A Storage-Driven CO<sub>2</sub> EOR for a Net-Zero Emission Target

Abstract

Stabilizing global climate change to within 1.5 °C requires a reduction in greenhouse gas emissions, with a primary focus on carbon dioxide (CO₂) emissions. CO₂ flooding in oilfields has recently been recognized as an important way to reduce CO₂ emissions by storing CO₂ in oil reservoirs. This work proposes an advanced CO₂ enhanced oil recovery (EOR) method—namely, storage-driven CO₂ EOR—whose main target is to realize net-zero or even negative CO₂ emissions by sequestrating the maximum possible amount of CO₂ in oil reservoirs while accomplishing the maximum possible oil recovery. Here, dimethyl ether (DME) is employed as an efficient agent in assisting conventional CO₂ EOR for oil recovery while enhancing CO₂ sequestration in reservoirs. The results show that DME improves the solubility of CO₂ in in situ oil, which is beneficial for the solubility trapping of CO₂ storage; furthermore, the presence of DME inhibits the “escape” of lighter hydrocarbons from crude oil due to the CO₂ extraction effect, which is critical for sustainable oil recovery. Storage-driven CO₂ EOR is superior to conventional CO₂ EOR in improving sweeping efficiency, especially during the late oil production period. This work demonstrates that storage-driven CO₂ EOR exhibits higher oil-in-place (OIP) recovery than conventional CO₂ EOR. Moreover, the amount of sequestrated CO2 in storage-driven CO₂ EOR exceeds the amount of emissions from burning the produced oil; that is, the sequestrated CO₂ offsets not only current emissions but also past CO₂ emissions. By altering developing scenarios, such as water alternating storage-driven CO₂ EOR, more CO₂ sequestration and higher oil recovery can be achieved. This work demonstrates the potential utilization of DME as an efficient additive to CO₂ for enhancing oil recovery while improving CO₂ storage in oil reservoirs.

Content

《1. Introduction 》

1. Introduction

As humanity’s dependence on fossil fuel is steadily increasing, our extensive utilization of fossil energy has led to proliferating carbon dioxide (CO₂) emissions [1,2]. It has been reported that anthropogenic CO₂ emissions reached 330 billion tonnes in 2021, more than three-quarters of which came from the combustion of fossil fuels [1,3,4]. Global climate change due to CO₂ emissions has become a serious environmental issue all over the world that cannot be ignored [5,6]. Over the past few decades, abundant CO₂ has been stored in deep saline aquifers at a global scale due to the simplicity of implementation [7–9]. Recently, depleted oil and gas reservoirs have been noted as ideal geological bodies for CO₂ storage, since the necessary infrastructure including ground facilities, injection wells, and transporting pipelines—in addition to well-known geological characteristics—already exists [10–13]. When injected into depleted oil and gas reservoirs, CO₂ can be used as a replacement agent that results in additional oil and gas recovery, which may offset a portion of the cost used for CO₂ capture and storage [14–16].

In addition to these types of storage, CO₂ is employed for oil recovery due to its superiority in improving fluid properties under oil reservoir conditions. The basic mechanism of CO₂ enhanced oil recovery (EOR) lies in the interfacial tension (IFT) deduction, oil viscosity reduction, oil swelling, and extraction effect on lighter hydrocarbon components [17–24]. Compared with other typical gases, such as natural gas, air, nitrogen (N₂), and so forth, CO₂ exhibits lower minimum miscible pressures (MMP) with the in situ oil; thus, CO₂ is considered to be a better candidate to achieve miscible flooding, which is deemed to be the most efficient method for oil recovery [25]. It has been reported that the first commercial CO₂ flooding project, which was invested in by Chevron (USA), was implemented on the Kelly-Snyder oilfield of SACROC in Texas in 1981 [26]. With the maturation of CO₂ EOR technology in conventional reservoirs, hundreds of CO₂ projects have been implemented all over the world as of 2021, contributing more than 300 000 barrels (bbl; bbl = 158.9873 L) per day of accumulated oil production in the United States alone [27]. Based on technological development in horizontal-well and multi-stage hydraulic fracturing, CO₂-based strategies are being employed for tight oil recovery [28–31]. Extensive work has been conducted to investigate the mechanism of CO₂ EOR in increasing tight oil recovery [32–35]. Some studies have claimed that CO₂ EOR is inefficient in tight reservoirs as a result of the early occurrence of serious gas breakthrough, which is due to the presence of complex fractures in these reservoirs [36–38].

