Technical and Economic Evaluation of CO 2 Capture and Reinjection Process in the CO 2 EOR and Storage Project of Xinjiang Oilﬁeld

: CO 2 capture and reinjection process (CCRP) can reduce the used CO 2 amount and improve the CO 2 storage efﬁciency in CO 2 EOR projects. To select the best CCRP is an important aspect. Based on the involved equipment units of the CCRP, a novel techno-economic model of CCRP for produced gas in CO 2 EOR and storage project was established. Five kinds of CO 2 capture processes are covered, including the chemical absorption using amine solution (MDEA), pressure swing adsorption (PSA), low-temperature fractionation (LTF), membrane separation (MS), and direct reinjection mixed with purchased CO 2 (DRM). The evaluation indicators of CCRP such as the cost, energy consumption, and CO 2 capture efﬁciency and purity can be calculated. Taking the pilot project of CO 2 EOR and storage in XinJiang oilﬁeld China as an example, a sensitivity evaluation of CCRP was conducted based on the assumed gas production scale and the predicted yearly gas production. Finally, the DRM process was selected as the main CCRP associated with the PSA process as an assistant option. The established model of CCRP can be a useful tool to optimize the CO 2 recycling process and assess the CO 2 emission reduction performance of the CCUS project.


Introduction
CO 2 capture and storage (CCS) has been an effective measure to reduce CO 2 emissions into the atmosphere. Injecting CO 2 into oil reservoirs not only can store CO 2 underground, but also can achieve EOR (enhanced oil recovery). However, field experiences show that only less than 50% of the injected CO 2 can be stored if no recycling of the produced CO 2 is considered. A CO 2 capture and reinjection process (CCRP) should be taken to reduce the purchased CO 2 and increase the CO 2 storage efficiency [1]. In the United States and Canada, there have been a large number of CO 2 EOR and storage projects, such as the projects in Weyburn, Rangely, and Kelly-Snyder oil fields [2]. These projects have extensive sources of CO 2 , which are captured from natural gas reservoirs or coal gasification plants, transported, and injected in a supercritical state on a large scale. In the earlier days, there were cases using membrane separation (MS) and chemical absorption (CA) methods to capture the CO 2 produced in wells [3][4][5][6]. At present, direct reinjection mixed with the necessary pure CO 2 (DRM) to improve the purity of injected gas is commonly adopted especially in the mid-late stage of the CO 2 EOR and storage project [7]. In China, some CO 2 EOR projects have also been conducted, but most of them are on a small scale using

Potential CCRPs in the CO 2 EOR and Storage Project in XinJiang Oilfield
In many oil fields in the world, CO 2 EOR and storage has been already a common technology, but this is still in its infancy in China. In XinJiang oilfield China, the pilot test of CO 2 EOR and storage has been conducted, but the disposal of produced gas in CO 2 flooding needs to be further studied.
XinJiang oilfield is located in the Junggar Basin of China. The blocks 530 and 53D in XinJiang oilfield are the potential sites for CO 2 EOR and storage, which are about 35 km and 20 km away from XinJiang city, respectively, as shown in Figure 1. After a preliminary evaluation, the Kexia group of block 530 was selected as the target reservoir. This reservoir is a sandy conglomerate formation with a buried depth of 2400 m and a thickness of 18.6 m. The average porosity and permeability are 11.40% and 19.20 md, respectively. 79 wells were deployed in an inverted seven-spot pattern with a well spacing of 280 m × 395 m for water flooding. Due to the low permeability, hydraulic fracturing was conducted in wells. At present, there are 49 wells opened with a daily fluid of 253 t, a daily oil of 68 t, a water cut of 75.9%. 66.25 × 10 4 t oil has been produced, and the current oil recovery degree is 26.72%. Therefore, based on the above analysis, five types of CCRPs were designed conceptually for the CO2 EOR and storage project in block 530, namely the PSA, MS, LTF, CA-MDEA capture process, and DRM process. Overall, CCRP can be divided into the following three modules: product gas treatment module, carbon capture module, and injection module, and the carbon module is the key difference between the above five types of CCRPs. Hence, taking the PSA capture process as an example (Figure 2a), the detailed capture process is explained: at first, the produced gas is separated from the produced fluid by a three-phase separator, and the solid particles and liquid droplets in the gas are removed through the gas-liquid separator and cyclone separator; then, the produced gas is compressed and pass through the molecular sieve for deep dehydration, and further, the high-purity CO2 is captured from the produced gas using the PSA system; finally, the captured CO2 is reinjected back to the oil reservoir at 20 MPa and 40 °C by compressors. For the MS and CA-MDEA processes, they have the similar CCRPs to that of the PSA process except for the CO2 capture system, while the CO2 captured in the LTF process should be injected by booster pump at a liquid state under the condition of 20MPa and −20 °C [27][28][29]. When the DRM process is adopted (Figure 2b), the produced gas can be reinjected directly after being pretreated. If necessary, before reinjection, the produced gas should be mixed with pure CO2 to reach the required gas amount and CO2 purity. For the disposal of produced gas in CO 2 flooding in block 530, many methods have been assessed. The schemes of direct reinjection mixed with pure CO 2 (DRM), combustion and flue gas reinjection (CFGR), and CO 2 capture and reinjection were analyzed. The study shows that: (1) the minimum miscible pressure between pure CO 2 and crude oil at the reservoir temperature of 64 • C is 21.25 MPa. Under the original formation pressure of 24 Mpa, if the CO 2 content in the produced gas mixed with necessary pure CO 2 is greater than 90 mol%, it can also achieve miscible flooding; (2) if the produced gas is used for combustion in a heating furnace or a gas turbine, its calorific value should be larger than 584 KJ/mol, and the CO 2 content in the produced gas cannot be higher than 40 mol%, besides, the flue gas produced by combustion can cause severe corrosion and explosion risk during reinjection, hence, the CFGR scheme is unattractive; (3) to purify the CO 2 in the produced gas for reinjection is a commonly used method to dispose of the produced gas, however, four types of CO 2 capture processes have different applicable conditions, thus the CO 2 capture process needs to be further evaluated and optimized according to the CO 2 content and scale of the produced gas.
Therefore, based on the above analysis, five types of CCRPs were designed conceptually for the CO 2  capture process, and DRM process. Overall, CCRP can be divided into the following three modules: product gas treatment module, carbon capture module, and injection module, and the carbon module is the key difference between the above five types of CCRPs. Hence, taking the PSA capture process as an example (Figure 2a), the detailed capture process is explained: at first, the produced gas is separated from the produced fluid by a three-phase separator, and the solid particles and liquid droplets in the gas are removed through the gas-liquid separator and cyclone separator; then, the produced gas is compressed and pass through the molecular sieve for deep dehydration, and further, the high-purity CO 2 is captured from the produced gas using the PSA system; finally, the captured CO 2 is reinjected back to the oil reservoir at 20 MPa and 40 • C by compressors. For the MS and CA-MDEA processes, they have the similar CCRPs to that of the PSA process except for the CO 2 capture system, while the CO 2 captured in the LTF process should be injected by booster pump at a liquid state under the condition of 20MPa and −20 • C [27][28][29]. When the DRM process is adopted (Figure 2b), the produced gas can be reinjected directly after being pretreated. If necessary, before reinjection, the produced gas should be mixed with pure CO 2 to reach the required gas amount and CO 2 purity. Therefore, based on the above analysis, five types of CCRPs were designed conceptually for the CO2 EOR and storage project in block 530, namely the PSA, MS, LTF, CA-MDEA capture process, and DRM process. Overall, CCRP can be divided into the following three modules: product gas treatment module, carbon capture module, and injection module, and the carbon module is the key difference between the above five types of CCRPs. Hence, taking the PSA capture process as an example (Figure 2a), the detailed capture process is explained: at first, the produced gas is separated from the produced fluid by a three-phase separator, and the solid particles and liquid droplets in the gas are removed through the gas-liquid separator and cyclone separator; then, the produced gas is compressed and pass through the molecular sieve for deep dehydration, and further, the high-purity CO2 is captured from the produced gas using the PSA system; finally, the captured CO2 is reinjected back to the oil reservoir at 20 MPa and 40 °C by compressors. For the MS and CA-MDEA processes, they have the similar CCRPs to that of the PSA process except for the CO2 capture system, while the CO2 captured in the LTF process should be injected by booster pump at a liquid state under the condition of 20MPa and −20 °C [27][28][29]. When the DRM process is adopted (Figure 2b), the produced gas can be reinjected directly after being pretreated. If necessary, before reinjection, the produced gas should be mixed with pure CO2 to reach the required gas amount and CO2 purity.   According to the function of each module, some necessary simplifications were carried out to unify the five types of CCRPs into one process for flexible technical and economic evaluation, as shown in Figure 3. In this simplified process, the main equipment units are gas-liquid separator, molecular sieve, compressor, boost pump, and carbon capture module. Among them, the gas-liquid separator and molecular sieve are units for dust removal and dehydration, compressor and boost pump are used to transport and inject liquid or gas CO 2 , and carbon capture module is the critical unit for capture CO 2 . Since the produced gas is processed on-site, the pipeline is not considered in this simplified process. The simplified process corresponding to each CCRP is shown in Table 1. According to the function of each module, some necessary simplifications were carried out to unify the five types of CCRPs into one process for flexible technical and economic evaluation, as shown in Figure 3. In this simplified process, the main equipment units are gas-liquid separator, molecular sieve, compressor, boost pump, and carbon capture module. Among them, the gas-liquid separator and molecular sieve are units for dust removal and dehydration, compressor and boost pump are used to transport and inject liquid or gas CO2, and carbon capture module is the critical unit for capture CO2. Since the produced gas is processed on-site, the pipeline is not considered in this simplified process. The simplified process corresponding to each CCRP is shown in Table 1.

