The construction of underground gas storage (UGS) in European and American countries can be traced back to the early 20th century, with a history of nearly 100 years^[1,2,3]. According to the statistics of IGU (International Gas Union) in 2018, there are 689 storages in the world, with a total working gas volume of 4165.3×10⁸ cm³, accounting for about 12% of the total global natural gas consumption (35429×10⁸ cm³), of which the working gas volume of major developed countries accounts for 19.5%^[4]. In the total working gas volume of global UGS, the oil-gas reservoir UGS is the largest and accounting for 80% of the total working gas volume, salt cavern UGS accounts for 9%, and aquifer UGS accounts for 11%.

The gas storage construction of China began in the 1960s in Daqing Oilfield. Since the 21st century, China has begun to construct large-scale commercial UGSs, and successively built Dazhangtuo, Jing 58 and Hutubi storages^[3]. By the end of 2020, the total capacity of 27 storages in China was 500×10⁸ cm³, and total designed working gas volume was 219×10⁸ cm³ (86% stored in gas reservoirs), and at present 147×10⁸ cm³ peak shaving capacity has been achieved, which account for 4.4% of the national natural gas consumption. Compared with foreign countries, the peak shaving capacity of China's storages is seriously insufficient, and the proportion of peak shaving capacity in natural gas consumption is less than one fourth of the average level of developed countries. The opinions on accelerating the construction of gas storage facilities and improving the market mechanism of gas storage and peak shaving auxiliary services (National Development and Reform Commission [2018] No. 637) requires that "gas supply enterprises must have a gas storage capacity no less than 10% of the annual contract sales volume in 2020". Therefore, vigorously promoting the construction of oil reservoir UGS is of great significance for enriching the types of UGS, improving the technical level of UGS, rapidly increasing the storage capacity and working gas volume of China's UGS, ensuring the national economy and people's livelihood, and maintaining national energy security^[5].

Jing 58 UGS is reconstructed on a depleted gas cap reservoir located in the Hexiwu structural belt of Huabei Oilfield. Jing 58 fault block was put into trial production in March 1989, and began to be built to a UGS after the termination of oilfield development in 2006, with a design capacity of 8.1×10⁸ cm³, working gas volume of 3.9×10⁸ cm³, the maximum storage pressure of 20.6 MPa and minimum storage pressure of 11.0 MPa, the average daily gas injection was 210×10⁴ cm³, and the average daily gas production was 13×10⁸ cm³. As an oil reservoir UGS, Jing 58 only focuses on the construction of gas storage, but does not carry out cooperative development with natural gas flooding to enhance oil recovery (EOR)^[6].

With advantages of gravity, imbibition, expansion and viscosity reduction, miscibility etc., natural gas top driving development can greatly improve the oil recovery higher than water flooding. There are many successful cases of natural gas drive projects in the world^[7,8,9]. For example, Prudhoe Bay oilfield in northern Alaska is the largest natural gas miscible drive project in the world. The oilfield is a structural reservoir with a gas cap. Gas injection was started in 1982, and all the produced gas was reinjected into the gas cap. After depletion, the gas injection recovery was increased to 45%. The effect of gas injection to enhance oil recovery by natural gas miscible flooding project is obvious in China. Pubei oilfield is a short axis anticline with a closure height of 105 m and an oil-bearing area of 4.43 km². The development of the oilfield has experienced three stages: effective natural gas injection, breakthrough of gas injection and water injection^[10]. Although the whole reservoir failed to switch from water flooding to gas driving, the oil recovery period free from water and at low water cut was extended, and the high and stable production was kept for 5 consecutive years, with the oil recovery rate of 6.9%.

However, the medium cost of natural gas flooding is higher than that of water flooding, which limits the application scale of natural gas flooding project. If the oil displacement and gas storage are effectively combined to build an integrated UGS and realize one-time investment, both crude oil exploitation and gas storage will benefit from it, and investment can be greatly saved.

At present, natural gas flooding development and UGS construction are either simply to improve crude oil recovery, or to build a UGS after reservoir abandonment. There is no precedent of integrated construction technology of oil recovery and gas storage. This paper focuses on the technical connotation and key technologies of integrated construction of oil recovery and gas storage, and analyzes the advantages and potential of such integrated construction.

The integrated UGS construction for oil recovery and gas storage is to combine the two projects of gravity drive and gas injection (Fig. 1). Natural gas is injected into reservoir top to form a secondary gas cap which expands continuously, and then under the influence of the gravity of crude oil, oil can be displaced, thus the oil recovery is greatly improved^[11,12,13]. At the same time, gas drive makes the reservoir change into reservoir UGS, which gradually expand in capacity, and finally becoming an oil reservoir UGS.

