Method for in-situ efficient hydrogen production from natural gas reservoirs

Abstract

The application provides a natural gas reservoir in-situ efficient hydrogen production method, which comprises the following steps: injecting combustion-supporting gas into the natural gas reservoir; injecting inert gas to push the natural gas and the combustion-supporting gas away from the wellbore; injecting liquid chemical igniter; injecting temperature-resistant gel to push the liquid chemical igniter away from the wellbore and prevent the liquid chemical igniter from flowing to the wellbore before being ignited; drilling holes around the wellbore and filling CO adsorption material and catalyst; lowering a slotted screen into the production section wellbore to prevent the adsorption material from flowing back to the wellbore with fluid; opening the well to produce the combustion-supporting agent to flow back and contact the liquid chemical igniter to generate an exothermic reaction, realize in-situ ignition and produce hydrogen; placing a gas separator below the well mouth to perform primary CO2 separation; and performing secondary separation of the gas by PSA to obtain high-purity hydrogen. The application forms a mixed flow state of oxygen and natural gas under the condition of the gas reservoir, realizes continuous heat release to improve the temperature of the gas reservoir, solves the problem of insufficient fuel per unit volume of the gas reservoir, and realizes in-situ efficient hydrogen production of the natural gas reservoir.

Description

Technical Field

[0001] This invention provides a method for efficient in-situ hydrogen production from natural gas reservoirs, belonging to the field of in-situ hydrogen production technology from oil and gas reservoirs. Background Technology

[0002] In 2009, CN102149898 proposed a method for generating hydrogen from oil and gas reservoirs, including a catalyst injection process and a hydrogen-producing well type. It briefly described the thermal reservoir method, but did not consider the implementation process of gas reservoir heating, the oxygen injection combustion method in the gas reservoir, the in-situ hydrogen production area in the gas reservoir, or the in-situ ignition process in the gas reservoir.

[0003] In 2019, CN12088242 disclosed an in-situ process for producing syngas from underground hydrocarbon reservoirs, which involved thermally treating oil reservoirs to generate syngas containing hydrogen and considered production well types. However, it did not consider hydrogen production from gas reservoirs, the implementation process of hydrogen production from gas reservoirs, or the in-situ ignition process for gas reservoirs.

[0004] In 2019, CN10529086 proposed a method for producing hydrogen from abandoned and shut-down oil fields, extra-heavy oil, shale oil, extra-heavy oil, and oil shale by injecting supercritical superheated steam, but it did not consider hydrogen production from gas reservoirs, the implementation process of hydrogen production from gas reservoirs, or the in-situ ignition process of gas reservoirs.

[0005] The boundary temperature for hydrogen production is 450℃. However, thermodynamic calculations show that the effective heating temperature of a unit volume of gas in a conventional natural gas reservoir to achieve complete combustion depends mainly on the reservoir pressure and porosity. At the same time, the exhaust gas generated during conventional combustion will displace the natural gas at the combustion front, further reducing the unit combustion temperature, which means that most gas reservoirs cannot produce hydrogen effectively and efficiently. Summary of the Invention

[0006] This invention proposes an efficient in-situ hydrogen production method for natural gas reservoirs, especially depleted gas reservoirs and water-intruded gas reservoirs.

[0007] The specific technical solution is as follows:

[0008] A method for efficient in-situ hydrogen production from natural gas reservoirs, including...

[0009] S1 injects combustion-supporting gas into the natural gas reservoir;

[0010] S2 injects inert gas to push the natural gas and combustion-supporting gas away from the wellbore;

[0011] S3 injects liquid chemical igniter;

[0012] S4 injection of heat-resistant gel pushes the fuel and igniter away from the wellbore and prevents them from flowing into the wellbore before they are ignited;

[0013] S5 involves drilling holes around the wellbore and filling them with CO adsorption material and catalyst;

[0014] S6 involves installing a slotted screen in the wellbore of the production section to prevent the adsorbent material from flowing back into the wellbore with the fluid;

[0015] S7 well opening production combustion aid reflux and liquid chemical igniter undergo an exothermic reaction to achieve on-site ignition and hydrogen production reaction;

[0016] A gas separator was placed below the S8 wellhead for initial CO2 separation.

