A high-efficiency displacement mining method for hydrate reservoirs containing associated gas sources

Abstract

The application discloses a kind of high-efficiency replacement mining methods for hydrate reservoir with associated gas source, belong to natural gas hydrate mining technical field.The method includes: for natural gas hydrate reservoir with upper free gas layer, gas injection well is set in hydrate layer, and mining well is set in upper free gas layer;For natural gas hydrate reservoir with underlying free gas layer, gas injection well is set in underlying free gas layer, and mining well is set in hydrate layer;Pressure is reduced through mining well, mining well is kept open, gas injection well is opened, carbon dioxide is injected, and mining is ended when the methane content in mining well is lower than preset value.The application is aimed at natural gas hydrate reservoir with associated gas source, fully considers two cases of underlying free gas and upper free gas, can realize efficient mining, and does not affect the structural strength of reservoir.

Description

Technical Field

[0001] This invention belongs to the field of natural gas hydrate extraction technology, specifically relating to an efficient replacement extraction method for reservoirs containing associated gas source hydrates. Background Technology

[0002] Under natural conditions, natural gas hydrates are non-stoichiometric cage-like crystalline substances formed with small-molecule gases, mainly methane. With the depletion of global oil resources, the urgent need to solve energy problems is pressing. Natural gas hydrates have attracted widespread attention due to their wide distribution, large scale, and high energy density, and are increasingly considered by many to be a potential clean energy source to replace oil.

[0003] Type I natural gas hydrate reservoirs containing underlying free gas have significant commercial exploitation value. They primarily consist of an upper hydrate-bearing sedimentary layer and an underlying gas-liquid two-phase flow layer, making them the preferred target for natural gas hydrate exploitation. Furthermore, free gas can exist not only as underlying free gas in Type I natural gas hydrate reservoirs but also as free gas located in the upper layer of the hydrate. Current experimental studies on Type I hydrate reservoirs mainly employ depressurization methods and their derived optimization schemes for simulation experiments. However, the reduction in reservoir pressure caused by depressurization can lead to irreversible damage to the reservoir structure, especially in shallowly buried and geologically loose deposits. Careless handling of these deposits can trigger geological disasters and environmental damage.

[0004] The use of carbon dioxide in different phases, as well as mixtures prepared with small-molecule gases such as hydrogen or nitrogen, for displacement extraction has become a mainstream research approach in recent years. This not only effectively improves methane recovery rates and stabilizes formation structure but also increases carbon dioxide sequestration rates. The key to the feasibility of this displacement scheme is that the heat of formation of each mole of carbon dioxide hydrate is slightly higher than the heat of absorption required for the decomposition of methane hydrate, resulting in a negative Gibbs free energy for the overall reaction, allowing for spontaneous reactions without energy input. The gas exchange process also reduces water production during methane recovery. Some free water in the reservoir, as well as hydrate decomposition water, combines with carbon dioxide to form hydrates, remaining within the reservoir. This significantly alleviates the blockage problem caused by hydrate regeneration due to temperature drops.

[0005] CN118895959A discloses a system and method for exploiting reservoirs containing free gas hydrates. This system employs a special diffused wellbore to improve gas production efficiency and achieve joint exploitation of the hydrate layer and the free gas layer. However, it does not protect the hydrate goaf, and the reduction in pore pressure can significantly affect the structural strength of the reservoir, potentially leading to serious geological problems. CN112780233A discloses a simulation device and method for exploiting underlying free gas natural gas hydrates, but it only considers the exploitation of free gas existing in the underlying gas form, without considering the upper free gas layer existing above the natural gas hydrate reservoir. These methods all encounter universality issues in practical applications.

[0006] In summary, current replacement extraction methods for natural gas hydrate reservoirs containing associated gas sources still have problems such as inefficient extraction, impact on reservoir structural strength, and insufficient consideration of underlying and upper free gas. Summary of the Invention

[0007] To address at least one of the aforementioned technical problems, the present invention aims to provide an efficient replacement extraction method for natural gas hydrate reservoirs containing associated gas sources. This invention, targeting natural gas hydrate reservoirs containing associated gas sources, fully considers both underlying free gas and upper free gas conditions, enabling efficient extraction without affecting the reservoir's structural strength.

[0008] To achieve the above objectives, the present invention provides the following technical solution:

[0009] An efficient replacement exploitation method for reservoirs containing associated gas source hydrates includes the following steps:

[0010] For natural gas hydrate reservoirs containing an upper free gas layer, the injection well is set in the hydrate layer and the production well is set in the upper free gas layer. Then, the pressure of the natural gas hydrate reservoir is reduced to a preset pressure through the production well, the production well is kept open, the injection well is opened, and carbon dioxide is injected into the hydrate layer. When the methane content in the production well is lower than the preset value, the production ends.

