Method for exploiting deep low-permeability condensate gas reservoir by injecting air, oxidizing, increasing heat and energy and combining CO2 pressure maintaining

Abstract

The invention provides a method for exploiting a deep low-permeability condensate gas reservoir through air injection oxidation heat increasing and energy increasing combined with CO2 pressure maintaining, and relates to the technical field of deep low-permeability condensate gas reservoir development. The method for exploiting the deep low-permeability condensate gas reservoir through air injection oxidation heat increasing and energy increasing combined with CO2 pressure maintaining comprises the four steps of dew point pressure measurement, air injection huff and puff heat increasing and energy increasing, oxygen concentration detection and gas injection conversion judgment and CO2 displacement. According to the method, the air injection oxidation heat and energy increasing technology and the CO2 pressure maintaining displacement technology are combined, the synergistic advantages of the two technologies are fully played, the limitation of a single technology is overcome, the recovery rate of the condensate oil is increased, meanwhile, the development cost is remarkably reduced, the technical effect and the economic benefit are both improved, and the method is suitable for industrial production. And a new method is provided for efficient development of the deep low-permeability condensate gas reservoir, and the method has important practical value and popularization and application prospects.

Description

Technical Field

[0001] This invention relates to the field of deep low-permeability condensate gas reservoir development technology, and in particular to a method for exploiting deep low-permeability condensate gas reservoirs by injecting air, oxidation, heating, and energy enhancement combined with CO2 pressure maintenance. Background Technology

[0002] Natural gas, as a clean and efficient energy source, plays an increasingly important role in the global energy structure. Condensate gas reservoirs, as an unconventional oil and gas resource possessing the dual value of natural gas and condensate oil, boast enormous reserves and occupy a pivotal position in global gas field development. With shallow and medium-depth conventional oil and gas resources entering the later stages of development after decades of exploration, resource succession faces severe challenges, making deep condensate gas reservoirs an important potential area for increasing oil and gas reserves and production.

[0003] However, the development of deep condensate gas reservoirs faces numerous technical challenges. In practice, depletion-based development is widely adopted as the primary method due to its simplicity and low investment cost. However, this method has inherent drawbacks: as reservoir pressure gradually decreases below the dew point pressure during continuous extraction, heavier hydrocarbon components in the condensate gas begin to condense and precipitate under formation conditions, forming liquid condensate oil. This condensate oil adheres to the surface of rock particles or remains trapped in pore throats, severely clogging the reservoir's pore space and significantly restricting fluid flow paths, thus drastically hindering normal natural gas production. More seriously, as reservoir pressure continues to decrease, the precipitated condensate oil will evaporate back into the gas phase. This reverse condensation phenomenon results in the permanent loss of a large amount of high-value condensate oil in the formation, making it unrecoverable and significantly reducing the overall development effectiveness of the condensate gas reservoir, with recovery rates far below expectations.

[0004] To address the technical challenges of pressure reduction and severe condensation losses after condensate gas reservoir depletion development, researchers have conducted extensive physical and numerical simulation studies in recent years. These studies have revealed that gas injection and pressure maintenance development techniques can be a crucial means to improve condensate gas reservoir recovery. Among these, carbon dioxide injection technology has attracted widespread attention due to its unique physicochemical properties. CO2 injection displacement technology demonstrates significant technical advantages in condensate gas reservoir development, primarily in reducing system saturation pressure and dew point pressure, enhancing condensate oil evaporation, and increasing recovery rates. CO2 has high solubility and a high dissolved gas-oil ratio in condensate oil, effectively reducing its viscosity and improving its fluidity. Simultaneously, it can inhibit the precipitation of new condensate oil by lowering the system's dew point pressure.

[0005] However, the application of CO2 injection alone in deep, low-permeability condensate gas reservoirs still has significant limitations. These limitations include low sweep efficiency of injected CO2 in the reservoir, uneven gas front advancement, and insufficient energy replenishment to the reservoir. These technical issues restrict the full effectiveness of CO2 displacement technology, thus limiting the extent to which condensate oil recovery can be improved. Meanwhile, air injection technology, as an emerging gas reservoir enhancement technology, is gradually being introduced into the development of condensate gas reservoirs, demonstrating unique technological advantages. The core mechanism of this technology lies in the oxidation reaction that occurs when oxygen in the air comes into contact with condensate oil and anticondensate oil in the reservoir, and even spontaneous combustion under high-temperature conditions. This chemical reaction process releases a large amount of heat energy, thus achieving the dual effects of increasing heat and energy. During air injection development, condensate oil adhering to the rock surface and anticondensate oil retained in the pores of the reservoir can fully contact the injected oxygen and undergo a high-temperature oxidation reaction. This reaction can form a stable thermal front in the reservoir and continuously advance, effectively increasing reservoir temperature and pressure.

