A method for enhanced recovery of natural gas hydrates in permafrost regions
By combining depressurization extraction of natural gas hydrates in permafrost regions with the purge of mixed CO2 and H2 gas and CO2 sequestration, the problems of low recovery rate and poor reservoir stability of natural gas hydrates in permafrost regions have been solved, achieving efficient recovery and reservoir stability, and breaking the self-protection effect below freezing point.
Patent Information
- Authority / Receiving Office
- CN · China
- Patent Type
- Patents(China)
- Current Assignee / Owner
- CHINA UNIV OF PETROLEUM (BEIJING)
- Filing Date
- 2023-10-09
- Publication Date
- 2026-05-12
AI Technical Summary
Natural gas hydrates in permafrost regions exhibit a self-protective effect below freezing point, resulting in low gas production efficiency and poor reservoir stability. Existing heat injection methods are energy inefficient and may trigger geological disasters, while carbon dioxide replacement extraction leads to a decline in gas production efficiency in the later stages.
The method employs depressurization extraction combined with CO2 and H2 mixed gas huff and purge and CO2 geological sequestration. By controlling temperature and pressure, the self-protection effect is broken, the recovery rate is improved, and the reservoir stability is ensured.
It significantly improves the recovery rate of natural gas hydrates in permafrost areas, ensures reservoir stability, avoids geological disasters, achieves geological sequestration of CO2, and has high energy utilization efficiency.
Smart Images
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Abstract
Description
Technical Field
[0001] This invention belongs to the field of natural gas hydrate extraction technology in permafrost areas, specifically relating to a method for improving the recovery rate of natural gas hydrates in permafrost areas. Background Technology
[0002] Natural gas hydrates are mainly composed of water and hydrocarbon gases such as methane. Under high pressure and low temperature, they form an ice-like solid, and because they are combustible, they are also known as "combustible ice." Natural gas hydrates are widely recognized as a clean energy source for the 21st century due to their large reserves, high energy density, and pollution-free combustion. In recent years, countries around the world have discovered vast reserves of natural gas hydrates in seabed sediments and permafrost.
[0003] Although the reserves of natural gas hydrates in permafrost regions are enormous, the strong self-protection effect of natural gas hydrates at freezing points greatly reduces gas extraction efficiency and volume, which severely restricts the commercial exploitation of natural gas hydrates in permafrost regions.
[0004] To address the strong self-protective effect of natural gas hydrates in permafrost regions, the most effective current solution is to combine depressurization with various heat injection methods for gas extraction. Large amounts of heat injection melt the ice crust on the surface of the natural gas hydrates, allowing for continuous decomposition and gas production. However, most of the injected heat is used to heat the gas hydrate reservoir, with very little actually utilized for decomposition, resulting in extremely low energy efficiency. Simultaneously, the heat injection disrupts the cementation between the natural gas hydrates or ice and reservoir sediments, significantly reducing the reservoir's mechanical strength. This can trigger geological hazards such as reservoir subsidence and formation collapse during gas hydrate extraction, seriously threatening downhole facilities and gas production safety. While conventional carbon dioxide replacement extraction is considered the safest method above and below freezing, its further development is limited by the sharp decline in gas production efficiency caused by carbon dioxide hydrate covering the natural gas hydrates. Therefore, improving the recovery rate of natural gas hydrates in permafrost regions while ensuring reservoir stability is a pressing issue for gas hydrate extraction in these areas. Summary of the Invention
[0005] The purpose of this invention is to provide a method that can improve the recovery rate of natural gas hydrates in permafrost areas while ensuring reservoir stability. This method can significantly improve the recovery rate of natural gas in permafrost areas, effectively ensure reservoir stability, and achieve geological sequestration of carbon dioxide.
[0006] To achieve the above objectives, the present invention provides a method for enhancing the recovery rate of natural gas hydrates in permafrost regions, wherein the method includes:
[0007] Pressure reduction extraction steps: Free gas is discharged from the natural gas hydrate reservoir in the target permafrost area using a pressure reduction method, so that the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area is reduced to the first rated pressure and the reservoir temperature reaches the first rated temperature; wherein, the first rated pressure is 0.8-1.2 times the phase equilibrium pressure of natural gas hydrate; the first rated temperature is less than 0℃ and greater than or equal to -6℃;
[0008] The purging process involves injecting a mixture of CO2 and H2 into the natural gas hydrate reservoir in the target permafrost region after the reservoir pressure drops to the first rated pressure and the reservoir temperature reaches the first rated temperature. Multiple rounds of purging are performed, with well shut-off between each round of purging. During these multiple purging rounds, the temperature of the natural gas hydrate reservoir in the target permafrost region is maintained between -6°C and 0°C.