[0011] For natural gas hydrate reservoirs containing underlying free gas layers, injection wells are placed in the underlying free gas layer, and production wells are placed in the hydrate layer. Then, the pressure in the natural gas hydrate reservoir is reduced to a preset pressure through the production well, the production well is kept open, the injection well is opened, and carbon dioxide is injected into the underlying free gas layer. Production ends when the methane content in the production well is lower than a preset value.

[0012] According to a specific embodiment of the present invention, preferably, in the natural gas hydrate reservoir containing the upper free gas layer, the volume ratio of the hydrate layer to the upper free gas layer is 1:9 to 9:1; in the natural gas hydrate reservoir containing the underlying free gas layer, the volume ratio of the hydrate layer to the underlying free gas layer is 1:9 to 9:1.

[0013] According to a specific embodiment of the present invention, preferably, for a natural gas hydrate reservoir containing an upper free gas layer, the wellhead of the injection well is located in the central region of the hydrate layer, and the wellhead of the production well is located in the central region of the upper free gas layer; for a natural gas hydrate reservoir containing an underlying free gas layer, the wellhead of the injection well is located in the central region of the underlying free gas layer, and the wellhead of the production well is located in the central region of the hydrate layer.

[0014] According to a specific embodiment of the present invention, preferably, both the gas injection well and the production well are vertical wells.

[0015] According to a specific embodiment of the present invention, preferably, the preset pressure is between the phase equilibrium pressure of carbon dioxide hydrate and the phase equilibrium pressure of methane hydrate under the temperature conditions of the natural gas hydrate reservoir.

[0016] According to a specific embodiment of the present invention, preferably, the injected carbon dioxide is gaseous carbon dioxide, and the injection rate is 200~400 sccm.

[0017] According to a specific embodiment of the present invention, preferably, the injection pressure of carbon dioxide is between the phase equilibrium pressure of carbon dioxide hydrate and the phase equilibrium pressure of methane hydrate under the temperature conditions of the natural gas hydrate reservoir, and the injection temperature is room temperature.

[0018] According to a specific embodiment of the present invention, preferably, mining is terminated when the methane content in the well is less than 10%.

[0019] The present invention has at least the following beneficial effects:

[0020] This invention targets natural gas hydrate reservoirs containing associated gas sources, fully considering both underlying and upper-layer free gas conditions. It plans the location distribution of injection and production wells separately, and by first depressurizing the reservoir, it achieves injection and extraction effects comparable to small-molecule mixed gas using only pure gaseous carbon dioxide. This results in considerable methane recovery and carbon dioxide sequestration rates, with methane recovery exceeding 80%. At the end of injection, the reservoir's hydrate saturation recovers to above its initial saturation, and the carbon dioxide sequestration rate reaches 70%. Furthermore, it significantly reduces the cost of mixed gas injection and substantially saves on produced gas separation costs. This invention utilizes the density difference between carbon dioxide and methane, employing a bottom-up injection direction to displace methane from the hydrates through the location distribution of injection and production wells. Existing technologies often use two horizontal wells as a group for injection and production, which may create pathways between the injection and production wells, hindering efficient displacement. This invention avoids these problems, achieving efficient extraction of natural gas hydrate reservoirs containing associated gas sources. Furthermore, this invention establishes a controllable and directional driving fluid field through the location distribution of injection and production wells. This avoids pressure disturbances and disordered flow in the underlying or upper free gas layers, while ensuring that carbon dioxide can effectively contact and replace natural gas, uniformly forming carbon dioxide hydrates and maintaining reservoir structural strength. Therefore, this invention does not affect reservoir structural strength and can protect the stability of the goaf. Simultaneously, this invention utilizes the latent heat of the free gas layer and the sensible heat of the injected carbon dioxide to effectively solve the problem of hydrate regeneration and subsequent blockage caused by temperature drop. This invention is simple to operate, low in cost, and has good extraction results, enabling cost reduction and efficiency improvement for existing extraction operations. Therefore, this invention can achieve economical and efficient extraction of natural gas hydrate reservoirs while protecting the stability of goafs, and is of great significance for the extraction of natural gas hydrates containing associated gas sources. Attached Figure Description

[0021] Figure 1 The diagram shows the structural schematics of the experimental apparatus used in Examples 1-2 and Comparative Examples 1-5.

[0022] Figure 2 The replacement mining schemes of Example 1, Example 2 and Comparative Example 1 are shown.

[0023] Figure 3 The temperature change curves of Examples 1-2 throughout the mining process are shown.

[0024] Figure 4 The curves showing the changes in pressure between the upper and lower layers of the reactor and the pressure in the gas collecting tank in Comparative Example 1 over time are presented.

[0025] Figure 5 The curves showing the changes in methane recovery rate and carbon dioxide sequestration rate over time in Examples 1-2 and Comparative Examples 2-5 are presented.

