A method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs

Abstract

The present invention discloses an integrated method of hydrogen foam oil recovery and geological hydrogen storage for depleted oil reservoirs, belonging to the field of oil extraction technology. The method injects carbon dioxide foam into the depleted oil reservoir to form a carbon dioxide foam segment plug, then injects hydrogen foam to displace the residual crude oil to the vicinity of the production well and extract it, and then continues to inject hydrogen foam to complete the geological hydrogen storage process, and finally uses hydrogen foam in-situ physical defoaming to recover hydrogen and utilize it. The method proposed by the present invention not only realizes the efficient exploitation of oil in depleted oil reservoirs and improves the oil recovery rate of some reservoirs; it also increases the underground storage space of hydrogen, realizes high-density and safe long-term hydrogen storage, and provides a new solution for the geological storage and recovery of hydrogen.

Description

Technical Field

[0001] The invention discloses an integrated method of hydrogen foam oil recovery and geological hydrogen storage for depleted oil reservoirs, belonging to the technical field of oil exploitation. Background Art

[0002] Hydrogen storage is a major issue facing the future hydrogen-based economy and is key to regulating the intermittent supply of renewable energy. Due to the high mobility, leakage tendency and low density of hydrogen, large-scale hydrogen storage is challenging both technically and economically.

[0003] Common hydrogen storage technologies include: surface containers, underground rock caverns or salt caverns, abandoned mines, depleted oil reservoirs, etc. Depleted oil reservoirs have great potential for hydrogen storage due to high porosity, sufficient permeability, good closure and huge spatial volume. Depleted oil reservoirs also have relatively complete surface and underground facilities to facilitate the injection, storage and recovery of large amounts of hydrogen. The depth of the reservoir ensures safety during long-term hydrogen storage. When depleted oil reservoirs are in a stage with high water content, oil production is low. Due to gravity differentiation, the injected water effectively displaces the oil from the lower part of the reservoir, but there is still some remaining oil in the upper part that cannot be displaced by water flooding. Injecting hydrogen into these depleted oil reservoirs can achieve the dual purposes of enhancing oil recovery and storing hydrogen at the same time.

[0004] The non-polar, low-density and low-viscosity properties of hydrogen make it easy for hydrogen to channel and finger in depleted oil reservoirs, forming a hydrogen-rich gas cap and premature breakthrough of production wells, resulting in reduced gas storage capacity, complex hydrogen recovery operations and low oil recovery efficiency. Summary of the invention

[0005] In view of the above-mentioned problems existing in the prior art, the purpose of the present invention is to propose an integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs, which not only realizes the efficient exploitation of oil in depleted oil reservoirs and improves the oil recovery rate of some reservoirs; it also increases the underground storage space of hydrogen, realizes high-density and safe long-term hydrogen storage, and provides a new solution for the geological storage and recovery of hydrogen.

[0006] To achieve the above object, the present invention adopts the following technical solution: a method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs, the method comprising the following steps:

[0007] Step 1: Setting up the oil recovery and geological hydrogen storage injection and production system:

[0008] Depleted oil reservoirs in the target area are identified, and an injection-production system for oil recovery and geological hydrogen storage is set up based on the geological structure parameters and injection-production process parameters of the oil reservoirs. An inverted seven-point well network is adopted, and temperature and pressure monitoring devices, electric heaters, ultrasonic defoaming devices, and hydrogen sensors are deployed in all injection wells and production wells of the inverted seven-point well network;

[0009] Step 2: Foam flooding stage:

[0010] First, carbon dioxide foam is continuously injected into the injection well as a pre-segment plug. When the injection volume of carbon dioxide foam reaches the preset injection volume, the injection of carbon dioxide foam is stopped. Subsequently, hydrogen foam is injected into the injection well. During the injection process, the pressure and temperature inside the reservoir are monitored in real time through a temperature and pressure monitoring device. The carbon dioxide foam and hydrogen foam injected into the formation are pushed forward in sequence to displace the residual crude oil in the reservoir to the vicinity of the production well and produced until the crude oil production of the production well drops to zero.

[0011] Among them, sodium α-olefin sulfonate is selected as a foaming agent for carbon dioxide foam, modified polyethoxylated silicone is selected as a foam stabilizer for carbon dioxide foam, and water is selected as a solvent and diluent for carbon dioxide foam;

[0012] Among them, sodium dodecyl sulfate is selected as the foaming agent of hydrogen foam, PEG grafted polymer is selected as the foam stabilizer of hydrogen foam, nanoparticles or inorganic salts are selected as the regulator of hydrogen foam, and water is selected as the solvent of hydrogen foam;

[0013] Step 3: Hydrogen storage stage:

[0014] When the residual crude oil in the reservoir is mined, the injection well is closed for three to five days for well soaking. After the well soaking is completed, hydrogen foam is continuously injected into the injection well for hydrogen storage. The hydrogen foam occupies all hydrogen storage space and displaces the residual carbon dioxide foam, so that the carbon dioxide foam is displaced to the vicinity of the production well and mined. When the injected hydrogen foam reaches the preset hydrogen storage volume or the pressure value inside the reservoir reaches the maximum bearing pressure of the reservoir, the injection well and the production well are closed, and the injection of hydrogen foam is stopped.

