Climate change and greenhouse gas emission reduction have attracted more and more attention from the international community. According to BP's statistics on CO₂ emissions from countries all over the world^[1,2], the global total CO₂ emissions reached 334.44×10⁸ t in 2017; China emitted 93.32×10⁸ t, 27.9% of the world total, which was 1.26×10⁸ t more than that in 2016, corresponding to an increase of 0.3%, indicating greater pressure for China in CO₂ emission reduction. The CO₂ flooding and sequestration technology can enhance oil recovery through CO₂ flooding and also realizes CO₂ geological sequestration. Therefore, it has both economic and social benefits, and is also the most effective way to reduce greenhouse gas emissions under the current economic and technological conditions^[3,4].

Overseas researches on CO₂ flooding started in the 1950s^[5]. Through 30 years of research and tests, the application technology was formed and commercialized gradually in the 1980s. In the 21st century, the international community's more attention on greenhouse gas emission reduction, rising of oil prices and progress of engineering technology further promoted the rapid development of CO₂ flooding technology^[6]. After over 60 years of development, all supporting technologies of CO₂ flooding have been basically mature. However, the CO₂ miscible flooding is still predominant at present ^[7]. The CO₂ immiscible flooding project started later, the first commercial CO₂ immiscible flooding project (Sho-Vel-Turn) was implemented in November 1998. However, the CO₂ immiscible flooding technology has been developing slowly because of high failures in practical projects.

The United States has the largest number of CO₂ flooding projects in the world, accounting for more than 90% of the global total. Its annual oil production by CO₂ flooding is about 1500×10⁴ t for five consecutive years, and oil recovery is enhanced by 7-15%. Hereinto, there are 109 CO₂ miscible flooding projects, with total oil production over 1440×10⁴ t^[1,2]. The CO₂ miscible flooding technology has become one of the most important EOR methods in the United States. At present, the United States is working on a new generation of CO₂ flooding technology for enhancing oil recovery by 25%. This new technology is expected to further reduce residual oil saturation by increasing CO₂ injection volume, optimizing injector-producer pattern, or adding polymer or other viscosifiers to improve fluidity, so as to greatly enhance oil recovery^[8].

Currently, large-scale comprehensive CO₂ sequestration projects are mainly concentrated in the United States and Europe, accounting for about 62% of the world total, followed by Canada and Australia. CO₂ emissions mainly come from power plants (52%), followed by natural gas treatment (20%) and syngas (14%), as well as coal liquefaction, fertilizer, hydrogen production, iron and steel, refining and chemical sectors. Most projects have a capacity larger than 100.0×10⁴ t/year, and the transportation distance exceeding 100 km^[3]. The number of CO₂ brine layer sequestration projects has been increasing^[9,10].

China began to pay attention to CO₂ flooding technology in the 1960s, when laboratory studies and field tests of CO₂ flooding were carried out in Pu I_4-7 layer and the transition zone of eastern South Saertu in Daqing Oilfield. In the 1990s, field tests of CO₂ huff and puff were conducted in Fumin Oilfield, Jiangsu province^[11]. Nevertheless, due to insufficient experience and knowledge, limited gas source supply and serious gas channeling, CO₂ flooding technology developed slowly in China before 2000. Over the past decade, China has intensified its efforts on key technologies of CO₂ flooding and sequestration. In 2005, PetroChina Research Institute of Petroleum Exploration & Development (RIPED) and Chinese Academy of Sciences (CAS) jointly initiated the Xiangshan Conference on “China's Greenhouse Gas Emission Reduction Strategy and Development”, at which the concept of carbon capture, utilization and storage (CCUS) combining with CO₂ flooding was put forward. Since the 11^th Five-Year Plan, a number of national projects on CO₂ emission reduction, storage, resource utilization and sequestration etc. have been set up. In line with the characteristics of crude oil and strata of continental reservoirs in China, specific researches have been conducted and made great progress. Meanwhile, pilot tests have been carried out in Fang-48 and Shu-101 blocks of Daqing Oilfield, Hailar Oilfield, Hei-59, Hei-79, Hei-46 and Yi-59 blocks of Jilin Oilfield, Gao 89-1 block of Shengli Oilfield, Pucheng block of Zhongyuan Oilfield, Caoshe Oilfield in Jiangsu, Liubei block of Jidong Oilfield, and Yaoyingtai Oilfield, to accelerate the popularization and application of the technology^[12,13]. Now, PetroChina is making research and pilot test of CO₂ flooding and sequestration technology respectively in Huang-3 well field of Changqing Oilfield for high-salinity oil reservoirs, and No.530 well field in Block 8 of Xinjiang Oilfield for sandy conglomerate oil reservoirs. These practices, once successful, will have positive impacts on greatly enhancing oil recovery and CO₂ geological sequestration in the Ordos Basin and the Junggar Basin.

Compared with other countries, China’s CO₂ sequestration projects in operation rarely correspond to a complete industrial chain, and they are characterized by small scale, relatively single capture object type, and no long-distance pipeline transportation; moreover, CO₂ captured is mainly utilized in food and chemical sectors, and there are few CO₂ sequestration projects in brine layers^[14,15].

This paper expounds the latest development of CO₂ flooding and sequestration theory and technology in China in recent years, and puts forward the future expectations in view of the problems existing in the development of CCUS technology. Additionally, this paper introduces the performance of four CO₂ flooding and sequestration field tests in Jilin Oilfield, and summarizes the relevant experience and enlightenments. These results can provide reference for further promotion of the CO₂ flooding and sequestration technology.

1.1.1. Mass transfer of components between CO₂ and crude oil

Mass transfer of components between gas and liquid is a unique phenomenon in gas flooding development. Because of the high wax and heavy hydrocarbon contents in continental crude oil in China, and the generally supercritical state of CO₂ under formation temperature and pressure, the mass transfer between CO₂ and hydrocarbon components of crude oil is complex^{[16,17,18,19]}.