Water alternating gas flooding makes it possible to control the mobility ratio, and has been shown to have better sweeping and displacing efficiency than the single CO₂ EOR method [39–41]. Within this scenario, water is injected intermittently, successfully preventing early gas breakthrough [42]. Previous studies have comprehensively investigated the key factors affecting water alternating gas flooding, including the number of cycles performed, slug ratio, and slug size [43]. The main controlling parameter—that is, soaking time, which is important formass transfer between CO₂ and the in situ oil— has been discussed in more depth in studies on tight reservoirs than in studies on conventional reservoirs [44–48].

In addition to oil recovery, the CO₂ EOR process holds potential for storing large amounts of CO₂ in reservoirs, thereby alleviating the greenhouse effect [49–53]. The first project involving CO₂ EOR and storage was implemented in the Weyburn oilfield in Canada in 2000 [54–57], which has a storage capacity of more than 25 million tonnes of CO₂ [58]. Geological storage of CO₂ has recently become a hot topic in the fossil fuel industry. The fundamental mechanism of CO₂ storage involves mineral trapping, solubility trapping, residual trapping, and structural trapping [59]. Recent studies have addressed the co-optimization of oil recovery and CO₂ storage, although most research has only analyzed very limited data and simple cases [60–67]. Thus, technical challenges remain in the co-optimization of CO₂ EOR and storage in oil reservoirs. For example, some phenomena during CO₂ EOR and storage negatively affect the final oil recovery and CO₂ sequestration capacity, including CO₂ override, gravity segregation, and viscosity fingering [68,69]. In future, more research attention should be paid to the basic mechanism of CO₂ EOR and storage in reservoirs, and new strategies should be inspired to maximize oil recovery and CO₂ storage capacity.

This work proposes a new generation of the CO₂ EOR method— namely, storage-driven CO₂ EOR—whose purpose is to realize netzero or even negative CO₂ emissions by sequestrating CO₂ in oil reservoirs while maximizing oil recovery. Here, dimethyl ether (DME) is used as a novel agent to assist CO₂ EOR in enhancing oil recovery while improving CO₂ storage in oil reservoirs. This paper illustrates the fundamental mechanism of the storage-driven CO₂ EOR method and is expected to inspire new insights into CO₂ EOR; that is, the future CO₂ EOR should not only focus on a single target (i.e., oil recovery) but also focus on how to create the maximum CO₂ storage capacity in oil reservoirs.

《2. Modeling approach》

2. Modeling approach

The efficiency of storage-driven CO₂ EOR was numerically investigated in order to enhance oil recovery and CO₂ storage in the Weyburn reservoir. The Weyburn reservoir, located in southeast Saskatchewan, Canada, has a depth of 1310–1500 m [70]. The reservoir temperature and pressure are 336.15 K and 14.0 MPa, respectively. The averaged reservoir permeability, porosity, and initial oil saturation are 20.0 mD, 30%, and 0.8, respectively, with a permeability that is isotropic in all directions. Components in the reservoir fluid can be lumped into 12 pseudo components, according to Pedersen’s weight-based grouping [71]. A correlation from the previous work [71] is used to estimate the critical properties of the reservoir fluids, which are a function of the molecular weight and density. The Computer Modeling Group (CMG) WinProp’s regression tool is used to tune this correlation by setting the fluid properties according to the original reservoir conditions. Table 1 presents the matched results between the fluid sample and the correlation, validating the reliability of this correlation. The physical properties of the Weyburn reservoir fluids and the binary interaction coefficients of each component are shown in Tables S1 and S2 in the Appendix A. The relative permeability of the oil reservoir was obtained from the Ref. [72].

