1 Introduction
The Paris Agreement’s goal is to keep the increase in the global average temperature to well below 2 °C above pre-industrial levels. Therefore, the global power sector is expected to meet the rising demand as access to electricity increases and to provide for a low-carbon future in which end-use activities are increasingly electricity-dependent. In the International Energy Agency’s (IEA) Sustainable Development Scenario, in which global CO2 emissions from the energy sector decrease to zero on a net basis by 2070, CO2 capture, utilization, and storage (CCUS) accounts for nearly 15% of the cumulative reduction in emissions compared with the Stated Policy’s Scenario [7]. The Global Carbon Capture and Storage Institute (GCCSI) has predicted that to achieve the Paris Agreement’s target, global annual carbon capture must reach 5 billion tons by 2050, and more than 2732 large-scale CCUS facilities will be required. This means that between 2020 and 2050, 90 CCUS facilities will be put into operation every year. According to The Role of CCUS in Low-Carbon Power Generation Systems report issued by IEA, 20 CCUS power generation projects are currently under development. Eleven of these 20 projects are in the United States; 3 are in China; 3 are located in the United Kingdom, and Ireland, Korea, and the Netherlands each have 1 project. The two large-scale CCUS power projects that are currently operational and the 20 in development have a combined potential capture capacity of more than 50 Mt of CO2 per year. This is lower than the stated 310 Mt CO2 that will need to be captured from power generation in 2030 under the IEA’s Sustainable Development Scenario, reflecting that carbon capture, utilization, and storage related to power generation are not currently on course.
The application and promotion of CCUS requires a synergy of policies, capital, and technology. At the technical level, CO2 source-sink matching, the total cost of the full CCUS chain, and the reduction of the total CO2 emissions are issues that need to be comprehensively considered [18].
Regarding source-sink matching, Al-Mohannadi and Linke [1] proposed an approach to the systematic design of low cost carbon integration networks for industrial parks through integrated analysis of the sources, utilization, and storage options, as well as the capture, separation, compression, and transmission options. Tan et al. [17] and Lee and Hash [11] developed a source-sink matching model, which provides a methodological basis for the rational use of source and sink resources. Fan et al. [5] developed an optimization model that does not consider the CCUS cost constraints in determining the CO2 reduction potential of existing coal-fired power plants with CCUS systems in China from the perspective of source-sink matching. Ecofys developed a series of methodologies to calculate the underground storage potential of each type of reservoir [4].
Regarding the cost of the CCUS chain, many studies have focused on the specific technical and economic evaluations of CCUS. CCUS demonstration projects launched in China have demonstrated that economic feasibility has become a substitute for technical feasibility and is the main obstacle to the large-scale industrialization of CCUS technology [21]. Zhang et al. [24] evaluated the investment in CCS (carbon capture and storage) retrofitting for two typical types of power plants from the perspective of power generation enterprises. Their results indicate that a large gap exists between the carbon price needed for CCS retrofitting of both typical types of power plants and the current prices on the voluntary emission reduction market. Selosse and Ricci [15] investigated various scenarios with different carbon storage potentials and examined the impact of an increase in carbon transport costs on CCS development. Durmaz [3] employed a simple energy generation model, scrutinized the economic drivers of CCS based on the analytical results, and discussed the possible obstacles that could prevent the widespread implementation of the technology. Lin and Tan [13] proposed a deferred option model to quantitatively evaluate the impacts of low oil price shocks and the carbon trading mechanism on CCUS-enhanced oil recovery (EOR) project investments based on real options theory. They found that the current economic environment is not sufficient to trigger immediate investment in CCUS projects, but the introduction of a carbon trading mechanism could significantly improve the investment value of such a project and reduce the probability of investment failure. As a value-adding benefit, CO2 injected into a mature oil reservoir can enable incremental oil to be recovered. Typically, CO2 flooding allows the recovery of an additional 10-15% of the original oil in place (OOIP) (2010). CO2-EOR is currently one technique being considered as an ultimate long-term geological storage solution for CO2 owing to its economic profitability, i.e., the incremental oil production offsets the cost of the carbon sequestration [19]. Fleten et al. [6] used a traditional dynamic programming approach to investigate the profitability of several value chains for large CO2 producers. Their main conclusion is that CO2-EOR will result in a situation more profitable than venting the CO2 or investing and in CCS alone. The oil revenues from EOR are the main driver of CCS + EOR implementation.