Establishment of Technical and Economic Evaluation Model of CCRP
To be used to flexibly calculate the process parameters, cost, energy consumption, and CO 2 capture efficiency for different CCRPs, the indicator calculation model for each possible involved equipment unit was established. Based on the equipment units, the indicators of the entire CCRP can be obtained.

Calculation Method of Capital Cost
Based on the main technical parameters of each equipment unit, the capital cost and the power can be estimated [30]. The main power/energy consumption units in CCRP include compressor, booster pump, and carbon capture module. For the no energy consumption units such as the gas-liquid separator and molecular sieve, their capital costs can be estimated by the analogy method.

Gas-Liquid Separator and Molecular Sieve
In CCRPs, both gas-liquid separator and molecular sieve have extremely low energy consumption in the process of dust removal and dehydration for produced gas, thus the analogy method is used to obtain their capital costs. According to the scale of the disposal gas, the capital cost can be calculated based on the following empirical formula [31]: (1) where C sep is the capital cost of gas-liquid separator, US$; M train is the mass flow rate of disposal gas, t/d; C mol is the capital cost of molecular sieve, US$; α sep1 and α sep2 are the cost coefficients of gas-liquid separator, taking 11 US$ and 0.6, respectively; α mol1 and α mol2 are the cost coefficients of molecular sieve cost, taking 19 US$ and 0.6, respectively. The above cost coefficients are obtained based on the capital cost of the gas-liquid separator and molecular sieve in the Chinese oilfield [13,32,33].

Compressor
In oil fields, compressors and booster pumps are the most used equipment to increase fluid pressure. Compressors are suitable for CO 2 in gas and supercritical state, while pumps are suitable for liquid CO 2 or high-dense CO 2 . For the capital cost of compressors, it can be estimated according to the CO 2 flow rate and the ratio of gas pressures at the outlet and inlet of the compressor. For the estimation of the compressor power, the physical properties of CO 2 gas and the multi-stage compression process with the optimal compression ratio for each stage should be considered.
(1) For the capital cost of the compressor [34], where C comp is the total capital cost of compressor, US$; m train is the mass flow rate of CO 2 gas in each compressor unit, kg/s; N train is the number of parallel compressors, dimensionless; m CO 2 is the CO 2 mass flow rate, t/d; P in-comp is the inlet pressure of compressor, MPa; P out-comp is the outlet pressure of compressor, MPa; α comp1 , α comp2 , α comp3 and α comp4 are the cost coefficients of compressor, taking 0.12 × 10 6 US$·kg −1 ·s, −0.71, 1.32 × 10 6 US$·kg −1 ·s and −0.60, respectively, which are converted from € into US$ at the current exchange rate [34].
(2) For the compressor power [35], where W comp is the compressor power, kW; Z s is the average compression factor of CO 2 at each stage, dimensionless; T in-comp is the inlet temperature of compressor, K; R is the universal gas constant, 8.314 kJ/(kmol·K); M CO 2 gas is the molar mass of CO 2 gas, if the CO 2 purity of gas is 100%, M CO 2 gas = 44.01 kg/kmol; η comp is the compressor efficiency, 0.75 is often used; k s is the average heat capacity ratio of CO 2 at each stage, 1.391 is often used; CR is the optimal compression ratio, 2.4-3.0 is often used; N stage is the number of compression stages. The maximum power of a single compressor was assumed to be 40MW. If the required compression power is greater than 40 MW, several parallel compressors will be used, and the N train is W comp /40.