According to the characteristics of integrated construction, it can be divided into three stages: oil displacement, cooperation and gas storage (Fig. 2): (1) In the oil displacement stage, the main tasks are gas injection and oil recovery. When natural gas is injected into the top of the reservoir for oil displacement, the reservoir pressure should be kept above the minimum miscible pressure as far as possible, which greatly improves the oil displacement efficiency and crude oil recovery. It is necessary to maintain high formation pressure in this stage. For example, in the oil displacement stage of the DH reservoir in Tarim Oilfield, the formation pressure has been kept above the minimum miscible pressure of 43.5 MPa to ensure that the injected natural gas and formation crude oil are miscible, so as to greatly improve the crude oil recovery. (2) In the cooperation stage, the main tasks are gas injection, oil recovery and gas withdrawal. When a secondary gas cap is initially formed, the minimum storage pressure of the reservoir can be reduced below the minimum miscible pressure by taking into account oil displacement, gas storage capacity expansion and peak shaving. The crude oil is further recovered under the action of natural gas drive. The remaining recoverable oil reserves are less and less, and the volume of gas storage is larger and larger. A certain scale of natural gas peak shaving capacity is realized. (3) In the stage of gas storage, the main task is to realize the expansion of gas storage, production capacity construction and stable operation of gas injection and withdrawal. By optimizing the reasonable maximum storage pressure, and reducing the minimum storage pressure of oil reservoir UGS, the working gas volume can be effectively improved.

There are essential differences between integrated construction and gas storage in the aspects of construction time, working mode and operation mode (Table 1):

(1) The time to build UGS is different. In the early stage of integrated construction, there are three phases of high pressure oil-gas-water in the reservoir, the reservoir pressure has been kept at a high level, the maximum and minimum pressure range is narrow. In the stages of cooperation and UGS construction, the minimum storage pressure gradually decreases, the maximum and minimum pressure range gradually widens, and the operation mode gradually approaches to gas reservoir UGS. However, in the initial stage of gas reservoir UGS, there is only low pressure saturated gas in the pores, and the reservoir pressure is close to the abandonment pressure. To realize the peak-shaving effect of gas storage, a larger scale of bottom gas is needed. If the gas producing field is converted into a gas storage at an opportunity, the scale of bottom gas can be reduced. (2) The working mode is different. In the initial stage of integrated construction, the crude oil production capacity of single well can be greatly improved; in the medium term, both oil and gas production of single well can be realized; and in the later stage, the peak shaving of natural gas production can be realized. Therefore, the integrated construction can be profitable by increasing crude oil production and gas storage transfer fees. Gas reservoir UGS only pursues to improve the gas production of the single well and working gas volume, so it can only make profits by charging storage transfer fee according to the working gas volume^[14]. (3) The operation mode is different. The oil reservoir UGS is injected gas under high pressure at the initial stage of construction. From the small scale huff and puff gradually transformed to the big scale huff and puff, the periodic stress doesn’t change strongly at the stage of gas injection and oil displacement. The gas reservoir UGS gradually changes from low-pressure gas injection to high-pressure gas injection, and maintains large scale huff and puff. High-strength stress changes occur in the injection-production cycle. Therefore, compared with the construction and operation of gas reservoir UGS, the integrated construction and operation are more complex, and it is more necessary to strengthen the research on basic theory, key technology and management mode.

According to the oil displacement mechanism by natural gas^[15,16], and combining with the experience of UGS construction^[17], seven principles should be followed for the location selection of favorable reservoir: (1) Large geological reserves with a clear understanding of the remaining oil; (2) Good sealing property. For example, the reservoirs with natural gas cap, abnormal high pressure or closed boundary, or reservoirs with good sealing proved by development; (3) High oil column can make good use of gravity of crude oil. For example, the structural reservoir with large dip angle and lithologic reservoir with thick oil layer; (4) Miscible flooding conditions, such as reservoirs with low miscibility pressure or reservoirs that can be displaced by miscible flooding through manual intervention; (5) Close to natural gas pipeline network and gas field to meet the demand of gas source; (6) In a strategic natural gas reserve area or a natural gas consumption area; (7) Good well conditions, and less serious casing damage.