[0017] High-purity hydrogen is obtained through secondary separation of S9 gas PSA.

[0018] The combustion-supporting gas mentioned in step S1 is any one of the following: air, oxygen-enriched air, or oxygen.

[0019] The inert gas mentioned in step S2 is any one of the following: nitrogen, argon, or carbon dioxide.

[0020] The liquid chemical igniter mentioned in step S3 includes fuel and igniter; the fuel is one or a mixture of tung oil, linseed oil, red oil, castor oil, turpentine oil, and tar oil, and the igniter is phosphorus or sodium nitrite.

[0021] The heat-resistant gel described in step S4 is not resistant to 120°C.

[0022] The drilling method described in step S5 is a type of hydraulic fracturing or drilling, and the CO adsorption material is one or a mixture of metal-organic framework materials and porous carbon materials, and the catalyst is one or a mixture of nickel-based catalysts, copper-based catalysts, iron-based catalysts and chromium-based catalysts.

[0023] The metal-organic framework material is one or a mixture of IRMOF-74-III, MOF-177, ZIF-8, and MOFs;

[0024] The porous carbon material is one or a mixture of CMK-3 and AC-35.

[0025] The slotted screen described in step S6 has a slot size smaller than the size of the CO adsorbed particles.

[0026] The in-situ ignition in step S7 is the process where the combustion aid comes into contact with the igniter during extraction, resulting in low-temperature oxidation and exothermic reaction, which ignites the fuel to achieve in-situ ignition of the reservoir, heats the reservoir, and enables in-situ hydrogen production.

[0027] The heating method of the reservoir is as follows: natural gas and combustion-supporting gas mix and pass through the ignition zone, and an exothermic oxidation reaction occurs continuously in the ignition zone, forming a high-temperature zone that continuously releases heat. The temperature in the high-temperature zone depends on the injected oxygen content and can reach more than 1000°C. When the temperature reaches the hydrogen production reaction temperature condition (temperature greater than or equal to 450°C), at least one or more hydrogen production reactions occur in the high-temperature zone, producing a large amount of hydrogen.

[0028] The hydrogen production reactions include: reforming of gasified water and methane in the formation to produce hydrogen; partial oxidation of oxygen and methane to produce hydrogen; and water-gas conversion of CO and gasified water to produce hydrogen.

[0029] The gas separator described in step S8 performs initial separation of the produced gas, separating CO2 from the residual gas to achieve wellhead carbon capture and treatment.

[0030] The carbon treatment described above involves capturing carbon for EOR or EGR reinjection into oil and gas reservoirs, or injecting it into nearby brine layers for storage.

[0031] The gas separation method described in step S9 involves collecting and transporting the remaining produced gas after separation, performing PSA separation, and obtaining high-purity hydrogen, methane, and CO. The recovered methane and CO are then used for hydrogen production on the ground.

[0032] The specific technical effects of this invention are as follows:

[0033] ① This invention enables the mixing and combustion of oxygen and natural gas, achieving continuous heat release to increase reservoir temperature and solve the problem of insufficient fuel per unit volume in the gas reservoir; ② The hydrogen production area of ​​this invention is in the near-wellbore zone, allowing for rapid extraction after hydrogen production, reducing the residence time of hydrogen in the reservoir and minimizing hydrogen loss; ③ This invention fills the area near the wellbore with CO adsorption material, reducing CO production and enabling water-gas conversion to hydrogen production near the wellbore; ④ This invention enables reverse ignition inside the gas reservoir, enhancing operational safety; ⑤ This invention installs a gas density separation device at the wellhead, enabling CO2 capture at the wellhead; ⑥ This invention separates the toxic CO gas from the syngas and provides raw materials for surface hydrogen production. This method is not only applicable to vertical wells but also to horizontal wells, dual horizontal wells, and directional wells. Attached Figure Description