It can be seen from Fig. 1 that three different kinds of crude oil present roughly the same process of mass transfer and phase transformation with CO₂. Under the initial pressure (10 MPa), the interface between oil and CO₂ is clearly visible. With the rise of pressure, CO₂ gradually dissolves into oil, the volume of oil phase increases, and the volume of gas phase decreases. At this time, the mass transfer between oil and gas is mainly CO₂ dissolution in oil phase. Moreover, CO₂ dissolution in oil phase makes oil phase lighter. When the pressure continues to rise, the mass transfer rate accelerates, and components in crude oil are extracted in large quantities. As the pressure rises further, the mass transfer intensifies; the liquid properties of gas phase gradually appear, and the gas properties of liquid phase are further enhanced. When the density of CO₂ enriched gas is equal to that of formation oil, oil and gas are rapid miscible and the oil-gas interface disappears completely. However, the intensity of gas-liquid mass transfer and the duration of the miscibility process are different among the three systems. The gas-liquid mass transfer between light volatile oil and CO₂ is the most intense. The minimum miscibility pressure of the three oil samples increases gradually with the increase of the content of heavy components.

During the experiments, samples were taken in different gas phase zones (No. ① to ④ zones in Fig. 1c). Components of the gas samples were quantitatively analyzed by chromatograph. The gas phase in No.① zone is mainly CO₂, with a little C₂-C₅. In the gas phase near No. ② zone (oil-gas contact), the contents of C₂-C₆ are apparently higher. When the pressure increases, the gas phase of No. ③ zone is darker in color than that of No. ① zone, and the light components extend to C₂-C₁₀. In the gas phase from No.④ zone, the components extend further to C₂-C₁₅. The results show that in an oil-gas system, the smaller the hydrocarbon molecule, the faster its mass transfer to gas phase is; the mass transfer between oil and gas is a process of gas phase enriching and liquid phase turning lighter; the light hydrocarbon components of C₂-C₆ have strong mass transfer ability, followed by C₇-C₁₀, C₁₁-C₁₅₊, and other components. This means besides C_2-6 internationally recognized, C_7-15 are also important components affecting CO₂-crude oil miscibility.

1.1.2. Microscopic oil displacement mechanism of CO₂ flooding

Injection pressure, pore size, interfacial tension and flooding timing are key factors affecting microscopic oil displacement effect of CO₂ flooding^[20,21].

Fig. 2 shows the experimental results of microscopic CO₂ flooding at 50 °C and different pressures. The pink part is crude oil, and the white (or colorless) part is CO₂. The different shapes of the model represent pore and throat. The throat diameters are divided into five grades: 20, 100, 200, 300, and 400 μm. When CO₂ is injected at low pressure, the interface between crude oil and CO₂ is obvious. When CO₂ is injected at medium pressure of 6.00 MPa and 9.05 MPa, a light color liquid slug appears between crude oil and CO₂, with an interface each between the slug and crude oil and between slug and CO₂. When CO₂ is injected at the pressure of 10.02 MPa, a continuous transition zone appears between crude oil and CO₂, and the interface disappears. Compared with the initial state, the crude oil recovery enhances with the increase of CO₂ displacement pressure, and especially after the pressure rises to the miscible pressure.

According to the experiments for the effect of pore size on the microscopic CO₂ flooding mechanism, with the increase of pressure, miscibility is completed gradually from large pores to small pores. Under the same conditions, the smaller the pore, the greater the minimum miscible pressure will be, but the increase amplitude of minimum miscible pressure is not obvious. For example, at 50 °C, the minimum miscible pressure for 20 μm pores is about 0.2 MPa higher than that for 400 μm pores.

The results of microscopic CO₂ flooding experiments under different interfacial tensions show that under high interfacial tension (8.32 mN/m), CO₂ displaces first the crude oil in the centre of the pore as non-wetting phase, the interface between them is obvious and slug-like flow appears. At the same time, the existence of interfacial tension makes if difficult for CO₂ to enter the small pores, so the crude oil in small pores is hardly recovered. Under low interfacial tension (0.91 mN/m), CO₂ can easily peel off the oil films at the pore edge layer by layer and the oil would float in CO₂ in a dispersed state. Moreover, the decrease of interfacial tension makes CO₂ easily enter the small pores, thus enhancing recovery of crude oil in the small pores.

CO₂ flooding after water flooding and direct CO₂ flooding were conducted under the miscible condition of CO₂-crude oil to identify the influence of CO₂ flooding timing on development effect. In the case of CO₂ flooding after water flooding, the water flooding makes the distribution of oil and water very complex, some oil is encapsulated by water, which hinders the contact between oil and CO₂ injected later, so this part of oil cannot be recovered. In the case of direct CO₂ flooding, almost all the oil in different pores is recovered. Because water phase disturbs the miscible process of CO₂-crude oil, the minimum miscible pressure in direct CO₂ flooding is lower than that of CO₂ flooding after water flooding.

1.1.3. CO₂ sequestration mechanism

CO₂ sequestration mainly includes three types: geological sequestration, marine sequestration, and vegetation sequestration. The geological sequestration technology is relatively mature. At present, the internationally recognized geological bodies suitable for CO₂ sequestration are oil reservoir, natural gas reservoir, brine layer and coal seam^[6].

The oil reservoirs are ideal places for CO₂ geological sequestration under current economic and technological conditions. On the one hand, the geological characteristics of the reservoir have been clearly recognized during oilfield development, which can ensure safe and effective CO₂ sequestration to protect ecological environment. On the other hand, the oil recovery can be enhanced greatly to bring about considerable economic benefits. The forms of CO₂ sequestration in oil reservoirs include structural sequestration, bound sequestration, dissolution sequestration, and mineralization sequestration. The main factors affecting the volume of CO₂ sequestration in a reservoir are: size of structural trap, capillary pressure, salinity of formation water, composition of crude oil and formation water, temperature and pressure of the reservoir, rock compressibility coefficient, caprock sealing capacity, mineral composition of the reservoir, and the time of reaction between CO₂, formation water and rock minerals, etc.

In natural gas reservoirs, CO₂ is usually directly injected into the reservoir for sequestration. The main mechanism is gas displacement, dissolution retention, and physical trapping, etc. Pressure of the gas reservoir and hydrodynamic diffusion are the main controlling factors. Due to bottom water intrusion, most gas reservoirs in China have smaller physical sequestration space, but higher dissolution retention volume. In CBM reservoir sequestration, CO₂ is also directly injected in, and the mechanisms also include gas displacement, dissolution retention, and physical traps, but displacement coefficient and bottom water dissolution are the main controlling factors. Water invasion should be considered for deep CBM reservoirs in China. In such reservoirs, CO₂ and methane are competitive for adsorption, with the displacement coefficient of 1.2-1.8.

