A device and method for enhancing natural gas hydrate production by utilizing deep gas geothermal energy

Abstract

The present invention proposes a device and method for utilizing deep gas geothermal energy to enhance the exploitation of natural gas hydrates, which belongs to the field of exploitation of multi-gas source co-existing reservoirs. The device includes an automatic control feedback system, a gas production monitoring system, a temperature monitoring system, a pressure monitoring system, and a saturation monitoring system; through the integrated use of the temperature, pressure, saturation, gas production monitoring system and the automatic control feedback system, the exploitation plan is timely adjusted as the effective utilization rate of deep gas injection energy and the upwelling rate of deep gas change, and the upwelling of deep gas is effectively utilized to enhance the rapid output of natural gas hydrate decomposition gas, solving the problem that the upwelling deep gas cannot promote the decomposition and gas production of natural gas hydrates due to the lack of exploitation and regulation basis in the multi-gas co-production process, and at the same time preventing the threat to the stability of the formation caused by the uncontrolled upwelling of deep gas. The present invention effectively promotes the safe and efficient exploitation of multi-gas source co-existing reservoirs of natural gas hydrates, shallow gas, and deep gas in marine environments.

Description

Technical Field

[0001] The present invention belongs to the field of multi-gas source co-existing reservoir exploitation, and specifically relates to a device and method for the joint exploitation of natural gas hydrates and deep gas geothermal resources. Background Art

[0002] Natural gas hydrate is a clean energy with extremely high energy density. At present, the method with the greatest potential for commercial application of natural gas hydrate exploitation is the depressurization method, which artificially extracts reservoir fluid to expose natural gas hydrate to a low-pressure environment for decomposition. At the same time, the decomposition of natural gas hydrates will absorb a large amount of heat, which will lead to insufficient sensible heat in the reservoir, and then cause problems such as freezing or secondary generation of natural gas hydrates, which increase the risk of blockage of fluid transport channels. Therefore, the depressurization method should be used in combination with other methods to ensure efficient and continuous decomposition of natural gas hydrates. The heat injection method has been proven to be the most effective method to increase the sensible heat of the reservoir. However, the traditional method of injecting hot water and hot steam will greatly increase the cost of exploitation due to the construction of heating equipment and the continuous transport of heat. Therefore, an economical heat injection method urgently needs to be introduced.

[0003] Geothermal energy is usually widely distributed in the earth's crust in the form of hot gas, hot water or hot dry rock. Geological exploration shows that the lower part of most gas hydrate reservoirs contains abundant natural geothermal energy. Using geothermal energy to heat gas hydrate reservoirs does not require the construction of heating equipment, which can significantly reduce the cost of mining. Inducing shallow gas or deep gas carrying a large amount of geothermal energy to rise to the gas hydrate layer can not only transport a large amount of heat energy to the reservoir, but also greatly increase the production of natural gas. Therefore, this is a highly economical mining method. Some scholars have studied the characteristics of joint mining of gas hydrates and shallow gas and found that regulating interlayer interference is the key to optimizing the utilization of geothermal energy carried by shallow gas. However, many joint mining studies, including this study, have not provided specific ways to regulate the upward movement of shallow gas and enhance the efficiency of gas hydrate mining. For deep gas with deeper burial depth, greater formation pressure and more geothermal energy, it will carry a more considerable amount of geothermal energy and driving work into the gas hydrate layer when it rises violently, which will have a significant impact on the overall energy transfer and conversion mode of the reservoir and the mass transfer efficiency of the gas. If this process is not intervened by humans, and the deep gas is allowed to pour into the gas hydrate layer without any rules, it will cause most of the deep gas injection energy to be wasted at best, and the decomposition rate of the gas hydrate will be inhibited at worst, and even endanger the stability of the seabed formation. In summary, during the on-site trial production process, it is very important to judge the current status of heat and mass transfer in the reservoir based on monitoring the evolution of reservoir temperature and pressure and real-time gas production, and then adjust the production plan in a targeted manner, so as to efficiently utilize the deep gas injection energy to enhance the production of gas hydrates. At present, there is still no effective solution to achieve this goal. Summary of the invention

[0004] The purpose of the present invention is to make up for the deficiencies of the prior art and to provide a device and method for utilizing deep gas geothermal energy to enhance the production of natural gas hydrates.

[0005] The technical solution of the present invention is as follows:

[0006] A device for enhancing the extraction of natural gas hydrates using deep gas geothermal energy, comprising a temperature monitoring system, a pressure monitoring system, a saturation monitoring system, a gas production monitoring system, an automatic control feedback system and a gas-liquid separation system;

[0007] The temperature monitoring system comprises a temperature sensor array arranged on the outer wall of a vertical fixed pipe of a monitoring well of a natural gas hydrate layer and a deep gas layer, the temperature sensor array being arranged axially along the vertical fixed pipe and used to monitor the temperature change of the reservoir around the temperature sensor and transmit the temperature signal to the automatic control feedback system;

[0008] The pressure monitoring system comprises a pressure sensor array arranged on the outer wall of a vertical fixed pipe of a natural gas hydrate layer and a deep gas layer monitoring well, the pressure sensor array being arranged axially along the vertical fixed pipe and used to monitor pressure changes in the reservoir around the pressure sensor and transmit the pressure signal to the automatic control feedback system;

[0009] The saturation monitoring system includes nuclear magnetic resonance logging and sonic logging set in the natural gas hydrate layer and nuclear magnetic resonance logging set in the deep gas layer; the nuclear magnetic resonance logging is used to reflect the saturation of water and free gas, and transmits the nuclear magnetic resonance signal to the automatic control feedback system; the sonic logging is used to reflect the saturation of natural gas hydrate, and transmits the sonic logging data to the automatic control feedback system;

[0010] The gas-liquid separation system is arranged on the seabed and is used to separate the natural gas and seawater in the gas-liquid mixture produced from the natural gas hydrate layer;

[0011] The gas production monitoring system includes a flow measurement device arranged behind the gas-liquid separation system, which is used to monitor the gas production rate and transmit the instantaneous gas production rate data to the automatic control feedback system;

[0012] The automatic control feedback system is arranged on a semi-submersible marine platform, and is used for receiving, processing and monitoring reservoir temperature signals, reservoir pressure signals, reservoir nuclear magnetic resonance signals, reservoir acoustic wave signals and reservoir gas production rate signals in real time, and automatically analyzing the decomposition gas production rate of natural gas hydrates, the upwelling rate of deep gas and the proportion of deep gas injection energy utilized by natural gas hydrate decomposition, so as to judge the decomposition status of natural gas hydrates in the reservoir and the effective utilization status of deep gas injection energy, and then make timely adjustments to the mining plan, so as to realize the overall control of strengthening the decomposition of natural gas hydrates by using deep gas injection energy. The above data analysis and processing processes can be visualized.