《Table 1》

Table 1 Physical properties of the Weyburn reservoir fluids [70].

Reservoir simulation is performed using the compositional simulator in CMG–GEM. A two-dimensional model is developed using the reservoir and the physical properties of the fluid sample in Table 1. The simulated reservoir has a grid dimension of 50 × 50 × 1, with the dimensions of 2500, 2500, and 20 ft (1 ft = 0.3048 m) in the x, y, and z directions, respectively. The injector is located at block 1 on the left edge of the simulated reservoir, and the producer is located at the other edge of the simulated reservoir. The bottomhole pressure is held at 10.0 MPa in the producer, and the gas injection rate is maintained at a constant rate of 700 m³ ∙d^–1. The total simulation time is set as 10 years. In this work, both conventional CO₂ EOR and storage-driven CO₂ EOR are performed for the Weyburn reservoir with a fixed DME concentration of 20.0 mol%. In addition, to further evaluate the reliability of this numerical model, slim-tube test simulations are used to calculate the miscible pressure between CO₂ and the oil sample. The pressure was found to be very close to the experimental data, at around 14.0 MPa compared with 14.2 MPa [70], for a relative deviation of –1.41%.

《3. Phase property measurement》

3. Phase property measurement

Fig. 1 provides a schematic diagram for measuring the phase composition and CO₂ solubility in crude oil using a pressure– volume–temperature (PVT) setup. The viscosity, density, swelling factor, and saturation pressure of the experimental oil sample are 1.81 mPa∙s, 810 kg∙m^–3 , 1.072 m³ ∙m^–3 , and 4.90 MPa, respectively, which are similar to those of the simulated oil used in the numerical model. Firstly, crude oil is introduced into the PVT cell at a given temperature and pressure. DME with a givenmolar concentration is then injected at a higher pressure. CO₂ is hereafter introduced into the PVT cell at the same temperature. The crude oil–DME–CO₂ mixture is pressed into a single phase under high-pressure conditions.

《Fig. 1》

Fig. 1. Schematic diagram for measuring the phase composition and solubility of CO₂ in crude oil using the PVT setup. BPR: back pressure regulator; P: pressure.

Gas chromatography (GC) is used to measure the composition of the crude oil–DME–CO₂ mixtures. Next, the system pressure is reset to the experimental pressure and held for at least 24 h, until the system reaches equilibrium. GC analysis is then used to measure the composition of the gas and oil phase in order to analyze the CO₂ solubility in crude oil by opening the valve connected to the PVT cell. Such a setup can withstand pressures of up to 100 MPa and temperatures as high as 473.15 K. The uncertainty in temperature and pressure measurement is controlled to within ± 0.5 K and ± 0.1 MPa, respectively, while the solubility uncertainty is around ± 0.5%.

《4. Results and discussion》

4. Results and discussion

《4.1. Solubility of CO2 in crude oil》

4.1. Solubility of CO₂ in crude oil

The solubility of CO₂ in crude oil is critical for the performance of a CO₂ EOR project for enhanced oil recovery and CO₂ storage.

Fig. 2 presents the CO₂ solubility in crude oil when DME is introduced under different pressure conditions. It is found that the solubility of CO₂ is highly influenced by the system pressure; that is, more CO₂ is dissolved as the pressure increases. More interestingly, DME significantly facilitates CO₂ solubility in the crude oil, especially under high-pressure conditions (> 4 MPa); the solubility is further improved as more DME is added. When DME is introduced, the DME molecules tend to form hydrogen bonds with the hydrocarbon carbon chains; this induces the rearrangement of the long carbon chains into a more regular and orderly arrangement, which beneficial for CO₂ dissolution in the in situ oil. In addition, the improved CO₂ solubility enables more CO₂ to be trapped in the in situ oil, which is essential for CO₂ storage in oil reservoirs.

