro pore), followed by 10–100ms (medium pore) and >100msT2 spectrum (large pore); therefore, it is important to enhance recovery in the pores and throats smaller than 10ms. Water flooding injection gives the worst oil recovery, but converting to CO2 injection can greatly improve the recovery efficiency depending on the injection mode. For extra-low permeability (1–10mD) cores, cyclic CO2 injection displacement of crude oil in the micro pores has the highest efficiency, followed by CO2 miscible flooding, WAG flooding and immiscible CO2 flooding in that order. For ultra-low permeability (<1mD) cores, WAG injection shows the best performance among the four injection schemes. The distribution of remaining oil from NMR shows that both CO2 miscible and immiscible injection mainly recover the oil in large-medium sized pores, whereas early gas breakthroughs cause the crude oil in clay micro pores to be difficult to displace. However, although the overall recovery factors of WAG and cyclic CO2 injection are very close, their mechanisms of recovering oil from clay micro pores are different. WAG greatly enhances the fluid mobility ratio and delays the breakthrough time due to the water blocking effect. In the cyclic CO2 injection process, pressure equilibration during the soak time causes the crude oil in the micro pore to flow into the large-medium pore, thus greatly increasing the displacement efficiency of crude oil in micro pores.

Evaluation of CO2 Low Salinity Water-Alternating-Gas for enhanced oil recovery

Low Salinity Waterflooding (LSW) is an emerging attractive enhanced oil recovery (EOR) method because of its oil recovery performance and relatively simple, environmentally friendly implementation, when compared with conventional high salinity waterflooding and EOR approaches. More importantly, another advantage of LSW is that it can be integrated with other EOR methods (in hybrid LSW processes), i.e. chemical or miscible gas flooding. The merits of combining LSW with CO2 injection is investigated in this paper, and a novel EOR method, Low Salinity Water Alternating CO2 (CO2 LSWAG), is proposed. CO2 LSWAG injection promotes the synergy of the mechanisms underlying these methods which further enhances oil recovery and overcomes the late production problems frequently encountered in conventional WAG. CO2 LSWAG has been evaluated in both one-dimensional and full-field scale with positive results compared with conventional high salinity WAG.To investigate the advantages of CO2 LSWAG, a comprehensive ion exchange model associated with geochemical processes has been implemented and coupled to the multi-phase multi-component flow equations in an equation-of-state compositional simulator. 1D simulation of different CO2 LSWAG schemes are first conducted to understand the combined effects of solubility of CO2 in brine, dissolution of carbonate minerals, ion exchange, and wettability alteration. CO2 LSWAG performance is then evaluated on a field scale through an integrated workflow that includes geological modeling, multi-phase multi component reservoir flow modeling and process optimization. The simulation results indicate that CO2 LSWAG has the highest oil recovery compared to conventional high salinity waterflood, high salinity WAG, continuous CO2 flooding, and low salinity waterflood. A number of geological realizations are generated to assess the geological uncertainty effect, in particular clay distribution uncertainties, on CO2 LSWAG efficiency. CO2 LSWAG injection strategies are optimized by identifying key WAG parameters. Finally, CO2 LSWAG is evaluated in the full field scale for a North Sea reservoir and the simulation results shows that CO2 LSWAG yields about 4.5% incremental OOIP compared to the conventional high salinity WAG.The proposed workflow demonstrates the synergy between CO2 WAG and LSW. Built in a robust reservoir simulator, it serves as a powerful tool for screening, design, optimization, and uncertainty assessment of the process. CO2 LSWAG is a promising EOR technique as it not only combines the benefits of CO2 injection and low salinity water floods but also promotes the synergy between these processes through the interactions between geochemical reactions associated with CO2 injection, ion exchange process, and wettability alteration. This paper demonstrates the merits of this process through modeling, optimization and uncertainty assessment.