[0026] Explanation of icon numbers:

[0027] 1-Hydrate layer; 2-Upper free gas layer; 3-Underlying free gas layer;

[0028] 101-Reaction vessel; 102-Methane cylinder; 103-Carbon dioxide storage tank; 104-Air bath; 105-Hand pump; 106-Data acquisition system; 107-Gas-liquid separator; 108-Gas collection tank; 109-Gas mass flow meter; 110-Back pressure valve. Detailed Implementation

[0029] To provide a clearer understanding of the technical features, objectives, and beneficial effects of the present invention, the present invention will now be described in detail below, but this should not be construed as limiting the scope of the invention.

[0030] It should be noted that, unless otherwise specified, all technical and scientific terms used in this invention have the same meaning as commonly understood by one of ordinary skill in the art to which this invention pertains.

[0031] Unless otherwise specified, all raw materials, reagents, instruments and equipment used in this invention can be purchased from the market or prepared by existing methods.

[0032] It should be understood that the terms “comprising,” “including,” and / or “containing” as used herein specify the presence of the stated features, integers, steps, components, or combinations thereof, but do not exclude the presence or addition of one or more other features, integers, steps, components, or combinations thereof.

[0033] The endpoints and any values ​​of the ranges disclosed in this invention are not limited to the precise ranges or values, and these ranges or values ​​should be understood to include values ​​close to these ranges or values. For numerical ranges, the endpoint values ​​of the various ranges, the endpoint values ​​of the various ranges and individual point values, and individual point values ​​can be combined with each other to obtain one or more new numerical ranges, which should be considered as specifically disclosed in this invention.

[0034] According to embodiments of the present invention, an efficient replacement exploitation method for reservoirs containing associated gas-generated hydrates is provided, comprising the following steps:

[0035] For natural gas hydrate reservoirs containing an upper free gas layer, the injection well is set in the hydrate layer and the production well is set in the upper free gas layer. Then, the pressure of the natural gas hydrate reservoir is reduced to a preset pressure through the production well, the production well is kept open, the injection well is opened, and carbon dioxide is injected into the hydrate layer. When the methane content in the production well is lower than the preset value, the production ends.

[0036] For natural gas hydrate reservoirs containing underlying free gas layers, injection wells are placed in the underlying free gas layer, and production wells are placed in the hydrate layer. Then, the pressure in the natural gas hydrate reservoir is reduced to a preset pressure through the production well, the production well is kept open, the injection well is opened, and carbon dioxide is injected into the underlying free gas layer. Production ends when the methane content in the production well is lower than a preset value.

[0037] It is understood that the natural gas hydrate reservoir containing the upper free gas layer includes a hydrate layer and an upper free gas layer located above the hydrate layer; the natural gas hydrate reservoir containing the underlying free gas layer includes a hydrate layer and an underlying free gas layer located below the hydrate layer.

[0038] In some embodiments, in the natural gas hydrate reservoir containing an upper free gas layer, the volume ratio of the hydrate layer to the upper free gas layer is 1:9 to 9:1; in the natural gas hydrate reservoir containing an underlying free gas layer, the volume ratio of the hydrate layer to the underlying free gas layer is 1:9 to 9:1.

[0039] In some embodiments, for a natural gas hydrate reservoir containing an upper free gas layer, the wellhead of the injection well is located in the central region of the hydrate layer, and the wellhead of the production well is located in the central region of the upper free gas layer; for a natural gas hydrate reservoir containing an underlying free gas layer, the wellhead of the injection well is located in the central region of the underlying free gas layer, and the wellhead of the production well is located in the central region of the hydrate layer.

[0040] In some embodiments, both the injection well and the production well are vertical wells.

[0041] In some embodiments, the preset pressure is between the phase equilibrium pressure of carbon dioxide hydrate and methane hydrate at the temperature conditions of the natural gas hydrate reservoir. That is, the preset pressure is higher than the phase equilibrium pressure of CO2 hydrate at the temperature conditions of the natural gas hydrate reservoir but lower than the phase equilibrium pressure of CH4 hydrate at the same temperature conditions. For example, when the temperature of the natural gas hydrate reservoir is 5 °C, the preset pressure is between 2.87 and 5.28 MPa.

[0042] In some embodiments, the injected carbon dioxide is gaseous carbon dioxide, and the injection rate is 200~400 sccm.

[0043] In some embodiments, the injection pressure of carbon dioxide is between the phase equilibrium pressure of carbon dioxide hydrate and the phase equilibrium pressure of methane hydrate at the temperature conditions of the natural gas hydrate reservoir. That is, the injection pressure is higher than the phase equilibrium pressure of CO2 hydrate at the temperature conditions of the natural gas hydrate reservoir but lower than the phase equilibrium pressure of CH4 hydrate at the same temperature conditions, and the injection temperature is room temperature. In this invention, room temperature is 10~30 °C. Preferably, the injection pressure of carbon dioxide is 3.5 MPa and the injection temperature is 22 °C.