The economic evaluation of the full-chain is greatly affected by energy prices, interest rates, carbon taxes, and renewable energy compensation policies, and it is time-sensitive, whereas energy budgets are not affected by the above factors and are deterministic. In this study, CCUS-EOR based on the post-combustion capture method was analyzed, and a full-chain energy consumption calculation software was developed. By analyzing the energy budget of the CO2 flooding system, the differences in the energy budgets of different injection designs were investigated, and a flooding scheme that improves the energy yield was determined.
2 Deconstruction and coupling of the full-chain system
The main processes of the full-chain system include CO2 capture, transport, and utilization. To meet the conditions for transport and utilization, compression, and purification processes need to be applied after capture. These processes are generally conducted directly in the power plant. In this study, the power plant, CO2 capture, CO2 compression, and purification were collectively referred to as the source of the CO2. During the oil displacement, to ensure continuous operation, CO2 buffer facilities are necessary, so a storage subsystem should be included in the full chain. When the storage pressure is set, the parameter passing of the pressure between the injection and the transport is blocked, and the complexity of the calculation is reduced. In this way, the full-chain CCUS-EOR system was deconstructed and coupled into five subsystems: CO2 source, transport, storage, oil displacement, and separation. Figure 1 shows the key parameters and their passing in each subsystem of the full-chain CCUS-EOR system. The subsystems are thermodynamically connected by the parameter passing, including the mass flow rate, pressure, temperature, and fluid composition and content.
Fig. 1 Schematic diagram of the full-chain CCUS-EOR system |
In the full-chain system, the oil displacement process is regarded as a quasi-closed cycle, and the flow includes CO2 injection, CO2 oil displacement in the oil reservoir, CO2 production, and separation. During the operation of the system, some CO2 leaks out, some is captured by the oil reservoir, and some is not separated from the associated gas. The separated CO2 and supplementary CO2 from the storage system are compressed to the injection pressure and are reinjected. The other processes in the full-chain system are regarded as processes with a constant flow of CO2.
For the oil displacement subsystem, to achieve the miscible pressure, the CO2 injection pressure is usually relatively high. In this study, considering the safety of transport, the pressure of the CO2 in the storage subsystem was set to 10 MPa. The final compression pressure at the power plant (referred to as the transport pressure) is determined by the transportation conditions and storage pressure.
3 Subsystem modeling and optimization
3.1 CO2 source
The power consumption of capture system is defined as ${E}_{1-1}$, and.
${E}_{1-1}= \left({\eta }_{t}, \text{capture process and technology}, {{x}_{co}}_{2}, {y}_{impure}\right),$
where $\eta$ is the thermal efficiency of the power station, which depends on the power plant’s processes and technology); ${{x}_{co}}_{2}$ is the CO2 content; and ${y}_{impure}$ is the content and composition of the impurities.
The simulation optimization of the CO2 capture system revealed that there are two ways to reduce the power consumption.
(1) Improve the efficiency of the power station. When the thermal efficiency of the power station is improved, the coal consumption of the system with a fixed net output decreases, the amount of CO2 that needs to be captured decreases, the total energy consumption for capture decreases, and the net CO2 emissions decrease.
(2) Reduce the equivalent work consumption of the capture system. For the post-combustion capture system, the energy consumption mainly occurs in the desorption process, and the absolute value of the heat consumption or the reduction of the enenrgy grade requires the development of new or improved existing absorbents. In addition, the use of new low-energy capture methods, such as pressurized oxygen-enriched combustion and chemical chain combustion, is also an effective way to reduce the energy consumption.