Booster Pump
In the CCRP, after being purified and liquefied, the liquid CO 2 can be transported and injected into the subsequent processes using booster pumps. The capital cost of booster pumps mainly depends on the pump power, while the pump power is selected based on the flow rate and pressures of CO 2 at the inlet and outlet of the pump [36].
(1) For the capital cost of the pump, (2) For the pump power, where C pump is the capital cost of booster pump, US$; W pump is the booster pump power, kW; P out-pump is the outlet pressure of booster pump, MPa; P in-pump is the inlet pressure of booster pump, MPa; ρ l-CO 2 is the density of liquid CO 2 , 1177 kg/m 3 ; η pump is the efficiency of booster pump, 0.75 was assumed; α pump1 and α pump2 are the cost coefficients of pump, taking 1.14 × 10 6 US$·W −1 and 0.07 × 10 6 US$, respectively.
(1) Pressure swing adsorption (PSA) In the PSA module, according to the difference of adsorption characteristics of different kinds of gases in physical adsorbent with pressure, specific gas (e.g., CO 2 ) will be absorbed and desorbed through periodic pressure changes to achieve the purpose of gas separation and purification [37]. The capital cost of the PSA CO 2 capture module is mainly composed of three parts: the capital cost of adsorption towers, the purchase cost of adsorbent, and the capital cost of the compressor.
First, the mass of CO 2 adsorbent for PSA can be calculated based on the gas production, CO 2 content in produced gas, and the adsorption capacity of the adsorbent [38]. (9) where W PSA-ad is the mass of adsorbent in PSA module, kg; Q PSA-g is the flow rate of the feed gas in the adsorption tower of PSA module, m 3 /s; t PSA-ad is the adsorption time of single bed operation of the tower in PSA module, s; y PSA-CO 2 is the CO 2 mole fraction of the feed gas in PSA module, dimensionless; ∆q PSA is the adsorption capacity in PSA module which depends on the adsorbent, for silica 0.35-0.50 kg/kg is taken, for activated carbon 0.40-0.50 kg/kg is taken, and for molecular sieves, 0.22-0.26 kg/kg is taken [39]; n PSA-bed is the number of beds for continuous adsorption in a single tower in PSA module, dimensionless.
Then, according to the mass of the adsorbent and the design requirements of the adsorption tower, the height, diameter, and number of the adsorption towers can be calculated [40].
n PSA−tower = W PSA−ad ρ PSA−ad 4 3.14D PSA 2 H PSA (12) where H PSA is the height of the tower in PSA module, m; n PSA-tower is the number of towers in PSA module dimensionless; ρ PSA-ad is the adsorbent density in PSA module, for silica 0.70-0.82 kg/m 3 is taken, for activated carbon 0.45-0.50 kg/m 3 is taken, and for molecular sieves, 0.61-0.67 kg/m 3 is taken; v PSA-g is the gas flow speed in the tower, 0.05 m/s was assumed according to common design of CO 2 absorption tower [41]; D PSA is the diameter of the tower in PSA module, m. Finally, through the unit height capital cost of the tower and the sizes of the tower, the capital cost of adsorption towers can be obtained [41]. C PSA−tower = C PSA−pc × H PSA × n PSA−tower (13) log C PSA−pc = α PSA1 log D PSA + α PSA2 (14) where C PSA-tower is the capital cost of towers in PSA module, US$; C PSA-pc is the unit height capital cost of the tower in PSA module, US$/m; α PSA1 and α PSA2 are the cost coefficients of PSA module, taking 1.34 and 4.27, respectively. CO 2 adsorbent with excellent adsorption and desorption performance should be selected for PSA. The commonly used adsorbents can be classified into carbon-based adsorption materials (e.g., activated carbon) and zeolite adsorption materials (e.g., 13X molecular sieve). The 13X is often used because of its large pore volume, high adsorption capacity, and high separation coefficient. Hence, the purchase cost of adsorbent can be determined as follows [39]: (15) where C PSA-ad is the purchase cost of adsorbent in PSA module, US$; P PSA-ad is the unit cost of adsorbent, for silica 1.58 US$/kg is taken, for activated carbon 0.47 US$/kg is taken, and for molecular sieves, 1.58 US$/kg is taken. Based on the above, the capital cost of the PSA module can be calculated.
where C PSA is the capital cost of the PSA module, US$. The power consumption in the PSA module mainly occurs when the feed gas is compressed to meet the adsorption pressure in towers, thus the power of the PSA module is equal to the power of the compressor. (17) where W PSA is the power of the PSA module, kW.
It should be noted that if the pressure of feed gas is high enough which can meet the requirement of adsorption pressure in towers, the compression process can be neglected in the PSA module, no power consumption is considered.
(2) Membrane separation (MS) In the MS module, the penetrability difference of each component in feed gas through the polymer membrane under a certain pressure is used to separate the CO 2 from the hydrocarbon gas. The capital cost of the MS module mainly comes from the compressor and the MS device [42]. The capital cost of the MS device, which consists of membrane material and frame, is determined by the film type and film property. The components in feed gas can be divided into the high-speed group and the low-speed group according to their difference in permeation rate through the membrane. Hence, the film area can be estimated as follows [5]: where A m is the film area in MS module, m 2 ; Y MS-F is the mole fraction of high-speed group (CO 2 ) in feed gas in MS module, dimensionless; Y MS-R is the mole fraction of the high-speed group in the nonpenetrating gas in MS module, dimensionless; Y MS-1 is the mole fraction of the high-speed group in the permeation gas in MS module, dimensionless; Q MS-P is the flow rate of permeation gas in MS module, kmol/s; R MS-f is the weighted average permeation velocity of the high-speed group in MS module, m/s; P MS-1 is the total pressure on the low-pressure side of the membrane in MS module, bar; and P MS-2 is the total pressure on the high-pressure side of the membrane in MS module, bar. The membranes used for CO 2 separation are mainly made of high molecular polymers, such as polydimethylsiloxane, cellulose acetate, polyimide, polysulfone, polycarbonate, etc. Due to the high permeation speed and excellent separation effect, polyimide has been widely used in China, and its hollow fiber membrane module has a low cost, high loading density, and adaptability to high pressure, which is often selected. [43] Hence, based on the Energies 2021, 14, 5076 9 of 26 film area and type, the capital cost of MS device can be estimated using the equations as follows [42]: where C M is the capital cost of MS device, US$; I m is the cost of membrane material in MS device, US$; I mf is the cost of membrane frame in MS device, US$; K m is the membrane material cost of unit film area, 4.73-18.93 US$/m 2 for hollow fiber membrane module; K mf is the membrane frame cost of unit film area, 315.46 US$/m 2 , the above MS device costs of unit film area are from the price survey in China; and α m1 and α m2 are the cost coefficients of MS module, taking 2000 and 0.7, respectively. Hence, based on the above, the capital cost of the MS carbon capture module can be obtained.