[0015] Step 4: Hydrogen foam in-situ physical defoaming stage:

[0016] Start the electric heater to increase the temperature of the hydrogen storage layer, and use the in-situ variable temperature defoaming method to perform preliminary defoaming. When the temperature in the hydrogen storage layer reaches the preset value, maintain the preset value unchanged, start the ultrasonic defoaming device, and use the ultrasonic defoaming method to perform deep defoaming. During the defoaming process, use a hydrogen sensor to detect the concentration of hydrogen in real time to determine the defoaming situation and recover the hydrogen. At this point, hydrogen foam oil recovery and geological hydrogen storage are completed.

[0017] Furthermore, the integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs also includes a hydrogen purification stage:

[0018] The recovered hydrogen is purified by pressure swing adsorption, the adsorption pressure is controlled between 0.1MPa and 0.5MPa, the temperature is controlled between 150℃ and 200℃, and the hydrogen flow rate is controlled between 10mL / min and 50mL / min; the purified hydrogen is collected and stored in a hydrogen storage tank after drying and dust removal.

[0019] Furthermore, the inverted seven-point well network includes at least one well group, each well group includes an injection well located at the center of a regular hexagon, and production wells located at six vertices of the regular hexagon, and the distance between wells in each well group is greater than 30m and less than 50m.

[0020] Furthermore, the raw materials of the foaming agent used to prepare the carbon dioxide foam are mixed in the following proportions by weight: 20 to 70 parts of sodium α-olefin sulfonate, 10 to 50 parts of modified polyethoxylated silicone, and 10 to 70 parts of water.

[0021] Furthermore, the concentration of sodium α-olefin sulfonate in the foaming agent used to prepare the carbon dioxide foam is controlled between 0.3% and 0.5%, and the optimal gas-liquid ratio of the carbon dioxide foam is controlled at 2:1 or 3:1.

[0022] Furthermore, the concentration of sodium dodecyl sulfate in the foaming agent used to prepare hydrogen foam is between 0.5% and 2%, the concentration of PEG grafted polymer is between 0.01% and 0.5%, and the gas-liquid ratio of the hydrogen foam is controlled between 2:1 and 5:1.

[0023] Furthermore, the nanoparticles in the regulator are nano-silicon dioxide, and the inorganic salt is sodium chloride or calcium chloride.

[0024] Furthermore, when injecting foam, the injection pressure of the injection well is set to 10.8MPa~20MPa, and the injection flow rate is set to 8m 3 / day~16m 3 / day.

[0025] Furthermore, when injecting hydrogen foam, the injection temperature is room temperature, and the foaming agent used to prepare hydrogen foam is first injected into the oil reservoir, and then the hydrogen used to prepare hydrogen foam is injected, forming a complete injection cycle.

[0026] Further, in step 4, the preset value ranges from 110°C to 120°C.

[0027] Compared with the traditional oil recovery and hydrogen storage methods, the integrated method of hydrogen foam oil recovery and geological hydrogen storage for depleted oil reservoirs provided by the present invention has the following advantages:

[0028] 1. By injecting hydrogen foam into depleted oil reservoirs, the low viscosity and low density characteristics of gaseous hydrogen are improved, the problem of effective utilization of upper residual crude oil caused by gravity differentiation in conventional water injection development is solved, and the hydrogen capture efficiency in porous media is improved to achieve high-density and safe long-term hydrogen storage.

[0029] 2. Residual crude oil has a negative impact on the stability of hydrogen foam. The pre-placement of carbon dioxide foam plugs can effectively avoid the defoaming phenomenon of hydrogen foam when it enters the formation.