[0013] Furthermore, the automatic control feedback system performs the following control method on the mining plan: if the upwelling rate of deep gas v d Less than N1, then increase the voltage reduction rate to V1 and maintain it for time t1; if v d If it is still less than N1, the pressure reduction rate is further increased to V2 or wells closer to the gas chimney and wells farther away are used as production wells at the same time to provide more migration channels for the upwelling deep gas in the natural gas hydrate layer; if v d Maintaining the range of N1 to N2 and the proportion of deep gas injection energy utilized by natural gas hydrate decomposition η is less than M1, the well far away from the gas chimney is used as the production well to extend the cross-flow distance of the upwelling deep gas in the hydrate layer; finally, the upwelling rate of deep gas v d Maintain within the range of N1 to N2 and maintain η above M1.

[0014] Furthermore, the proportion of the deep gas injection energy utilized by the decomposition of natural gas hydrates is as follows:

[0015]

[0016] in, The geothermal energy injected into the gas hydrate layer from deep gas, The driving work done when injecting deep gas into the natural gas hydrate layer, Q TE The amount of energy injected into a gas hydrate layer for deep gas is lost by being absorbed by the surrounding formations.

[0017] Furthermore, the geothermal energy injected into the natural gas hydrate layer by the deep gas The calculation formula is as follows:

[0018]

[0019] In the formula, Refers to the specific heat capacity of deep gas at time δ, which is obtained by screening from the basic physical property database by the automatic control feedback system based on the temperature and pressure of the deep gas layer at time δ fed back by the temperature monitoring system and the pressure monitoring system respectively; Refers to the instantaneous production rate of deep gas at time δ fed back by the gas production monitoring system; and They refer to the average temperatures of the deep gas layer and the natural gas hydrate layer at time δ respectively as fed back by the temperature monitoring system.

[0020] Furthermore, the driving work done by the deep gas when injected into the natural gas hydrate layer The calculation formula is as follows:

[0021]

[0022] In the formula, Refers to the pressure of the deep gas layer at time δ fed back by the pressure monitoring system.

[0023] Furthermore, the energy of the deep gas injected into the natural gas hydrate layer is lost by being absorbed by the surrounding formations. TE The calculation method is as follows:

[0024] Calculation of the change in sensible heat of the natural gas hydrate layer

[0025]

[0026] In the formula, Refers to the quality of the natural gas hydrate layer as a whole, which is calculated by the automatic control feedback system based on the saturation of each phase in the natural gas hydrate layer fed back by the saturation monitoring system; Refers to the rate of change of the average temperature of the natural gas hydrate layer at time δ, which is calculated by the automatic control feedback system based on the natural gas hydrate layer temperature signal fed back by the temperature monitoring system; Refers to the specific heat capacity of the entire natural gas hydrate layer at time δ, which is calculated by the automatic control feedback system based on the temperature and pressure signals of the natural gas hydrate layer fed back by the temperature monitoring system and the pressure monitoring system respectively, combined with the saturation signals of the porous medium, gas, water and hydrate phases in the reservoir:

[0027]

[0028] Where S refers to saturation, and the subscripts MS, g, w, and h refer to porous media, gas, water, and hydrate, respectively;

[0029] Calculation of the heat absorption Q of natural gas hydrate decomposition h :

[0030] Q h =ΔH(T)·n hdis,Ini→δ(6)

[0031] Where n hdis,Ini→δ It refers to the cumulative decomposition amount of natural gas hydrate from the initial stage of mining to the time δ, which is calculated by the automatic control feedback system based on the natural gas hydrate saturation signal fed back by the saturation monitoring system; ΔH(T) refers to the decomposition heat of natural gas hydrate, which is calculated by formula (7):

[0032] ΔH(T)=4.184·(13521-4·T) (7)

[0033] Where, T refers to the decomposition temperature of natural gas hydrate, which is obtained by the automatic control feedback system based on the temperature signal fed back by the temperature monitoring system;

[0034] Calculate the driving work W done by the gas in the natural gas hydrate layer from the production well push,Hpro :

[0035]

[0036] In the formula, represents the pressure of the natural gas hydrate layer at time δ fed back by the pressure monitoring system, It represents the instantaneous gas production rate of the natural gas hydrate layer itself at time δ fed back by the gas production monitoring system;

[0037] Calculate the driving work W done by the deep gas injected into the gas hydrate layer when it is produced from the production well push,Dpro :

[0038]

[0039] Let i = 0.01h, calculate the time period from i-0.01 to i Q h , W push,Hpro and W push,Dpro The instantaneous change values ​​of six kinds of energy; taking the natural gas hydrate layer as the thermal system, the change Q of the thermal system energy during this period is calculated:

[0040]

[0041] When Q is less than 0, it indicates that the thermal system is transferring heat to the surrounding environment, and Q is recorded as b i If i = the end time of production, then calculate the amount of energy injected into the natural gas hydrate layer by the deep gas and lost by being absorbed by the surrounding formations Q TE :

[0042]

[0043] Otherwise, let i=i+0.01h and repeat the above calculation process.