[0006] Existing technologies reveal that while CO2 injection alone can effectively reduce dew point pressure and improve condensate flowability, it suffers from problems in deep, low-permeability condensate gas reservoirs, including insufficient energy replenishment, the need for large-scale CO2 injection, and high economic costs. Air injection alone, while achieving heat and energy enhancement through oxidation, lacks effective subsequent displacement mechanisms to fully recover the activated condensate. Therefore, there is an urgent need to develop a composite extraction method that integrates the advantages of both technologies, achieving synergy and effectively addressing a series of technical challenges such as pressure recovery difficulties, severe condensate loss, and low recovery rates after exhaustion development in deep, low-permeability condensate gas reservoirs. This would provide a new technological approach for the efficient and economical development of such complex gas reservoirs. Summary of the Invention

[0007] In view of this, the present invention provides a method for the exploitation of deep, low-permeability condensate gas reservoirs using a combined air-injection oxidation, heating, and energy-enhancing CO2 pressure-maintaining process. The invention first injects air into a depleted condensate gas reservoir, allowing it to fully contact the condensate oil adhering to the surface of rock particles or remaining in pores within the reservoir. This oxidation generates heat and may even spontaneously combust, thereby enhancing energy and pressure, and improving the reservoir's permeability. This process not only effectively reduces the viscosity of the condensate oil and promotes its flow, but also restores the formation pressure to above the dew point pressure through thermal pressurization, suppressing reverse condensation and achieving pressure-maintaining exploitation. Once the formation pressure has recovered to above the dew point pressure, CO2 flooding is initiated. CO2 has a high solubility and dissolved gas-oil ratio in condensate oil, which can reduce the system's dew point pressure and saturation pressure, effectively inhibiting the re-precipitation of condensate oil underground, and significantly improving the evaporation efficiency and flowability of the condensate oil, thereby effectively increasing the final recovery rate.

[0008] The method for exploiting deep, low-permeability condensate gas reservoirs using a combination of air injection, oxidation, heating, and energy enhancement with CO2 pressure maintenance, as described in this invention, includes the following steps: S1. Dew point pressure measurement: A constant mass expansion experiment was conducted using compound condensate gas under reservoir temperature and pressure conditions to measure the dew point pressure. S2. Air injection for heating and energy enhancement: A monitoring device is installed in the target wellbore. Air is injected into the depleted condensate gas reservoir through the injection well of the implementation well group at the surface. After the air injection is completed, the well is shut in and kept closed. During the well closure period, the pressure and temperature changes are tracked in real time through the downhole monitoring device. If the reservoir pressure does not recover to above the dew point pressure after the well closure is completed, the air injection-well closure operation is repeated until the pressure meets the requirements. S3. Oxygen concentration detection and gas injection conversion judgment: After the well is shut off, monitor the oxygen concentration in the gas produced at the wellhead. When the oxygen content is stably below 8%, switch to CO2 displacement. S4, CO2 displacement: Indoor displacement experiments were conducted to determine the injection rate. The injection rate should be selected in a way that takes into account both dissolution and carrying capacity. Then, CO2 was injected in a pulsed manner. Throughout the entire gas injection-well shut-off process, the reservoir temperature, pressure, and composition of the produced gas are continuously monitored, and the gas injection parameters are dynamically adjusted based on real-time data to ensure that the formation pressure is always maintained above the dew point pressure, thereby achieving efficient pressure-maintaining production.

[0009] Preferably, the deep low-permeability condensate gas reservoir has a depth > 4500 m and a permeability of 1~10 mD.

[0010] Preferably, in step S2, the detection device is a temperature and pressure detection device; the air injection pressure is 1.1 to 1.3 times the original formation pressure; and the well shut-in time is 10 to 20 days. More preferably, the detection device is a composite fiber optic temperature and pressure monitoring system.