《Fig. 2》

Fig. 2. CO₂ solubility in crude oil as a function of pressure and DME concentration.

Fig. 3 presents the molar fraction of the lighter components— that is, C₁–C₅—in the gas phase for the CO₂–crude oil and CO₂– DME–crude oil mixtures at different temperatures. To validate the reliability of this simulation model, we compare the prediction results from the simulation model with the experimental data. It is found that the predicted results agree well with the experimental data, suggesting that our simulation model is reliable. As shown in Fig. 3, the molar fraction of the lighter hydrocarbons increases in the gas phase as the temperature increases, indicating that a greater amount of lighter hydrocarbons is extracted by CO₂ at higher temperatures. In addition, the molar fraction of the lighter hydrocarbons in the gas phase of the CO₂–DME–crude oil mixture is smaller than that of the CO₂–crude oil mixture. This finding suggests that the extraction effect on the lighter components is greatly inhibited when DME is introduced, especially under hightemperature conditions. When a CO₂ EOR project is implemented in a reservoir, the CO₂ dissolves into the in situ oil, and the lighter components in the crude oil tend to ‘‘vaporize” into the gas phase due to the CO₂ extraction effect. However, with the addition of DME, most of the lighter hydrocarbons remain ‘‘fixed” in the oil phase, which favors sustainable oil recovery.

《Fig. 3》

Fig. 3. Molar fraction of the lighter components (C₁–C₅) in the gas phase for CO₂– crude oil and CO₂–DME–crude oil mixtures at different temperatures.

《4.2. Improved oil recovery》

4.2. Improved oil recovery

The superiority of DME in improving CO₂ solubility gives it the potential to enhance oil recovery while assisting CO₂ storage in oil reservoirs. In this section, the performance of traditional CO₂ EOR is compared with that of storage-driven CO₂ EOR to evaluate the potential of DME for enhancing oil recovery. Fig. 4 illustrates oil recovery in terms of the production time for conventional CO₂ EOR and storage-driven CO₂ EOR at different gas injection rates. As shown in Fig. 4, oil recovery increases linearly during the initial stage of a conventional CO₂ EOR project, until CO₂ is produced from the production wells (around 1200 d). Furthermore, it seems that the gas injection rate does not affect oil recovery during the early oil production period. After gas breakthrough, oil recovery increases with an increasing gas injection rate; it then tends to level off and less oil is produced. After introducing DME, the initial oil recovery is increased; during the late oil production period, oil recovery increases continuously, indicating that storage-driven CO₂ EOR favors sustainable oil recovery.

《Fig. 4》

Fig. 4. Oil recovery in terms of the production time for conventional CO₂ EOR and storage-driven CO₂ EOR at different gas injection rates.

Fig. 5 presents digital images of oil saturation in reservoirs for conventional CO₂ EOR and storage-driven CO₂ EOR at a pore volume (PV) of 0.5. In the dominating channel, a large proportion of the in situ oil is displaced, leading to relatively lower oil saturation. In conventional CO₂ EOR, the oil saturation in the dominating channel is still higher than 0.40; in comparison, after introducing DME, additional oil is mobilized and the oil saturation in the dominating channel is generally lower than 0.32. Conventional CO₂ flooding exhibits less sweep efficiency in oil reservoirs, resulting in a large portion of the in situ oil being untouched, whereas storage-driven CO₂ EOR is superior in expanding the sweeping efficiency and thereby enhancing oil recovery.

《Fig. 5》

Fig. 5. Digital images of oil saturation in the reservoir for (a) conventional CO₂ EOR and (b) storage-driven CO₂ EOR at 0.5 PV. INJ: injection well; RPOD: production well.