According to the above-mentioned seven principles, PetroChina has selected 20 blocks covering more than 2×10⁸ t in 9 oilfields for integrated UGS construction. Sinopec and CNOOC have similar reservoirs. These UGS sites are mainly around Beijing major consumption areas. These storages have a good promoting prospect.

The density of natural gas is very different from crude oil and water, causing gravity override. Choosing the reservoir with a high structural amplitude and good sealing property, and injecting gas at the top, gas pressure and gravity difference will drive oil while delaying gas channeling and greatly improving gas sweeping volume.

Taking the DH reservoir in Tarim Oilfield as an example, under the formation conditions, the density of natural gas is 0.15 g/cm³, the density of crude oil is 0.64 g/cm³, and the density of formation water is 1.20 g/cm³. Numerical simulation shows that the recovery of natural gas gravity drive is 20% higher than that of water flooding development (Fig. 3).

When the displacement pressure by natural gas drive exceeds the miscible pressure, the natural gas and crude oil begin to mix, and the phase interface disappears after gas and oil mixing. The interfacial tension is infinitely close to 0, and the capillary number increases by several orders of magnitude, which can effectively extract, separate and displace the remaining oil, significantly reduce the residual oil saturation and improve the reservoir recovery. Due to miscibility, the recovery of miscible flooding can be increased by about 10% on the basis of gravity flooding (Fig. 3). The tube experiment on the DH reservoir in Tarim Oilfield shows that the minimum miscible pressure of dry gas injection is 43.5 MPa, and the displacement efficiency of miscible flooding can exceed 90% (Fig. 4).

In the process of natural gas drive, the oil displacement efficiency is different under different displacement pressures. Generally, oil displacement efficiency increases with the increase of oil displacement pressure and is positively correlated to injected PV (pore volume) (Fig. 5). According to the relationship between oil displacement pressure and oil displacement efficiency, reasonable oil displacement pressure can be optimized. When the displacement pressure of the DH reservoir reaches 50 MPa (miscible displacement) and the injected PV reach 1.0, the displacement efficiency exceeds 90%, which is more than 30% higher than that of the condition at oil displacement pressure of 31 MPa (immiscible displacement). When the oil displacement pressure is 50 MPa, the formation pressure kept at 80% (the original formation pressure is 62.4MPa), the empirical value of reasonable pressure is met for field production.

For reservoirs without miscible phases, the oil displacement efficiency can be greatly improved by increasing the gas injection pressure or changing the composition of the injected natural gas to mix the injected gas with crude oil^{[18,19,20,21]}. For example, in block G52 of Changqing Oilfield, the content of intermediate hydrocarbons (C₂-C₆) in associated gas is 31.1%, and that in dry gas is 9.7%. The minimum miscible pressure of crude oil and associated gas is 14.8 MPa, and that with dry gas is 38.9 MPa (Fig. 6). It can be seen that the associated gas with higher intermediate hydrocarbon content can greatly reduce the minimum miscible pressure.

Generally, for a reservoir in the middle and late development stages, the formation pressure is relatively low, and miscible flooding cannot be achieved by gas injection at that time. However, laboratory experiments show that natural gas dissolved in crude oil can greatly improve the expanding capacity of crude oil. When the injected PV of gas is 0.65, the volume coefficient of crude oil will increase by 57% (Fig. 7), and the viscosity of crude oil will decrease by 83% (Fig. 8). Natural gas injection can greatly improve the flow capacity of crude oil^[22,23,24].

In the cooperative development process of oil displacement and gas storage, natural gas is injected in summer and withdrawn in winter. During summer injection and winter withdrawal, pressure pulse is formed in the reservoir, and the oil displacement efficiency can be improved by imbibition. Long core displacement experiments show that the oil displacement efficiency is 63.7% after injecting gas of 0.8 PV. In the process of soaking at constant pressure, the oil displacement efficiency was increased by 5%. Continuing to soak the well at increasing pressure, the oil displacement efficiency was increased to 88.4% with the cumulative gas injection of 6.5 PV, and the oil recovery was enhanced by 24.7%. Pressure increasing and soaking can play the role of gas imbibition displacement to deep crude oil in the matrix (Fig. 9).

Numerical simulation of the XG reservoir in Liaohe Oilfield shows that the recovery factor of depletion development is 12%, the ultimate recovery factor of continuous natural gas displacement is 30.6%, and the ultimate recovery factor of cooperative development (oil displacement and gas storage) can reach 40.4%, which enhancing the oil recovery by 9.8% (Fig. 10).