[0044] Furthermore, it also includes a sand control system, which is a mining sand control device arranged at the gas collection port and consists of a double layer of screens; the outer layer of the screen has a pore size of 50 microns, which is used to prevent coarse sand from entering the wellbore; the inner layer of the screen has a pore size of 20 microns, which is used to prevent fine sand from entering the wellbore; gravel with a particle size of 30 to 80 microns is filled between the two layers of screens to maintain the permeability of the gas-liquid two phases at the gas collection port.

[0045] Furthermore, the gas-liquid separation system is a gas-liquid separation device arranged on the seabed. The gas-liquid mixture obtained by mining is separated into natural gas and seawater by the gas-liquid separation device. The natural gas enters the semi-submersible marine platform through the gas production pipeline, and the seawater is discharged into the sea from the outlet.

[0046] A method for utilizing deep gas geothermal energy to enhance natural gas hydrate production comprises the following steps:

[0047] The first step is to conduct exploration operations in the target area where natural gas hydrates and deep gas coexist with multiple gas sources to determine the spatial distribution of gas chimneys; collect data on the initial temperature, initial pressure and saturation of each phase of the natural gas hydrate layer and deep gas layer;

[0048] The second step is to set the well close to the gas chimney as a production well, control the initial pressure reduction rate to V0, turn on the gas collection pump and water collection pump, and start the initial pressure reduction and gas production;

[0049] The third step is to calculate the geothermal energy and driving work of deep gas injected into the gas hydrate layer based on the temperature, pressure, saturation of each phase and instantaneous total gas production rate of the gas hydrate layer and the deep gas layer measured at each time t, as well as the amount lost due to absorption by the surrounding formations, and calculate the proportion η of the deep gas injection energy utilized by the decomposition of gas hydrates;

[0050] Step 4: If the upwelling rate of deep gas v d If it is less than N1, it means that the upwelling rate of deep gas is too slow and cannot provide sufficient heat for the decomposition of natural gas hydrates. At this time, the pressure reduction rate is increased to V1 and maintained for time t1. d If it is still less than N1, the pressure reduction rate is further increased to V2 or wells closer to the gas chimney and wells farther away are used as production wells at the same time, so as to provide more migration channels for the upwelling deep gas in the natural gas hydrate layer; if v d Maintaining within the range of N1 to N2 and η being less than M1, it means that the deep gas injection rate is moderate but the proportion of injected energy wasted is too high, which still cannot effectively enhance the decomposition rate of natural gas hydrates. At this time, the well far away from the gas chimney is used as the production well to extend the cross-flow distance of the upwelling deep gas in the hydrate layer and buy time for the natural gas hydrate layer to absorb the injected energy of the deep gas. By increasing the upwelling rate of deep gas v dMaintaining the energy in the deep gas injection zone within the range of N1 to N2, and maintaining the proportion η of the energy injected into the deep gas layer that is utilized by the decomposition of natural gas hydrates above M1, thereby achieving the goal of efficiently utilizing the energy injected by the deep gas layer to enhance the decomposition of natural gas hydrates while developing both natural gas hydrates and deep gas resources;

[0051] The fifth step is to separate the gas-liquid mixture produced by mining, and the natural gas enters the semi-submersible offshore platform through the gas production pipeline to complete the gas collection, and the seawater is discharged into the sea from the outlet;

[0052] Step 6: When the reservoir gas production rate is lower than v1, it means that the natural gas hydrate in the enriched area has been basically decomposed, and the production well will be recovered to complete the production operation.

[0053] Furthermore, the ratio η of the deep gas injection energy utilized by the decomposition of natural gas hydrates is a parameter characterizing the effective utilization of the deep gas injection energy, and the calculation method is as follows:

[0054] According to the temperature of the gas hydrate layer and the deep gas layer, as well as the instantaneous production rate of the deep gas, the geothermal energy injected into the gas hydrate layer is calculated.

[0055]

[0056] In the formula, Refers to the specific heat capacity of deep gas at time δ, which is obtained by screening from the basic physical property database based on the temperature and pressure of the deep gas layer at time δ; Refers to the instantaneous production rate of deep gas at time δ; and They refer to the average temperatures of the deep gas layer and the natural gas hydrate layer at time δ, respectively.

[0057] According to the pressure of the deep gas layer and the instantaneous production rate of deep gas, the driving work done by deep gas when injected into the natural gas hydrate layer is calculated.

[0058]

[0059] In the formula, Refers to the pressure of the deep gas layer at time δ.

[0060] According to the temperature of the gas hydrate layer and the saturation of each phase, the change in the sensible heat of the gas hydrate layer is calculated.

[0061]

[0062] In the formula, Refers to the mass of the entire natural gas hydrate layer, which is calculated based on the saturation of each phase in the natural gas hydrate layer; Refers to the rate of change of the average temperature of the gas hydrate layer at time δ, which is converted from the temperature of the gas hydrate layer; Refers to the specific heat capacity of the entire natural gas hydrate layer at time δ, which is calculated from the temperature and pressure of the natural gas hydrate layer and the saturation of the porous medium, gas, water and hydrate phases in the reservoir:

[0063]

[0064] Where S refers to saturation, and the subscripts MS, g, w, and h refer to porous media, gas, water, and hydrate, respectively.

[0065] Calculation of the heat absorption Q of natural gas hydrate decomposition based on natural gas hydrate saturation h :

[0066] Q h =ΔH(T)·n hdis,Ini→δ (5)

[0067] Where n hdis,Ini→δ It refers to the cumulative decomposition amount of natural gas hydrate from the initial stage of mining to the time δ, which is calculated based on the saturation of natural gas hydrate; ΔH(T) refers to the decomposition heat of natural gas hydrate, which is calculated by formula (6):

[0068] ΔH(T)=4.184·(13521-4·T) (6)

[0069] Where T refers to the decomposition temperature of natural gas hydrate.

[0070] The driving work W done by the gas in the gas hydrate layer from the production well is calculated by the pressure of the gas hydrate layer and the instantaneous production rate of the gas in the gas hydrate layer itself. push,Hpro :

[0071]

[0072] In the formula, represents the pressure of the gas hydrate layer at time δ, It represents the instantaneous gas production rate of the natural gas hydrate layer itself at time δ.