In this study, the reference plant was an air-based supercritical pulverized coal Rankine cycle plant with a net output of 550 MW. The post-combustion CO2 recovery technology was designed to remove 90% of the CO2 from the flue gas based on a compromise between energy and CO2 emissions [12]. An monoethanolamine (MEA)-based absorption system was used to capture the CO2, which has been demonstrated to be one of the most mature and least expensive technologies. For an amine CO2 capture system, a large amount of heat is required to regenerate the solvent in the stripper. This heat is provided by the steam drawn from the steam cycle. Compressing the captured CO2 for pipeline transport also consumes substantial electrical energy, which is also provided by the plant. To ensure a net output of 550 MW, the steam turbine needs to generate more power and the boiler needs to burn more coal. In this study, it was assumed that the parameters (temperature and pressure) of the steam extracted from the steam turbine can be changed according to the demand of the stripper in the capture system without affecting the performance of the steam turbine itself.
The thermal efficiency (${\eta }_{t}$) of the plant was set to 40.62%, which is the average for 113 supercritical wet cooling units (600–660 MW) in China.
The heat requirements for solvent regeneration mainly depend on the lean sorbent and other system parameters. This heat is provided by the low-pressure steam extracted from the steam turbine. Rochelle [14] summarized the evolution of the heat load for post-combustion CO2 capture since 1976, and the reboiler load decreased from nearly 12 MJ/kg CO2 in 1978 to less than 4.3 MJ/kg CO2. In 2009, for the plant in Mitsubishi, the heat consumption is expected to decrease to less than 2.5 MJ/kg CO2 [8]. The first commercialized CO2 capture plant built by Shell reduced the capture heat consumption to 2.33 GJ/t CO2 [16]. Experiments [20] have shown that for a MEA solvent system with a mass fraction of 20%, the optimal energy consumption for CO2 regeneration is about 3.6 GJ/t CO2. In this study, considering the technological maturity and develop ment of the existing technology, the heat cons umption was set to 2500 kJ/kg CO2. In addition, the circulation of MEA solution in the capture system, the flow of the flue gas, and the discharge of the waste heat all require energy to run the pumps, fans, and other equipment. According to Desideri and Paolucci [2], the power consumption of the post-combustion capture system is 13-120 kWh/t CO2 (46.8-432 kJ/kg CO2). Based on this and the simulation calculation of the capture system, the power consumption was assumed to be 135 kJ/kg CO2.
Except for CO2, most of the other impurities in the captured gas are non-condensable gases, such as N2, O2, and Ar, which will affect the power consumption of the compression process in preparation for transport and injection and may have an impact on the oil displacement. When the MEA-based absorption method is used to remove CO2 from the flue gas, the separated CO2 content can exceed 98%. In this study, the CO2 content (${x}_{{CO}_{2}}$) was assumed to be 98.6%. Owing to a lack of research results on the impact of the above-mentioned impurities on oil displacement and, the impurities were attributed to N2 in the simulation, that is, the captured gas was assumed to contain only two components, CO2 and N2, and the other impurities were calculated as N2. For the transport system, replacing other impurities with N2 will cause a change in power consumption, but calculations show that the error is less than 0.5%.
The power consumption of the compression system is ${E}_{1-2}$, and.
${E}_{1-2}=f \left({t}_{0},{p}_{1} \text{capture process and technology}, {p}_{2}, {{x}_{co}}_{2}, {y}_{impure}\right),$
where ${t}_{0}$ is the ambient temperature; ${p}_{1}$ is the pressure of the captured gas at the outlet of the capture system; and ${p}_{2}$ is the transportation pressure.
For the MEA-based absorption method, the purification of the captured CO2 with a high purity is not necessary. Drying and compression are conducted simultaneously.
Multi-stage compression and intermediate cooling were adopted, and the adiabatic efficiency of the compressor was set to 80%. Based on experience, the temperature of the discharged gas at the outlet of the compressor does not exceed 150 °C, and the compression ratio is about 3, so the optimum intermediate pressure can be determined. The compression system technology is mature, and optimization is quite unlikely.