[0009] CO2 geological sequestration steps: After the huff and purge steps are completed, CO2 is injected into the natural gas hydrate reservoir in the target permafrost area to purge and recover free H2 and perform CO2 geological sequestration.
[0010] The method for enhancing the recovery rate of natural gas hydrates in permafrost regions provided by this invention can not only break the self-protection effect of hydrates below freezing point, but also avoid excessive energy loss compared to thermal injection extraction, thus solving the problem of low recovery rate caused by ice covering hydrates and greatly improving the recovery rate of natural gas in permafrost regions. At the same time, this method can maintain formation stability and achieve geological sequestration of CO2.
[0011] Preferably, during the process of releasing free gas from the natural gas hydrate reservoir in the target permafrost region using a depressurization method, if the reservoir temperature is higher than the first rated temperature, the reservoir temperature can be reduced to the first rated temperature by controlling the depressurization rate and degree of the depressurization process. If the reservoir temperature is lower than the first rated temperature, the reservoir temperature can be raised by pre-injecting steam into the reservoir to achieve the first rated temperature. If the reservoir temperature is at the first rated temperature, the reservoir temperature can be maintained at the first rated temperature by controlling the depressurization rate and degree of the depressurization process.
[0012] Preferably, during the multiple rounds of huff and puff purging of a mixture of CO2 and H2 injected into the natural gas hydrate reservoir in the target permafrost region, each round of huff and puff purging ends when the molar percentage of CH4 in the puffed gas drops to a rated content; wherein, the rated content is 10%-20%.
[0013] Preferably, between each round of huff and puff, the well is kept simmering until the growth rate of the CH4 molar percentage in the gas within the natural gas hydrate reservoir in the target permafrost area does not exceed 5% / h before proceeding to the next round of huff and puff.
[0014] Preferably, during the multiple rounds of huff and puff purging of a mixture of CO2 and H2 into the natural gas hydrate reservoir in the target permafrost region, the huff and puff purging process ends when the molar content of CH4 in the reservoir no longer increases after the injection of the mixture of CO2 and H2.
[0015] Preferably, the initial hydrate saturation of the natural gas hydrate reservoir in the target permafrost region is 40%-60%.
[0016] Preferably, the initial water saturation of the natural gas hydrate reservoir in the target permafrost region is 40%-70%.
[0017] Preferably, in the mixture of CO2 and H2, the molar percentage of CO2 to H2 is 80:20-20:80.
[0018] Preferably, the temperature of the CO2 and H2 mixture injected into the natural gas hydrate reservoir in the target permafrost region is 15°C-30°C; in a specific embodiment, the temperature of the CO2 and H2 mixture injected into the natural gas hydrate reservoir in the target permafrost region is room temperature.
[0019] Preferably, during the multiple rounds of huff and puff purging of a mixture of CO2 and H2 into the natural gas hydrate reservoir in the target permafrost area, the injection pressure of the mixture of CO2 and H2 is 25%-95% higher than the extraction pressure.
[0020] Preferably, during the process of injecting CO2 into the natural gas hydrate reservoir in the target permafrost region to purge and recover free H2 and to carry out geological sequestration of CO2, the CO2 injection pressure is lower than the CO2 liquefaction pressure at the temperature of the natural gas hydrate reservoir in the target permafrost region at this time, and higher than the phase equilibrium pressure of CO2 hydrate at the temperature of the natural gas hydrate reservoir in the target permafrost region at this time.
[0021] Preferably, during the process of injecting CO2 into the natural gas hydrate reservoir in the target permafrost region to purge and recover free H2 and to carry out CO2 geological sequestration, the CO2 geological sequestration step ends when no more carbon dioxide hydrate is generated after CO2 injection. That is, the injection of CO2 is stopped when the reservoir pressure of the natural gas hydrate reservoir in the target permafrost region is higher than the CO2 hydrate formation pressure at the natural gas hydrate reservoir temperature in the target permafrost region but lower than the CO2 liquefaction pressure at the natural gas hydrate reservoir temperature in the target permafrost region, and the reservoir pressure no longer decreases.