where C MS is the capital cost of MS module, US$. Similarly, the power consumption of the MS module mainly occurs when the feed gas is needed to be compressed to form a high-enough permeation pressure difference on both sides of the membrane, so the power of the MS module is equal to the power of the compressor. W MS = W comp (23) where W MS is the power of the MS module, kW.
(3) Low-temperature fractionation (LTF) In the LTF module, the separation of CO 2 from feed gas is realized based on the difference in boiling temperature of each component in the feed gas. The pressurization effect of the compressor and the cooling effect of the heat exchanger is utilized to achieve the gas liquefaction. For the heat exchanger, after the structure is determined, the technical and economic model of the heat exchanger can be established based on the heat exchange area [15]. The heat exchange area can be determined by the parameters in the operating environment of the heat exchanger. When the heat exchanger recovers waste heat, it also needs to consume some power to overcome the flowing resistance of fluid passing through the heat exchanger and the cooler. This power consumption is the operating cost of the equipment [44].
where C hx is the capital cost of the heat exchanger, US$; A hx-p is the actual heat exchange area in heat exchanger, m 2 ; α hx1 , α hx2 and α hx3 are the cost coefficients of heat exchanger, taking 9.41 × 10 4 US$, 1.13 × 10 3 US$ and 0.98, respectively; α hx4 is the coefficients obtained by unit conversion, 0.28; Q hx is the heat flow in heat exchanger, kJ/h; m hf is the mass flow rate of hot fluid in heat exchanger, kg/h; C p is the specific heat capacity of fluid in heat exchanger in heat exchanger, kJ·kg −1 · • C −1 ; ∆t hx is the temperature change of hot fluid in heat exchanger, • C; ∆T m is the logarithmic mean temperature changes of heat exchanger, • C; T HI is the hot fluid temperature at the inlet of the heat exchanger, • C; T HO is the hot fluid temperature at the outlet of the heat exchange, • C; T CI is the cold fluid temperature at the inlet of the heat exchanger, • C; T CO is the cold fluid temperature at the outlet of the heat exchanger, • C; W hx is the power of heat exchanger, kW; and K hc is the heat transfer coefficient between the hot fluid and the cold fluid, taking 1134 W/(m 2 · • C) (between liquid-phase fluids) or 279 W/(m 2 · • C) (between gas-phase fluids). Hence, the capital cost of the LTF module is mainly composed of the capital costs of the compressor and heat exchanger [45]. Similarly, the power of LTF covers the powers of the compressor and heat exchanger.
where C LTF is the capital cost of LTF module, US$; W LTF is the power of LTF module, kW.
(4) Chemical absorption (CA-MDEA) In the CA module, CO 2 is captured from the feed gas by a chemical reaction between alkaline solution and CO 2 . CO 2 is absorbed by the alkaline solution at a low temperature and desorbed at a high temperature. The capital cost of the chemical absorption module includes the capital costs of solvent towers, booster pumps, heat exchangers, and the purchase cost of chemical absorption solution [14]. MDEA (methyldiethanolamine) is the often used solvent for CO 2 chemical absorption. Hence, the MDEA is taken as a typical example to establish the capital cost calculation model of CA.
The solvent towers mainly include the absorption tower and the desorption tower. For the absorption tower, firstly, the diameter of the tower can be determined according to feed gas flow; and then, the height of the tower can be estimated according to the tower diameter and CO 2 absorption capacity of MDEA; finally, based on the cost of unit height tower, the capital cost of absorption tower can be obtained [40,[46][47][48].
where D CA-ab is the diameter of absorption tower in CA module, m; V CA-ab is the flow rate of feed gas in the absorption tower in the CA module, m 3 /h; v CA-ab is the gas flow velocity in the adsorption tower which should make sure that the CO 2 in feed gas can fully combine with the MDEA solution, 0.722 m/s was used according to the common design for the chemical absorption tower [41]; H CA-ab is the cumulative height of absorption towers in the CA module, m; m CA-CO 2 is the mass flow rate of CO 2 gas in CA module, kg/h; K Ga is the mass transfer coefficient, 20 kmol/(m 3 ·h·atm) was taken from the calculation process of Zhang [46]; Y CO 2 -inab is the CO 2 content of inlet gas in the absorption tower, g/m 3 ; Y CO 2 -outab is the CO 2 content of outlet gas in the absorption tower, g/m 3 ; A CA-t is the cross-section area of absorption tower in CA module, m 2 ; ∆P CA-m is the driving pressure difference, the default value is 0.026 atm at the oilfield site; C CA-ab is the cost of the unit height tower in the CA module, US$/m; C CA-abt is the capital cost of the absorption tower in the CA module, US$; and α ab1 and α ab2 are the cost coefficients of the absorption tower in the CA module, taking 1.34 and 4.27, respectively, based on the data from the Chinese oilfield [12,32].
Similarly, the capital cost of desorption tower can be calculated using the following formulas [46,47]: where D CA-de is the diameter of the desorption tower in CA module, m; V CA-de is the flow rate of feed gas in the desorption tower in the CA module, m 3 /h; v CA-de is the gas flow velocity in the desorption tower which should make sure that the CO 2 can be effectively separated from the MDEA solution, 0.91 m/s was used according to the common design for chemical absorption tower [41]; N CA-t is the total number of theoretical plates in the desorption tower in the CA module, dimensionless; C CA-de is the tower cost of a single plate of the desorption towers in the CA module, US$; α de1 is the mole flow rate which can be supported by one plate based on the common design of the desorption tower, 6.96 kmol/h is used [41]; α de2 , α de3 and α de4 are the cost coefficients of the desorption tower in the CA module, taking 0.56, 1.06 and 3.89, respectively, based on the data from Chinese oilfield [12,32]; and C CA-det is the capital cost of the desorption tower in the CA module, US$. The purchase cost of the MDEA solution can be calculated according to the required circulation amount of MDEA solution, which can be estimated based on the CO 2 absorption capacity of MDEA [48].
where M MDEA is the required circulation amount of the MDEA solution, t; C s is the purchase cost of MEDA solution, US$; C us is the unit cost of the MEDA solution, 2176.66 US$/t was referenced; and α MDEA is the circulation amount of the MDEA solution which can be used to absorb the unit mole flow rate of CO 2 gas, based on the reaction mechanism between DMEA and CO 2 and the common design of the CO 2 absorption tower, 0.73 t·kmol −1 ·h, is taken [49]. Based on the above analysis, the capital cost of the MEDA carbon capture module can be obtained.
Then, the power of the MEDA module can be calculated as follows.
where C CA is the capital cost of CA module, US$; W CA is the power of CA module, kW.