Brine layers are the main site for CO₂ geological sequestration. International Energy Agency (IEA) estimated the global total volume of CO₂ geological sequestration at about 10 850×10¹² t, of which the CO₂ buried in brine layer accounts for 92%^[22]. In brine layer sequestration, CO₂ is usually injected continuously. The main mechanisms are dissolution retention, mineralization reaction, physical trap, and so on. Hydrodynamic diffusion and dissolution coefficient are the main controlling factors. During hydrodynamic diffusion of CO₂ in brine layers, the effective dissolution range is affected by the salinity of water; the dissolution sequestration quantity decreases with the increase of the brine salinity, and the free CO₂ sequestration quantity decreases slightly with the increase of rock compressibility.

1.2.1. Design of reservoir engineering parameters

Based on reservoir geological characteristics and gas flooding characteristics, the reservoir engineering parameters such as layer combination, well pattern deployment and injection scheme for CO₂ flooding and sequestration are designed, optimized and adjusted^[23], according to the principle of "maintaining pressure to promote miscible state, and alternating water and gas to control fluidity". In the design and adjustment of well pattern and well spacing, the main things considered are control degree of gas flooding and the establishment of effective displacement system. Gas injection rate and flow pressure control of producers are optimized on the basis of "maintaining the balance of miscible pressure and production rate in reservoirs". The design of cumulative injection volume should consider the relationship between the maximization of recovery factor, the utilization ratio of injected gas and the capacity of surface system to handle produced gas. Alternating water-gas injection is an effective method to control the gas flooding fluidity.

In view of the characteristics of multi-layers, strong heterogeneity and relatively inadequate capacity of gas source supply and surface treatment facilities, the gradual water-gas slug mode is preferred for gas flooding, i.e., a large continuous gas flooding slug is injected, and then a smaller water slug is injected. This process is repeated, with the gas slug becoming gradually smaller, the water slug larger, to reduce the CO₂ output and enhance displacement efficiency of the injected gas^[24,25,26]. After years of practices, the displacement characteristics and adjustment measures of CO₂ flooding for low-permeability reservoirs in China (Table 1) and the injection-production parameters limitations of reservoir engineering in each stage have been summed up (Table 2).

1.2.2. Injection-production adjustment

The main factors affecting the effect of CO₂ flooding in continental reservoirs include the difference between formation pressure and miscible pressure, and physical properties and heterogeneity of reservoirs. The purpose of injection-production adjustment is to maintain the state of miscible displacement, expand sweep volume at reasonable production rate, prevent and control CO₂ breakthrough, promote effective stimulation, and improve development effect^[27]. The injection-production adjustment for CO₂ flooding in continental reservoirs is implemented by way of injection-production coordination, water-gas alternation, stratified control and profile adjustment.

(1) Maintain and promote miscibility. In the process of CO₂ flooding, because of reservoir heterogeneity, gas breakthroughs or no CO₂ flooding effect may occur in some well clusters. Therefore, the technical indexes of production, such as formation pressure maintenance level, injection-production ratio and flow pressure, should be controlled properly during field tests.

(2) Control gas channeling. Excessive low gas-oil ratio will affect production rate, on the contrary, if the gas-oil ratio is incorrectly controlled in excessive high level, gas channeling will occur rapidly, and formation pressure will drop drastically, which can lower oil recovery. It is necessary to synthetically analyze and determine the threshold of gas-oil ratio of oil wells. Water alternating gas (WAG) is a combination of water injection and gas injection. The CO₂-EOR process is essentially attributed to the well control over fluidity ratio and the communication to areas not swept by water flooding. Reasonable determination on the timing of CO₂ flooding converting to WAG and the size of water-gas slug will directly contribute to the stability of formation pressure, the effect of WAG displacement, and the overall EOR performance of water flooding + gas flooding.

(3) Control profile. Due to the reservoir heterogeneity and high permeability belts, when the casing pressure of some producers in the cluster rises, and the CO₂ content increases to cause gas channeling, thus seriously affecting production, profile control should be made for gas injectors. When gas channeling occurs to impress the CO₂ flooding effect of other producers in the cluster, mechanical plugging is needed to further control gas channeling layer in gas injectors.

1.2.3. Evaluation method of development effect

Evaluating the development effect of CO₂ flooding systematically and normatively is the basis for objectively evaluating the development level of CO₂ flooding projects. Currently, the CO₂ flooding development effect is mainly evaluated from the development characteristics of CO₂ flooding, referring to the evaluation method of polymer flooding development effect and comparing with water flooding development effect. This evaluation technology involves 15 indicators in three aspects (technology, economy, safety and environmental protection), including 8 critical indicators (i.e. formation-miscible pressure coefficient, increase amplitude of production, increase of oil production by injecting one ton of gas, phasic recovery degree, increase amplitude of recovery, gas sequestration rate, financial internal rate of return and abnormal rate of environmental monitoring), and 7 auxiliary indicators (i.e. cumulative increase of oil production, annual oil production rate, water cut decrease range, new reserves benefit, greenhouse gas emission reduction benefit, oilfield development life extension period and corrosion rate).

Based on the actual data of CO₂ flooding projects around the world, we have formulated the evaluation criteria of some critical indicators (Table 3).

1.3.1. Stratified CO₂ injection technology

There are mainly two ways to inject CO₂ into reservoirs: general injection and stratified injection. Because of the strong interlayer heterogeneity of continental reservoirs, the general gas injection often results in vertical inhomogeneous gas absorption in reservoirs due to the prominent interlayer contradiction, thus reducing the sweep volume of CO₂^[28]. In order to realize stratified gas injection, according to the actual well conditions of CO₂ flooding, we optimized the gas injector head and downhole string to realize surface stratified gas injection and downhole stratified gas injection. Thus, we developed the concentric two-pipe stratified gas injection process (Fig. 3) and downhole injection regulator stratified gas injection process.