Water alternating gas injection is performed with the purpose of further enhancing oil recovery. Fig. 6 depicts oil recovery as a function of the production time for water alternating gas injection at different bottomhole pressures. The solid lines in the figure represent water alternating CO₂ EOR, while the dotted lines represent water alternating storage-driven CO₂ EOR. As shown in Figs. 4 and 6, water alternating gas EOR generally yields higher oil recovery than conventional gas flooding. The viscosity of the liquid-like CO₂ is very small, resulting in an unstable contacting front and gravity separation when injected; such behavior makes CO₂ EOR inefficient. However, water alternating gas EOR overcomes these shortcomings and is therefore superior for the recovery of oil-in-place (OIP). As shown in Fig. 6, oil recovery for water alternating storage-driven CO₂ EOR is higher than that for water alternating CO₂ EOR during the late oil production period. This finding indicates that water alternating storage-driven CO₂ EOR achieves sustainable oil recovery.

《Fig. 6》

Fig. 6. Oil recovery in terms of the production time for water alternating gas injection at different bottomhole pressures.

《4.3. Improved CO2 storage》

4.3. Improved CO₂ storage

In this section, the influence of DME on CO₂ storage during CO₂ EOR is specially investigated. Fig. 7 presents the CO₂ storage ratio according to the oil production time for conventional CO₂ EOR and storage-driven CO₂ EOR, where the CO₂ storage ratio is defined as the ratio of the sequestrated CO₂ to the total injected CO₂. During the initial oil production period (< 1200 d), the oil reservoir has an extremely high CO₂ geological storage capacity at low gas injection rates. During the late oil production period, the CO₂ becomes increasingly saturated in the residual oil, rock pore spaces, and so forth, resulting in decreasing CO₂ storage efficiency. In both injection scenarios, the CO₂ storage ratio decreases as the gas injection rate increases. Gas figuring readily occurs and a large proportion of the injected CO₂ flows through the dominating channels when the gas injection rate is high, resulting in decreased CO₂ storage efficiency in reservoirs. As shown in Fig. 7, the CO₂ storage ratio for storagedriven CO₂ EOR is significantly higher than that for conventional CO₂ EOR under the same conditions (i.e., the same gas injection rate and production time). Thus, it can be reasonably inferred that DME can be used as a favorable agent to improve CO₂ storage in oil reservoirs.

《Fig. 7》

Fig. 7. CO₂ storage ratio versus oil production time for conventional CO₂ EOR and storage-driven CO₂ EOR at different gas injection rates.

The CO₂ storage ratio is then obtained for a scenario involving the water alternating gas injection method. Fig. 8 presents the CO₂ storage ratio according to the oil production time for water alternating CO₂ EOR and water alternating storage-driven CO₂ EOR at different bottomhole pressures. In general, the water alternating gas injection method exhibits a higher CO₂ storage ratio than the conventional gas injection method (Figs. 7 and 8). The water alternating gas injection method overcomes gravity separation and the gas figuring effect, which is beneficial for increasing the sweep efficiency and CO₂ storage efficiency in oil reservoirs. As expected, water alternating storage-driven CO₂ EOR exhibits higher CO₂ storage efficiency in oil reservoirs than water alternating CO₂ EOR: as high as 0.95, even after 3000 d’s production. Fig. 9 presents digital images of the ratio of free gas to dissolved CO₂ in the oil reservoir at a production time of 2000 d for both EOR scenarios, with a bottomhole pressure of 6.0 MPa. It can be seen that the quantity of dissolved CO₂ is higher than that of free-state CO₂. In both developing methods, the relative quantity of dissolved CO₂ gradually decreases as the production wells are approached. However, the presence of DME results in a lower ratio of free gas to dissolved CO₂; this indicates that DME improves the solubility trapping of CO₂ in the in situ oil, demonstrating the superiority of DME in enhancing oil recovery while assisting with CO₂ storage in reservoirs.

《Fig. 8》

Fig. 8. CO₂ storage ratio versus oil production time for water alternating CO₂ EOR and water alternating storage-driven CO₂ EOR at different bottomhole pressures.