[0022] Preferably, injecting CO2 into the natural gas hydrate reservoir in the target permafrost region for purging and recovering free H2 and for geological sequestration of CO2 includes:
[0023] 1) Inject CO2 into the natural gas hydrate reservoir in the target permafrost area until the reservoir pressure reaches the second rated pressure, then stop injection and shut down the well until the reservoir pressure no longer decreases; wherein, the second rated pressure is higher than the CO2 hydrate formation pressure at the natural gas hydrate reservoir temperature in the target permafrost area at this time and lower than the CO2 liquefaction pressure at the natural gas hydrate reservoir temperature in the target permafrost area at this time;
[0024] 2) Repeat step 1) until no more carbon dioxide hydrate is produced after CO2 injection. The CO2 geological sequestration step is completed, that is, CO2 is injected into the natural gas hydrate reservoir in the target permafrost area until the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area reaches the second rated pressure. Then, the injection is stopped and the reservoir pressure does not decrease during the well shut-in process.
[0025] Furthermore, the second rated pressure is greater than 95% of the liquefaction pressure of CO2 at the target permafrost region natural gas hydrate reservoir temperature; in one specific embodiment, the second rated pressure is greater than or equal to 99% of the liquefaction pressure of CO2 at the target permafrost region natural gas hydrate reservoir temperature.
[0026] Preferably, the process of discharging free gas by depressurization can be carried out using conventional techniques in the field.
[0027] Preferably, the process used in each round of purging can be carried out using conventional techniques in the field; in one specific embodiment, a method of injecting a mixture of CO2 and H2, shutting down the well, and then mining is adopted; in another specific embodiment, a method of injecting a mixture of CO2 and H2, shutting down the well, mining, injecting a mixture of CO2 and H2, shutting down the well, mining, and then cycling through injecting a mixture of CO2 and H2, shutting down the well, mining, and so on for 3-8 times.
[0028] The method for enhancing the recovery rate of natural gas hydrates in permafrost regions provided by this invention has the following advantages compared with existing technologies:
[0029] (1) The method for enhancing the recovery rate of natural gas hydrate in permafrost areas provided by the present invention takes advantage of the natural temperature below freezing point in permafrost areas, so that the water generated during the entire hydrate extraction process immediately freezes into ice and continues to cement the sediment. Combined with the CO2 / H2 purging and CO2 sequestration process, CO2 hydrate is generated to stabilize the reservoir, ensuring the formation stability when the reservoir temperature in the permafrost area rises to above freezing point, ensuring the formation stability of the entire extraction process, preventing geological disasters such as formation collapse and subsidence, and ensuring the safety and sustainability of the entire extraction process.
[0030] (2) Due to the self-protection effect of natural gas hydrates below freezing point, and the stronger the self-protection effect at lower temperatures, it is difficult for natural gas hydrates to continue decomposing once the decomposition conditions are met. The method for enhancing the recovery rate of natural gas hydrates in permafrost areas provided by this invention utilizes the characteristics of natural permafrost areas where hydrate decomposition water can form porous ice at temperatures below 0℃ and above -6℃, and porous CO2 hydrates can be formed under CO2 / H2 purging. The decomposition gas on the surface of CH4 hydrates can be continuously carried away, reducing the partial pressure of methane on the surface of methane hydrates and promoting the continuous decomposition of methane hydrates. This effectively breaks the self-protection effect of natural gas hydrates below freezing point. Compared with thermal injection, there is no excessive energy loss. At the same time, due to the strong diffusion ability of H2, natural gas hydrates in porous ice or porous CO2 hydrates formed below freezing point can be continuously produced, greatly improving the recovery rate of natural gas hydrates in permafrost areas.
[0031] (3) The mixed gas produced by the method for enhancing the recovery rate of natural gas hydrate in permafrost areas provided by the present invention is easy to separate. The CH4, H2, CO2 produced are reformed with water to obtain a mixed gas with a high hydrogen concentration of CO2 and H2. After separating and purifying H2, the remaining mixed gas of CO2 and H2 can still be used for the mining of hydrates in permafrost areas. Attached Figure Description
[0032] Figure 1 This is a schematic diagram of the indoor simulation device for natural gas hydrate extraction in permafrost regions used in Example 1.