[0034] Figure 1 This is a flowchart of the present invention;

[0035] Figure 2 This is a schematic diagram illustrating an embodiment of the present invention;

[0036] Figure 3 This is a graph showing the gas molar distribution of the gas reservoir fracture medium during the injection process and the gas composition change curve of a certain grid during production, as described in the embodiment.

[0037] Figure 4 The graph shows the hydrogen molar distribution in the reservoir fracture medium and the produced gas and hydrogen curves during the production process of this embodiment. Detailed Implementation

[0038] The specific technical solutions of the present invention will be described with reference to the embodiments.

[0039] like Figure 1 The process shown illustrates the efficient hydrogen production method from natural gas reservoirs. Figure 2 As shown. Gas reservoir 1 is equipped with a slotted screen pipe 3, with a packer 2 at the top. The lower end of a production string 4 is inserted into the slotted screen pipe 3. A casing 5 is installed outside the production string 4, and a density separator 6 is installed at the top of the production string 4, which is connected to a carbon dioxide storage tank 7. The carbon dioxide storage tank 7 contains carbon dioxide 18 and is connected to an injection well 8, which is used to supply gas to the brine layer 20. The production string 4 is also connected to a gas pipeline to a PSA (Pressure Swing Separator) 9. The PSA 9 is connected to a surface hydrogen production unit 10 and a hydrogen storage tank 11. The surface hydrogen production unit 10 is connected to the hydrogen storage tank 11, where hydrogen 19 is stored.

[0040] Outside the slotted screen tube 3, in order, are CO adsorbent 12, heat-resistant gel 13, liquid chemical igniter 14, nitrogen 15, oxygen 16, and natural gas 17.

[0041] This embodiment establishes a 42×42m, 5m thick mechanistic model using the popular petroleum industry software CMG-Stars. The model represents a dual-medium medium of pores and fractures, with a matrix porosity of 5% and a permeability of 2mD, and fracture porosity of 1% and a permeability of 10mD. A model for natural gas oxidation, hydrogen production, and hydrogen consumption is established by coupling the Arrhenius equation, and a seepage-thermal coupled fluid model is also established. The injection parameter system and injection sequence are oxygen, nitrogen, fluid chemical igniter, and heat-resistant gel, respectively.

[0042] like Figure 3 The graph shows the gas molar distribution of the gas reservoir fracture medium during the injection process and the gas composition change curve of a certain grid during production. It can be seen from about 30 days that only nitrogen exists in the unit volume. After 30 days, production begins, and methane and oxygen flow in at the same time, producing CO and CO2 gases. Subsequently, hydrogen is produced, which proves the rationality and feasibility of the operation process. Figure 4 This is a graph showing the hydrogen molar distribution in the reservoir fracture medium and the produced gas and hydrogen curves during the production process of this embodiment. Hydrogen production after well opening was 2718 m³. 3 CH41581m 3 CO2 production 2111m 3 CO6m 3 Total gas production: 7003 m³ 3The simulation achieved a hydrogen production molar ratio of 38.8%, demonstrating highly efficient hydrogen production from the natural gas reservoir. Furthermore, no CO adsorption materials or catalysts were added in the simulation, suggesting that actual operation could achieve even higher hydrogen production efficiency than the simulation results. In addition, CH4 and CO, transported to the chemical plant for PSA separation, are the main materials for surface hydrogen production, enabling further surface hydrogen production. Even more advantageously, CO2 captured at the wellhead can be reinjected into the nearby natural gas reservoir to improve recovery or injected into the brine layer for geological storage.