In the concentric two-pipe stratified gas injection process, the central pipe is run into the tubing, and two oil layers are separated by packer; gas is injected to the lower oil layer through the central pipe, and to the upper oil layer through the annulus between the central pipe and the tubing, thus, the stratified gas injection is realized in two oil layers. The design of gas injector head and the size of gas injection string should be considered in process design.

If the casing in old well of CO₂ flooding is non-gas-sealed casing, the concentric two-pipe stratified gas injection process can only realize two-layer stratified gas injection, and the later operation is difficult. Stratified gas injection process controlled by downhole injection regulator is based on the idea of eccentric stratified water injection^[29], gas injection in 2-3 layers can be realized by using packers to separate the layers and injecting CO₂ into different layers with gas nozzle injection regulator.

1.3.2. High-efficiency lifting technology

The oil producer with CO₂ breakthrough often suffer a series of problems, such as increasing CO₂ content, gas-oil ratio (GOR) and casing pressure. Conventional sucker rod pumping isn’t very suitable for the case with high gas-oil ratio and cannot effectively maintain production capacity. The high casing pressure and high GOR lifting technology can solve such problems caused by CO₂ channeling and casing pressure rise^[30].

For oil wells with high GOR, a gas-liquid separator can be installed below the pump to separate the gas and liquid, and reduce the amount of gas entering the pump, make most of the CO₂ into the casing-tubing annulus. Then, the gas lift valve is used to assist the pumping to control the casing pressure and improve the lifting efficiency, thus forming the gas-lifting and casing pressure-controlling integrated lifting process. This process has been applied 6 well-times in Block Hei-59 of Jilin Oilfield, as a result, the casing pressure reduced obviously and was controlled within 2 MPa. By lifting while carrying liquid, the filling coefficient of oil wells has been improved to a certain extent, and the pumping efficiency of the oil pumps has been improved. Four oil wells have better lifting and pumping assistance effect, with average production increasing by 33.5%.

With the increase of GOR, when the gas volume exceeds the gas-liquid separation range, the anti-gas pump lifting process is needed. This process can separate gas and liquid under gravity condition by using the reciprocating motion of plunger, and discharge the gas mixed in oil through connecting hollow pipe with tubing. The hollow pipe provides a bypass channel for the gas in the pump, so that the filling coefficient of liquid in the working cylinder increases and the gas-liquid ratio in the pump reduces. As a result, the interference of the gas is eliminated, and the pump efficiency is improved. This process has been applied four well-times in two pilots (Hei-59 and Hei-79) in the Jilin Daqingzijing Oilfield. The results show the anti-gas pump lifting works very well, with dynamic liquid level rising and daily CO₂ production and GOR dropping considerably. The wells had an average increment of daily fluid and oil production of 18.63 t and 6.61 t, respectively, and an increase of average pump efficiency of 11.5%. This shows that the process can meet the normal production requirement of oil wells with a GOR of 300 m³/t.

1.3.3. Corrosion monitoring and anti-corrosion for wellbore in CO₂ flooding

Corrosion is an important factor affecting the effect of CO₂ flooding. It is mainly related to the composition and texture of pipes, CO₂ partial pressure, temperature, medium composition, pH value, and crude oil properties, as well as flow rate and flow pattern of multiphase flow media^[31]. The corrosion can be divided into global corrosion and local corrosion.

Compared with surface pipeline corrosion monitoring technology, the downhole pipe string corrosion monitoring technology has advanced more slowly. The downhole pipe string corrosion status is mainly diagnosed through operation inspection and colorimetric determination of produced water. The operation inspection can only judge the corrosion qualitatively, not quantitatively. The colorimetric determination of produced water can quantitatively measure the corrosion, but with high error and poor data reliability, and it is unable to show the variation of downhole corrosion rate with well depth. Currently, the commonly used downhole corrosion monitoring methods include downhole hanging ring, downhole electrochemical corrosion online monitoring and downhole resistance probe corrosion monitoring^[32].

Adding corrosion inhibitor is an important means of anti- corrosion in CO₂ flooding. According to the results of corrosion experiment, for N80, N20, Q235, P110 and X70 steels, the optimum types and dosages of corrosion inhibitors are IMCA (100 mg/L), IMCB (200 mg/L), IMCC (200 mg/L) or IMCA (100 mg/L), ZKB (150 mg/L) and IMCA (100 mg/L). The corrosion inhibitors have concentration extremes under different temperature and pressure conditions. In a practical system, the concentration of inhibitor should be adjusted according to specific temperature, pressure and flow rate to achieve the best corrosion inhibition effect. The method of adding corrosion inhibitor on site depends on characteristics of the corrosion inhibitor and the downhole conditions. Generally, there are three injection manners: periodic injection, continuous injection and extrusion injection. For injectors, the corrosion inhibitor should be injected at 1-3 m from the inlet of the injection pump (the closer to the pump inlet, the better). For producers, the corrosion inhibitor should be added into the casing-tubing annulus at the wellhead or directly into the bottom of the well (below the screen pipe).

Through more than 10 years of research and tests , some breakthroughs have been made in surface engineering technologies of CO₂ flooding and sequestration in the respect of CO₂ capture, pipeline transportation, injection, gathering and treatment of produced fluids, and circulation injection of produced gas from CO₂ flooding. Moreover, relevant on-site technologies have evolved from small station with single well to large-scale station, from tanker transport to pipeline transport, from liquid-phase injection to supercritical injection, from non-recycling to recycling injection of all produced gas^[33].

1.4.1. CO₂ capture technology

CO₂ can be captured from various gas mixtures by way of amine absorption, pressure swing adsorption, and cryogenic separation^[34]. The amine absorption method is used to separate CO₂ and CH₄ or other gas components based on their different solubility values in amine absorption solvents. It is suitable for the case of low CO₂ content in the gas mixture. This mature method is still the main CO₂ capture technology for its good separation effect; however, it has the disadvantages of high energy consumption and high separation cost. The pressure swing adsorption (PSA) method realizes pressurized adsorption and depressurized desorption based on the characteristic that the equilibrium adsorption capacity of adsorbent increases with the increase of component partial pressure. The PSA method has been widely used in separating gas, especially the hard-to-adsorb components, such as the production and recovery of hydrogen. After upgrading of adsorbents, it can also be used for the separation and purification of easy-to-adsorb components, such as the production of CO₂, natural gas purification and CO₂ removal. The cryogenic separation method condensates and separates the hydrocarbons or other gases with higher boiling point in the process of gradual cooling, based on the nature that CO₂ has different condensation temperature from hydrocarbon and other gases. Essentially, the cooling capacity at lower temperature should be provided to cool the raw gas. According to the way of providing cooling capacity, there are external refrigeration, direct expansion refrigeration and mixed refrigeration. The above three CO₂ capture methods have been all applied in China.