[0033] Figure 2 This is a schematic diagram illustrating the mechanism by which the method for enhancing the recovery rate of natural gas hydrates in permafrost regions, as provided in Example 1, improves the recovery rate of natural gas hydrates in permafrost regions.
[0034] Figure 3 This is a graph showing the changes in temperature, pressure, and longitudinal wave velocity over time during the entire process in Example 1.
[0035] Figure 4 This is a scatter plot showing the change in recovery rate over time at different mining stages in Example 1. Detailed Implementation
[0036] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of the present invention. Based on the embodiments of the present invention, all other embodiments obtained by those skilled in the art without creative effort are within the protection scope of the present invention.
[0037] A specific embodiment of the present invention provides a method for enhancing the recovery rate of natural gas hydrates in permafrost regions, wherein the method includes:
[0038] Step S1: The free gas in the natural gas hydrate reservoir in the target permafrost area is discharged by depressurization, so that the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area is reduced to the first rated pressure and the reservoir temperature reaches the first rated temperature; wherein, the first rated pressure is 0.8-1.2 times the phase equilibrium pressure of natural gas hydrate; the first rated temperature is less than 0℃ and greater than or equal to -6℃;
[0039] Step S2: After the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area drops to the first rated pressure and the reservoir temperature reaches the first rated temperature, a mixture of CO2 and H2 is injected into the natural gas hydrate reservoir in the target permafrost area for multiple rounds of huff and puff purging; during each round of huff and puff purging, the well is shut off; during the multiple rounds of huff and puff purging, the temperature of the natural gas hydrate reservoir in the target permafrost area is maintained at less than 0℃ and greater than or equal to -6℃;
[0040] Step S3: After the huff and purge process is completed, CO2 is injected into the natural gas hydrate reservoir in the target permafrost area to purge and recover free H2 and to perform geological sequestration of CO2.
[0041] Furthermore, during the process of releasing free gas from the natural gas hydrate reservoir in the target permafrost region using a depressurization method, if the reservoir temperature is higher than the first rated temperature, the reservoir temperature can be reduced to the first rated temperature by controlling the extraction rate of the depressurization process. If the reservoir temperature is lower than the first rated temperature, the reservoir temperature can be raised by pre-injecting steam into the reservoir to achieve the first rated temperature. If the reservoir temperature is at the first rated temperature, the reservoir temperature can be maintained at the first rated temperature by controlling the extraction rate of the depressurization process.
[0042] Furthermore, during the multiple rounds of huff and puff purging of a mixture of CO2 and H2 injected into the natural gas hydrate reservoir in the target permafrost region, each round of huff and puff purging is terminated when the molar percentage of CH4 in the puffed gas drops to a rated content; wherein, the rated content is 10%-20%.
[0043] Furthermore, between each round of huff and purge, the well is kept slack until the growth rate of the CH4 molar percentage in the gas within the natural gas hydrate reservoir in the target permafrost area does not exceed 5% / h before proceeding to the next round of huff and purge.
[0044] Furthermore, during multiple rounds of huff and puff purging of a mixture of CO2 and H2 into the natural gas hydrate reservoir in the target permafrost region, the CH4 molar content in the reservoir no longer increases after the injection of the CO2 and H2 mixture, and step S2 ends.
[0045] Furthermore, the initial hydrate saturation of the natural gas hydrate reservoir in the target permafrost region is 40%-60%.
[0046] Furthermore, the initial water saturation of the natural gas hydrate reservoir in the target permafrost region is 40%-70%.
[0047] Furthermore, in the mixture of CO2 and H2, the molar percentage of CO2 to H2 is 80:20-20:80.
[0048] Furthermore, the temperature of the CO2 and H2 mixture injected into the natural gas hydrate reservoir in the target permafrost region is room temperature, specifically 15℃-30℃.
[0049] Furthermore, during the multiple rounds of huff and puff purging of a mixture of CO2 and H2 into the natural gas hydrate reservoir in the target permafrost region, the injection pressure of the CO2 and H2 mixture is 25%-95% higher than the extraction pressure.