[0073] The driving work W done by the deep gas injected into the gas hydrate layer when it is produced from the production well is calculated by using the pressure of the gas hydrate layer and the instantaneous production rate of the deep gas. push,Dpro :

[0074]

[0075] Let i = 0.01h, calculate the time period from i-0.01 to i Q h , W push,Hpro and Wpush,Dpro The instantaneous change values ​​of six kinds of energy; taking the natural gas hydrate layer as the thermal system, the change Q of the thermal system energy during this period is calculated:

[0076]

[0077] In the formula, Q h , W push,Hpro and W push,Dpro The four types of energy are the energy lost by the thermal system and are connected by positive signs; The two types of energy are the energies obtained by the thermodynamic system and are connected by a negative sign.

[0078] If Q is greater than 0, it means that the energy consumed by the thermal system is greater than the energy supplied. At this time, the surrounding environment is transferring heat to the thermal system, and Q is recorded as a i On the contrary, the thermal system transfers heat to the surrounding environment, and Q is recorded as b i ;

[0079] If i = the end time of production, then the amount of energy lost by deep gas injection into the natural gas hydrate layer and absorbed by the surrounding strata Q is calculated according to equations (10) and (11) respectively: TE and the heat transfer Q from the surrounding formation to the gas hydrate layer FE ; Otherwise, let i=i+0.01h and repeat the above calculation process.

[0080]

[0081] The calculation formula for the ratio η of the deep gas injection energy utilized by the decomposition of natural gas hydrate is as follows:

[0082]

[0083] The beneficial effects of the present invention are as follows: the present invention proposes a set of geothermal enhanced natural gas hydrate mining equipment and methods suitable for natural gas hydrate and deep gas multi-gas source symbiotic environments, which solves the problem that the upwelling deep gas cannot promote the decomposition and gas production of natural gas hydrates due to the lack of mining control basis in the multi-gas co-production process, thereby avoiding the low effective utilization rate of deep gas injection energy and the instability of the formation induced by the uncontrolled upwelling of deep gas. The present invention realizes the timely adjustment of the mining plan with the changes in the effective utilization rate of deep gas injection energy and the upwelling rate of deep gas through the integrated use of temperature, pressure, saturation, gas production monitoring system and automatic control feedback system, effectively utilizes the upwelling of deep gas to strengthen the rapid production of natural gas hydrate decomposition gas, and at the same time can prevent the threat to formation stability caused by the uncontrolled upwelling of deep gas. The equipment and method can effectively promote the safe and efficient mining of multi-gas source symbiotic reservoirs of natural gas hydrate, shallow gas and deep gas in marine environments. BRIEF DESCRIPTION OF THE DRAWINGS

[0084] Figure 1 This is a schematic diagram of the natural gas hydrate and deep gas joint production device.

[0085] Figure 2 Schematic diagram of the calculation process for the amount of energy QTE lost by deep gas injected into the natural gas hydrate layer and the amount of heat QFE transferred from the surrounding formation to the natural gas hydrate layer.

[0086] Figure 3 Schematic diagram of the experimental device at the experimental scale of Example 2.

[0087] In the figure: 1 automatic control feedback system; 2 gas production monitoring system; 3 gas-liquid separation system; 4 temperature monitoring system; 5 pressure monitoring system; 6 saturation monitoring system; 7 sand control system. DETAILED DESCRIPTION

[0088] The specific implementation of the present invention is described in detail below in conjunction with the technical scheme and the accompanying drawings.

[0089] Embodiment 1:

[0090] The method for combined exploitation of marine natural gas hydrate and deep gas using the exploitation device comprises the following steps:

[0091] The first step is to carry out exploration operations in the designated target area of ​​natural gas hydrate and deep gas multi-gas source coexistence, determine the specific location of the gas chimney, place suction anchors in the formation just above the gas chimney and 10 kilometers away from the gas chimney to stabilize the wellhead, use the deflection tool to carry out horizontal well deflection drilling in deep-water shallow soft formations, and set the horizontal well inclination angle between 70° and 90°. Set a fixed pipe outside the production well, and after completing the reservoir transformation and sand control operations, build a natural gas hydrate production device that uses deep gas geothermal to enhance the production, and conduct joint debugging of various systems of the production device;

[0092] In the second step, the mining device uses the temperature monitoring system 4, the pressure monitoring system 5 and the saturation monitoring system 6 to obtain the initial temperature, initial pressure and saturation of each phase of the target area of ​​natural gas hydrate and deep gas multi-gas source coexistence, and automatically transmits the data to the automatic control feedback system 1;

[0093] The third step is to set the production well to the W01 well near the gas chimney, set the gas production pressure of the production platform to 4MPa, control the initial pressure reduction rate to 200kPa / min, turn on the gas collection pump and water collection pump, and start the initial pressure reduction gas production;

[0094] In the fourth step, the temperature monitoring system 4, the pressure monitoring system 5, the saturation monitoring system 6, and the gas production monitoring system 2 measure the temperature, pressure, saturation of each phase, and the instantaneous total gas production rate of the natural gas hydrate layer and the deep gas layer respectively every 10 minutes, and transmit the signal to the automatic control feedback system 1; the automatic control feedback system 1 calculates the instantaneous and cumulative gas production data of the natural gas hydrate layer and the deep gas layer according to the real-time instantaneous total gas production rate and the saturation data of each phase of the deep gas layer, and calculates the instantaneous and cumulative gas production data of the natural gas hydrate layer and the deep gas layer according to the real-time feedback of the natural gas hydrate layer by the temperature monitoring system 4 and the pressure monitoring system 5. The temperature and pressure data of the gas hydrate layer and the deep gas layer are used to calculate the geothermal energy and driving work of the deep gas injected into the gas hydrate layer, as well as the amount lost due to absorption by the surrounding strata, the amount of heat transferred from the surrounding strata to the gas hydrate layer, the change in the sensible heat of the gas hydrate layer itself, the amount of heat absorbed by the decomposition of the gas hydrate, the driving work done by the gas of the gas hydrate layer itself when it is produced from the production well, and the driving work done by the deep gas injected into the gas hydrate layer when it is produced from the production well; and then calculate the specific value of the proportion η of the deep gas injection energy that is decomposed and utilized by the gas hydrate;