[0030] Further advantages are: by optimizing the injection and production process parameters such as foaming agent concentration, gas-liquid ratio, injection flow rate, pressure, etc., the recovery rate, geological hydrogen storage capacity and safety of depleted oil reservoirs can be significantly improved. BRIEF DESCRIPTION OF THE DRAWINGS

[0031] The accompanying drawings herein are used to provide a further understanding of the present invention and constitute a part of the present application. The exemplary embodiments of the present invention and their descriptions are used to understand the present invention and do not constitute improper limitations of the present invention. In the accompanying drawings:

[0032] Figure 1 This is a flow chart of the integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs proposed by the present invention;

[0033] Figure 2 It is a schematic diagram of the integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs;

[0034] Figure 3 It is the well pattern layout diagram of the integration of hydrogen foam flooding and geological hydrogen storage;

[0035] Figure 4 It is the crude oil recovery factor diagram of the integration of hydrogen foam flooding and geological hydrogen storage;

[0036] Figure 5 It is a hydrogen storage efficiency diagram of the integration of hydrogen foam flooding and geological hydrogen storage.

[0037] Figure numerals: 1-injection well; 2-production well; 3-hydrogen foam; 4-carbon dioxide foam segment plug; 5-residual crude oil; 6-temperature and pressure monitoring device; 7-electric heater; 8-ultrasonic defoaming device; 9-hydrogen sensor. DETAILED DESCRIPTION

[0038] In order to make the purpose, features and advantages of the present invention more obvious and easy to understand, the technical scheme of the present invention is clearly and completely described below in conjunction with the accompanying drawings in the embodiments of the present invention. Obviously, the present invention is not limited to the following embodiments, and the specific implementation method can be determined according to the technical scheme of the present invention and the actual situation. In order to avoid confusing the essence of the present invention, the known methods, processes, procedures, components and circuits are not described in detail.

[0039] Figure 1 The flow chart of the integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs proposed by the present invention is shown; Figure 2 The schematic diagram of the integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs proposed by the present invention is shown. Figure 1 and Figure 2 As shown, the present invention proposes an integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs, which injects carbon dioxide foam slugs 4 and hydrogen foam 3 into the depleted oil reservoir to displace residual crude oil 5 to the vicinity of the production well 2 and produce it, then continues to inject hydrogen foam 3 to complete the geological hydrogen storage process, and finally uses in-situ physical defoaming to recover hydrogen and utilize it.

[0040] The integrated method of hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs specifically includes:

[0041] Step 1: Setting up the oil recovery and geological hydrogen storage injection and production system:

[0042] Investigate the geological exploration data and drilling data of the depleted oil reservoirs in the target area, obtain the geological structure parameters of the reservoirs, determine the depleted oil reservoirs in the target area, and then, based on the geological structure parameters and injection and production process parameters (such as foaming agent concentration, gas-liquid ratio, injection flow rate, injection pressure, and the maximum bearing pressure P of the reservoir), max The injection and production system for oil recovery and geological hydrogen storage is set up with an inverted seven-point well pattern. All injection wells 1 and production wells 2 are equipped with temperature and pressure monitoring devices 6 to monitor the pressure and temperature values ​​inside the oil reservoir in real time. Electric heaters 7, ultrasonic defoaming devices 8 and hydrogen sensors 9 are also set downhole in all injection wells 1 and production wells 2. The electric heater 7 is used to increase the temperature of the hydrogen storage layer to eliminate foam. The ultrasonic defoaming device 8 is used to emit ultrasonic waves to the hydrogen storage layer, and use the destructive characteristics of ultrasonic high-frequency vibration to further break the foam and rupture the remaining foam. The hydrogen sensor 9 is used to detect the concentration of hydrogen in real time to determine the defoaming situation.

[0043] The geological structural parameters of the oil reservoir include the structural morphology and closure conditions of the oil reservoir, the volume of gas storage space, reservoir parameters (porosity, permeability, continuity and stability of the reservoir), fluid distribution and properties, and pressure and temperature distribution of the oil reservoir.

[0044] The reverse seven-spot well pattern adopts a regular hexagonal well pattern arrangement of one injection and six production. Figure 3The diagram shows the layout of the well pattern for the integration of hydrogen foam flooding and geological hydrogen storage. The reverse seven-point well pattern includes at least one well group, each of which includes an injection well 1 located at the center of a regular hexagon and production wells 2 located at the six vertices of the regular hexagon. The reverse seven-point well pattern layout helps to achieve a more uniform injection of hydrogen foam 3. Since the production wells 2 are distributed around the injection well 1, the injected hydrogen foam 3 can penetrate more evenly into the depleted oil reservoir, reducing the loss and unevenness during the injection of hydrogen foam 3 and improving the injection efficiency.

[0045] Preferably, the reverse seven-spot well pattern adopts vertical wells, and the well spacing in the well group is greater than 30m and less than 50m. The well spacing within this range can ensure uniform injection of hydrogen foam 3 in the depleted oil reservoir, ensure the mining effect while reducing the number of drilling, thereby reducing drilling costs.

[0046] Preferably, the temperature and pressure monitoring device 6 uses an optical fiber temperature and pressure sensor to achieve high-precision and long-term stable monitoring of the interior of the depleted oil reservoir.