1.4.2. CO₂ pipeline transportation

The CO₂ pipeline transportation system (Fig. 4) includes pipeline, intermediate pressure station (compressor or pump), injection compressor and auxiliary equipment^[35]. Because of the lower critical parameters of CO₂, pressurizing process and phase control are critical for its transportation. It can be transported in three phases: (1) gas phase, (2) liquid phase, and (3) supercritical phase. During the gas-phase transportation process, CO₂ remains in gas phase in the pipeline, and the transporting pressure is increased by the compressor; however, the overall operating pressure of the pipeline is low and the transporting volume is small. During the liquid-phase transportation process, CO₂ remains in liquid phase in the pipeline, and the transporting pressure is increased by the compressor to overcome friction loss and topographic height difference along the route. CO₂ needs to be cooled to liquid phase. In the case of a high-pressure gas well, the gas can be cooled by the pressure of the gas source itself. If there is no pressure, it can be cooled by using an external cooling source. Meanwhile, the pipeline should be protected with cooling insulation measures. During the supercritical transportation process, CO₂ maintains at supercritical state in the pipeline, and the transportation pressure can be raised by compressor or pump, the minimum operating pressure must be controlled to maintain its dense phase.

The supercritical transportation method is superior to the gas-phase transportation and liquid-phase transportation methods in economy and technology, saving nearly 20% of cost than gas-phase transportation. In addition, the high pressure at the end of the supercritical transportation pipeline enables CO₂ to be directly injected into formations in some cases without injection compressor. Of course, the proper transportation method for a certain project should be selected according to the actual CO₂ gas source and site conditions.

1.4.3. Ground CO₂ injection

The key technologies of ground injection system are phase analysis and pressurization. Different pressurization equipment is selected depending on phases. Regardless of pressurization pump or compressor, the phase and physical properties of CO₂ gas source and the pressure of injection station should be fully considered. There are three modes of ground CO₂ injection: liquid-phase injection, dense-phase injection and supercritical injection. Because of the high injection pressure, liquid injection is pressurized by plunger pump, supercritical injection is pressurized by compressor, and dense-phase injection is pressurized by pump. Usually the CO₂ used in the small-scale test is transported by tank trucks, and injected by liquid phase technology that is mature and reliable. For the large-scale test, pipeline transportation is often adopted. Compressor or pump pressurization injection should be selected according to the phase of pipeline transportation. The key point in the injection process is to control the phase of CO₂ entering the entrance of pressurization equipment.

There are many application examples for all the three injection processes, including liquid plunger pump injection process, supercritical compressor injection process and compressor & pump injection process. Each process is applicable to specific conditions.

1.4.4. Recycling injection of produced gas in CO₂ flooding

The composition of CO₂ produced in the process of CO₂ flooding has complex variation, with a CO₂ content of 10%-90%. Only when meeting the required indexes of re-injected gas, can the produced gas be injected back into underground reservoirs. At present, there are mainly three recycling injection modes of produced gas: direct reinjection, mixed reinjection, and reinjection after separation and purification. If the CO₂ content of the produced gas meets the required indexes, it can be directly re-injected by the supercritical injection process. If the CO₂ content of the produced gas is lower than the indexes required for reinjection gas, the produced gas is mixed with pure CO₂ gas and then be re-injected in supercritical phase into oil reservoirs. If the CO₂ content after the produced gas is mixed with pure CO₂ still fails to meet the required indexes, the pressure swing adsorption method is used to enrich and purify CO₂, then the CO₂ is injected back into the oil reservoir.

1.4.5. Field application of whole surface process technology

The whole surface engineering process of CO₂ flooding and sequestration has been tested and applied in Jilin Oilfield. Three application modes have been developed: (1) pilot test mode, (2) expanded test mode, and (3) industrialized application mode. The pilot test mode was applied in the block Hei-59, where with fewer wells and uncertain gas source, the CO₂ was transported by tank truck and injected in liquid phase; the produced gas from CO₂ flooding was reinjected without separation in supercritical phase after mixed with pure CO₂ gas. The expanded test mode was applied in the block Hei-79, with more wells and larger scale. The block is adjacent to the CO₂ source, thus CO₂ was transported by pipeline in liquid phase, with centralized station constructed. The produced gas from CO₂ flooding was reinjected after enrichment and purification. The industrialized application mode was applied in the block Hei-46, with more wells, large scale and assured gas source, CO₂ was transported by pipeline in gas phase and injected in supercritical phase. The produced gas from CO₂ flooding was reinjected without separation in supercritical phase after mixed with pure CO₂ gas.

1.5.1. Reservoir monitoring technologies for CO₂ flooding

CO₂ flooding faces a series of challenges, such as miscible instability, difficult control of fluid migration, prominent corrosion and high requirements in safety and environmental protection. Accordingly, some special reservoir monitoring items should be added, such as gas absorption profile monitoring, direct-reading pressure monitoring, well fluid analysis, gas-phase tracer, corrosion monitoring and environmental monitoring^[36]. These items have achieved good results in practical application, and provided technical support for understanding the characteristics and trends of dynamic changes of CO₂ flooding, as well as for maintaining miscibility, preventing gas channeling, anticorrosion and leak prevention. The reservoir dynamic monitoring technology suitable for CO₂ flooding and sequestration characteristics has been initially established.

(1) Injection status monitoring. This includes injection dynamic monitoring, water absorption and gas absorption profile testing, water absorption and gas absorption index testing, and wellbore bottom-hole temperature and pressure testing. Among all these testing items, the most important are the water absorption and gas absorption profile testing, and water absorption and gas absorption index testing.