Calculation Method of Running Cost
The running cost of each equipment unit mainly includes the maintenance cost and operating cost. Maintenance cost refers to the fees paid to maintain or restore the technical performance of the equipment. Operating cost is mainly the energy cost of the equipment, which is generally the electric charge calculated according to the equipment power. Hence, the running cost of the entire process can be obtained as follows.
where O&M annual is the annual running cost of CCRP, US$; C unit is the capital cost of equipment unit, US$; M factor is the ratio of annual maintenance cost to total infrastructure Energies 2021, 14, 5076 12 of 26 cost, 0.05 is often used; W unit is the power of equipment unit, kW; F elec is the electricity price, generally 0.08 US$/kWh is taken in China.

Calculation Method of CO 2 Capture Parameters
In CCRP, the gas flow rate and CO 2 content will change, especially before and after the carbon capture module. Due to the limit of capture purity, part of CO 2 will be lost in the separated hydrocarbon gas. Moreover, China's power generation is still dominated by thermal power using coal at present, thus the energy consumption of each equipment unit during operation is equivalent to an additional amount of CO 2 emissions. Therefore, the concepts of CO 2 flow, energy consumption equivalent CO 2 emissions, and CO 2 capture efficiency of basic equipment units were proposed.
As shown in Figure 4, taking the CO 2 capture module as an example, the CO 2 flow should satisfy the material balance when the CO 2 -contained gas flows through the capture equipment. If the gas flow rate and CO 2 content at the inlet are defined to be Q in-gas and x in-CO 2 , respectively, then the pure CO 2 gas flow rate at the inlet is Q in-CO 2 = Q in-gas × x in-CO 2 . For the gas flow at the outlet, Q out-gas , it is divided into the CO 2 gas flow Q out-CO 2 gas and the hydrocarbon gas flow Q out-CH4gas ; if their CO 2 and hydrocarbon gas purities are x out-CO 2 and y out-CH4, respectively, then the captured pure CO 2 gas flow rate is Q out-CO 2 = Q out-CO 2 gas × x out-CO 2 , and the CO 2 lost in hydrocarbon gas is Q out-CO 2 -loss = Q out-CH4gas × (1 − y out-CH4 ). Moreover, the additional CO 2 emission released by coal-fired power generation due to energy consumption during capture is Q power-CO 2 , then the CO 2 capture efficiency of the capture module can be calculated to be η = (Q out-CO 2 − Q power-CO 2 )/Q in-CO 2 . Similarly, the CO 2 flow variation and CO 2 capture efficiency of other equipment units in CCRP can also be obtained, as shown in Table 2. Based on these equations, the indicators of the entire CCRP can be determined. For the CO 2 capture and reinjection efficiency (CCRE) of the CCRP, it can be calculated based on the total Q power-CO 2 , Q out-CO 2 , and Q in-CO 2 of the process, or calculated by multiplying the CO 2 capture efficiencies of all units in the process. the additional CO2 emission released by coal-fired power generation due to energy consumption during capture is Qpower-CO2, then the CO2 capture efficiency of the capture module can be calculated to be η = (Qout-CO2 − Qpower-CO2)/Qin-CO2. Similarly, the CO2 flow variation and CO2 capture efficiency of other equipment units in CCRP can also be obtained, as shown in Table 2. Based on these equations, the indicators of the entire CCRP can be determined. For the CO2 capture and reinjection efficiency (CCRE) of the CCRP, it can be calculated based on the total Qpower-CO2, Qout-CO2, and Qin-CO2 of the process, or calculated by multiplying the CO2 capture efficiencies of all units in the process.  For the Qpower-CO2, it can be estimated based on the power of the equipment unit, coal consumption required for unit power generation, and the CO2 emission per unit coal by burning, as follows [50]:  Compressor/Pump Q out-gas = Q in-gas x out-CO 2 = x in-CO 2 Q out-CO 2 = Q out-gas × x out-CO 2 Q power-CO 2 H = (Q out-CO 2 − Q power-CO 2 )/Q in- CO 2 Carbon Capture Module Q out-CO 2 gas Q out-CH4gas Q in-gas = Q out-CO 2 gas + Q out-CH4gas x out-CO 2 y out-CH4 Q in-gas × x in-CO 2 = Q out-CO 2 gas × x out-CO 2 + Q out-CH4gas × (1 − y out-CH4 ) Q out-CO 2 = Q out-CO 2 gas × x out-CO 2 Q power-CO 2 H = (Q out-CO 2 − Q power-CO 2 )/Q in- CO 2 For the Q power-CO 2 , it can be estimated based on the power of the equipment unit, coal consumption required for unit power generation, and the CO 2 emission per unit coal by burning, as follows [50]: where Q power-CO 2 is the energy consumption equivalent CO 2 emission of equipment unit, Sm 3 /d; t u is the unit time, h; M coal is the coal consumption required for unit power generation, 0.313 kg/kWh was taken; E CO 2 is the CO 2 emissions per unit coal by burning, generally 2.6 kg CO 2 /kg coal is used; t u is unit time, taking 24 h; and ρ CO 2 is the density of CO 2 gas, taking 1.98 kg/m 3 . For the gas capture purity, we have conducted a sensitivity simulation for different kinds of carbon capture modules using the software Aspen Hysys 2006. The composition of feed gas referred to the associated gas in Block 530 in XinJiang oilfield, which has 84.98% C1, 7.21% C2, 3.04% C3, 1.23% C4, 0.54% C5, 2.60% N 2 , and 0.4% CO 2 . By mixing CO 2 with the associated gas, feed gases with different CO 2 contents and at different flow rates were input in the simulation models for calculation. The results show that the capture purity of gas is mainly determined by the CO 2 content in the feed gas. Hence, we regressed the relation equations of gas capture purity with CO 2 content in feed gas for usage in our models to calculate the CO 2 flow variation, as shown in Figure 5 and Table 3. It can be seen that as the CO 2 content in feed gas increases, the CO 2 capture purity of PSA, MS, LTF modules gradually increases, while the CO 2 capture purity of the MDEA module is always high. When the CO 2 content in the feed gas is larger than 75 mol%, all the CO 2 capture purities of all capture modules can reach larger than 90 mol%. Overall, the ranking of CO 2 capture purity is MDEA > PSA > MS > LTF. The CO 2 capture purity of the LTF module is the lowest one, because a part of liquefied C2+ can mix into liquid CO 2 and hardly be separated. On the other side, the purity of natural gas ranks in an order of MDEA >LTF> PSA > MS.

Calculation Method of Unit Cost
The CO2 capture and reinjection cost (CCRC) per unit volume of CO2 gas can be calculated by the annual cost divided by the annual captured CO2 gas. The annual cost includes two parts, namely the annual operating and maintenance cost, and the annual capital cost calculated by dividing the total capital cost equally over each year of the project [35]. The specific formulas are as follows. For comparison purposes, the unit CO2 cost is expressed by the cost per 500 sm 3 CO2 gas which is about one ton pure CO2.

Calculation Method of Unit Cost
The CO 2 capture and reinjection cost (CCRC) per unit volume of CO 2 gas can be calculated by the annual cost divided by the annual captured CO 2 gas. The annual cost includes two parts, namely the annual operating and maintenance cost, and the annual capital cost calculated by dividing the total capital cost equally over each year of the project [35]. The specific formulas are as follows. For comparison purposes, the unit CO 2 cost is expressed by the cost per 500 sm 3 CO 2 gas which is about one ton pure CO 2 .
C lev = C tca /Q out−CO 2 gas /365 × 500 (46) C tca = C annual + O&M annual = ∑ C unit × CRF + O&M annual (47) where C lev is the CO 2 capture and reinjection cost per 500 Sm 3 CO 2 gas, US$/500 Sm 3 ; C tca is the total annual cost of CCRP, US$; C annual is the annual capital cost by dividing the total capital cost equally over each year of the project duration, US$; CRF is the discount factor, which can be calculated according to project duration and the interest rate, in this study, it is assumed that the project lasts for 15 years, and the interest rate is 12%, hence the CRF of 0.1827 was applied.

Evaluation of the CCRPs Based on the Assumed Gas Production and CO 2 Purity
A sensitivity evaluation on the CCRP of the CO 2 EOR and storage project in XinJiang oilfield was conducted according to the possible gas production scale and CO 2 purity. It was assumed that the project lasts for 15 years, the discount rate is 12%, and the gas is produced at a scale of (5-50) × 10 4 Sm 3 /d with a CO 2 content varying in a range of 20-80 mol%. The unit cost, unit energy consumption, CCRE, and CO 2 capture purity of different CCRPs (as shown in Table 3) were calculated using the established evaluation model for CCRP, and the results are shown in Figure 6.
The calculated unit cost of CO 2 capture and unit cost of CO 2 capture and reinjection are shown in Figure 6a,b respectively, where the former covers the cost of equipment from the produced gas to the CO 2 capture system, while the latter further covers the cost of pressure boosting equipment for reinjection. It can be seen that both the unit capture cost and the unit capture and reinjection cost decrease with the increase of CO 2 content and gas production. The cost of capture accounts for the vast majority of the cost of the whole CCRP. By comparing these unit costs, the applicable CO 2 content of produced gas for different CCRPs can be obtained. The unit cost of the MDEA process is weakly sensitive to the CO 2 content in the produced gas, and it is economical at a low CO 2 content of 20-40 mol%. The unit cost of the SPA process is relatively low, and it has a large applicable CO 2 content range of 20−80 mol%. The unit costs of MS and LTF processes are high, but decrease rapidly with CO 2 content increase. These two CO 2 capture processes are suitable for the conditions when the produced gas CO 2 contents are larger than 50 mol% and 80 mol% respectively. Figure 6c,d show the unit energy consumptions of different CCRPs. It can be seen that the unit energy consumption is mainly decided by the CO 2 content in the produced gas. The higher the CO 2 content, the smaller the unit energy consumption. Similarly, the CO 2 capture process consumes most of the power of the whole CCRP. By comparison, the unit energy consumptions of SPA and MS processes are much lower than those of the other two. The unit energy consumption of the MDEA process is weakly affected by the CO 2 content in the produced gas, while the unit energy consumption of the LTF process is the most sensitive to the CO 2 content. When the CO 2 content of produced gas is larger than 40-60mol%, with the CO 2 liquefaction efficiency increase, the unit energy consumption of the LTF process will be lower than that of MDEA.
As shown in Figure 6e, the CCRE of the whole CCRP is also mainly affected by the CO 2 content in the produced gas. The higher the CO 2 content is, the higher the CCRE is. Among the four types of the CO 2 capture process, the CCRE of the PSA process is the highest. The CCRE of the MS process is lower than that of the PSA process, but it increases quickly as the CO 2 content in the produced gas increases. At a low CO 2 content of 20-40 mol%, due to the low gas capture purity, a large part of CO 2 will be lost in the captured natural gas, resulting in a low CCRE of the MS process, even lower than that of the MDEA process. Relatively, the CCRE of the LTF process is low due to the high energy consumption and low CO 2 capture purity. At a low CO 2 content, the CCRE of the LTF process can be as low as 30%, while when the CO 2 content in the produced gas is larger than 60mol%, the CCRE of the LTF process can exceed that of the MDEA process. The CCRE of the MDEA process will be the lowest when the CO 2 content in the produced gas is above 60mol%. it is assumed that the project lasts for 15 years, and the interest rate is 12%, hence the CRF of 0.1827 was applied.