[0011] Preferably, in step S3, the method for determining the stability of oxygen content is as follows: after the well is shut off, the gas produced at the wellhead is tested. When the oxygen content is lower than 8% after three consecutive samplings, it can be determined as "stable". The 8% oxygen content is selected as the threshold for engineering safety considerations. This value is chosen to take into account the explosion limit of hydrocarbon gases.

[0012] Preferably, in step S4, the purity of the CO2 is >99%, the pulse frequency of the pulsed CO2 injection is 1:(2-5), the pulse step length is 10-40 h, the pulse amplitude is 1-4, and the pulse peak value is 10-22 mL / min. More preferably, the pulse frequency of the pulsed CO2 injection is 1:4, the pulse step length is 30 h, the pulse amplitude is 2.67, and the pulse peak value is 18 mL / min. In this invention, the pulse amplitude refers to the ratio of the pulse peak value to the pulse trough value, and the pulse frequency refers to the ratio of the pulse peak time to the pulse trough time.

[0013] This invention achieves a synergistic effect mechanism of air oxidation enhancing energy and CO2 displacement reducing dew point pressure. The injected air reacts with residual condensate oil in the reservoir (the reservoir temperature in deep condensate gas reservoirs is generally above 130°C; coupled with the high pressure conditions of deep reservoirs, condensate oil can undergo oxidation with oxygen, increasing heat and energy) and reverse condensate oil. This chemical reaction releases a large amount of heat energy, raising the reservoir temperature and directly reducing the viscosity of the condensate oil, thus improving its flowability, which was originally poorly fluid and attached to the rock surface or trapped in pores. Furthermore, the energy generated by the oxidation reaction effectively restores and increases the reservoir pressure. Once the reservoir pressure recovers above the dew point pressure, the process promptly transitions to the CO2 displacement stage. At this point, CO2, under higher pressure and temperature conditions, can dissolve more fully in the condensate oil. CO2's ability to reduce the system's dew point pressure and saturation pressure effectively prevents the condensate oil from re-precipitating in the formation, while significantly improving the evaporation efficiency and flowability of the condensate oil. This combined effect of pressurization and heating followed by displacement ensures that the reservoir pressure is always maintained above the dew point pressure, fundamentally suppressing the occurrence of anti-condensation and avoiding underground loss of condensate oil, thus creating favorable conditions for efficient pressure-maintaining extraction.

[0014] This invention significantly reduces the required CO2 injection volume, achieving a good balance between economic benefits and development effectiveness. In traditional single-injection CO2 pressure-maintaining extraction technology, a large amount of CO2 gas needs to be injected to restore reservoir pressure from a depleted state to above the dew point pressure. This not only leads to high CO2 procurement and injection costs but is also limited by CO2 supply, making large-scale application difficult in many oil and gas fields. This invention uses air injection for oxidation enhancement in the early stages. The cost of obtaining air is far lower than that of CO2, and some CO2 gas is generated in situ during the oxidation reaction. This in-situ generated CO2 can directly participate in subsequent displacement. Therefore, while achieving the same reservoir pressure recovery effect and condensate oil recovery rate, the required external CO2 injection volume can be significantly reduced, resulting in a significant improvement in economic efficiency. Meanwhile, the exothermic reaction of air oxidation raises the reservoir temperature. On the one hand, the amount of condensate oil that was originally in liquid state in the reservoir will partially evaporate and decrease due to the increased temperature, thus reducing the degree of condensate oil blockage. On the other hand, the higher reservoir temperature enhances the displacement capacity, pressurization effect, solubility of CO2 in condensate oil, and diffusion capacity in the reservoir. These factors work together to significantly improve the utilization efficiency of CO2, which helps to further improve the final recovery rate of condensate oil.

[0015] This invention enables real-time and continuous monitoring of reservoir temperature, pressure, and the composition of produced gas throughout the entire gas injection-well shut-off process. This real-time monitoring data provides timely and accurate underground information feedback to on-site operators, allowing technicians to dynamically adjust gas injection parameters based on trends, including key parameters such as injection rate, injection pressure, injection time, and well shut-off duration. In particular, by monitoring changes in the oxygen concentration in the produced gas at the wellhead, when the oxygen content steadily decreases to below 8%, it indicates that the oxygen in the reservoir has been fully consumed and the oxidation reaction is essentially complete, making this the optimal time to switch to CO2 displacement. This dynamic optimization based on real-time monitoring data ensures that the formation pressure remains within a safe range above the dew point pressure, effectively preventing reverse condensation and maximizing the protection of condensate oil resources from loss.