[0095] Step 5: If the upwelling rate of deep gas v d Less than 500m 3 / h, indicating that the upwelling rate of deep gas is too slow and will not provide sufficient heat for the decomposition of natural gas hydrates. At this time, the automatic control feedback system 1 increases the pressure reduction rate to 300kPa / min and maintains it for 5h; if v d Still less than 500m 3 / h, the depressurization rate is further increased to 500 kPa / min or the W01 well closer to the gas chimney and the W02 well farther away are used as production wells at the same time, so as to provide more migration channels for the upwelling deep gas in the natural gas hydrate layer; if v d Maintain at 500m 3 / h~1200m 3 / h and η is less than 60%, indicating that the deep gas injection rate is moderate but the proportion of injected energy wasted is too high, which still cannot effectively enhance the decomposition rate of natural gas hydrates. At this time, the automatic control feedback system 1 is set to use the W02 well far away from the gas chimney as the production well, so as to extend the cross-flow distance of the upwelling deep gas in the hydrate layer and buy time for the natural gas hydrate layer to absorb the injected energy of the deep gas; through the regulation of the automatic control feedback system 1, the upwelling rate v of the deep gas is set to d Maintain at 500m 3 / h~1200m 3 / h, and maintaining the utilization ratio η of the deep gas injection energy used by the decomposition of natural gas hydrate at more than 60%, so as to achieve the goal of efficiently utilizing the energy injected by deep gas to enhance the gas production by the decomposition of natural gas hydrate while developing natural gas hydrate and deep gas resources at the same time;

[0096] Step 6: The gas-liquid mixture produced by mining is separated by the gas-liquid separation system 3 installed on the seabed, the natural gas enters the semi-submersible offshore platform through the gas production pipeline, the gas is collected, and the seawater is discharged into the sea from the outlet;

[0097] Step 7: End of mining; the gas production rate of the reservoir is less than 40m 3 / h, it indicates that the natural gas hydrate in the enriched area has been basically decomposed, and the horizontal well can be recovered to complete the mining operation.

[0098] Embodiment 2:

[0099] At laboratory scale, the experimental setup is as follows Figure 3 , using a method of utilizing deep gas geothermal energy to enhance natural gas hydrate production according to the present invention, the experimental steps are as follows:

[0100] In the first step, a South China Sea marine soil reservoir with a porosity and initial water saturation of 50.86% and 47.78% was prepared in a natural gas hydrate kettle, and a South China Sea marine soil reservoir with a porosity and initial water saturation of 59.41% and 13.66% was prepared in a deep gas kettle;

[0101] The second step is to prepare a marine soil reservoir containing natural gas hydrates: inject 13.53MPa of natural gas into the natural gas hydrate kettle, set the air bath at 21.77℃, and after the temperature and pressure inside the reservoir are stable, set the air bath at 4.53℃ to induce the formation of natural gas hydrates inside the reservoir; prepare a marine soil reservoir containing deep gas: inject 12.28MPa of natural gas into the deep gas kettle, and set the water bath at 29.72℃; after the temperature and pressure inside the two reactors are stable, open the valve on the connecting pipeline between the two reactors to induce the deep gas to move upward in preparation for extraction;

[0102] The third step is to design a mining scheme. In order to induce the deep gas to be injected into the natural gas hydrate layer on a large scale in a short period of time and provide sufficient energy for the decomposition of the natural gas hydrate in time, a high depressurization rate is firstly adopted to accelerate the decomposition of the natural gas hydrate and reduce its hindering effect on the upward migration of the deep gas. Secondly, a combination mode of double mining wells is adopted to provide more channels for the migration of the deep gas in the natural gas hydrate layer. In order to increase the proportion of the energy injected into the natural gas hydrate layer by the decomposition of the natural gas hydrate, the distance between the deep gas and the gas chimney is extended on the basis of the use of double mining wells, so that the migration distance required for the deep gas from the injection into the natural gas hydrate layer to the production from the mining well becomes longer, and time is gained for the natural gas hydrate layer to absorb the injected energy of the deep gas. Therefore, the mining scheme of this embodiment is as follows: a depressurization rate of 200 kPa / min is adopted, a combination mode of double mining wells is used, and the length between the double mining wells and the deep gas injection inlet is 177.85 mm.

[0103] Step 4: The plunger pump controls the change of the pressure drop rate in the back pressure valve to implement the mining plan described in Step 3;

[0104] The fifth step is to end the exploitation. When the pressure in the two reservoirs stabilizes at 4 MPa and the temperature of the two reservoirs returns to the initial temperature before exploitation, it indicates that the hydrates inside the natural gas hydrate layer have basically been decomposed, and the deep gas in the deep gas layer has also been produced, and the exploitation experiment is over.

[0105] The experimental results are as follows:

[0106] It took 7.57 hours to produce 90% of the total gas production of the combined mining, and 13.41 hours to produce 90% of the total gas production of the natural gas hydrate layer. During the combined mining process, the cumulative injection energy of the deep gas was 3212.81 kJ and its effective utilization rate was 64.56%.