《 Fig. 9》

Fig. 9. Digital images of the ratio of free gas to dissolved CO₂ in an oil reservoir when the production time is 2000 d for (a) water alternating storage-driven CO₂ EOR and (b) water alternating CO₂ EOR, at a bottomhole pressure of 6.0 MPa.

《Fig. 10》

Fig. 10. Net CO₂ emitted from incremental production and net CO₂ emissions as a function of cumulative oil production over the lifetime of an oilfield.

《4.4. Economics and operations of storage-driven CO2 EOR》

4.4. Economics and operations of storage-driven CO₂ EOR

The concept of storage-driven CO₂ EOR is proposed for this first time in this work, with the aim of realizing net-zero or even negative CO₂ emissions by sequestrating CO₂ in oil reservoirs while maximizing oil recovery. Here, net CO₂ emissions are defined as the difference between the CO₂ emissions from burning the produced oil (approximately 0.0027 t∙bbl^–1 ) and the sequestrated CO₂ in oil reservoirs during conventional CO₂ EOR or storagedriven CO₂ EOR [73]. Primary and secondary production typically recover around 30% of the in situ oil from a reservoir. According to our simulation results, conventional CO₂ EOR achieves around 60% recovery of the OIP, while storage-driven CO₂ EOR and water alternating storage-driven CO₂ EOR has the technical potential to increase OIP recovery to approximately 68% and 73%, respectively. The economics of CO₂ EOR projects greatly depend on the cost of the CO₂ source and the oil price over the project’s lifetime [73]. Here, we take a hypothetical oilfield with 200 million barrels OIP as an example, as described in Table 2.

《Table 2》

Table 2 Assumptions and physical properties in the hypothetical analysis.

Note: the initial OIP is assumed to be 200 million barrels.

^a At 2.5 bbl∙t^–1 CO₂.

^b At 1.25 bbl∙t^–1 CO₂.

After primary and secondary production, it is assumed that conventional CO₂ EOR, storage-driven CO₂ EOR, and water alternating storage-driven CO₂ EOR are respectively implemented in the hypothetical oilfield for oil production. Here, ‘‘storage-driven CO₂ EOR” refers to DME-assisted CO₂ EOR, and ‘‘water alternating storagedriven CO₂ EOR” refers to water alternating DME-assisted CO₂ EOR.

Fig. 10 illustrates the net CO₂ emitted from the incremental production and the net CO₂ emissions as a function of the cumulative oil production over the lifetime of an oilfield. During primary and secondary production, CO₂ emissions increase linearly with increasing oil production. When conventional CO₂ EOR begins, a proportion of the injected CO₂ is sequestrated in the reservoir, offsetting part of the incremental CO₂ emissions from the oil burning. In comparison, when using storage-driven CO₂ EOR, the sequestrated CO₂ exceeds the CO₂ emissions from oil burning; that is, the sequestrated CO₂ offsets not only the current CO₂ emissions but also some of the past CO₂ emissions, resulting in the linearly decreasing net CO₂ emissions shown in Fig. 10. In a further comparison, when using water alternating storage-driven CO₂ EOR, even more CO₂ is sequestrated in the reservoir, resulting in a greater decrement in the net CO₂ emissions from incremental oil production. As shown in Fig. 10 (right), the net CO₂ emitted from incremental production is 13.8 Mt with conventional CO₂ EOR, while the net CO₂ emissions with storage-driven and water alternating storage-driven CO₂ EOR are both negative, at –6.32 and –14.02 Mt, respectively. These results indicate that the CO₂ sequestrated when using storage-driven and water alternating storage-driven CO₂ EOR far exceeds the net CO₂ emitted from incremental production, suggesting that storage-driven CO₂ EOR is a promising way to achieve a win-win scenario for both oil production and CO₂ sequestration.

《Table 3》

Table 3 Economic analysis of conventional CO₂ EOR and storage-driven CO₂ EOR.