[0016] This invention is particularly applicable to the development of complex condensate gas reservoirs—deep, low-permeability reservoirs that have already experienced anti-condensation losses—a challenging technical problem. Deep gas reservoirs are typically characterized by deep burial, high temperature, and high pressure. Their low permeability results in high flow resistance and a limited reach for the fluid within the reservoir. For gas reservoirs that have undergone depletion-style development, experienced significant pressure drops, and suffered severe anti-condensation, conventional techniques are often ineffective. This invention fully considers the unique characteristics of these complex reservoirs. It overcomes the difficulty of external energy injection by generating thermal and pressure energy in situ within the reservoir through an air oxidation reaction; it improves reservoir permeability through oxidation under high-temperature conditions, alleviating the flow resistance caused by low permeability; and it effectively treats the precipitated condensate oil through the dissolution and depressurization effects of CO2, specifically addressing the anti-condensation loss problem.

[0017] This invention maximizes displacement efficiency through the optimization of a pulsed CO2 injection method and injection parameters. The pulsed injection method, through intermittent injection and cessation, allows CO2 to rapidly advance and carry condensate oil during the injection phase, while fully dissolving and diffusing into the deeper reservoir during the cessation phase, effectively improving CO2 sweep efficiency and displacement effect. Simultaneously, by adjusting process parameters, an optimal balance is found between CO2 dissolution and carrying capacity, avoiding the problems of insufficient carrying capacity due to excessively slow injection rates and incomplete dissolution due to excessively fast injection rates, thus ensuring the efficient execution of the displacement process.

[0018] Compared with the prior art, the beneficial technical effects of the present invention are as follows: This invention combines air injection oxidation heating and energy enhancement technology with CO2 pressure-maintaining displacement technology, giving full play to the synergistic advantages of the two technologies and overcoming the limitations of single technologies. While improving the recovery rate of condensate oil, it significantly reduces development costs, achieving a dual improvement in technical effect and economic benefits. It provides a new method for the efficient development of deep, low-permeability condensate gas reservoirs and has important practical value and prospects for promotion and application. Attached Figure Description

[0019] The present invention will be further described below with reference to the accompanying drawings.

[0020] Figure 1 This is the curve showing the relative volume change with pressure during the constant mass expansion of the condensate gas sample in Example 1 of the present invention; Figure 2 This is a diagram of the air-CO2 composite displacement experimental apparatus for Embodiment 1 of the present invention; Figure 3 This is a graph showing the pressure and temperature changes during the air injection and well shut-off process in Embodiment 1 of the present invention. Figure 4 This is a graph showing the relationship between CO2 injection timing and recovery rate in Embodiment 1 of the present invention; Figure 5This is a graph showing the relationship between CO2 injection method and recovery rate in Embodiment 1 of the present invention; Figure 6 This illustrates the variation in extraction rate under different pulse injection step lengths in Embodiment 1 of the present invention. Detailed Implementation

[0021] The technical solution of the present invention will be clearly and completely described below with reference to the embodiments of the present invention. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments. Based on the embodiments of the present invention, all other embodiments obtained by those of ordinary skill in the art without creative effort are within the scope of protection of the present invention.

[0022] Unless otherwise specified, all experiments were repeated three times, and the results are expressed as averages.

[0023] Example 1 S1, Dew Point Pressure Test: Condensate gas samples were collected using a surface separator. The condensate gas was then compounded according to the methods in the national standard "Methods for Fluid Property Analysis of Oil and Gas Reservoirs" (GB / T 26981-2020). Subsequently, the condensate gas was injected into a PVT analyzer under reservoir pressure and temperature conditions. After the temperature and pressure stabilized, a constant mass expansion experiment was conducted using a stepwise pressure drop method. After each stage of pressure reduction expansion, the mixture was thoroughly stirred and stabilized. The pressure and sample volume were recorded. Figure 1 The measured dew point pressure of the condensate gas reservoir was 51 MPa, and the maximum reverse condensate pressure was 35 MPa. The composition of the condensate gas used in the compounding experiment is as follows: CO2 (0.61 mol%), N2 (0.92 mol%), C1 (92.63 mol%), C2 (4.30 mol%), C3 (0.81 mol%), iC4 (0.23 mol%), nC4 (0.17 mol%), iC5 (0.13 mol%), nC5 (0.09 mol%), C6 (0.07 mol%). S2, air-CO2 combined displacement experiment: Conduct indoor air injection-CO2 combined displacement experiment ( Figure 2 The experimental setup consisted of a high-temperature, high-pressure heat-tracking compensated adiabatic static oxidation apparatus and a high-temperature, high-pressure core displacement device. The pre-treated core was placed horizontally in the heat-tracking compensated apparatus. The experimental temperature was 140℃, and a confining pressure of 25 MPa was applied. Air was injected at a rate of 60 mL / min at a rate of 1 PV. The inlet and outlet valves were then closed, and the well was shut off for 8 hours. Temperature and pressure data were continuously monitored during the shut-off period. The results showed that the system temperature increased by 17.5℃ and the pressure increased by 0.6 MPa during the shut-off process. Figure 3 ).