3.2 Transportation
For large-scale application, pipeline transport is considered. Since the factors influencing the energy consumption related to transportation are clear, to simplify the calculations, the transport path was set as land and plains, with a 45° elbow every 10 km. The transport length was set to 100 km.
The resistance loss was calculated as follows:
$dp=\rho f\frac{dL}{{D}_{i}}\frac{{v}^{2}}{2},$
where ρ is the density; f is the Fanning friction factor; L is the distance/depth; D is the well diameter and v is the flow rate.
The energy consumption related to transportation is the power consumption of the compression in the booster station:
${E}_{2}=f\left(\begin{array}{c}{t}_{0},\text{ compresion process and technology}, {x}_{{CO}_{2}},{y}_{impure},\\ {p}_{2},{p}_{3},\text{pipeline parameters}\end{array}\right),$
where ${p}_{3}$ is the pressure in the storage subsystem.
3.3 Injection and production
When CO2 is injected into a wellbore, there is friction and heat transfer occurs between the borehole wall and the fluid. The calculation model has been described by Zhang et al. [22], and Jiang et al. [9]. The oil displacement injection pipe (DN65) has an inner pipe diameter of 67 mm and an outer pipe diameter of 76 mm.
The power consumption related to the injection includes three compression processes: compressing the CO2 separated from the produced gas and supplemented from the storage system to the injection pressure; and compressing the water to the injection pressure, if the Water Alternate Gas (WAG) flooding method is used.
The power consumption related to the production wells includes the work required to suck out the gas and liquids, i.e., the crude oil and water.
When writing the program, the bottom hole pressure was optimized via EOR modeling, and then, the injection pressure and power consumption were calculated.
3.4 CO2-EOR flooding
The Petrel software was used to simulate and optimize the oil displacement. Oil recovery is influenced by the geologic, structural, and stratigraphic features. To clarify the influence of the flooding method on the energy budget of the full-chain, a typical reservoir model was designed. A 1:1 well-pattern configuration (one injection well and one production well) was adopted. The reservoir depth was set to 800-810 m, the effective thickness of the oil layer was 10 m, the oil reserve was 3.35 × 104 m3, and the original pressure of the reservoir was 20 MPa. The purpose of this model design was to minimize the influence of the reservoir itself to focus on the influence of the EOR flooding method and the gas injection parameters.
3.5 Produced gas separation
Oil displacement in a typical reservoir was simulated. Figure 2 shows the CO2 and CH4 contents of the produced gas for three different impurity contents. The composition of the produced gas was analyzed, and it was found that in the initial phase of injection, the gas produced only contained the gas from the crude oil. During the gas injection, CO2 breakthrough occurred, CO2 began to appear in the produced gas, and its content continued to increase.
Fig. 2 Variations in the N2, CO2, and CH4 contents of the produced gas with injection time |
For pure CO2 injection, it was found that the produced gas did not contain CO2 until 3.13 years after the CO2 injection, and the methane and ethane contents of the produced gas reached 94.8% (76.09% + 18.66%) or greater. From 3.13 years to 4.93 years, the CO2 content was 1%. After 4.93 years, the CO2 content increased rapidly, and it only took 26 days to increase from 1 to 28%. During the next 134 days, the CO2 content increased from 28 to 70%, and it reached 90% after 529 days. Finally, the average CO2 content remained above 96%. The simulation results indicate that the proportion of CO2 kept changing throughout the production period. Large changes in the associated gas volume and the CO2 content severely affect the operation of the equipment, especially the gas processing facilities. Therefore, once gas breakthrough occurs, the produced gas must be separated for re-injection to avoid excessive purchase of CO2 and greenhouse gas emissions. This requires a huge set of gas processing equipment. According to research and practice [23], the following treatment processes can be used for different CO2 gas contents.
i) When the CO2 content of the produced gas is 97% to 98%, the produced gas often does not require decarburization treatment. After pressure regulation, it is directly reinjected into the reservoir for CO2 flooding.
ii) When the CO2 content of the produced gas is less than 3%, and the methane content is greater than 92%, it is close to the technical indicators for commercial natural gas, so it does not need to be decarbonized, and it can be used as commercial gas after water dew point control.
iii) When the CO2 content is between 3 and 97%, the CO2 needs to be separated from the produced gas. The CO2 separated from the production gas is reinjected, and the methane is used as commercial gas.