Evaluation of the CCRPs Based on the Assumed Gas Production and CO2 Purity
A sensitivity evaluation on the CCRP of the CO2 EOR and storage project in XinJiang oilfield was conducted according to the possible gas production scale and CO2 purity. It was assumed that the project lasts for 15 years, the discount rate is 12%, and the gas is produced at a scale of (5-50) × 10 4 Sm 3 /d with a CO2 content varying in a range of 20-80 mol%. The unit cost, unit energy consumption, CCRE, and CO2 capture purity of different CCRPs (as shown in Table 3) were calculated using the established evaluation model for CCRP, and the results are shown in Figure 6.  Figure 6f shows the purity of CO 2 captured from the produced gas. The CO 2 purities captured by the MDEA and PSA processes all exceed 90 mol% when the CO 2 content in the produced gas is 20-80 mol%. However, for the MS and LTF processes, only when the CO 2 contents in the produced gas are more than 50 mol% and 70 mol%, respectively, the CO 2 capture purities can be larger than 90 mol%. The multi-stage membrane treatment can improve the CO 2 purity, while the heavy components liquefied with CO 2 are also conducive to miscible flooding.
When the produced gas is reinjected directly with necessary purchased pure CO 2 , the unit cost, unit energy consumption, and CCRE of the DRM process are shown in Figure 7. Due to the simple process of DRM, both the unit cost and unit energy consumption are much lower than those of other CCRPs. The CCRE of the DRM process can be up to 70-93%, also larger than that of any other CCRPs. The DRM process demonstrates a strong attraction. Moreover, the unit cost of the DRM process increases with CO 2 content rise because compressing CO 2 needs more energy than natural gas.

Evaluation of the CCRPs Based on the Designed CO2 Flooding Schemes
In order to optimize the CO2 EOR and storage scheme in block 530, four times of CO2 flooding were predicted by reservoir numerical simulation. In this part, five types of CCRPs are assessed and compared according to the predicted gas production.

CO2 Injection schemes and Predicted Gas Production
The CO2 injection schemes and predicted gas productions in XinJiang oilfield are summarized in Table 4 and Figure 8. In the simulation of CO2 − EOR schemes, after CO2 is injected into the ground, it interacts with formation water and crude oil, causing the composition and properties of liquid phase to be changed. Part of the injected CO2 is dissolved in the oil underground and cannot be produced in gaseous form. CMG software was used to simulate the above process to obtain CO2 − EOR simulation cases. The four CO2 flooding schemes are marked as cases A, B, C, and D, respectively. The CO2 injection undergoes three stages: pressure build-up for 0.5 years, continuous gas injection for 4.5 years, and water-alternating-gas (WAG) injection for 10 years.
In four cases, the simulation results are various. (1) In case A, 139.93 × 10 4 t of CO2 will be injected with a primary storage efficiency of 61.38%, and about 41.60 × 10 4 t of crude oil will be produced out with a CO2-oil ratio of 3.36 tCO2/t oil. The maximum gas production rate is expected to be 10 × 10 4 Sm 3 /d, while the CO2 content in the produced gas will be maintained at 65-76 mol% after the CO2 breaks through in the production wells in the third year. (2) Case B has lower cumulative CO2 injection and cumulative oil production, only 26.04 × 10 4 t and 26.93 × 10 4 t, respectively. CO2 breakthrough of the production well occurs in the second year, and then the CO2 content in the produced gas will gradually rise to more than 80mol %. (3) In case C, 108.22 × 10 4 t of CO2 will be injected into 15 wells with a high storage efficiency of 79.85%, and 33.17 × 10 4 t of crude oil will be produced out with a relatively higher CO2-oil ratio of 3.26 tCO2/t oil. CO2 was produced in the first year, and the CO2 content in produced gas can close to 90mol% after 5 years. (4) Case D has a similar CO2 injection scale with case A, reaching 123.93 × 10 4 t, but has greater oil production of 49.49 t. CO2 breaks through in the second year, and the CO2 con-

Evaluation of the CCRPs Based on the Designed CO 2 Flooding Schemes
In order to optimize the CO 2 EOR and storage scheme in block 530, four times of CO 2 flooding were predicted by reservoir numerical simulation. In this part, five types of CCRPs are assessed and compared according to the predicted gas production.

CO 2 Injection Schemes and Predicted Gas Production
The CO 2 injection schemes and predicted gas productions in XinJiang oilfield are summarized in Table 4 and Figure 8. In the simulation of CO 2 − EOR schemes, after CO 2 is injected into the ground, it interacts with formation water and crude oil, causing the composition and properties of liquid phase to be changed. Part of the injected CO 2 is dissolved in the oil underground and cannot be produced in gaseous form. CMG software was used to simulate the above process to obtain CO 2 − EOR simulation cases. The four CO 2 flooding schemes are marked as cases A, B, C, and D, respectively. The CO 2 injection undergoes three stages: pressure build-up for 0.5 years, continuous gas injection for 4.5 years, and water-alternating-gas (WAG) injection for 10 years.
In four cases, the simulation results are various. (1) In case A, 139.93 × 10 4 t of CO 2 will be injected with a primary storage efficiency of 61.38%, and about 41.60 × 10 4 t of crude oil will be produced out with a CO 2 -oil ratio of 3.36 tCO 2 /t oil. The maximum gas production rate is expected to be 10 × 10 4 Sm 3 /d, while the CO 2 content in the produced gas will be maintained at 65-76 mol% after the CO 2 breaks through in the production wells in the third year. (2) Case B has lower cumulative CO 2 injection and cumulative oil production, only 26.04 × 10 4 t and 26.93 × 10 4 t, respectively. CO 2 breakthrough of the production well occurs in the second year, and then the CO 2 content in the produced gas will gradually rise to more than 80mol %. (3) In case C, 108.22 × 10 4 t of CO 2 will be injected into 15 wells with a high storage efficiency of 79.85%, and 33.17 × 10 4 t of crude oil will be produced out with a relatively higher CO 2 -oil ratio of 3.26 tCO 2 /t oil. CO 2 was produced in the first year, and the CO 2 content in produced gas can close to 90mol% after 5 years. (4) Case D has a similar CO 2 injection scale with case A, reaching 123.93 × 10 4 t, but has greater oil production of 49.49 t. CO 2 breaks through in the second year, and the CO 2 content can also be close to 90 mol %. Note: primary CO 2 storage efficiency refers to the ratio of the amount of stored CO 2 (=cumulative CO 2 injectioncumulative CO 2 production) and the cumulative CO 2 injection.  Note: primary CO2 storage efficiency refers to the ratio of the amount of stored CO2 (= cumulative CO2 injection-cumulative CO2 production) and the cumulative CO2 injection.
(a) (b) (c) Figure 8. (a) Gas injection rate, (b) Gas production rate, and (c) CO2 content in produced gas. The predicted gas injection and production in the CO2 EOR and storage project in XinJiang oilfield.