Gas channeling control during CO2 immiscible flooding in 3D radial flow model with complex fractures and heterogeneity

Fractures and heterogeneity commonly exist in ultra-low permeability reservoirs, which will cause serious gas channeling phenomena and lead to poor oil recovery during CO2immiscible flooding. CO2water alternating gas (WAG) flooding combined with gas channeling control treatments are recognized as effective approaches to enlarge the sweep efficiency of CO2. Performance of gel systems were evaluated to screen out a high-strength gel which can be utilized as fracture blocking agent. Then, performance of small molecule amines were evaluated to screen out a kind of small molecule amine which can be utilized as rock-matrix blocking agent. Performance evaluation results showed that high-strength gel with 8% modified starch + acrylic amide, 0.05% crosslinking agent, 0.15% initiator and 0.15% stabilizer could be served as fracture blocking agent, while etheylenediamine was proposed as rock-matrix blocking agent which could react with CO2 and generate solid particles to improve the heterogeneity of the reservoirs.To examine gas channeling control effect in actual reservoir conditions, a 3D radial flow model with complex fractures and heterogeneity was designed according to the actual oilfield, and five-spot pattern was employed in the model. Waterflooding, continuous CO2 flooding, and gas channeling control using high-strength gel, etheylenediamine and CO2 WAG flooding were conducted successively in the 3D radial flow model. After a series of treatments, the oil recovery was enhanced by 15.09%, which was significant for CO2 immiscible flooding in the field application. The gas channeling along major fracture and microfractures of the model was effectively controlled by high-strength gel, while fluid diversion could occurred after ethylenediamine injection due to the solid particles which could mitigate gas channeling along relatively high permeability areas of the rock-matrix, and the gas channeling phenomena can be further mitigated by the mobility control ability of CO2 WAG flooding.

Experimental investigation of the effect of injection water salinity on the displacement efficiency of miscible carbon dioxide WAG flooding in a selected carbonate reservoir

The effect of injection brine salinity on the displacement efficiency of low water salinity flooding was investigated using sea water at 35,000 ppm, and two field injection waters, namely, Um-Eradhuma (UER) at 171,585 ppm and simsima (SIM) at 243,155 ppm. The salinity of the employed waters was varied from original salinity to 1,000 ppm and used in the displacement of oil in selected core samples. The results of this set of experiments revealed that UER salinity of 5,000 ppm is the optimum system for the candidate reservoir. UER original water and its optimum water were then used in this project as the high and low salinity waters in the CO2–WAG flooding experiments. Displacement efficiencies were evaluated under three injection modes: carbon dioxide WAG miscible flooding (CO2–WAG, 1:1, 2:1, and 1:2), continuous CO2 injection, and waterflood. The WAG performance parameters, such as secondary and tertiary displacement efficiencies, CO2 flood utilization factor, and CO2 performance during different WAG flood cycles were determined. To insure miscibility condition between the injected gas and the employed oil, all of the flooding experiments were conducted at 3,200 psia (which is 300 psia above the minimum miscibility pressure of CO2 and used oil) and 250 °F. Experimental results indicated that core length is a critical parameter in determining the optimum WAG process, and that a minimum core length of 29 cm is required to insure the generation of miscibility before breakthrough in CO2–WAG flooding experiments. On the other hand, core length had no effect on the performance of the low salinity flooding experiments. Using single core flooding low salinity CO2–WAG of 1:2 flooding produced an improvement in the displacement efficiency of 29 % over the high salinity system. Also, composite core flooding experiments showed that the high salinity CO2-2:1 WAG achieved a displacement efficiency of 98 %. These results indicate that achieving miscibility at the reservoir conditions is the dominant mechanism and that low salinity will have no major effect on the displacement efficiency of CO2-Miscible WAG flooding. Results also indicate that oil recovery during different CO2–WAG cycles is a function of WAG ratios.