For the model used in this study, since the content of light hydrocarbons in the associated gas exceeded 94% in the first 4.93 years, it could be directly exported as commercial gas. Thereafter, the CO2 content exceeded 95%, and it could be dried and pressure-regulated and then mixed with the supplementary gas to create the gas to be reinjected. For the following two years (days 1816-2479) due to the large changes in the CO2 content, the CO2 treatment process was relatively complicated.
The most promising high-CO2 treatment methods are cryogenic distillation, triethanolamine (TEA) for large-scale CO2 removal, and membrane permeation. Clifton Goodin, Gene Goar, and others have investigated the investment and operation energy consumption of the CO2 separation units used in the EOR projects run by Shell, Monsabto, Union Texas, and Dow in many oilfields and refineries, and they calculated the relative cost of the gas treatment processes for CO2 contents ranging from 20 to 90 mol%. Figure 3 shows the equivalent heat requirements (CO2 outlet pressure of 3.1 MPa) for the four CO2 removal methods.
Fig. 3 Equivalent heat requirements for CO2 extraction processes |
For CO2-EOR, the gas produced contains large amounts of methane and ethane, and the recovery of hydrocarbons is beneficial to reducing the energy consumption and improving the economy of the project. Thus, in this study, the cryogenic distillation method was used to extract the CO2 from the produced gas, the separated CO2 was reinjected, and the natural gas was sold.
Based on the above results, the energy requirement correlation was fitted for the cryogenic distillation method:
${E}_{sep}=-10.55{ln}\left(x\right)+2.2972.$
Then, the benefits of the oil displacement and separation process, E4, can be expressed as
${E}_{4}=\sum \begin{array}{c} \, {\text{(Oil}} \, {\text{Equivalent}} \, {\text{Work}}{+}{\text{Associated}}\, {\text{Gas}}\, {\text{Equivalent}} \, {\text{Work}}-\\ {\text{production}} \, {\text{gas}} \, {\text{separation}} \, {\text{work}}-{\text{injection}} \, {\text{and}} \, {\text{production}} \, {\text{work).}}\end{array}$
The produced gas was condensed and the heavy hydrocarbons were separated. Then, the CO2 was extracted. It was assumed that the calorific value of the mixed gas was 42 MJ/Nm3, which is same as that of the associated gas even though the mixed gas contained a small amount of N2. For the energy balance calculations, the calorific value of the natural gas was set to 44 MJ/kg. The fuel heat energy and work equivalent value was set to 0.45.
4 Energy flow and carbon footprint of CO2 flooding in the full-chain
With the help of the Petrel software, the CO2-EOR process was optimized for the reservoir model with typical physical characteristics, and the energy flow and carbon footprint of the full-chain CCUS-EOR system were analyzed.
4.1 Influence of EOR methods
In this study, the simulation optimization was conducted for CO2 injection into an oil reservoir via either as continuous gas injection (CGI) or WAG. The results confirm that WAG is an economical and feasible method. The results are shown in Table 1.