[0024] The reservoir pressure is restored mainly through two pathways: 1) air injection to increase pressure; 2) oxygen reacts with condensate oil to increase heat and energy. The two work together to eventually increase the pressure to over 50 MPa. After the pressure reaches the dew point pressure, the well shut-in is completed. The composition of the produced gas is detected by a gas analyzer. After three consecutive sampling tests, the oxygen content is found to be below 8%. Then, a CO2 displacement experiment is carried out to evaluate and optimize the timing, method, and rate of CO2 injection. The injection timing is set at the current formation pressure (25 MPa), the maximum reverse condensation pressure (35 MPa), and the pressure above the dew point (51.0 MPa). The injection methods include continuous CO2 injection and pulsed CO2 injection. The continuous CO2 injection adopts a constant injection rate, with the injection rate set at 12 mL / min and the total injection volume at 2.5 PV. The injection rate settings for the pulsed CO2 injection are shown in Table 1.

[0025] Depend on Figure 4 Therefore, CO2 injection should be performed when the pressure is higher than the dew point pressure. Figure 5 It can be seen that pulsed gas injection is the most effective method, achieving a recovery rate of 90%.

[0026] Example 2 The pulse amplitude of the pulsed CO2 injection was optimized, with the pulse peak value fixed at 16 mL / min, the pulse frequency fixed at 1:3, and the pulse step length fixed at 10 h. The results are shown in Table 1.

[0027] Table 1 Pulse Amplitude Scheme Design

[0028] As shown in Table 1, as the pulse amplitude increased from 1.14 to 2.67, the recovery rate increased from 85.4% to 93.2%. However, with further increases in pulse amplitude, the gas injection fluctuations intensified, and the recovery rate actually decreased. Example 3 The peak value of the pulsed CO2 injection was optimized by fixing the pulse frequency to 1:3, the pulse step length to 10 h, and the pulse amplitude to 1.5. The results are shown in Table 2.

[0029] Table 2 Pulse Peak Scheme Design

[0030] As shown in Table 2, the recovery rate first increases and then decreases with the increase of the pulse peak value. This is because the increase in pulse peak value promotes the miscibility of CO2 and condensate oil, thereby expanding the swept volume and improving the recovery rate. However, when the pulse peak value is too high, it may lead to CO2 channeling or fingering, resulting in a decrease in swept efficiency. Therefore, the pulse peak value should not be too high.

[0031] Example 4 The pulse frequency of the pulsed CO2 injection was optimized, with the pulse peak value fixed at 16 mL / min, the pulse step length fixed at 10 h, and the pulse amplitude fixed at 1.5. The results are shown in Table 3.

[0032] Table 3 Pulse Frequency Scheme Design

[0033] As shown in Table 3, the recovery rate first increases and then decreases with the increase of pulse frequency. This indicates that there is an optimal balance point for pulse frequency, which can ensure gas sweep efficiency and maintain sufficient displacement efficiency. Once this value is exceeded, the recovery rate will decrease.

[0034] Example 5 The pulse step length of the pulsed CO2 injection was optimized, with the pulse peak value fixed at 16 (mL / min), the pulse amplitude fixed at 1.5, and the pulse frequency fixed at 1:3. The results are shown in Table 4.

[0035] As shown in Table 4, when the injection step length is short, the peak injection stage is insufficient in duration, and CO2 cannot fully contact the condensate oil in the formation to complete effective miscible extraction and reverse condensation, thus reducing the degree of recovery. When the pulse step length is long, gas channeling will be exacerbated, further reducing the degree of recovery.