^a If credited with the social cost of carbon (30 USD∙t^–1 ) for incremental storage.

^b At 2.5 bbl∙t^–1 CO₂.

^c At 1.25 bbl∙t^–1 CO₂.

The economics of CO₂ EOR projects strongly depend on the price of oil, cost of CO₂ acquisition, other costs associated with the CO₂ EOR, and so forth [73]. Table 3 presents an economic analysis of conventional CO₂ EOR and storage-driven CO₂ EOR. ‘‘Low,” ‘‘reference,” and ‘‘high” oil prices are assumed to be 40, 60, and 80 USD∙bbl^–1 , respectively, over the life of the EOR project. The economic analysis also considers the CO₂ acquisition cost and other related costs. Even though the oil production from storage-driven CO₂ EOR is higher than that from conventional CO₂ EOR, the EOR project margin of the former is smaller than that of the latter. When the EOR scenarios are adjusted, it can be seen that storage-driven CO₂ EOR—and particularly water alternating storage-driven CO₂ EOR—yields the greatest EOR project margin. The project margins are sensitive not only to the oil price but also to the CO₂ acquisition cost, the imposed charge on CO₂ emissions, and so forth [73]. In other words, without an imposed charge on CO₂ emissions, the implementation of storage-driven CO₂ EOR may not be financially attractive to investors. Our analysis reveals that the additional costs required in order for storage-driven CO₂ EOR to break even with conventional CO₂ EOR range from 15 to 22 USD∙Mt^–1 for water alternating storage-driven CO₂ EOR and from 56 to 60 USD∙Mt^–1 for storage-driven CO₂ EOR.

《5. Conclusions》

5. Conclusions

This work proposes a storage-driven CO₂ EOR method involving the application of DME as an additive to CO₂ in order to improve oil recovery while assisting CO₂ storage in oil reservoirs. The main conclusions are as follows:

Test results show that the introduction of DME greatly inhibits the ‘‘escape” of lighter components from the crude oil, especially under high-temperature conditions; in addition, DME improves CO₂ solubility in crude oil, especially under high-pressure conditions (> 4 MPa).

Simulation results show that storage-driven CO₂ EOR is superior to conventional CO₂ EOR in expanding the sweeping efficiency, which greatly increases oil recovery, especially during the late oil production period. This finding suggests that DME favors sustainable oil recovery by assisting conventional CO₂ EOR. Furthermore, when the development scenarios are transformed to involve water alternating gas injection, oil recovery is more enhanced in comparison with scenarios involving gas injection methods.

Storage-driven CO₂ EOR provides a higher CO₂ storage ratio in oil reservoirs than conventional CO₂ EOR. When water alternating gas injection is used, the CO₂ storage ratio is further improved. This finding suggests that DME can be used as a favorable agent with CO₂ to improve oil recovery while assisting with CO₂ storage in oil reservoirs.

The sequestrated CO₂ from storage-driven CO₂ EOR exceeds the CO₂ emissions that result from burning the produced oil; thus, the sequestrated CO₂ offsets not only current CO₂ emissions but also past emissions. Furthermore, water alternating storage-driven CO₂ EOR sequestrates even more CO₂ in reservoirs than storagedriven CO₂ EOR. Nevertheless, the implementation of storagedriven CO₂ EOR may not be financially attractive to investors compared with conventional CO₂ EOR without any other imposed charge on CO₂ emissions.

《Acknowledgments》

Acknowledgments

We acknowledge the financial support from the Science Foundation of China University of Petroleum, Beijing (2462021QNXZ012 and 2462021YJRC012). This research is also supported by the Fundamental Research Funds for the Central Universities.

《Compliance with ethics guidelines》

Compliance with ethics guidelines

Yueliang Liu and Zhenhua Rui declare that they have no conflict of interest or financial conflicts to disclose.

《Appendix A. Supplementary data》

Appendix A. Supplementary data

Supplementary data to this article can be found online at https://doi.org/10.1016/j.eng.2022.02.010.

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