[0050] Furthermore, during the process of injecting CO2 into the natural gas hydrate reservoir in the target permafrost region to purge and recover free H2 and to carry out geological sequestration of CO2, the CO2 injection pressure is lower than the CO2 liquefaction pressure at the natural gas hydrate reservoir temperature in the target permafrost region, but higher than the phase equilibrium pressure of CO2 hydrate at the natural gas hydrate reservoir temperature in the target permafrost region.
[0051] Furthermore, during the process of injecting CO2 into the natural gas hydrate reservoir in the target permafrost region to purge and recover free H2 and to carry out CO2 geological sequestration, the CO2 geological sequestration step ends when no more carbon dioxide hydrate is generated after CO2 injection. That is, the injection of CO2 is carried out until the reservoir pressure of the natural gas hydrate reservoir in the target permafrost region is higher than the CO2 hydrate formation pressure at the current temperature of the natural gas hydrate reservoir in the target permafrost region, and then the injection is stopped and the reservoir pressure no longer decreases.
[0052] Furthermore, injecting CO2 into the natural gas hydrate reservoir in the target permafrost region to purge and recover free H2 and perform geological CO2 sequestration includes:
[0053] 1) Inject CO2 into the natural gas hydrate reservoir in the target permafrost area until the reservoir pressure reaches the second rated pressure, then stop injection and shut down the well until the reservoir pressure no longer decreases; wherein, the second rated pressure is higher than the CO2 hydrate formation pressure at the natural gas hydrate reservoir temperature in the target permafrost area at this time and lower than the CO2 liquefaction pressure at the natural gas hydrate reservoir temperature in the target permafrost area at this time;
[0054] 2) Repeat step 1) until no more carbon dioxide hydrate is produced after CO2 injection. The CO2 geological sequestration step is completed, that is, CO2 is injected into the natural gas hydrate reservoir in the target permafrost area until the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area reaches the second rated pressure. Then, the injection is stopped and the reservoir pressure does not decrease during the well shut-in process.
[0055] Furthermore, the second rated pressure is greater than 95% of the liquefaction pressure of CO2 at the temperature of a natural gas hydrate reservoir in a standard permafrost region; for example, the second rated pressure is greater than or equal to 99% of the liquefaction pressure of CO2 at the temperature of a natural gas hydrate reservoir in a standard permafrost region.
[0056] Preferably, the process of discharging free gas by depressurization can be carried out using conventional techniques in the field.
[0057] Preferably, the process used in each round of purging can employ conventional techniques in the art; in one specific embodiment, a mixture of CO2 and H2 is injected, the well is shut down, and production is carried out; in another specific embodiment, a mixture of CO2 and H2 is injected, the well is shut down, production is carried out, a mixture of CO2 and H2 is injected, the well is shut down, production is carried out, and this process is repeated 3-8 times.
[0058] Example 1
[0059] This embodiment provides a method for enhancing the recovery rate of natural gas hydrates in permafrost regions, which is carried out using indoor simulation.
[0060] This embodiment provides a method for enhancing the recovery rate of natural gas hydrates in permafrost regions, employing methods such as... Figure 1The indoor simulation device for natural gas hydrate extraction in permafrost areas is shown. The device comprises four systems: a reaction system, an intake system, a collection system, and a data acquisition system. The reaction system includes a cryogenic bath (4), valves (5), a reaction vessel (6), a piezoelectric transducer (7), a rotating screw (8), a stainless steel ring (9), and sediment (10). The intake system includes gas cylinders (12), valves (13, 14), and a buffer tank (15). The collection system includes a collection tank (2) and a gas-liquid separator (3). The data acquisition system includes a temperature and pressure data acquisition computer (1) and an ultrasonic longitudinal wave velocity acquisition device (11). In this device, P1 and P2 are pressure sensors, and T1 and T2 are thermocouple temperature sensors. The intake system provides the necessary gases for the experiment: a mixture of CH4, CO2, and H2. The injection process for the CO2 and CO2 / H2 mixtures is mainly controlled by the buffer tank (15). Valve 5 in the reaction system includes a shut-off valve to control the intake speed and pressure, and a back pressure valve to control the internal pressure of the reaction system during the extraction process. The rotating screw 8 applies axial pressure to the stainless steel ring 9, compacting the sediment 10 as a whole. The temperature of the entire reaction system is controlled by the cryogenic bath 4. In the collection system, the gas-liquid separator 3 separates the collected gas and water by gravity, and the collected gas is collected in the collection tank 2. Real-time temperature and pressure data are recorded by computer data acquisition software, and the ultrasonic longitudinal wave velocity is acquired and processed in real time by an ultrasonic transceiver.