[0044] In some embodiments, mining is terminated when the methane content in the well falls below 10%.

[0045] The present invention is illustrated in detail below by way of examples, but the present invention is not limited to these examples. Of course, various modifications can be made within the scope of the present invention.

[0046] Example 1

[0047] This embodiment simulates a highly efficient replacement extraction method for natural gas hydrate reservoirs containing upper free gas layers in a laboratory setting.

[0048] The experimental apparatus used in this embodiment is as follows: Figure 1 As shown, it includes: a reaction vessel 101, a methane cylinder 102, a carbon dioxide storage tank 103, an air bath 104, a hand pump 105, a data acquisition system 106, a gas-liquid separator 107, a gas collecting tank 108, a gas mass flow meter 109, a back pressure valve 110, and temperature and pressure sensors.

[0049] Weigh dry sand and wet sand separately at a 1:1 weight ratio (the initial water saturation of the wet sand is approximately 40%, using brine). Fill the reactor 101 with wet sand, compact it, and then fill the remaining volume of the reactor 101 with dry sand. Install the reactor 101 and then move it into the air bath 104. The bottom of the reactor 101 is equipped with an air inlet and an air inlet pipeline, with the air inlet pipeline simulating a gas injection well, and the wellhead located in the central area of ​​the wet sand. The air inlet of the reactor 101 is connected to a methane cylinder 102 and a carbon dioxide storage tank 103. The top of the reactor 101 is equipped with an air outlet and an air outlet pipeline, with the air outlet pipeline simulating a production well, and the wellhead located in the central area of ​​the dry sand. The air outlet of the reactor 101 is connected to a gas-liquid separator 107. The gas-liquid separator 107 is connected to a gas collecting tank 108. The reactor 101 is also connected to a hand pump 105. A gas mass flow meter 109 is installed on the pipeline connecting the methane cylinder 102, the carbon dioxide storage tank 103, and the reaction vessel 101. A back pressure valve 110 is installed on the pipeline connecting the gas-liquid separator 107 and the reaction vessel 101. The locations of the temperature and pressure sensors are as follows. Figure 1As shown (temperature sensors T1, T2, T3, T4, T5, T6, pressure sensors P1, P2, P3, P4, P5, P6), and these are conventionally positioned locations in the art, which will not be described further in this invention. The temperature and pressure sensors are communicatively connected to the data acquisition system 106.

[0050] Turn on the air bath 104 and set the temperature to lower the temperature of reactor 101 to 5 °C (i.e., the target temperature). Due to the thick walls of the stainless steel reactor 101, the cooling process is slow. When reactor 101 reaches the target temperature, inject nitrogen to check for leaks. At this time, the nitrogen pressure should be 1-2 MPa higher than the experimental pressure. After the leak check, release the gas. Purge the entire system with methane to remove residual nitrogen, then close the air inlet of reactor 101. Then, continuously introduce methane until the pressure in reactor 101 reaches 7 MPa. After closing the air inlet, let it stand for 12 hours. Introduce methane again to replenish the pressure to 7 MPa, and continue to let it stand for about 12 hours. When the pressure in reactor 101 no longer decreases within 2 hours, the hydrate layer 1 is considered to have formed completely.

[0051] This embodiment prepared a natural gas hydrate reservoir containing an upper free gas layer, comprising a hydrate layer 1 and an upper free gas layer 2 located above the hydrate layer 1. An injection well is located in the hydrate layer 1, and a production well is located in the upper free gas layer 2. Both the injection and production wells are vertical wells. Figure 2 The replacement mining schemes of Example 1, Example 2 and Comparative Example 1 are shown.

[0052] After the natural gas hydrate reservoir is prepared, the back pressure valve 110 is adjusted to 3.5 MPa, the production well switch is opened, and the pressure in reactor 101 will drop to the back pressure in a short time. When the pressures of the upper and lower layers of reactor 101 are consistent, the production well is kept open, the injection well is opened, and gaseous carbon dioxide is injected into hydrate layer 1. The gas mass flow meter 109 is set to 300 sccm, the injection pressure is 3.5 MPa, and the injection temperature is 22 ℃. Samples are taken from the production well, gas collecting tank 108, and reactor sampling well using a 0.1 L gas sampling bag at 5, 15, and 25 minutes after the start of injection. Samples are taken every 15 minutes after 25 minutes, and the gas composition is analyzed by gas chromatography. Sampling from gas collecting tank 108 is used to analyze the cumulative amount of methane produced. The sampling port of the production well is set on the pipeline connected to the production wellhead, and the reactor sampling well is set in hydrate layer 1 to analyze the amount of CO2 sealed in the reservoir. When the methane content of the sample from the production well is below 10%, carbon dioxide injection is stopped, the production well and the injection well are shut down, and production ends.