(2) Miscible status monitoring. It mainly includes formation pressure monitoring, real-time bottom-hole flowing pressure monitoring of oil wells, well fluid monitoring and high-pressure physical property sampling analysis. Formation pressure is a key index for judging miscible status, and formation pressure monitoring mainly targets oil wells, including general pressure measurement and stratified pressure measurement. When the well conditions are permissible, stratified pressure measurement is preferred. In order to continuously observe the changes of bottom-hole flow pressure, static pressure and temperature, and master the injection-production pressure profile and miscible state, direct reading pressure gauge can be run into representative producers to monitor the bottom-hole pressure in real time manner. The component analysis of produced gas and crude oil and monitoring well fluid provide the basis for determining the miscible state of the production wells. The representative producers with water cut of less than 10% are selected for high-pressure physical property sampling analysis before and after gas injection. Through these means, the variation of crude oil composition and properties during the CO₂ flooding under formation conditions can be analyzed to judge the miscible state.

(3) Displacement fluid migration and monitoring of CO₂ flooding front. This includes CO₂ tracer testing and micro seismic monitoring. Gas tracer is mainly used to monitor the main seepage passage, direction and velocity of CO₂ migration in the process of CO₂ flooding. Micro seismic gas flooding front monitoring technology can be used to monitor gas injection well, and the gas flooding front, sweep range of injected gas and dominant gas flooding direction of monitored wells can be obtained, thus providing reliable technical basis for reservoir performance analysis and injection-production adjustment.

(4) CO₂ leakage monitoring. In order to detect any CO₂ leakage timely, analyze the causes of leakage, strictly control the environmental pollution and injuries caused by the leakage, a monitoring method of CO₂ leakage based on "soil carbon flux + carbon isotope" monitoring has been established. It includes two monitoring modes: linear spotting monitoring and mesh spotting monitoring.

1.5.2. Safety evaluation technologies for CO₂ sequestration

Through dissection, analysis and comparison of domestic and foreign examples, the evaluation indexes and index connotations of the basins and geological bodies (the products of geological processes with certain space and inherent components in the crust, which can be distinguished from the surrounding materials) to judge safe CO₂ sequestration have been selected, as shown in Table 4.

According to the engineering characteristics and requirements of safe CO₂ sequestration, it is necessary to evaluate the sealing performance of caprock in different stages. For instance, based on stages, it can be divided into exploration and primary selection stage, site selection stage, and sequestration design stage.

In the on-site operation and management process of CO₂ flooding and sequestration, it is also necessary to establish the risk identification standards for production management, production operation and the corresponding risk control system.

Expensive CO₂ source and unsatisfactory development effect of CO₂ flooding are two main factors restricting large-scale popularization of CO₂ flooding. (1) Stable CO₂ supply, convenient way to obtain and low cost is the prerequisites for promotion of CO₂ flooding technology, and high capture cost limits the source of CO₂. (2) The paraffin-base crude oil in China is mainly composed of heavy constituents, with obviously lower C₂-C₆ components, higher C₁₁₊, gum and bituminous contents. Moreover, the temperature of most reservoirs is higher, and the underground viscosity of crude oil is high. All these add difficulty to the miscibility of oil with CO₂, thus affecting the displacement efficiency of CO₂ flooding. Even for some reservoirs in which the crude oil and CO₂ can be miscible, because of the smaller difference between the original formation pressure and the minimum miscible pressure, the adjustable space after gas channeling is limited, and the CO₂ flooding effect is sometimes not very ideal either. Comparing with marine reservoirs, continental reservoirs have stronger heterogeneity, so gas channeling is more common during CO₂ flooding, thus the injected CO₂ could form invalid circulation, which seriously affects the sweep volume of the gas and significantly reduces the ultimate recovery of CO₂ flooding.

It is necessary to put more efforts into research to reduce the cost of CO₂ supply and improve the development effect of CO₂ flooding. At present, it is urgent to tackle the following five technologies: (1) Low-cost CO₂ capture technology to provide cheap CO₂ sources; (2) Developing and modifying the CO₂ and crude oil miscibility technology to achieve higher oil displacement efficiency; (3) Developing technologies that can enhance CO₂ sweep volume, such as low-cost foam compound flooding technology, stratified gas injection and profile control technology, etc.; (4) Developing higher-performance lifting tools and technology to ensure continuous production of low-liquid production wells after the gas-oil ratio rises; (5) Basic theory and key technology of CO₂ sequestration monitoring to improve the accuracy and reliability of long-term monitoring, and ensure the long-term safe sequestration of CO₂.

Over the past decade, China's CO₂ flooding and sequestration field tests have achieved leapfrog development, which has gone through three stages: pilot test, expanded test and gradual industrialization application. With more and more types of reservoir and larger scale of test, some results have been obtained and some practical experiences have been accumulated.

The Jilin Oilfield began CO₂ flooding and sequestration tests since 2008. Through efforts in over 10 years, four tests have been constructed in the Daqingzijing Oilfield, including Hei-59, Hei-79 South, Hei-79 North and Hei-46 as showed in Table 5. These tests have 60 CO₂ injector clusters, and 251 oil production wells. The annual oil production capacity exceeds 10×10⁴ t and annual CO₂ sequestration capacity is 35×10⁴ t.

Daqingzijing Oilfield is located in the middle of the Changling sag in the central depression area of southern Songliao Basin. It appears as a long-axis syncline striking NNE with many faults in general. The Gaotaizi oil reservoir of the Qingshankou Formation is a delta front subfacies in the shore shallow lake setting. The reservoirs are dominated by siltstone, and the cement is dominated by lime and shale. The first member of the Qingshankou Formation (Qing 1 Member) has the best reservoir properties, with an average permeability of 4.5×10^-3 μm². On the plane, the reservoir near provenance area has good physical properties, while the reservoir in the depositional front turns worse in physical properties sharply. It is a large complex lithologic reservoir formed under syncline tectonic setting, with low reserves abundance, low reservoir permeability and low oil saturation.

The crude oil in this oilfield has a density of 787.7-829.5 kg/m³, and in-situ viscosity of 1.82-9.34 mPa•s. The Qing 1 oil reservoir has a middle depth of 2350 m, reservoir pressure of 20.3-24.4 MPa (22.8 MPa on average), and reservoir temperature of 93-104 °C (averaging 97.3 °C), representing normal temperature and pressure system. This oilfield was put into large-scale exploration and development in 2000. The oil wells were produced by fracturing, and had an average productivity of 5.0 t/d per well and an initial water cut of more than 40%. By the end of 2010, there were 1130 oil producers and 318 water injectors in operation. The producers had an average daily fluid production of 6.1 t and daily oil production of 1.9 t per well and a total water cut of 68.8%. The reservoir had an average formation pressure of 17.0 MPa, which is 74.6% of the original formation pressure, a recovery percentage of OOIP of 8.73%, and a calibrated recovery of 21.9%.