Claims

1. A method for efficient in-situ hydrogen production from a natural gas reservoir, characterized in that, include: S1 injects combustion-supporting gas into the natural gas reservoir; S2 injects inert gas to push the natural gas and combustion-supporting gas away from the wellbore; S3 injects liquid chemical igniter; S4 injection of heat-resistant gel pushes the fuel and igniter away from the wellbore and prevents them from flowing into the wellbore before they are ignited; S5 involves drilling holes around the wellbore and filling them with CO adsorption material and catalyst; The drilling method described in step S5 is a type of hydraulic fracturing or drilling, and the CO adsorption material is one or a mixture of metal-organic framework materials and porous carbon materials, and the catalyst is one or a mixture of nickel-based catalysts, copper-based catalysts, iron-based catalysts, chromium-based catalysts and platinum-based catalysts. The metal-organic framework material is one or a mixture of IRMof-74-III, MOF-177, or ZIF-8; The porous carbon material is one or a mixture of CMK-3 and AC-35; S6 A slotted screen is installed in the producing section of the wellbore to prevent CO adsorbent material from flowing back into the wellbore with the fluid; The S7 well opening process generates combustion-supporting gas that flows back into the liquid chemical igniter, resulting in an exothermic reaction that enables on-site ignition and hydrogen production. The in-situ ignition in step S7 is the process where the combustion-supporting gas comes into contact with the igniter during low-temperature oxidation and exothermic reaction, igniting the fuel to achieve in-situ ignition of the reservoir, heating the reservoir and realizing the hydrogen production reaction. The heating method of the reservoir is that, as natural gas and combustion-supporting gas mix and pass through the ignition zone, an exothermic oxidation reaction continuously occurs in the ignition zone, forming a high-temperature zone that continuously releases heat. The temperature in the high-temperature zone depends on the oxygen content injected and can reach over 1000℃. When the temperature reaches the hydrogen production reaction temperature condition, which is greater than or equal to 450℃, at least one or more hydrogen production reactions occur in the high-temperature zone, producing a large amount of hydrogen. The hydrogen production reaction is as follows: hydrogen is produced by reforming gasified water and methane in the formation, hydrogen is produced by partial oxidation of oxygen and methane, and hydrogen is produced by water-gas conversion of CO and gasified water. A gas separator was placed below the S8 wellhead for initial CO2 separation. The gas separator described in step S8 performs initial separation of the produced gas, separating CO2 and residual gas to achieve wellhead carbon capture and carbon treatment. The carbon treatment described above involves capturing carbon for EOR or EGR reinjection into oil and gas reservoirs, or injecting it into nearby brine layers for storage. High-purity hydrogen is obtained through secondary separation of S9 gas PSA.

2. The method for in-situ efficient hydrogen production from a natural gas reservoir according to claim 1, characterized in that, The combustion-supporting gas mentioned in step S1 is any one of the following: air or oxygen.

3. The method for in-situ efficient hydrogen production from a natural gas reservoir according to claim 1, characterized in that, The inert gas mentioned in step S2 is any one of the following: nitrogen or argon.

4. The method for efficient in-situ hydrogen production from a natural gas reservoir according to claim 1, characterized in that, The liquid chemical igniter mentioned in step S3 includes fuel and igniter; the fuel is one or a mixture of tung oil, linseed oil, red oil, castor oil, turpentine oil, and tar oil, and the igniter is phosphorus or sodium nitrite.

5. The method for efficient in-situ hydrogen production from a natural gas reservoir according to claim 1, characterized in that, The slotted screen mentioned in step S6 has a slot size smaller than that of the CO adsorbent material and the catalyst.

6. The method for efficient in-situ hydrogen production from a natural gas reservoir according to claim 1, characterized in that, In step S9, the remaining produced gas after separation is collected and transported, and PSA separation is carried out to obtain high-purity hydrogen, methane and CO. The recovered methane and CO are used for hydrogen production on the ground.

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