[0053] Experiments showed that, due to the presence of the upper free gas layer 2, Example 1 was successfully mined throughout the entire process without any blockage. Figure 3(a) illustrates the temperature change process of Example 1 throughout the extraction process. It can be seen that when free gas is present, the temperature recovery rate of the lower hydrate layer 1 is significantly faster, only 50 minutes in Example 1. This is due to both the sensible heat from the injected carbon dioxide and the heat released during the formation of mixed hydrates. The temperature change of the upper free gas layer 2 in Example 1 can be divided into two stages. The rapid temperature recovery caused by the large-scale regeneration of lower hydrates also radiates and affects the upper free gas layer 2 (stage 1). When the temperature of hydrate layer 1 stabilizes, carbon dioxide has already risen to the upper free gas layer 2, and the sensible heat it brings, along with the heat from hydrate formation, raises the temperature of the free gas layer to slightly higher than the initial temperature, before slowly decreasing (stage 2). All these phenomena indicate that the method of this embodiment has great potential for replacement extraction of hydrate reservoirs with an upper free gas layer 2, effectively avoiding wellbore blockage and allowing for rapid reservoir temperature recovery.

[0054] Furthermore, gaseous carbon dioxide has a much higher density than methane. When free gas is in the upper layer and hydrate is injected from the lower layer, the carbon dioxide will accumulate in the lower layer of reactor 101 like a liquid, gradually submerging the entire reactor 101. The accumulated carbon dioxide rapidly combines with free water and decomposed water to regenerate methane-carbon dioxide mixed hydrate. This process releases a large amount of heat, which explains the faster temperature recovery rate of hydrate layer 1 in Example 1. Figure 5 The high methane recovery rate (82.35%) and carbon dioxide sequestration rate (69.83%) of Example 1 are shown in the figure. Methane recovery rate = (cumulative methane produced / original methane content in the reservoir) × 100%. Carbon dioxide sequestration rate = (CO2 sequestrated in the reservoir / cumulative CO2 injected) × 100%. Furthermore, the gas ratio in the final gas collection tank 108 is methane:carbon dioxide = 8:2, which saves on produced gas separation costs. Moreover, the overall hydrate saturation of the reservoir after extraction is 47.29%, which can be restored to above the initial saturation. The overall hydrate saturation of the reservoir after extraction refers to the overall saturation of methane hydrate and carbon dioxide hydrate. Through material conservation calculations, the methane and carbon dioxide contents in the gas phase and hydrate phase of the reactor are calculated separately, and the methane hydrate saturation and carbon dioxide hydrate saturation are calculated separately and then added together. The formula for calculating the overall hydrate saturation of the reservoir after extraction is as follows: In the formula, S H final This represents the final saturation level. , These represent the final carbon dioxide hydrate saturation and the final methane hydrate saturation, respectively. , The final molar amounts of carbon dioxide hydrate and methane hydrate (obtained from the sampling described above). The molar density of the salt water is taken as 55.56 mol / L; The coefficient of volume expansion of water during its conversion into hydrates is taken as... V pore Let be the reservoir pore volume. The formula for calculating the initial saturation of the reservoir is: In the formula, S H initial V represents the initial saturation. H This represents the initial volume of the hydrate. This represents the volume of brine in the wet sand consumed during the formation of CH4 hydrates. In the formula, V i ρ is the volume of the CH4 gas phase space in the reactor before hydrate formation (i.e., the volume remaining after subtracting the initial water volume carried by the wet sand from the reservoir pore volume); i and ρ e , representing the molar concentrations of CH4 gas before and after hydrate formation in the reactor, respectively, were estimated using the BWRS equation; N H The value is 6.0, representing the molar amount of water required for the formation of one mole of hydrate. Based on this, the initial hydrate saturation of the reservoir is calculated to be 28.96%.

[0055] Example 2

[0056] This embodiment simulates a highly efficient replacement extraction method for natural gas hydrate reservoirs containing underlying free gas layers in a laboratory setting.

[0057] The experimental apparatus used in this embodiment is as follows: Figure 1 As shown.

[0058] First, invert reactor 101 and weigh dry sand and wet sand in a 1:1 weight ratio (the initial water saturation of the wet sand is approximately 40%). Fill reactor 101 with wet sand, compact it, and then fill the remaining volume of reactor 101 with dry sand. Install reactor 101. During installation, the wet sand will temporarily be in the upper part of reactor 101, and moisture in the wet sand may migrate to the dry sand; therefore, this process must be completed very quickly. Then, keeping reactor 101 inverted, move reactor 101 into air bath 104. The connection relationships of the components in the experimental setup are the same as in Example 1.