2.2.1. Test of Hei-59 block

This block has six test well groups and 25 oil production wells. The well pattern is inverted-seven-spot areal well pattern, with well spacing and row spacing of 440 m×140 m. The main gas injection horizons include No.7, No.12, No.14 and No.15 layers in Qing 1 Member, which are developed as one set of strata. Gas injection began in March 2008, with a daily gas injection volume of 120-164 t in stable stage. In the initial stage of gas injection, some of the oil production wells were shut in to recover formation energy. In January 2009, all oil wells started in production by pumping. In October 2014, gas injection was stopped because of well conditions and other factors, then water flooding was implemented again.

This pilot is characterized by extensive miscible scope and high miscible degree. But because of the small pressure difference between formation pressure and miscible pressure, the miscibility is unstable, showing dynamic miscible behavior. When the CO₂ supply was sufficient and the gas injection was normal, the formation pressure was higher than the minimum miscible pressure, and the oil reservoir was in miscible state. When the CO₂ supply was insufficient and the gas injection was abnormal, the formation pressure was lower than the minimum miscible pressure, and the oil reservoir or local areas were in immiscible state. The response wells showed sharp rise of oil production and drop of water cut.

Before gas injection, the oil wells had a calibrated daily liquid production of 140.7 t and daily oil production of 66 t, a water cut of 53.1%, and cumulative oil production of 3.6×10⁴ t. The reservoir had an oil production rate of 1.7% and recovery percentage of OOIP of 3.5%. After gas injection, the oil wells had a daily liquid production of 159.0 t, daily oil production of 81.0 t, water cut of 49.1%, annual oil production of 2.6×10⁴ t, and oil production rate of 2.5%.

By the end of 2017, this pilot had a total gas injection volume of 27.3×10⁴ t, cumulative CO₂ production of 1.1×10⁴ t, phasic CO₂ sequestration rate of 95.9%, cumulative oil production of 13.8×10⁴ t during gas injection, phasic recovery percentage of OOIP of 13.6%, and cumulative oil production increment of 3.9×10⁴ t. By tracing and fitting the performance of CO₂ flooding and numerical simulation, the oil recovery of CO₂ flooding was predicted at 29.5%, which is 10.4% higher than that of water flooding.

2.2.2. Test of Hei-79 South block

In this pilot, gas injection layer in this block is No. 2 layer of Qing 1 Member. The northern fracturing zone adopted 480 m×160 m inverted-seven-spot areal well pattern, and the southern composite perforation zone used 480 m×160 m rhombic inverted-nine-spot areal well pattern. There are 60 oil producers and 18 gas injectors. Gas was continuously injected for one year. When formation pressure restored to basically the miscible pressure, WAG injection was conducted, at gas-water ratio of 1:1, daily injection rate of single well (water and liquid CO₂) of 40 t, and the designed total injection volume of CO₂ of 131.4×10⁴ t (about 0.5 times of the reservoir pore volume). During gas injection, oil production wells produced continuously; in well groups with local gas channeling, intermittent production mode (30-day production and 15-day shut-in) was adopted to control production. During gas injection, the injection-production ratio was 2.0. During water injection, the injection-production ratio was 1.35:1.00. The oil production rate was controlled below 4.0%.

Gas was started to inject into the reservoir successively since June 2010. The number of gas injectors was regulated according to CO₂ deliverability from Changling Gasfield. There were 8 gas injectors in 2010, with an average daily gas injection volume of 146.7 t. By 2014, there were 17 gas injection groups, with an average daily gas injection volume of 232.8 t. In October 2014, influenced by factors such as injected water quality, gas injection in this reservoir was stopped and waterflooding was adopted again.

Before gas injection, the block had a daily liquid production of 362.3 t, daily oil production of 179.3 t, water cut of 50.5%, oil production rate of 2.7%, and recovery percentage of OOIP of 17.8%. After gas injection, the oil wells had a daily liquid production of 411.4 t, and daily oil production of 200.2 t, and water cut of 50.9%. In May 2013, the pilot witnessed rise of GOR, and the gas injectors successively suffered injection difficulty and could not implement water alternate gas injection. Comprehensive regulation including periodic production, anti-gas pump technology and deepening pump hanging, etc. were taken to keep the production stable.

By the end of 2017, this pilot had a total gas injection volume of 41.2×10⁴ t (amounting to 0.214 times of hydrocarbon pore volume), cumulative CO₂ production of 2.1×10⁴ t, and CO₂ sequestration rate of 94.9%. During gas injection, the pilot had a cumulative oil production of 29.8×10⁴ t, phasic recovery percentage of OOIP of 12.4%, 1.6% higher than water flooding, and cumulative oil production increment of 3.8×10⁴ t. By tracing and fitting the production performance of this pilot and numerical simulation, the oil recovery by CO₂ flooding was predicted to be 14.5% higher than water flooding.

2.2.3. Short well spacing test of Hei-79 North block

The test scheme includes 10 well groups, 10 gas injectors and 27 oil producers. The well pattern is 80 m×240 m inverted-seven-spot well pattern. The gas injection horizons are No.11 and No.12 layers in Qing 1 Member, with reserves of 108×10⁴ t. The designed total gas injection quantity is 1.3 times of hydrocarbon pore volume. In October 2012, gas was injected throughout the pilot. Before gas injection, the block had a calibrated daily liquid production of 160 t, daily oil production of 15.1 t, water cut of 90.5%, and oil production rate of 0.62%. Clearly, this test was one converting to CO₂ flooding in super-high water cut stage.

The test included three phases. In the continuous gas injection phase, formation energy was effectively replenished, and formation pressure reached the minimum miscible pressure; as a result, liquid and oil production increased. In the alternative water-gas injection phase, gas channeling was effectively prevented and controlled; consequently water cut went down, oil production went up, and GOR remained stable. In the comprehensive injection-production regulation phase, the oil wells kept production under high GOR, with oil production increasing by more than three times and the water cut reducing by 10%.