Experimental investigation of heavy oil recovery by continuous/WAG injection of CO&lt;SUB align="right"&gt;2 saturated with silica nanoparticles

In this work, application of CO2 saturated with silica nanoparticles in continuous/water alternating gas (WAG) injection for heavy oil recovery was investigated which has been rarely attended in the available literature. Core displacement tests were conducted to monitor heavy oil recovery in both continuous and WAG injection schemes. It has been observed that for continuous nano-saturated CO2 injection, the oil recovery is higher than pure CO2 injection. This observation might be explained by alteration of rock wettability to a more water-wet condition. In WAG injection scheme, water breakthrough happened later in nano-saturated CO2 than pure CO2 injection. This delayed water breakthrough can be caused by nano-stabilised oil in water emulsions. These oil emulsions hindered the oil recovery before breakthrough. However, recovery factor of WAG injection of nano-saturated CO2 exceeded that of pure CO2 as those stabilised oil emulsion were produced along with water after breakthrough. The results of this work reveal that saturation of CO2 with silica nanoparticles can improve the microscopic efficiency of continuous CO2 injection, while in CO2 WAG injection this hampers oil recovery before water breakthrough.

Production performance of water alternate gas injection techniques for enhanced oil recovery: effect of WAG ratio, number of WAG cycles and the type of injection gas

Production performance of a water alternate gas injection (WAG) method has been reported for the effect of several operating parameters, such as, WAG injection cycles, viz., single cycle WAG and five-cycle WAG and the tapered WAG at the reservoir conditions of 120°C and 230 kg/cm2 for hydrocarbon gas and CO2 gas. It is observed that the number of cycles in the WAG injection process affects the recovery of oil from the core sample. It is observed that the tapering in the WAG injection process improves the recovery of oil initially in place. The observations on the effect of gases revealed that the CO2 gas with five-cycle WAG process gives higher incremental recovery than the five cycle WAG process using hydrocarbon gas. It is observed that the saturation profile of CO2 WAG injection shows the better gas saturation in the core as against the hydrocarbon gas in the WAG process.

An Experimental Study of CO2-low Salinity Water Alternating Gas Injection in Sandstone Heavy Oil Reservoirs

Several studies have shown that oil recovery significantly increased by low salinity water flooding (LSWF) in sandstones. However, mechanism of oil recovery improvement is still controversial. CO2 that develops buffer in presence of water is expected as a deterrent factor in LSWF efficiency based on mechanism of IFT reduction due to pH uprising. No bright evidence in literature supports this idea. Here, a set of core floods including a pair of CO2 WAG and a pair of water injection tests are conducted and, the efficiency of LSWF and high salinity water flooding (HSWF) were compared for each pair. HSWF was followed by LSWF in tertiary mode. Results showed that not only CO2 does not deteriorate LSWF recovery efficiency, but also improves recovery. Since CO2-low salinity WAG showed best performance among types by constant pore volume injected. Positive results in both secondary and tertiary modes with Kaolinite free samples used here showed that Kaolinite release is not the critical phenomenon in LSWF brisk performance. Also different pressure behaviour of CO2 WAG processes in comparison with reported behaviour of LSWF proves that LSWF performance may not depend on how pressure changes through flooding.

The Numerical Simulation of Buried Hill Fractured Reservoir by CO2 WAG with Overlap Alternative Horizontal Well Pattern

For the trends of global climate warming, it is great important to implement the Carbon capture and storage (CCS) technology. This paper describes the numerical simulation of CO2 displacement enhanced oil recovery (EOR) in M reservoir. The M reservoir is an extra-thick buried hill fractured reservoir, which use overlap alternative horizontal well pattern to produce. Considering the time-varying effects of fracture’s porosity and permeability parameters, combining the develop dynamic and the diversification of physical property parameters of fractured formation, use the dual porosity dual permeability model and the three-dimensional components simulator to simulate the develop process. By CO2 WAG orthogonal experiment design, can simulate and predict the development effect of fractured buried hill reservoir affected by factors such as: different production and injection well pattern, injection intensity, gas water slug ratio, alternating cycle and so on. The results show that in the process of CO2 WAG can significantly reduce the risk of gas breakthrough by overlap alternative horizontal well pattern, and reduce the negative impact by fracture properties, also can improve EOR and CO2 sequestration effectively. On this basis, this paper evaluates the suitability of WAG development methods to fractured buried hill reservoir with overlap alternative horizontal well pattern, also optimizes the reasonable development plan for M reservoir.