[0059] Turn on the air bath 104 and set the temperature to lower the temperature of reactor 101 to 5 °C (i.e., the target temperature). Due to the thick walls of the stainless steel reactor 101, the cooling process is slow. When reactor 101 reaches the target temperature, inject nitrogen to check for leaks. At this time, the nitrogen pressure should be 1-2 MPa higher than the experimental pressure. After the leak check, release the gas. Purge the entire system with methane to remove residual nitrogen, then close the air inlet of reactor 101. Then, continuously introduce methane until the pressure in reactor 101 reaches 7 MPa. After closing the air inlet, let it stand for 12 hours. Introduce methane again to replenish the pressure to 7 MPa, and continue to let it stand for about 12 hours. When the pressure in reactor 101 no longer decreases within 2 hours, the hydrate layer 1 is considered to have formed completely.

[0060] Then, the reactor 101 is inverted back and the inlet and outlet pipelines are reconnected. This embodiment prepares a natural gas hydrate reservoir containing an underlying free gas layer, comprising a hydrate layer 1 and an underlying free gas layer 3 located below the hydrate layer 1. Furthermore, an injection well is located in the underlying free gas layer 3, and a production well is located in the hydrate layer 1. Both the injection and production wells are vertical wells. Figure 2 The replacement mining schemes of Example 1, Example 2 and Comparative Example 1 are shown.

[0061] The extraction process after the natural gas hydrate reservoir is prepared is the same as in Example 1. The reactor sampling well is located in the underlying free gas layer 3.

[0062] Experiments showed that Example 2 also proceeded smoothly throughout the process without any blockage. Example 2 exhibited similar phenomena to Example 1, but the hydrate layer and free gas layer switched between each other. The early temperature rise of the underlying free gas layer 3 and the lag phenomenon of the hydrate layer 1 corresponded to the injection characteristics from bottom to top. Figure 3 (b) illustrates the temperature change process throughout the extraction process in Example 2. In this example, when the extraction well is located in hydrate layer 1, the pressure differential near the extraction well provides a large decomposition driving force, resulting in a high methane hydrate decomposition rate. Figure 5 The reservoir exhibits a relatively high methane recovery rate (71.27%) and carbon dioxide sequestration rate (72.96%). Furthermore, the final gas ratio in the gas collection tank 108 is methane:carbon dioxide = 8:2, which reduces the cost of produced gas separation. Moreover, the overall hydrate saturation of the reservoir after extraction is 33.46%, which can be restored to above the initial saturation level.

[0063] Comparative Example 1

[0064] Comparative Example 1 served as the control group, and a third type of hydrate reservoir was synthesized, which is the absence of an upper free gas layer and an underlying free gas layer.

[0065] The experimental setup used in this comparative example is as follows: Figure 1 As shown. Reactor 101 is filled with wet sand (initial water saturation of the wet sand is approximately 40%), reactor 101 is installed, and then reactor 101 is moved into air bath 104. An air inlet and air inlet pipeline are provided at the bottom of reactor 101; the air inlet pipeline simulates a gas injection well, with the wellhead located in the central area of ​​the wet sand. The air inlet of reactor 101 is connected to a methane cylinder 102 and a carbon dioxide storage tank 103. An air outlet and air outlet pipeline are provided at the top of reactor 101; the air outlet pipeline simulates a production well, with the wellhead located in the central area of ​​the wet sand. The distance between the wellhead of the gas injection well and the wellhead of the production well is the same as in Examples 1 and 2. The connection relationships of the components in the experimental setup are the same as in Example 1.

[0066] Turn on the air bath 104 and set the temperature to lower the temperature of reactor 101 to 5°C (i.e., the target temperature). Due to the thick walls of the stainless steel reactor 101, the cooling process is slow. When reactor 101 reaches the target temperature, inject nitrogen to check for leaks. At this time, the nitrogen pressure should be 1-2 MPa higher than the experimental pressure. After the leak check, release the gas. Purge the entire system with methane to remove residual nitrogen, then close the air inlet of reactor 101. Then, continuously introduce methane until the pressure in reactor 101 reaches 7 MPa. After closing the air inlet, let it stand for 12 hours. Introduce methane again to replenish the pressure to 7 MPa, and continue to let it stand for about 12 hours. When the pressure in reactor 101 no longer decreases within 2 hours, the hydrate layer 1 is considered to have formed completely.

[0067] This comparative example demonstrates the preparation of a natural gas hydrate reservoir, comprising only hydrate layer 1. Both injection and production wells are located within hydrate layer 1, with the injection well positioned below the production well. Both injection and production wells are vertical wells. Figure 2 The replacement extraction schemes of Examples 1, 2, and Comparative Example 1 are shown. The extraction process after the natural gas hydrate reservoir preparation is completed is the same as in Example 1.