Table 1 Energy analysis results of CO2-EOR simulation for the typical reservoir model |
| EOR method | Production | Equivalent work consumption | CO2 sequestration | Equivalent work gained per kg CO2 | ||||
|---|---|---|---|---|---|---|---|---|
| Oil | Associated gas | CO2 extraction | Gas injection | Water injection | Gas and water production | |||
| m3 | m3 | MJ | MJ | MJ | MJ | kg | MJ/kg CO2 | |
| CGI (CO2) | 18,434 | 5,657,029 | − 6,742,346 | − 1,322,319 | 0 | − 104,616 | 16,729,850 | 17.6280 |
| WAG (CO2) | 21,045 | 4,274,791 | − 5,378,858 | − 822,605 | − 777,682 | − 167,775 | 8,001,782 | 42.094 |
| Increase | 13.57% | − 20.22% | 23.91% | − 52.17% | 138.78% | |||
It can be seen from Table 1 that the WAG method greatly improves the benefits of EOR. The increase in the profit is mainly due to the following three aspects. i) The WAG method reduces the significant fluctuation of the gas produced, delays the rate of increase of the gas-oil ratio, and increases the displacement life. The maximum limit of the gas-oil ratio was set to 3000 in this study; otherwise, the oil displacement process stopped operating. For continuous pure CO2 injection, it took 3422 days to reach this limit, while it took 5764 days when the WAG method was used. ii) The WAG method reduces the output of associated gas, which in turn reduces the separation work. iii) Owing to the alternate injection of water, the amount of CO2 (sequestration) is greatly reduced, resulting in a significant increase in the unit CO2 profit.
The WAG method greatly reduces the amount of CO2 sequestration. In the case without considering the carbon tax, it is beneficial for oil companies to reduce the amount of CO2 usage, thereby reducing the cost. When the environmental benefits of CO2 sequestration are considered, the carbon tax benefits should be taken into account. Figure 4 shows the economic change in the CO2-EOR of the simulated reservoir in response to changes in the carbon tax (only the oil and gas revenue and carbon tax are considered. The electricity price was set to 0.38¥/kWh). It can be seen that as the carbon tax increased, the economic advantage of the WAG method decreased comparing to the continuous pure CO2 injection method. However, even when the carbon tax reached €55, the economic advantage of the WAG was still obvious.
Fig. 4 Effect of the carbon tax on the economics of CO2-EOR for the typical reservoir model |
4.2 Influence of injection gas composition
The continuous gas injection methods were simulated. The gas was CO2 or CO2 with different proportions of N2. The CO2 content of the gas captured using the post-combustion capture method is > 98%, while it is less than 98% for oxygen combustion capture method. The data analysis results are shown in Table 2.
Table 2 Simulation results for a reservoir with typical physical characteristics |
| Boundary conditions: The pressure at the bottom of the production well was set as 5 MPa | |||||||
|---|---|---|---|---|---|---|---|
| Injection gas content | Production oil | Injection gas | Oil change ratio | EOR duration | Equivalent work gained | ||
| Total gas | CO2 | ||||||
| m3 | m3 | t | toil/tgas | toil/tCO2 | day | MJ/kg CO2 | |
| CO2 | 18,434 | 13,051,111 | 25,799 | 0.5674 | 0.5674 | 3422 | 17.628 |
| CO2:N2 = 0.989:0.011 | 18,344 | 12,836,782 | 24,994 | 0.5741 | 0.5828 | 3377 | 18.552 |
| CO2:N2 = 0.97:0.03 | 18,353 | 12,758,040 | 24,463 | 0.5844 | 0.5958 | 3351 | 18.174 |
| CO2:N2 = 0.95:0.05 | 18,507 | 13,350,481 | 25,072 | 0.5674 | 0.5862 | 3468 | 18.509 |
| CO2:N2 = 0.90:0.10 | 18,501 | 13,352,959 | 23,757 | 0.5780 | 0.6184 | 3468 | 19.487 |
It was found that the difference in the cumulative oil was within 1% for the injection of gases with different N2 contents. Considering the simulation error, it can be concluded that the N2 content has no obvious effect on the oil yield within the simulated range. However, the unit CO2 equivalent work gained increased with increasing N2 content. This is mainly because the presence of N2 reduced the CO2 usage, but the oil production was only slightly different.
4.3 Influence of EOR methods
Crude oil contains light hydrocarbons such as CH4, which are partially separated from the crude oil during the production process. Figure 5 shows the variations in the CO2 and CH4 contents of the gas produced when the CO2 continuous injection and WAG methods are used.