By the end of 2017, this block had a total gas injection volume of 17.8×10⁴ t (amounting to 0.55 times of hydrocarbon pore volume), and annual oil production of 1.2×10⁴ t. This pilot had a total oil production of 4.5×10⁴ t and total oil production increment of 2.9×10⁴ t. The actual production of the core evaluation zone was higher than the predicted value in the scheme. Inferred from this trend, the oil recovery can be enhanced by more than 15%.

By dissecting this small well spacing pilot, the CO₂ miscible flooding has the following five performance characteristics: First, wells differ in response timing. Response occurred first in oil wells with good reservoir physical properties and high residual oil saturation, and then progressively advanced to the edge wells. After injecting CO₂ of 0.1-0.2 times of hydrocarbon pore volume, the oil wells 140-160 m away from injectors took response. After injecting CO₂ of 0.3-0.4 times of hydrocarbon pore volume, the edge oil wells 220-270 m away from injectors saw responses. Second, the wells vary in response degree. From inside to outside, there are three zones: miscible zone, near miscible zone, and energy replenishment zone. In the miscible zone, the oil wells have the highest cumulative oil production increment. In the energy replenishment zone, oil wells have the lowest oil production increment. Third, liquid production changes in different stages. During early gas injection stage, formation pressure recovered and liquid production rose too. During later gas injection stage, liquid production dropped. Fourth, in terms of well production decline, some earlier miscible wells showed step-like decline trend. Hence the key to long-term stable production is to expand the miscible range and recovery oil in small pore. Fifth, with respect to gas breakthrough, before the oil well responsed, hydrocarbon gas appeared in oil well first, and then CO₂ content rose. The CO₂ production during early and middle phases had similar trend with increased oil production. During later phase, higher gas saturation would impede liquid and oil productivity.

2.2.4. Test of Hei-46 block

In this test, 150 m×600 m inverted-nine-spot areal well pattern is adopted in the southern part, and 212 m×424 m inverted-nine-spot areal well pattern in the central part. According to the adjustment principle of well pattern from water flooding to CO₂ flooding, 26 wells (21 water injectors and 5 oil producers) were changed to be gas injectors; there are 139 oil producers.

This gas injection began in October 2014. CO₂ supply decreased since July 2015 to about 200 t a day. In the northern part, 67 oil wells were in production. According to formation pressure test, the formation pressure in the area with dense well pattern was higher (22.3 MPa), but still lower than the initial formation pressure (23.9 MPa). However, the overall formation pressure in the zone was low (only 12 MPa). Influenced by injection discontinuity and other factors, oil wells in the pilot declined in production slowly on the whole, of them, 13 oil wells increased, 29 oil wells stabilized and 21 oil wells decreased in production. In the southern part, 54 oil wells were in production. As the CO₂ injection was discontinuous, the overall formation pressure was low (average on 11.2 MPa). The production continued the decline trend during water flooding. 9 oil wells rose and 14 oil wells fell in production.

By the end of 2017, this pilot had a total gas injection volume of 32.6×10⁴ t (amounting to 0.076 times of hydrocarbon pore volume). From numerical simulation, the oil recovery of CO₂ flooding was predicted to be 11.5% higher than water flooding.

From the CO₂ flooding tests for more than 10 years since 2008, we have got the following experience and enlightenments in eight aspects. (1) In the case that there is CO₂ gas source near the oilfield, CO₂ flooding is recommended, because the supply of gas source is stable in a long period and the cost of CO₂ can be kept at a low level. (2) CO₂ flooding should be conducted in the oilfields where miscibility of CO₂ and oil can be realized. The CO₂ non-miscible flooding is much worse in effect and benefit. The CO₂ near-miscible flooding, similar to CO₂ miscible flooding in effect, should be further tested. (3) In the scheme design, the scale and progress should be arranged according to the balance of CO₂ injection and production. Referring to the available experience of CO₂ flooding, proper blocks should be selected firstly, then well pattern and injection-production parameters are optimized. Finally, the economic and social benefits of CO₂ flooding should be evaluated, and the well control and HSE requirements should be put forward. (4) Continental low-permeability reservoirs vary widely in the development law of CO₂ flooding, and the understanding is superficial too, so it is necessary to continuously strengthen monitoring, tracking, analyzing and evaluating of CO₂ flooding reservoirs and injection-production adjustment, to adjust the scheme in real time. (5) As field tests go deeper, many problems start to occur, such as difficult lifting and metering caused by the rising CO₂ content of produced fluid in oil wells, more difficult gas-liquid separation after the increase of gas output in gathering and transportation system, and more difficult CO₂ injection for injection pressure rising after water-gas alternation. Relevant solutions should be prepared in advance. (6) Field tests must be given priority. Then the CO₂ flooding project should expand in scale gradually from the pilot test to expanded test and industrialized application. (7) CO₂ flooding is an effective means to continuously improve oil recovery in mature oilfields, and it is also an effective way to develop new oilfields and tight oil reservoirs. (8) CO₂ flooding can not only improve oil recovery, but also realize effective sequestration of CO₂, with good economic and social benefits. Therefore, this technology has a broad prospect of popularization and application.

Annual CO₂ emissions in China have exceeded 90×10⁸ t, with an increasing trend. The government of China attaches great importance to the reduction of greenhouse gas emissions, so there is an urgent technical demand. The CO₂ flooding and sequestration technology has a very broad application prospect. Oil and gas reservoirs are ideal places for CO₂ sequestration, where CO₂ can be safely stored for a long time and can also increase recoverable oil and gas reserves and enhance oil and gas recovery, thereby it can achieve social and economic benefits simultaneously.

Through years of efforts, especially in the past 10 years, the CO₂ flooding and sequestration technology suitable for continental reservoirs has been formed initially in China. It comprises main technologies in reservoir engineering, injection and production engineering, surface engineering, supporting technologies of reservoir monitoring, and safety and environmental protection evaluation. These technologies provided powerful support for the construction and development of many field pilots, and good application results and practical experience have been achieved. These study results can also provide valuable reference for CO₂ flooding and sequestration projects in similar oil reservoirs in other countries and regions.