Comparison Analysis of the Different CCRPs
(1) Comparison between the different CCRPs The best CO2 injection scheme, case D, was taken as an example, and different CCRPs were compared and analyzed according to their technical and economic indicators calculated based on the predicted gas production of each year.
As shown in Figure 9a,b, as the CO2 content in the produced gas increases with production, the unit CO2 capture costs of different CCRPs decrease first and tend to be stable after a 5-year injection when the CO2 content exceeds 80mol%. The unit CO2 capture costs of PSA, MS, and LTF processes become close, varying in a range of 17.63-20.35 US$/500 Sm 3 CO2, while the unit CO2 capture cost of the MDEA process maintains at a high level of 28.46-31.17 US$/500 Sm 3 CO2. When the cost of the injection process is further involved, the unit costs of CCRPs will increase by about 10 US$/500 Sm 3 CO2, except for the unit cost Overall, case A has the largest CO 2 injection scale, while case D is the most attractive scheme because of the smallest CO 2 -oil ratio and the little smaller gas production with the higher CO 2 content. For cases B and C, the CO 2 injection and gas production are small. Although their primary storage efficiencies are relatively high (66.68% and 79.85%, respectively), less amount of crude oil will be produced than that of cases A and D.

Comparison Analysis of the Different CCRPs
(1) Comparison between the different CCRPs The best CO 2 injection scheme, case D, was taken as an example, and different CCRPs were compared and analyzed according to their technical and economic indicators calculated based on the predicted gas production of each year.
As shown in Figure 9a,b, as the CO 2 content in the produced gas increases with production, the unit CO 2 capture costs of different CCRPs decrease first and tend to be stable after a 5-year injection when the CO 2 content exceeds 80mol%. The unit CO 2 capture costs of PSA, MS, and LTF processes become close, varying in a range of 17.63-20.35 US$/500 Sm 3 CO 2 , while the unit CO 2 capture cost of the MDEA process maintains at a high level of 28.46-31.17 US$/500 Sm 3 CO 2 . When the cost of the injection process is further involved, the unit costs of CCRPs will increase by about 10 US$/500 Sm 3 CO 2 , except for the unit cost of the LTF process, which is only improved by 3-4 US$/500 Sm 3 CO 2 due to the low injection cost of liquid CO 2 . However, the cheapest way to dispose of the produced gas is to reinject the produced gas directly. The unit cost of the DRM process is only 13.58-15.64 US$/500 Sm 3 CO 2 . Figure 9c shows the unit energy consumptions of different CCRPs with time. The unit energy consumptions of PSA, MS, and LTF processes decrease quickly in the first 2-3 years and tend to be stable, while the unit energy consumptions of MDEA and DBM processes always remain stable. The order of unit energy consumptions of different CCRPs is MDEA > LTF > MS ≈ PSA > DRM (1143, 721, 342, 328, and 244 MJ/500 Sm 3 , respectively, after 15 years of injection). A high energy consumption usually means a large amount of additional CO2 emissions and a low effective CO2 capture efficiency; hence, the ranking of CCREs of different CCRPs is DRM > MS ≈ PSA > LTF > MDEA (93.97%, 91.48%, 90.96%, 83.10%, and 74.86%, respectively, 15 years later), as shown in Figure 9d.
For the CO2 capture purity, as shown in Figure 9e, only in the MDEA and PSA processes can it reach 90 mol% in the first 2 years, while the CO2 capture purity of the LTF process is as low as 77.69% at the beginning. After 4 years of production, the CO2 capture purities of different CCRPs become stable with an order of MDEA > LTF > PSA ≈ MS > 90mol%. For the CO2 capture rate, only a little difference is between different CCRPs because of the high CO2 content in the produced gas, as shown in Figure 9f. Based on the above analysis, it can be seen that the DRM process is the best way to deal with the produced gas. However, before reinjection, the produced gas should be mixed with the purchased pure CO2 if necessary to meet CO2 purity and injection amount requirements. As shown in Figure 10a, when the produced gas is mixed with the purchased pure CO2 to meet the required CO2 purity of 90 mol%, no more than 8 × 10 4 Sm 3 /d of pure CO2 is needed, and with the increase of gas production and decrease of required  For the CO 2 capture purity, as shown in Figure 9e, only in the MDEA and PSA processes can it reach 90 mol% in the first 2 years, while the CO 2 capture purity of the LTF process is as low as 77.69% at the beginning. After 4 years of production, the CO 2 capture purities of different CCRPs become stable with an order of MDEA > LTF > PSA ≈ MS > 90 mol%. For the CO 2 capture rate, only a little difference is between different CCRPs because of the high CO 2 content in the produced gas, as shown in Figure 9f.
Based on the above analysis, it can be seen that the DRM process is the best way to deal with the produced gas. However, before reinjection, the produced gas should be mixed with the purchased pure CO 2 if necessary to meet CO 2 purity and injection amount requirements. As shown in Figure 10a, when the produced gas is mixed with the purchased pure CO 2 to meet the required CO 2 purity of 90 mol%, no more than 8 × 10 4 Sm 3 /d of pure CO 2 is needed, and with the increase of gas production and decrease of required injection amount, no additional pure CO 2 will be needed 10 years later. However, when the produced gas is mixed with pure CO 2 according to the required CO 2 purity, the total amount of produced gas and pure CO 2 is still less than the designed amount. Hence, more purchased pure CO 2 is needed, which will make the CO 2 content in the mixed gas up to 91-95 mol%, as shown in Figure 10b. Based on the above analysis, it can be seen that the DRM process is the best way to deal with the produced gas. However, before reinjection, the produced gas should be mixed with the purchased pure CO2 if necessary to meet CO2 purity and injection amount requirements. As shown in Figure 10a, when the produced gas is mixed with the purchased pure CO2 to meet the required CO2 purity of 90 mol%, no more than 8 × 10 4 Sm 3 /d of pure CO2 is needed, and with the increase of gas production and decrease of required injection amount, no additional pure CO2 will be needed 10 years later. However, when the produced gas is mixed with pure CO2 according to the required CO2 purity, the total amount of produced gas and pure CO2 is still less than the designed amount. Hence, more purchased pure CO2 is needed, which will make the CO2 content in the mixed gas up to 91-95 mol%, as shown in Figure 10b. (2) Comparison of CCRPs between the different cases Besides case D, the other three cases of CO2 flooding were also assessed to study the influence of gas production characteristics on selecting the optimal CCRP. The evaluation indicators of all CCRPs of all cases are summarized in Table 5.
For case A, the order of different CCRPs is MDEA > MS ≈ PSA ≈ LTF > DRM according to the unit costs of CCRPs when the CO2 content in the produced gas has reached stable after several years of production. Due to the stable CO2 content of 65-76 mol% in the produced gas, the CO2 capture purity, unit energy consumption, and CCRE are all kept stable during the project. However, it is not easy to design the DRM process. On the one side, the amount of mixed gas will be much larger than the required amount if the produced (2) Comparison of CCRPs between the different cases Besides case D, the other three cases of CO 2 flooding were also assessed to study the influence of gas production characteristics on selecting the optimal CCRP. The evaluation indicators of all CCRPs of all cases are summarized in Table 5.
For case A, the order of different CCRPs is MDEA > MS ≈ PSA ≈ LTF > DRM according to the unit costs of CCRPs when the CO 2 content in the produced gas has reached stable after several years of production. Due to the stable CO 2 content of 65-76 mol% in the produced gas, the CO 2 capture purity, unit energy consumption, and CCRE are all kept stable during the project. However, it is not easy to design the DRM process. On the one side, the amount of mixed gas will be much larger than the required amount if the produced gas is mixed with the purchased pure CO 2 based on the required CO 2 purity. On the other side, the CO 2 purity of mixed gas will be lower than 90 mol% during most of the project time if the produced gas is mixed with the purchased pure CO 2 based on the required injection amount. For this case, the MS, PSA, or LTF process may be an assistant selection.
For case B, the unit costs of different CCRPs are in the order of MDEA > MS > PSA > LTF > DRM. The CO 2 content in the produced gas is 56-88 mol%, and after three years of production, the CO 2 content can maintain above 80 mol%. At such a high CO 2 content, the unit CO 2 capture cost of the LTF process is close to that of MS and PSA processes, while the total unit cost of the LTF process is lower than that of any other capture processes because of the low injection cost of liquid CO 2 . Besides, the LTF process has the second-high CO 2 capture purity, although the unit energy consumption is high and the CCRE is as low as about 80%. This case is similar to case D. The DRM process is the most attractive option, and when the produced gas is mixed with pure CO 2 according to the required injection amount, the CO 2 content of the mixed gas can be high up to 92-95 mol%.
For case C, the unit costs of different CCRPs have the same order as that of case B. In this case, the injected CO 2 will breakthrough in the first year, and the CO 2 content in the produced gas is only 20 mol%; only in the fourth year will the CO 2 content exceed 80 mol%. Hence, in the early stage of the project, the unit cost of CO 2 capture will be very high. For the DRM process, a large amount of pure CO 2 should be purchased to mix with the produced gas, which will lead to a high CO 2 purity of mixed gas in a range of 95-98 mol%. Note: the data marked by * are the pretreatment costs of the produced gas in the DRM process; the data marked by ** are the CO 2 contents of the produced gas after being mixed with the purchased pure CO 2 in the DRM process.
By comparing the four cases of CO 2 flooding, it can be seen that (1) the DRM process is the best selection, but if the gas production is large and has a low-medium CO 2 content, the DRM process may bring new issues such as more blocks are needed for gas injection or the Energies 2021, 14, 5076 21 of 26 CO 2 content of the mixed gas cannot meet the required CO 2 purity. (2) The MDEA process can be excluded because of its high cost and energy consumption during most project times. (3) When the CO 2 content in the produced gas is above 80 mol%, the LTF process is an attractive option, while when the CO 2 content is lower than 80 mol%, the PSA process is better than the MS process. Because of the considering of the probable adjustment of CO 2 injection during the project, a more flexible and applicable CCRP is recommended as the following: the DRM process is selected as the main CCRP, and the PSA process is chosen as an assistant option that has a wide range of applicable CO 2 content in the produced gas.