[0061] This embodiment provides a method for enhancing the recovery rate of natural gas hydrates in permafrost regions, specifically employing the following steps in indoor simulation:
[0062] 1) Open the gas cylinder valve and valve 5 shut-off valve to inject CH4 gas into reactor 6 to synthesize natural gas hydrate at freezing point. When the natural gas hydrate sediment sample reaches the preset high saturation, adjust the low temperature bath 4 to below freezing point (-6℃ to -1℃) to simulate the natural gas hydrate reservoir in the target permafrost region.
[0063] 2) When the temperature of reactor 6 stabilizes below freezing (-5℃ to -1℃), the pressure inside reactor 6 is adjusted using a pressure reduction method. The regulating valve 5 shuts off the pressure in reactor 6 to approximately 0.5 MPa above the equilibrium pressure of the natural gas hydrate phase at this freezing point. After the temperature and pressure of the reactor stabilize again, and the temperature of the reactor remains at freezing (-5℃ to -1℃), natural gas hydrate extraction is carried out. The back pressure valve 5 is adjusted to the specified extraction pressure using a pressure reduction method, and the free gas extracted during the pressure reduction process is collected. This simulates the natural gas hydrate reservoir in the target permafrost region by removing free gas through a pressure reduction method, reducing the reservoir pressure of the natural gas hydrate reservoir in the target permafrost region to the rated pressure (slightly higher than the equilibrium pressure of the natural gas hydrate phase) while maintaining the reservoir temperature at freezing.
[0064] 3) Open valve 13 and control the inlet flow rate of the CO2 and H2 mixture by controlling the opening of the shut-off valve 5. Stop the inlet flow when the pressure of the CO2 and H2 mixture is 25%-95% higher than the mining pressure. After the mixture has been stabilized for a period of time and fully mixed, open the back pressure valve 5 to discharge the gas to the mining pressure. Repeat the above operation 3-8 times (control the inlet flow rate of the CO2 and H2 mixture by controlling the opening of the shut-off valve 5, stop the inlet flow when the pressure of the CO2 and H2 mixture is 25%-95% higher than the mining pressure, stabilize the mixture for a period of time and fully mixed, then open the back pressure valve 5 to discharge the gas to the mining pressure) to carry out as much CH4 free gas as possible from the reactor until the molar percentage of CH4 gas in the discharged gas is less than 10%-20%, at which point this round of huff and purge is over.
[0065] Close valve 5 (back pressure valve) and shut-off valve to allow the well to be shut down, causing the hydrates in the natural gas hydrate reservoir to decompose or be replaced. Take gas from the natural gas hydrate reservoir to analyze the molar percentage of each component, and take gas for analysis at regular intervals until the molar percentage of CH4 in the natural gas hydrate reservoir no longer increases or increases slowly. Then, perform the next round of huff and puff operations in the same manner.
[0066] Repeat this process multiple times until the next round of gas injection and purging is completed. If the methane molar percentage in the natural gas hydrate reservoir no longer increases or increases slowly over a relatively long period of time, it indicates that the natural gas hydrate reservoir is no longer worth exploiting.
[0067] During the mining process, the temperature of reactor 6 was maintained between -5℃ and -1℃.
[0068] To achieve the goal of reducing the reservoir pressure to the first rated pressure and the reservoir temperature to the first rated temperature in the simulated target permafrost region's natural gas hydrate reservoir, a mixture of CO2 and H2 gas is injected into the natural gas hydrate reservoir in the target permafrost region for multiple rounds of huff and puff. Each round of huff and puff is terminated when the molar percentage of CH4 in the puffed gas drops to the rated content of 10%-20%. Between each round of huff and puff, the well is shut-in until the growth rate of the molar percentage of CH4 in the gas in the target permafrost region's natural gas hydrate reservoir does not exceed 5% / h before the next round of huff and puff is carried out. This process continues until the molar percentage of CH4 in the reservoir no longer increases after the injection of the mixture of CO2 and H2 gas, at which point the huff and puff process ends.