[0036] The relationship between the well-closing time in the experiment and the actual field application represents a scale-up process from laboratory mechanism verification to field implementation of the same technical solution. The 8-hour well-closing time in the example was used to verify the feasibility of this technology. However, there is a significant scale difference between centimeter-level core samples in the laboratory and tens of meters-level reservoirs in the field. Therefore, the well-closing time implemented in the field in this invention is 10-20 days.

[0037] The embodiments described above are merely illustrative of several implementations of the present invention, and while the descriptions are relatively specific and detailed, they should not be construed as limiting the scope of the invention patent. It should be noted that those skilled in the art can make various modifications and improvements without departing from the concept of the present invention, and these all fall within the protection scope of the present invention. Therefore, the protection scope of this invention patent should be determined by the appended claims.

Claims

1. A method for exploiting deep, low-permeability condensate gas reservoirs using a combination of air injection, oxidation, heating, and energy enhancement with CO2 pressure maintenance, characterized in that... Includes the following steps: S1. Dew point pressure measurement: A constant mass expansion experiment was conducted using compound condensate gas under reservoir temperature and pressure conditions to measure the dew point pressure. S2. Air injection for heating and energy enhancement: A monitoring device is installed in the target wellbore. Air is injected into the depleted condensate gas reservoir through the injection well of the implementation well group at the surface. After the air injection is completed, the well is shut in and kept closed. During the well closure period, the pressure and temperature changes are tracked in real time through the downhole monitoring device. If the reservoir pressure does not recover to above the dew point pressure after the well closure is completed, the air injection-well closure operation is repeated until the pressure meets the requirements. S3. Oxygen concentration detection and gas injection conversion judgment: After the well is shut off, monitor the oxygen concentration in the gas produced at the wellhead. When the oxygen content is stably below 8%, switch to CO2 displacement. S4, CO2 displacement: Indoor displacement experiments were conducted to determine the gas injection rate, and then pulsed CO2 injection was used to realize the exploitation of deep low-permeability condensate gas reservoirs. During the mining process, the formation pressure is maintained above the dew point pressure.

2. The method for exploiting deep, low-permeability condensate gas reservoirs using a combination of air injection, oxidation, heating, and energy enhancement with CO2 pressure maintenance, as described in claim 1, is characterized in that... The depth of the deep, low-permeability condensate gas reservoir is >4500 m.

3. The method for exploiting deep, low-permeability condensate gas reservoirs using a combination of air injection, oxidation, heating, and energy enhancement with CO2 pressure maintenance, as described in claim 1, is characterized in that... The permeability of the deep, low-permeability condensate gas reservoir is 1~10 mD.

4. The method for exploiting deep, low-permeability condensate gas reservoirs using air injection oxidation, heating, and energy enhancement combined with CO2 pressure maintenance, as described in claim 1, is characterized in that... In step S2, the detection device is a temperature and pressure detection device.

5. The method for exploiting deep, low-permeability condensate gas reservoirs using air injection oxidation, heating, and energy enhancement combined with CO2 pressure maintenance, as described in claim 1, is characterized in that... In step S2, the air injection pressure is 1.1 to 1.3 times the original formation pressure.

6. The method for exploiting deep, low-permeability condensate gas reservoirs using air injection oxidation, heating, and energy enhancement combined with CO2 pressure maintenance, as described in claim 1, is characterized in that... In step S2, the well-sealing time is 10 to 20 days.

7. The method for exploiting deep, low-permeability condensate gas reservoirs using air injection oxidation, heating, and energy enhancement combined with CO2 pressure maintenance, as described in claim 1, is characterized in that... In step S3, the method for determining the stability of oxygen content is as follows: After the well is shut off, the gas produced at the wellhead is tested. When the oxygen content is below 8% after three consecutive samplings, it can be determined to be stable.

8. The method for exploiting deep, low-permeability condensate gas reservoirs using air injection oxidation, heating, and energy enhancement combined with CO2 pressure maintenance, as described in claim 1, is characterized in that... In step S4, the purity of the CO2 is >99%, the pulse frequency of the pulsed CO2 injection is 1:(2-5), the pulse step length is 10-40 h, the pulse amplitude is 1-4, and the pulse peak value is 10-22 mL / min.

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