Conclusions
(1) For the CO 2 EOR and storage project in XinJiang oilfield, a technical and economic evaluation model of CCRP was established based on the basic equipment units involved in the process, which can be applicable for any flexibly designed CCRPs. The evaluation indicators such as unit cost, unit energy consumption, CO 2 capture efficiency, and CO 2 capture purity of each equipment unit and the whole process can be calculated and used as the basis for the optimization of CCRP.
(2) The results of sensitivity evaluation of CCRPs show that with the increase of gas production rate and CO 2 content in the produced gas, the unit cost and energy consumption of CCRP will decrease, while the CCRE and CO 2 capture purity will increase. The MDEA and LTF processes have large unit energy consumptions, while the PSA process has a large CCRE and a high CO 2 capture purity. In terms of the unit cost, the applicable CO 2 contents in the produced gas for the MDEA, PSA, MS, and LTF processes are <20-40 mol%, >20-80 mol%, >50 mol%, and >80 mol% respectively, which are consistent with published studies. The DRM process is the most attractive selection because of its simple process, low unit cost, and high CCRE.
(3) According to the designed CO 2 flooding schemes in XinJiang oilfield, different CCRPs were assessed. Different CCRPs have different advantages at different stages of the project. For the case of high gas injection and high gas production with a relatively low CO 2 content, the DRM process is hard to apply. All or part of the produced gas may need to be purified by PSA, MS, or LTF processes, of which the PSA process has the widest applicable CO 2 content range. For the case of high gas injection and low gas production with high CO 2 content, the DRM process can be applied by mixing the produced gas with pure CO 2 according to the required injection amount. Considering the probable adjustment of the CO 2 injection scheme, a flexible and applicable CCRP is recommended to select the DRM process as the main CCRP associated with the PSA process as an assistant option.
(4) In general, the implementation of CCS in the oil field is economically rewarding, and CO 2 can be stored permanently and safely. Besides, a large number of CO 2 flooding projects around the world have also proved that this is the most feasible commercialization model. Therefore, a reasonable CCRP after enough evaluation can provide a guarantee for the CO 2 EOR and storage project of XinJiang Oilfield. Furthermore, the success of the XinJiang oilfield provides a reference for the process optimization and environmental protection indicators of the CCS technology in China.   We also appreciate the reviewers and editors for their constructive comments to make the paper high quality.

Conflicts of Interest:
The authors declare no conflict of interest.  ratio of annual maintenance cost to total infrastructure cost (dimensionless) W unit power of equipment unit (kW) F elec electricity price (US$/kWh) Q in-gas gas flow rate at the inlet of equipment unit (Sm 3 /d) x in-CO 2 CO 2 content at the inlet of equipment unit (dimensionless) Q in-CO 2 pure CO 2 gas flow rate at the inlet of equipment unit (Sm 3 /d) Q out-gas gas flow rate at the outlet of equipment unit (Sm 3 /d) Q out-CO 2 gas CO 2 gas flow rate at the outlet of equipment unit (Sm 3 /d) Q out-CH4gas CH 4 gas flow rate at the outlet of equipment unit (Sm 3 /d) x out-CO 2 CO 2 purity of CO 2 gas flow at the outlet of equipment unit (dimensionless) y out-CH4 CH 4 purity of CH 4 gas flow at the outlet of equipment unit (dimensionless) Q out-CO 2 pure CO 2 gas flow rate at the outlet of equipment unit (Sm 3 /d) Q power-CO 2 energy consumption equivalent CO 2 emission of equipment unit (Sm 3 /d) η CO 2 capture efficiency of the capture module (dimensionless) M coal coal consumption required for unit power generation (kg/kWh) E CO 2 CO 2 emissions per unit coal by burning (kg CO 2 /kg coal) t u unit time (h) ρ CO 2 density of CO 2 gas (kg/m 3 ) C lev CO 2 capture and reinjection cost per 500 Sm 3 CO 2 gas (US$/500Sm 3 ) C tca total annual cost of CCRP (US$) C annual annual capital cost by dividing the total capital cost equally over each year of the project duration (US$) CRF the discount factor (dimensionless)