During the process of integrated UGS construction, it is necessary to optimize the maximum and minimum operating pressure, focus on the reservoir sealing evaluation and risk evaluation and control, and calculate the cushion gas volume and working gas volume. The optimization process is shown in Fig. 11. Taking the DH reservoir of Tarim Oilfield as an example, the original formation pressure is 62.4 MPa, and the maximum pressure of gas injection should be kept near the original formation pressure. Considering the factors such as sealing, lateral pressure, hydrostatic column pressure, compressor working condition, fracture opening pressure and formation fracture pressure, the maximum pressure is optimized to 56.0 MPa. The lowest formation pressure that can be reached by the operation of storage is set as the minimum pressure, which is 31.0 MPa. When the reservoir pressure maintains at the minimum storage pressure, the required cushion gas volume is 34.2×10⁸ m³. The gas produced during the operation in the range of the maximum and the minimum pressure is taken as the working gas volume, which is 28.0×10⁸ m³. The gas volume when operating at the maximum pressure is taken as the storage capacity, which is 6.22×10⁸ m³ (Fig. 12). Considering the cooperative development of oil displacement and gas storage, it is necessary to optimize the operation pressures of oil displacement and gas storage to obtain higher oil recovery.

The DH reservoir in Tarim Oilfield is a large nose-like uplift with a NE-SW dip and 5760 m deep. Its original formation temperature is 140 °C, original formation pressure is 62.4 MPa and formation water salinity is 23.4%×10⁴ mg/L. On the whole, it is a deep reservoir with high temperature and high salinity. The dip of the reservoir structure is 4.5° to 12.0°. The height of the oil column is 120 m. The average thickness of the heavy oil pad is 16 m. The density of the surface crude oil is 0.85-0.87 g/cm³. The viscosity of the surface crude oil is 5.23-12.47 mPa·s. It has been proved that the reservoir has a strong sealing ability by early water injection, and close to the major gas transmission trunk with sufficient gas. In conclusion, the reservoir meets the site selection conditions for integrated UGS construction.

The DH reservoir began to put into production in 1990, and then went through initial production, stable production, well pattern adjustment and pay zones adjustment. By December 2013, there were 25 production wells, 21 open wells, with cumulative oil production of 838.4×10⁴ t and average daily oil production per well of 16.5 t. The comprehensive water cut was 67.5%, the comprehensive decline rate was 14.3%. By the beginning of 2014, the oilfield began to carry out development test on natural gas gravity drive and miscible flooding. The production has been stabilized and recovered (Fig. 13).

After injecting natural gas, the formation pressure rose, the effective wells reached 17, the output of 13 wells was doubled, and 10 wells converted into flowing, including 2 wells with production of 100 t/d and 8 wells with production of 50 t/d. The production of the reservoir stopped falling and recovered for the first time in many years. The comprehensive decline has decreased to 2.7%, the water cut increase rate has decreased from 8.13% to -2.76%, and the average daily oil production per well has increased from 14 t to 27 t. By December 2020, the cumulative gas injection to the reservoir was 6.2×10⁸ m³, the cumulative oil production in gas injection stage was 104.0×10⁴ t, the cumulative oil increased by 43.6×10⁴ t. The cumulative gas capacity was 3.9×10⁸ m³. The reservoir began to have the peak shaving capacity of natural gas.

The structure area of the XG buried hill in Liaohe Oilfield NE China is 85 km², and the average effective thick ness of pay zone is 189.7 m. The density of formation crude oil is 0.64 g/cm³, the viscosity is 0.38 mPa·s and the saturation pressure is 21.3 MPa. The oil column is 752 m high, which is conducive to natural gas gravity drive. The upper cap rock with a good sealing performance is suitable for integrated reservoir construction.

The XG buried hill started pilot test in 2007, and put into large-scale production in 2010 of a million tons. The production began to decline in June 2012. At the end of 2015, the reservoir had a daily oil production of 808.0 t, cumulative oil production of 612.68×10⁴ t, oil recovery rate of 0.59%, and recovery degree of 10.1%. In 2016, the XG buried hill was established as a pilot zone for gas injection development. Then large-scale gas injection was carried out primarily at the top and secondarily at the middle and lower parts, which completely reversed the continuous production decline (Fig. 14). By the end of 2020, the cumulative injection of natural gas was 1.3×10⁸ m³, the cumulative oil increase was 27.7×10⁴ t, and the cumulative natural gas was 0.11×10⁸ m³. It was almost capable of natural gas peak shaving.