[0107] Comparative Example 1:

[0108] On a laboratory scale, without using the natural gas hydrate production method of the present invention, a blank experiment 1 was conducted only to accelerate the upwelling rate of deep gas and provide sufficient energy for the decomposition of natural gas hydrates. The experimental apparatus was the same as that of Example 2, and the experimental steps were as follows:

[0109] In the first step, a South China Sea marine soil reservoir with a porosity and initial water saturation of 50.86% and 47.78% was prepared in a natural gas hydrate kettle, and a South China Sea marine soil reservoir with a porosity and initial water saturation of 59.41% and 13.66% was prepared in a deep gas kettle;

[0110] The second step is to prepare a marine soil reservoir containing natural gas hydrates: inject 13.48MPa of natural gas into the natural gas hydrate kettle, set the air bath at 21.58℃, and after the temperature and pressure inside the reservoir are stable, set the air bath at 4.87℃ to induce the formation of natural gas hydrates inside the reservoir; prepare a marine soil reservoir containing deep gas: inject 12.19MPa of natural gas into the deep gas kettle, and set the water bath at 29.78℃; after the temperature and pressure inside the two reactors are stable, open the valve on the connecting pipeline between the two reactors to induce the deep gas to move upward in preparation for extraction;

[0111] The third step is to exploit the natural gas hydrate and deep gas in the two reactors. The plunger pump controls the pressure drop rate in the back pressure valve. The pressure drop rate is 200 kPa / min. A double exploitation well is used and the length between the well and the deep gas injection inlet is 83.85 mm.

[0112] The fourth step is to end the exploitation. When the pressure in the two reservoirs stabilizes at 4 MPa and the temperature of the two reservoirs returns to the initial temperature before exploitation, it indicates that the hydrates inside the natural gas hydrate layer have basically been decomposed, the deep gas in the deep gas layer has also been produced, and the exploitation experiment is over.

[0113] The experimental results are as follows:

[0114] It took 8.26 hours to produce 90% of the total gas production of the combined mining, and 14.57 hours to produce 90% of the total gas production of the natural gas hydrate layer. During the combined mining process, the cumulative injection energy of the deep gas was 3404.41 kJ and its effective utilization rate was 50.31%.

[0115] Comparative Example 2:

[0116] On a laboratory scale, without using the above-mentioned natural gas hydrate production method, a blank experiment 2 was conducted only to extend the migration time of deep gas in the natural gas hydrate layer and improve the effective utilization rate of deep gas injection energy. The experimental device was the same as that of Example 2, and the experimental steps were as follows:

[0117] In the first step, a South China Sea marine soil reservoir with a porosity and initial water saturation of 50.86% and 47.78% was prepared in a natural gas hydrate kettle, and a South China Sea marine soil reservoir with a porosity and initial water saturation of 59.41% and 13.66% was prepared in a deep gas kettle;

[0118] The second step is to prepare a marine soil reservoir containing natural gas hydrates: inject 13.48MPa of natural gas into the natural gas hydrate kettle, set the air bath at 21.58℃, and after the temperature and pressure inside the reservoir are stable, set the air bath at 4.87℃ to induce the formation of natural gas hydrates inside the reservoir; prepare a marine soil reservoir containing deep gas: inject 12.19MPa of natural gas into the deep gas kettle, and set the water bath at 29.78℃; after the temperature and pressure inside the two reactors are stable, open the valve on the connecting pipeline between the two reactors to induce the deep gas to move upward in preparation for extraction;

[0119] The third step is to exploit the natural gas hydrate and deep gas in the two reactors. The plunger pump controls the pressure drop rate change in the back pressure valve. The pressure drop rate is 200 kPa / min. A single exploitation well is used and the length between it and the deep gas injection inlet is 177.85 mm.

[0120] The fourth step is to end the exploitation. When the pressure in the two reservoirs stabilizes at 4 MPa and the temperature of the two reservoirs returns to the initial temperature before exploitation, it indicates that the hydrates inside the natural gas hydrate layer have basically been decomposed, the deep gas in the deep gas layer has also been produced, and the exploitation experiment is over.

[0121] The experimental results are as follows:

[0122] It took 11.66 hours to produce 90% of the total gas production of the combined mining, and 19.80 hours to produce 90% of the total gas production of the natural gas hydrate layer. During the combined mining process, the cumulative injection energy of the deep gas was 2004.91 kJ and its effective utilization rate was 70.52%.

[0123] It can be seen that, compared with Example 1, in Example 2, the natural gas hydrate production method of the present invention reduces the cumulative injection energy of deep gas by 191.6 kJ, but extends the crossflow distance of deep gas in the natural gas hydrate layer, which significantly improves the effective utilization rate of the cumulative injection energy of deep gas by 14.25%, thereby enhancing both the efficiency of combined production and the efficiency of decomposition of natural gas hydrates; compared with Example 2, in Example 2, the natural gas hydrate production method of the present invention reduces the effective utilization rate of the cumulative injection energy of deep gas by 5.96%, but increases the number of production wells to accelerate the upward movement rate of deep gas, thereby significantly increasing the cumulative injection energy of deep gas by 1207.9 kJ, thereby also enhancing both the efficiency of combined production and the efficiency of decomposition of natural gas hydrates.

[0124] The above is a detailed description of a device and method for enhancing the production of natural gas hydrates using deep gas geothermal energy provided by the present invention. The above description is only used to help understand the technical solution and core idea of ​​the present invention. It should be pointed out that for technicians in this technical field, without departing from the spirit and principles of the present invention, the present invention can also be improved and modified. These improvements and modifications are also included in the scope of protection of the present invention.