Fig. 5 Variations in the CO2 and CH4 contents of the produced gas with time |
It can be seen from the simulation in Sect. 4.2 that the presence of a small amount of non-condensable gas has little effect on the oil recovery. If the CH4 content of the produced gas is less than 3% after CO2 breakthrough occurs, the produced gas can be directly reinjected without separation. This reduced the separation work and improves the benefits of the full-chain system. Therefore, a flooding scheme with a variable-CO2-content was designed, in which the CO2 and CH4 contents of the injected gas change with increasing injection time. The gas composition was designed based on the simulation results for continuous CO2 injection. That is, when the average CO2 content of the produced gas exceeded 96% and 98%, it was used as the gas injection composition. The results are shown in Table 3.
Table 3 Influence of the CH4 contents of injected gas on the energy budget of EOR |
| perEOR method | Production | Equivalent work consumption | Equivalent work gained | CO2 sequestration | Equivalent work gained per kg CO2 | ||||
|---|---|---|---|---|---|---|---|---|---|
| Oil | Gas | Gas separation | Injection and production | ||||||
| m3 | m3 | MJ | MJ | MJ | kg | MJ/kg CO2 | |||
| CGI (CO2) | 18,434 | 5,657,029 | − 6,742,346 | − 1,426,935 | 295,040,745 | 16,729,850 | 17.628 | ||
| WAG (CO2) | 21,045 | 4,274,791 | − 5,378,858 | − 1,768,063 | 337,217,574 | 8,001,782 | 42.094 | ||
| Mean injection gas content (CO2: CH4) | 0.98 | CGI | 19,677 | 6,255,996 | − 7,804,335 | − 1,621,566 | 316,460,138 | 16,342,603 | 19.355 |
| WAG | 21,125 | 4,261,366 | − 5,588,987 | − 1,824,216 | 339,535,341 | 7,700,037 | 44.042 | ||
| 0.96 | CGI | 19,455 | 5,788,515 | − 7,305,274 | − 1,598,413 | 313,101,857 | 15,476,283 | 20.221 | |
| WAG | 20,967 | 6,416,204 | − 8,769,794 | − 2,133,706 | 335,835,226 | 7,855,226 | 42.713 | ||
It can be seen from Fig. 5 that the WAG method increases the oil recovery factors because the intermittent water injection causes the flow of the produced gas to fluctuate less, effectively reducing the gas-oil ratio of the produced gas and increasing the EOR duration by more than 40%.
It can be seen from Table 3 that allowing the existence of CH4 improves the income per unit CO2 compared with injecting pure CO2. This may be because CH4 is a type of organic matter, which is soluble in crude oil, so its presence promotes fluidity and improves oil recovery. For the WAG method, although the power consumption of the injection and production processes increases, the separation work decreases more. The equivalent work gained for a mean CH4 content of 98% is higher than that for 96%.
4.4 Multi-well combined injection and production EOR design
It can be seen from Fig. 5 that the CO2 content of the produced gas quickly reached > 95% after CO2 breakthrough occurred. After cooling, the condensable gas was separated. Except for the CO2, most of the remaining gas was CH4. Based on the results presented in Sect. 4.3, variable-component gas injection has no significant adverse effects on the unit CO2 income. To decrease the separation work, we propose a direct reinjection scheme in which the produced gas is used as injection gas after cooling.
Figure 6 shows a schematic diagram of the design of the multi-well combined injection and production (MWCIP) scheme. The key to the realization of MWCIP is to set up a control system to dynamically monitor the composition of the gas produced by different production wells, and mix the gas separated from the production well with the supplementary gas of the buffer tank according to the designed injected gas composition. At the beginning of the EOR, CO2 is injected, and the associated gas is composed of hydrocarbons. After cooling and other handling processes, the gas can exported as natural gas. After a period of time, CO2 begins to appear in the produced gas. When the CO2 content does not exceed the allowable CO2 content for natural gas, the associated gas does not need to be separated. When the content increases further, the produced gas needs to be separated, the separated light hydrocarbons are exported as natural gas, and the CO2 is reinjected. When the CO2 content of the produced gas exceeds the set value (e.g., 94%, the CO2 content can exceed 96% when mixed with the supplementary CO2 from the storage tank), then after the necessary treatment, the produced gas is mixed with supplementary CO2 and is reinjected. The composition of the reinjected gas changes with the composition of the produced gas, which is referred to as variable composition injection.