Natural gas top gravity drive can obtain higher crude oil recovery by taking advantages of density difference, miscibility, pulse imbibition, natural gas expansion and viscosity reduction of crude oil^[25]. In 2020, PetroChina selected four oil reservoirs (DH and TZ in Tarim Oilfield, XG in Liaohe Oilfield and PB in Tuha Oilfield) to carry out cooperative construction test of gas drive and gas storage. By that time, the four reservoirs covered geo-logical reserves of 7797×10⁴ t, and with a recovery degree of 25.5%, annual oil production of 35×10⁴ t, and an oil recovery rate of only 0.4%. After carrying out the integrated UGS construction, the peak annual oil production of four cooperative projects has reached 104×10⁴ t, the production is 2.97 times of that before gas injection, the average recovery has increased by 26.7%, and the recoverable reserves have increased by 2084×10⁴ t (Table 2).

In recent years, the demand on natural gas of China in winter has increased year by year, which makes higher requirements on natural gas supply in winter. In 2020, the average daily gas supply in China increased by more than 10% year on year (Fig. 15).

After the completion of four storages with integrated construction technology by PetroChina, the total gas capacity is 189.7×10⁸ m³, the working gas volume is 83.0×10⁸ m³, the maximum daily peak shaving capacity is 0.77×10⁸ m³, and the gas supply in winter is nearly 10.0×10⁸ m³. The storage capacity and working gas volume have been greatly increased, and the strategic supply has been effectively improved (Table 3).

The peak shaving capacity of storages can effectively decrease the peak-valley difference of gas production, maintain stable production and delay water invasion, and ensure high recovery and wellbore safety. At the same time, they can ensure the smooth operation of long natural gas transmission through pipelines.

The peak-valley difference of natural gas production in winter and summer is 2500×10⁴ m³/d in a gas field in China (Fig. 16). If the natural gas produced by the gas field is used to support the integrated construction of oil displacement and gas storage, more gas can be injected to "suppress the peak" of gas production in summer, and gas is produced to "raise the valley" in winter. The gas field can always maintain at a reasonable development rate and long-term stable production.

Integrated UGS construction can obtain higher economic benefits, which is reflected in three aspects: (1) Efficient utilization of natural gas. When natural gas is injected into the reservoir, it can be used as the displacement medium to enhance the oil recovery, and at the same time, peak shaving can be carried out after the gas storage construction is completed. (2) One-time investment in drilling and surface construction. The design of well type and well pattern of integrated construction technology can meet the needs of EOR improvement in the early stage and large scale of huff and puff of gas storage in the later stage. The cementing quality, compressive strength and corrosion resistance of the drilling and completion string meet the requirements of gas storage. The ground treatment system, gathering and transportation system and compressor system all meet the relevant standards for the construction of gas storage, which make the gas storage can directly use in the later operation without reconstruction or replacement, so as to save investment. (3) Cooperative integration of oil recovery and gas storage can meet the requirements of industry benchmark internal rate of return, and the cooperative project also has good economic benefits.

The evaluation period of PetroChina's four integrated UGS construction projects lasts 40 years. Calculated at a fixed oil price of 283 US dollars/m³ (45 US dollars/bbl), the internal rate of return is more than 6%. Among them, the internal rate of return of DH and TZ oilfields in Tarim oilfield is more than 8%. The successful implementation of the pilot projects has laid a good foundation for PetroChina to build a demonstration project of oil displacement and gas storage of "one million tons oil field and ten billion cubic meters gas storage".

By making full use of features including gravity displacement, miscibility, viscosity reduction, and imbibition, natural gas can be injected into oil reservoirs to enhance oil recovery and build strategic UGS at the same time, realizing the win-win situation of oil production and natural gas peak shaving.

Compared with a gas reservoir UGS, an integrated UGS has two profit modes: increasing crude oil production and gas storage transfer fee, so it has better economic benefits. At the same time, in this kind of UGS, gas is injected at high pressure in the initial stage of its construction, gas is injected and produced by a small volume in the initial operation stage of the UGS, and then by a large volume in the middle and late operation stages. In this way, the UGS will not have drastic changes in periodic stress, while the shortcomings of large stress variation in a gas reservoir UGS can be overcome at large gas injection and production volumes.

Important factors on integrated UGS construction are oil reservoir selection and evaluation, gravity displacement, optimization of displacement pressure, and gas storage operating parameters, etc. The pilot test shows that the technology has achieved an initial success, and it is a new idea for rapid development of UGS construction in China.