Claims

1. A device for enhancing the production of natural gas hydrates by using deep gas geothermal energy, characterized in that: Including temperature monitoring system, pressure monitoring system, saturation monitoring system, gas production monitoring system, automatic control feedback system and gas-liquid separation system; The temperature monitoring system comprises a temperature sensor array arranged on the outer wall of a vertical fixed pipe of a monitoring well of a natural gas hydrate layer and a deep gas layer, the temperature sensor array being arranged axially along the vertical fixed pipe and used to monitor the temperature change of the reservoir around the temperature sensor and transmit the temperature signal to the automatic control feedback system; The pressure monitoring system comprises a pressure sensor array arranged on the outer wall of a vertical fixed pipe of a natural gas hydrate layer and a deep gas layer monitoring well, the pressure sensor array being arranged axially along the vertical fixed pipe and used to monitor pressure changes in the reservoir around the pressure sensor and transmit the pressure signal to the automatic control feedback system; The saturation monitoring system includes nuclear magnetic resonance logging and sonic logging set in the natural gas hydrate layer and nuclear magnetic resonance logging set in the deep gas layer; the nuclear magnetic resonance logging is used to reflect the saturation of water and free gas, and transmits the nuclear magnetic resonance signal to the automatic control feedback system; the sonic logging is used to reflect the saturation of natural gas hydrate, and transmits the sonic logging data to the automatic control feedback system; The gas-liquid separation system is arranged on the seabed and is used to separate the natural gas and seawater in the gas-liquid mixture produced from the natural gas hydrate layer; The gas production monitoring system includes a flow measurement device arranged behind the gas-liquid separation system, which is used to monitor the gas production rate and transmit the instantaneous gas production rate data to the automatic control feedback system; The automatic control feedback system is arranged on a semi-submersible marine platform, and is used for receiving, processing and monitoring reservoir temperature signals, reservoir pressure signals, reservoir nuclear magnetic resonance signals, reservoir acoustic wave signals and reservoir gas production rate signals in real time, and automatically analyzing the decomposition gas production rate of natural gas hydrates, the upwelling rate of deep gas and the proportion of deep gas injection energy utilized by natural gas hydrate decomposition, so as to judge the decomposition status of natural gas hydrates in the reservoir and the effective utilization status of deep gas injection energy, and then timely adjust the mining plan to achieve overall control of strengthening the decomposition of natural gas hydrates by using deep gas injection energy.

2. The device for enhancing natural gas hydrate production by utilizing deep gas geothermal energy according to claim 1, characterized in that: The automatic control feedback system performs the following control methods on the mining plan: If the upwelling rate of deep gas v d Less than N1, then increase the voltage reduction rate to V1 and maintain it for time t1; if v d If it is still less than N1, the pressure reduction rate is further increased to V2 or wells closer to the gas chimney and wells farther away are used as production wells at the same time to provide more migration channels for the upwelling deep gas in the natural gas hydrate layer; if v d Maintaining the range of N1 to N2 and the proportion of deep gas injection energy utilized by natural gas hydrate decomposition η is less than M1, the well far away from the gas chimney is used as the production well to extend the cross-flow distance of the upwelling deep gas in the hydrate layer; finally, the upwelling rate of deep gas v d Maintain within the range of N1 to N2 and maintain η above M1.

3. The device for enhancing natural gas hydrate production by utilizing deep gas geothermal energy according to claim 1 or 2, characterized in that: The proportion of the deep gas injection energy utilized by the decomposition of natural gas hydrates is as follows: in, The geothermal energy injected into the gas hydrate layer from deep gas, The driving work done when injecting deep gas into the natural gas hydrate layer, Q TE The amount of energy injected into a gas hydrate layer for deep gas is lost by being absorbed by the surrounding formations.

4. The device for enhancing natural gas hydrate production by utilizing deep gas geothermal energy according to claim 3, characterized in that: The geothermal energy injected into the natural gas hydrate layer by the deep gas The calculation formula is as follows: In the formula, Refers to the specific heat capacity of deep gas at time δ, which is obtained by screening from the basic physical property database by the automatic control feedback system based on the temperature and pressure of the deep gas layer at time δ fed back by the temperature monitoring system and the pressure monitoring system respectively; Refers to the instantaneous production rate of deep gas at time δ fed back by the gas production monitoring system; and They refer to the average temperatures of the deep gas layer and the natural gas hydrate layer at time δ respectively as fed back by the temperature monitoring system.

5. The device for enhancing natural gas hydrate production by utilizing deep gas geothermal energy according to claim 4, characterized in that: The driving work done when the deep gas is injected into the natural gas hydrate layer The calculation formula is as follows: In the formula, Refers to the pressure of the deep gas layer at time δ fed back by the pressure monitoring system.

6. The device for enhancing natural gas hydrate production by utilizing deep gas geothermal energy according to claim 5, characterized in that: The energy of the deep gas injected into the natural gas hydrate layer is absorbed by the surrounding formations and lost. TE The calculation method is as follows: Calculation of the change in sensible heat of the natural gas hydrate layer In the formula, Refers to the quality of the natural gas hydrate layer as a whole, which is calculated by the automatic control feedback system based on the saturation of each phase in the natural gas hydrate layer fed back by the saturation monitoring system; Refers to the rate of change of the average temperature of the natural gas hydrate layer at time δ, which is calculated by the automatic control feedback system based on the natural gas hydrate layer temperature signal fed back by the temperature monitoring system; Refers to the specific heat capacity of the entire natural gas hydrate layer at time δ, which is calculated by the automatic control feedback system based on the temperature and pressure signals of the natural gas hydrate layer fed back by the temperature monitoring system and the pressure monitoring system respectively, combined with the saturation signals of the porous medium, gas, water and hydrate phases in the reservoir: Where S refers to saturation, and the subscripts MS, g, w, and h refer to porous media, gas, water, and hydrate, respectively; Calculation of the heat absorption Q of natural gas hydrate decomposition h : Where n hdis,Ini→δ It refers to the cumulative decomposition amount of natural gas hydrate from the initial stage of mining to the time δ, which is calculated by the automatic control feedback system based on the natural gas hydrate saturation signal fed back by the saturation monitoring system; ΔH(T) refers to the decomposition heat of natural gas hydrate, which is calculated by formula (7): Where, T refers to the decomposition temperature of natural gas hydrate, which is obtained by the automatic control feedback system based on the temperature signal fed back by the temperature monitoring system; Calculate the driving work W done by the gas in the natural gas hydrate layer produced from the production well push,Hpro : In the formula, represents the pressure of the natural gas hydrate layer at time δ fed back by the pressure monitoring system, It represents the instantaneous gas production rate of the natural gas hydrate layer itself at time δ fed back by the gas production monitoring system; Calculate the driving work W done by the deep gas injected into the gas hydrate layer when it is produced from the production well push,Dpro : Let i = 0.01h, calculate the time period from i-0.01 to i Q h , W push,Hpro and W push,Dpro The instantaneous change values ​​of six kinds of energy; taking the natural gas hydrate layer as the thermal system, the change Q of the thermal system energy during this period is calculated: When Q is less than 0, it indicates that the thermal system is transferring heat to the surrounding environment, and Q is recorded as b i If i = the end time of production, then calculate the amount of energy lost by the surrounding strata absorbed by the deep gas injected into the natural gas hydrate layer Q TE : Otherwise, let i=i+0.01h and repeat the above calculation process.