[0069] 4) Using CO2 for reservoir purging to recover H2 from the reservoir and for CO2 geological sequestration, specifically including:
[0070] A. Inject CO2 into the natural gas hydrate reservoir in the target permafrost region until the reservoir pressure reaches the second rated pressure. Then, stop injection and shut down the well until the reservoir pressure no longer decreases. The second rated pressure is higher than the CO2 hydrate formation pressure at the target permafrost region's natural gas hydrate reservoir temperature but lower than the CO2 liquefaction pressure at the target permafrost region's natural gas hydrate reservoir temperature. In this embodiment, the second rated pressure is approximately 99% of the CO2 liquefaction pressure at the target permafrost region's natural gas hydrate reservoir temperature.
[0071] B. Repeat step A until no more carbon dioxide hydrate is produced after CO2 injection. The CO2 geological sealing step ends, that is, CO2 is injected into the natural gas hydrate reservoir in the target permafrost area until the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area reaches the second rated pressure, and then injection is stopped to perform well shut-in. During this process, the reservoir pressure does not decrease.
[0072] Figure 2 A schematic diagram illustrating the mechanism by which the method of this embodiment can improve the recovery rate of natural gas hydrates in permafrost regions is provided. Figure 2 This clearly reveals why injecting a mixture of CO2 and H2 below freezing point can improve the recovery rate of natural gas hydrates. The injection of the mixture of CO2 and H2 below freezing point causes the decomposition water of natural gas hydrates to freeze into porous ice or form porous CO2 hydrates with CO2 at freezing point. Because H2 molecules have strong diffusion ability, they can continuously enter the porous structure and contact the natural gas hydrates, causing them to decompose continuously and promoting the production of free CH4 gas.
[0073] Figure 3 The method of this embodiment provides graphs showing the changes in temperature, pressure, and longitudinal wave velocity over time throughout the entire process. Figure 4 This provides a scatter plot showing the recovery rate changing over time at different mining stages in the method of this embodiment. According to... Figure 3 Phase C and Figure 4 The first stage shows that during the freezing point depressurization process, the longitudinal wave velocity fluctuations are small, and the reservoir remains stable. Due to the strong self-protection effect of natural gas hydrates below the freezing point, their decomposition is minimal under phase equilibrium pressure, resulting in low recovery rates. According to... Figure 3 The D-stage analysis shows that the fact that the longitudinal wave velocity of the reservoir was not reduced after multiple CO2 and H2 mixtures were introduced at room temperature and then purged indicates that the reservoir has good stability and will not experience geological disasters. Figure 4The two-stage analysis shows that injecting a mixture of CO2 and H2 can effectively break the strong self-protection effect of natural gas hydrates below the freezing point, allowing the hydrates to continue decomposing. Simultaneously, the strong diffusion capacity of small-molecule H2 allows it to enter porous ice or porous CO2 hydrates, promoting the production of internal CH4 free gas. This effectively solves the problem of high mass transfer resistance in the later stages of natural gas hydrate extraction due to thick ice shells or excessively thick CO2 hydrate layers. Compared to pure depressurization extraction below the freezing point, depressurization combined with injecting a mixture of CO2 and H2 increases the final recovery rate of natural gas hydrates by approximately 292.68%. According to... Figure 3 As can be seen from the E stage, during the CO2 injection and sequestration stage, the large-scale generation of CO2 hydrates releases heat, causing the ice in the reservoir to melt and the P-wave velocity to decrease slightly. However, with the large-scale generation of CO2 hydrates, the P-wave velocity quickly recovers, ensuring the stability of the reservoir and realizing the geological sequestration of CO2.
[0074] The above embodiments are merely one or more embodiments of this specification, and various variations can be made to the one or more embodiments of this specification by those skilled in the art. Any modifications, equivalent substitutions, improvements, etc., made within the spirit and principle of this application should be included within the scope of the claims.