Fig. 6 Schematic diagram of the design of the multi-well combined injection and production (MWCIP) scheme |
For the WAG method, the gas injection into a single well is discontinuous, while the production is continuous. Simulation and application results have shown that the flow rate of the produced gas accounts for 38-54% of the injection flow rate. Thus, two or more injection-production modules are used for joint operation. When the CO2 content of the production gas is greater than the set value, the production gas enters the processing station first. After the gas is cooled, complemented, mixed, compressed, and subjected to other processes, it is reinjected according to the injection plan.
The advantages of MWCIP is that after the CO2 content reaches a high value, the produced gas can be used as reinjection gas after simple gas processes, such as cooling, which decreases the separation work.
4.5 Full-chain CCUS-EOR energy flow and carbon footprint
Fig. 7 Flow chart of the energy budget calculation for the full-chain CCUS-EOR system |
Fig. 8 Diagram showing the energy flow and carbon flow of the full-chain CCUS-EOR |
It can be seen that the equivalent power consumption of the post-combustion capture and compression accounts for 30% of the net output of the power station based on the same net output power and a capture rate of 90%. In addition, it was found that the oil displacement equivalent energy gain is much higher than the power consumption of the capture, compression, and other processes, that is, CCUS-EOR is an application with a positive energy gain. It can be seen from the schematic diagram of the carbon flow that the actual reduction of the CO2 emissions is 84% compared to a power station without CO2 capture.
5 Conclusions
(1) From the perspective of the energy budget, the energy gained in CCUS-EOR is greater than the energy consumed. CCUS-EOR is a CO2 utilization application with positive energy benefits.
(2) The energy budget of the oil displacement was deconstructed, and the advantages of the WAG method were confirmed. The source of this advantage is that the intermittent injection of water reduces the gas-oil ratio, increases the EOR duration, and improves the recovery factor. The flow rate of the produced gas decreases, which reduces the separation work. The amount of CO2 used decreases, and the equivalent work gained of per kg of CO2 increases.
(3) The presence of CH4 in the injection gas can improve the recovery; therefore, a multi-well combined injection-production process is proposed. The reason why the MWCIG method improves the profit is that when the CO2 content of the production gas exceeds a certain value, the associated gas is not separated and is reinjected directly after simple gas processing, which reduces the separation work, thereby further improving the benefits of the full-chain system.
Abbreviations
D :Well diameter (m);E :Power consumption (MW);f :Fanning friction factor;L :Distance/depth (m);p :Pressure (MPa);x :Gas content;y :Gas content;η t :Thermal efficiency (%);ρ :Density (kg/m3);EGS:Enhanced geothermal system;EOR:Enhanced oil recovery;CCS:Carbon capture and storage;CCUS:CO2 capture, utilization, and storage;CGI:Continuous gas injection;MEA:Monoethanolamine;MWCIP:Multi-well combined injection and production;WAG:Water alternating gas
Acknowledgements
This work was supported by the National Key Research and Development Program of China (No. 2016YFB0600805).
Authors’ Contributions
All authors contributed to the study conception and design. Material preparation, data collection and analysis were performed by FZ, XR, HY, FX and JP. The first draft of the manuscript was written by FZ and all authors commented on previous versions of the manuscript. All authors read and approved the final manuscript.
Funding
This work was supported by the National Key Research and Development Program of China (No. 2016YFB0600805).
Availability of data and materials
All data generated or analysed during this study are included in this published article.
Declarations
Ethics approval and consent to participate
Not applicable.
Consent for publication
Not applicable.
Competing interests
We declare that we have no financial and personal relationships with other people or organizations that can inappropriately influence our work, there is no professional or other personal interest of any nature or kind in any product, service and/or company that could be construed as influencing the position presented in, or the review of, the manuscript “Analysis and optimization of energy flow in the full-chain of carbon dioxide capture and oil recovery”.