[0068] Figure 4The pressure curves of the upper and lower layers of reactor 101 and the pressure of gas collecting tank 108 in Comparative Example 1 over time are shown. Initially, during the depressurization phase, the pressure inside reactor 101 rapidly decreased from 6 MPa to 3.5 MPa within 5 minutes. Immediately afterward, carbon dioxide was injected. For a period, the pressure at each layer remained the same, but around minute 35, the pressure in the lower layer began to rise, and the pressure in gas collecting tank 108 stopped increasing—a very clear sign of blockage. Furthermore, starting from minute 30, two consecutive samples taken from the production well yielded the same gas composition: 60% methane / 40% carbon dioxide. The composition subsequently stagnated at 40% methane / 60% carbon dioxide, indicating blockage within the production well, at a pressure of 3.5 MPa. Phase equilibrium calculations using the Chen-Guo model showed that the well was now under phase equilibrium conditions for the formation of mixed hydrates in this proportion. Once blockage occurs, the continuous injection of carbon dioxide gradually increases the pressure, accelerating the rate of hydrate regeneration and exacerbating the blockage within the wellbore. Hydrate blockage reduces the flow area within the pipeline, interrupting natural gas production and causing localized pressure increases, potentially leading to safety incidents.

[0069] Comparative Example 2

[0070] This comparative simulation focuses on the extraction method of natural gas hydrate reservoirs containing underlying free gas layers. The positions of the injection well and the production well are interchanged with those in Example 2, with the injection well located in hydrate layer 1 and the production well located in underlying free gas layer 3. The sediment filling method in reactor 101 and the extraction method are the same as in Example 2.

[0071] The experiment found that no blockage occurred during the entire extraction process, and the methane recovery rate and carbon dioxide sequestration rate during the experiment were as follows: Figure 5 As shown, the final methane recovery rate was 65.46%, and the carbon dioxide sequestration rate was 45.59%, both lower than those of Examples 1 and 2. Furthermore, the final gas ratio in the gas collection tank 108 using this method was methane:carbon dioxide = 0.557:0.443, which, compared to 8:2 in Examples 1 and 2, significantly increases the cost of subsequent gas separation. The overall hydrate saturation of the reservoir after extraction was 35.75%.

[0072] Comparative Example 3

[0073] This comparative simulation focuses on the extraction method of natural gas hydrate reservoirs containing an upper free gas layer. The positions of the injection well and the production well are interchanged with those in Example 1, with the injection well located in the upper free gas layer 2 and the production well located in the hydrate layer 1. The sediment filling method in the reactor 101 and the extraction method are the same as in Example 1.

[0074] The experiment revealed that, due to the well's location within hydrate layer 1, intermittent blockage occurred after 120 minutes of initial extraction, ultimately resulting in complete blockage at 235 minutes, terminating the experiment. During this period, the methane recovery rate and carbon dioxide sequestration rate were as follows: Figure 5 As shown, the final methane recovery rate was 61.12%, and the carbon dioxide sequestration rate was 59.26%, both lower than those of Examples 1 and 2. This method not only experienced clogging but also suffered from the same problems as Comparative Example 2. The final gas ratio in the gas collection tank 108 was methane:carbon dioxide = 0.607:0.393, resulting in high gas separation costs. The overall hydrate saturation of the reservoir after extraction was 46.96%.

[0075] Comparative Example 4

[0076] This comparative simulation focuses on the extraction method of natural gas hydrate reservoirs containing underlying free gas layers. The locations of the injection and production wells are consistent with those in Example 2, but pressure reduction is not performed beforehand; instead, pressure-maintaining injection is used. The sediment filling method in reactor 101 is the same as in Example 2.

[0077] The extraction method in this comparative example is basically the same as that in Example 2. The difference is that after the natural gas hydrate reservoir is prepared, the back pressure valve 110 is directly adjusted to the reservoir pressure without prior pressure reduction. Simultaneously, the production well and injection well are opened. The gas mass flow meter 109 is also set to 300 sccm, the injection pressure is 6 MPa, and the injection temperature is 22 ℃. Due to the pressure-maintaining injection method, the overall experimental time is longer, and the sampling time interval is correspondingly increased. Gas composition is analyzed by gas chromatography.

[0078] The experiment revealed that no blockage occurred during the entire process, but the experimental period was approximately three times that of Examples 1 and 2. The obtained methane recovery rate and carbon dioxide sequestration rate were as follows: Figure 5 As shown, the final methane recovery rate was 45.33%, and the carbon dioxide sequestration rate was 95.16%. Compared with Example 1 and Example 2, this pressure-maintaining mining scheme lacks the driving force to promote hydrate decomposition, resulting in a lower methane recovery rate. However, due to the slow gas flow, a higher carbon dioxide sequestration rate can be obtained, and the excessively long cycle leads to increased costs.

[0079] Comparative Example 5

[0080] This comparative simulation demonstrates a method for exploiting a natural gas hydrate reservoir containing an upper free gas layer. The locations of the injection and production wells are the same as in Example 1, but pressure reduction is not performed beforehand; instead, pressure-maintaining injection is used. The sediment filling method in reactor 101 is the same as in Example 1.