Claims
1. A method for enhancing the recovery rate of natural gas hydrates in permafrost regions, wherein, The method includes: Pressure reduction extraction steps: Free gas is discharged from the natural gas hydrate reservoir in the target permafrost area using a pressure reduction method, so that the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area is reduced to the first rated pressure and the reservoir temperature reaches the first rated temperature; wherein, the first rated pressure is 0.8-1.2 times the phase equilibrium pressure of natural gas hydrate; the first rated temperature is less than 0℃ and greater than or equal to -6℃; The purging process involves injecting a mixture of CO2 and H2 into the target permafrost natural gas hydrate reservoir after the reservoir pressure drops to the first rated pressure and the reservoir temperature reaches the first rated temperature. Multiple rounds of purging are performed, with well shut-off between each round. During these multiple purging rounds, the temperature of the target permafrost natural gas hydrate reservoir is maintained between -6°C and 0°C. The molar percentage of CO2 to H2 in the CO2 and H2 mixture is 80:20 to 20:
80. CO2 geological sequestration steps: After the huff and purge steps are completed, CO2 is injected into the natural gas hydrate reservoir in the target permafrost area to purge and recover free H2 and perform CO2 geological sequestration. In the process of releasing free gas from the natural gas hydrate reservoir in the target permafrost region using a depressurization method, if the reservoir temperature is higher than the first rated temperature, the reservoir temperature is reduced to the first rated temperature by controlling the depressurization rate and degree of the depressurization process. If the reservoir temperature is lower than the first rated temperature, the reservoir temperature is raised by pre-injecting steam to achieve the first rated temperature. If the reservoir temperature is at the first rated temperature, the reservoir temperature is maintained at the first rated temperature by controlling the depressurization rate and degree of the depressurization process. The process of injecting CO2 into the natural gas hydrate reservoir in the target permafrost region to purge and recover free H2 and to perform geological CO2 sequestration includes: 1) Inject CO2 into the natural gas hydrate reservoir in the target permafrost area until the reservoir pressure reaches the second rated pressure, then stop injection and shut down the well until the reservoir pressure no longer decreases; wherein, the second rated pressure is higher than the natural gas hydrate formation pressure at the natural gas hydrate reservoir temperature in the target permafrost area at this time and lower than the CO2 liquefaction pressure at the natural gas hydrate reservoir temperature in the target permafrost area at this time. 2) Repeat step 1) until no more carbon dioxide hydrate is produced after CO2 injection. The CO2 geological sequestration step is completed, that is, CO2 is injected into the natural gas hydrate reservoir in the target permafrost area until the reservoir pressure of the natural gas hydrate reservoir in the target permafrost area reaches the second rated pressure, and then injection is stopped to perform well shut-in. During this process, the reservoir pressure does not decrease.
2. The method according to claim 1, wherein, During the multiple rounds of huff and puffing of a mixture of CO2 and H2 into a natural gas hydrate reservoir in the target permafrost region, each round of huff and puffing ends when the molar percentage of CH4 in the puffed gas drops to a rated content; wherein, the rated content is 10%-20%.
3. The method according to claim 1, wherein, Between each round of huff and puff, the well is kept slack until the growth rate of the CH4 molar percentage in the gas within the natural gas hydrate reservoir in the target permafrost area does not exceed 5% / h before proceeding to the next round of huff and puff.
4. The method according to claim 1, wherein, During the multiple rounds of huff and puff purging of a mixture of CO2 and H2 into a natural gas hydrate reservoir in the target permafrost region, the huff and puff purging process ends when the molar content of CH4 in the reservoir no longer increases after the injection of the mixture of CO2 and H2.
5. The method according to claim 1, wherein, The initial hydrate saturation of the natural gas hydrate reservoir in the target permafrost region is 40%-60%; and / or The initial water saturation of the natural gas hydrate reservoir in the target permafrost region is 40%-70%.
6. The method according to claim 1, wherein, The temperature of the CO2 and H2 mixture injected into the natural gas hydrate reservoir in the target permafrost region is 15℃-30℃.
7. The method according to claim 1, wherein, During multiple rounds of huff and puff purging of a mixture of CO2 and H2 into the natural gas hydrate reservoir in the target permafrost region, the injection pressure of the CO2 and H2 mixture is 25%-95% higher than the extraction pressure.
8. The method according to claim 1, wherein, During the process of injecting CO2 into the natural gas hydrate reservoir in the target permafrost region to purge and recover free H2 and to carry out geological CO2 sequestration, the CO2 injection pressure is lower than the CO2 liquefaction pressure at the temperature of the natural gas hydrate reservoir in the target permafrost region, but higher than the phase equilibrium pressure of CO2 hydrate at the temperature of the natural gas hydrate reservoir in the target permafrost region.
9. The method according to claim 1, wherein, The second rated pressure is greater than 95% of the CO2 liquefaction pressure at the temperature of the natural gas hydrate reservoir in the target permafrost region.