7. The device for enhancing natural gas hydrate production by utilizing deep gas geothermal energy according to claim 1, characterized in that: It also includes a sand control system, which is a mining sand control device arranged at the gas collection port and consists of a double layer of screens; the outer layer of the screen has a pore size of 50 microns, which is used to prevent coarse sand from entering the wellbore; the inner layer of the screen has a pore size of 20 microns, which is used to prevent fine sand from entering the wellbore; gravel with a particle size of 30 to 80 microns is filled between the two layers of screens to maintain the permeability of the gas-liquid two phases at the gas collection port.

8. The device for enhancing natural gas hydrate production by utilizing deep gas geothermal energy according to claim 1, characterized in that: The gas-liquid separation system is a gas-liquid separation device arranged on the seabed. The gas-liquid mixture obtained by mining is separated into natural gas and seawater by the gas-liquid separation device. The natural gas enters the semi-submersible marine platform through the gas production pipeline, and the seawater is discharged into the sea from the outlet.

9. A method for intensifying the production of natural gas hydrates using deep gas geothermal energy, characterized in that: The following steps are involved: The first step is to conduct exploration operations in the target area where natural gas hydrates and deep gas coexist with multiple gas sources to determine the spatial distribution of gas chimneys; collect data on the initial temperature, initial pressure and saturation of each phase of the natural gas hydrate layer and deep gas layer; The second step is to set the well close to the gas chimney as a production well, control the initial pressure reduction rate to V0, turn on the gas collection pump and water collection pump, and start the initial pressure reduction and gas production; The third step is to calculate the geothermal energy and driving work of deep gas injected into the gas hydrate layer based on the temperature, pressure, saturation of each phase and instantaneous total gas production rate of the gas hydrate layer and the deep gas layer measured at each time t, as well as the amount lost due to absorption by the surrounding formations, and calculate the proportion η of the deep gas injection energy utilized by the decomposition of gas hydrates; Step 4: If the upwelling rate of deep gas v d Less than N1, then increase the voltage reduction rate to V1 and maintain it for time t1; if v d If it is still less than N1, the pressure reduction rate is further increased to V2 or wells closer to the gas chimney and wells farther away are used as production wells at the same time to provide more migration channels for the upwelling deep gas in the natural gas hydrate layer; if v d Maintained within the range of N1 to N2 and η is less than M1, the well far away from the gas chimney is used as the production well to extend the cross-flow distance of the upwelling deep gas in the hydrate layer; finally, the upwelling rate of deep gas v d Maintain within the range of N1 to N2 and maintain η above M1; The fifth step is to separate the gas-liquid mixture produced by mining, and the natural gas enters the semi-submersible offshore platform through the gas production pipeline to complete the gas collection, and the seawater is discharged into the sea from the outlet; Step 6: When the reservoir gas production rate is lower than v1, it means that the natural gas hydrate in the enriched area has been basically decomposed, and the production well will be recovered to complete the production operation.

10. The method for intensifying natural gas hydrate production by using deep gas geothermal energy according to claim 9, characterized in that: The calculation method of η is as follows: Calculating the geothermal energy of deep gas injection into a gas hydrate layer In the formula, Refers to the specific heat capacity of deep gas at time δ, which is obtained by screening from the basic physical property database based on the temperature and pressure of the deep gas layer at time δ; Refers to the instantaneous production rate of deep gas at time δ; and They refer to the average temperatures of the deep gas layer and the gas hydrate layer at time δ, respectively; Calculation of the thrust work done by deep gas injection into a gas hydrate layer In the formula, Refers to the pressure of the deep gas layer at time δ; Calculation of the change in sensible heat of the natural gas hydrate layer In the formula, Refers to the mass of the entire natural gas hydrate layer, which is calculated based on the saturation of each phase in the natural gas hydrate layer; Refers to the rate of change of the average temperature of the gas hydrate layer at time δ, which is converted from the temperature of the gas hydrate layer; It refers to the specific heat capacity of the entire natural gas hydrate layer at time δ, which is calculated from the temperature and pressure of the natural gas hydrate layer and the saturation of the porous medium, gas, water and hydrate phases in the reservoir: Where S refers to saturation, and the subscripts MS, g, w, and h refer to porous media, gas, water, and hydrate, respectively; Calculation of the heat absorption Q of natural gas hydrate decomposition h : Q h =ΔH(T)·n hdis,Ini→δ (5) Where n hdis,Ini→δ It refers to the cumulative decomposition amount of natural gas hydrate from the initial stage of mining to the time δ, which is calculated based on the saturation of natural gas hydrate; ΔH(T) refers to the decomposition heat of natural gas hydrate, which is calculated by formula (6): ΔH(T)=4.184·(13521-4·T) (6) Where T refers to the decomposition temperature of natural gas hydrate; Calculate the driving work W done by the gas in the natural gas hydrate layer produced from the production well push,Hpro : In the formula, represents the pressure of the gas hydrate layer at time δ, represents the instantaneous gas production rate of the natural gas hydrate layer itself at time δ; Calculate the driving work W done by the deep gas injected into the gas hydrate layer when it is produced from the production well push,Dpro : Let i = 0.01h, calculate the time period from i-0.01 to i Q h , W push,Hpro and W push,Dpro The instantaneous change values ​​of six kinds of energy; taking the natural gas hydrate layer as the thermal system, the change Q of the thermal system energy during this period is calculated: When Q is less than 0, it indicates that the thermal system is transferring heat to the surrounding environment, and Q is recorded as b i ; If i = the end time of production, then calculate the amount of energy lost by the surrounding strata absorbed by the deep gas injected into the natural gas hydrate layer Q TE ; Otherwise, let i = i + 0.01h and repeat the above calculation process; The calculation formula of η is as follows:

Images