[0081] The extraction method in this comparative example is basically the same as that in Example 1. The difference is that after the natural gas hydrate reservoir is prepared, the back pressure valve 110 is directly adjusted to the reservoir pressure without prior pressure reduction. Simultaneously, the production well and injection well are opened. The gas mass flow meter 109 is also set to 300 sccm, the injection pressure is 6 MPa, and the injection temperature is 22 ℃. Due to the pressure-maintaining injection method, the overall experimental time is longer, and the sampling time interval is correspondingly increased. Gas composition is analyzed by gas chromatography.

[0082] The experiment revealed that no blockage occurred during the entire process, and the experimental period was approximately three times that of Examples 1 and 2. The obtained methane recovery rate and carbon dioxide sequestration rate were as follows: Figure 5 As shown, the final methane recovery rate was 46.14%, and the carbon dioxide sequestration rate was 89.75%. Compared with Example 1 and Example 2, this pressure-maintaining mining scheme achieved a lower methane recovery rate and a higher carbon dioxide sequestration rate, and the excessively long cycle led to increased costs.

[0083] In summary, compared to the comparative examples, Examples 1 and 2 of this invention combine higher carbon dioxide sequestration and methane recovery rates, balanced reservoir repair effects, and reservoir temperature recovery efficiency. Furthermore, the overall hydrate saturation after extraction is higher, with Example 1 exhibiting the highest overall hydrate saturation. Examples 1 and 2 of this invention target natural gas hydrate reservoirs containing associated gas sources, fully considering both underlying and upper free gas conditions. They plan the location distribution of injection and production wells separately, and by first depressurizing the reservoir, achieve injection extraction effects comparable to small-molecule mixed gas using only pure gaseous carbon dioxide. This results in considerable methane recovery and carbon dioxide sequestration rates, significantly reduces the cost of mixed gas injection, and substantially saves on produced gas separation costs. Simultaneously, it does not affect the reservoir structural strength and solves the blockage problem, thereby achieving economical and efficient extraction of natural gas hydrate reservoirs containing associated gas sources while protecting the stability of the goaf.

[0084] Finally, it is understood that the above embodiments are merely illustrative of the technical concept and features of the present invention, and are intended to enable those skilled in the art to understand the content of the present invention and implement it accordingly. They should not be construed as limiting the scope of protection of the present invention. For those skilled in the art, various modifications and improvements can be made without departing from the principles and essence of the present invention, and these modifications and improvements are also considered to be within the scope of protection of the present invention.

Claims

1. A highly efficient replacement exploitation method for reservoirs containing associated gas-generated hydrates, comprising the following steps: For natural gas hydrate reservoirs containing an upper free gas layer, the injection well is set in the hydrate layer and the production well is set in the upper free gas layer. Then, the pressure of the natural gas hydrate reservoir is reduced to a preset pressure through the production well, the production well is kept open, the injection well is opened, and carbon dioxide is injected into the hydrate layer. When the methane content in the production well is lower than the preset value, the production ends. For natural gas hydrate reservoirs containing underlying free gas layers, injection wells are placed in the underlying free gas layer and production wells are placed in the hydrate layer. Then, the pressure of the natural gas hydrate reservoir is reduced to a preset pressure through the production well, the production well is kept open, the injection well is opened, and carbon dioxide is injected into the underlying free gas layer. Production ends when the methane content in the production well is lower than a preset value. In the natural gas hydrate reservoir containing the upper free gas layer, the volume ratio of the hydrate layer to the upper free gas layer is 1:9 to 9:1; in the natural gas hydrate reservoir containing the lower free gas layer, the volume ratio of the hydrate layer to the lower free gas layer is 1:9 to 9:

1. The preset pressure is between the phase equilibrium pressure of carbon dioxide hydrate and the phase equilibrium pressure of methane hydrate under the temperature conditions of the natural gas hydrate reservoir. The injected carbon dioxide is gaseous carbon dioxide, and the injection rate is 200~400 sccm; the injection pressure of the injected carbon dioxide is between the phase equilibrium pressure of carbon dioxide hydrate and the phase equilibrium pressure of methane hydrate under the temperature conditions of the natural gas hydrate reservoir, and the injection temperature is room temperature. Mining should cease when the methane content in the well falls below 10%.

2. The efficient replacement exploitation method for reservoirs containing associated gas source hydrates according to claim 1, wherein, For natural gas hydrate reservoirs containing an upper free gas layer, the wellhead of the injection well is located in the central region of the hydrate layer, and the wellhead of the production well is located in the central region of the upper free gas layer; for natural gas hydrate reservoirs containing an underlying free gas layer, the wellhead of the injection well is located in the central region of the underlying free gas layer, and the wellhead of the production well is located in the central region of the hydrate layer.

3. The efficient replacement exploitation method for reservoirs containing associated gas-generated hydrates according to claim 1, wherein, Both the gas injection well and the production well are vertical wells.

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