[0047] Step 2: Foam flooding stage:

[0048] Since residual crude oil 5 tends to reduce the stability of hydrogen foam 3. In order to alleviate this challenge, a layer of viscous foam is required to be placed in advance and enter the formation before injecting hydrogen foam 3. The pre-placed carbon dioxide foam segment plug 4 isolates hydrogen foam 3 from residual crude oil 5, minimizes contact with residual crude oil 5, and effectively avoids defoaming of hydrogen foam 3 during its entry into the formation. The foaming agent used to prepare carbon dioxide foam uses sodium α-olefin sulfonate (AOS) as a foaming agent to provide the ability to foam and stabilize the foam; modified polyethoxylated silicone (MPS) is used as a foam stabilizer to enhance the stability of the foam and its compatibility with the formation.

[0049] Preferably, the raw materials of the foaming agent used to prepare the carbon dioxide foam are mixed in the following proportions by weight: 20 to 70 parts of sodium α-olefin sulfonate, 10 to 50 parts of modified polyethoxylated silicone, and 10 to 70 parts of water.

[0050] Preferably, the concentration of sodium α-olefin sulfonate in the foaming agent used to prepare carbon dioxide foam is controlled between 0.3% and 0.5%, and the optimal gas-liquid ratio of carbon dioxide foam is controlled at 2:1 or 3:1.

[0051] Compared with the prior art, the above measures have the following advantages: the carbon dioxide foam prepared by the method proposed in the present invention not only has good foaming properties and high stability, but also has excellent hard water resistance, biodegradability and environmental protection. At the same time, the addition of modified polyethoxylated silicone (MPS) further improves the stability and oil recovery efficiency of the foam, and reduces the oil recovery cost.

[0052] The low viscosity of gaseous hydrogen will lead to low displacement efficiency and premature breakthrough of production well 2, resulting in low oil displacement efficiency and poor hydrogen storage capacity. The injection of hydrogen foam 3 reduces gas mobility and makes the displacement effect of residual crude oil 5 to production well 2 better. The foaming agent used to prepare hydrogen foam 3 uses sodium dodecyl sulfate (SDS) as a hydrogen foam foaming agent. The amphiphilic sodium dodecyl sulfate (SDS) surfactant greatly promotes the adsorption of hydrogen through its hydrophobic tail; PEG grafted polymer is used as a foam stabilizer to enhance the stability of the foam; nanoparticles or inorganic salts are used as hydrogen foam regulators to adjust the viscosity, density and stability of the foam. Nanoparticles use nanosilica; inorganic salts use sodium chloride or calcium chloride; water is used as a solvent for hydrogen foam.

[0053] Preferably, the concentration of sodium dodecyl sulfate in the foaming agent used to prepare hydrogen foam is between 0.5% and 2%, depending on the stability and fluidity of the desired foam, the concentration of PEG grafted polymer is between 0.01% and 0.5%, and the gas-liquid ratio of the hydrogen foam is controlled between 2:1 and 5:1.

[0054] Preferably, the purity of hydrogen used to prepare hydrogen foam is not less than 99% to achieve optimal storage effect and safety.

[0055] Compared with the prior art, the above measures have the following advantages: the stability of hydrogen foam 3 is much better than that of carbon dioxide foam, because the permeation channels generated by the aggregation of surfactants allow the carbon dioxide in the water phase to dissolve. The hydrogen foam 3 maintains a uniform surfactant film to prevent hydrogen from entering the water.

[0056] The two types of foam are injected into the oil reservoir in sequence. First, the prepared carbon dioxide foam is continuously injected into the oil reservoir through injection well 1. When the injection amount of carbon dioxide foam reaches one-third of the volume of the oil reservoir, the injection of carbon dioxide foam is stopped. Subsequently, hydrogen foam 3 is injected into the oil reservoir through injection well 1. During the injection process, the temperature and pressure monitoring device 6 of each well should be used to monitor the pressure and temperature inside the oil reservoir in real time. Figure 2 As shown, the carbon dioxide foam injected into the well forms a carbon dioxide foam segment plug 4, and the carbon dioxide foam segment plug 4 and the hydrogen foam 3 are sequentially advanced toward the production well 2 in the oil reservoir, displacing the residual crude oil 5 in the depleted oil reservoir to the vicinity of the production well 2 and produced until all the residual crude oil 5 is produced.

[0057] Preferably, when injecting foam, the injection pressure of the injection well 1 is set to 10.8MPa~20MPa, and the injection flow rate is set to 8m 3 / day~16m 3 / day. The injection rate of the foam can be adjusted to maintain a stable change in gas pressure, and the reservoir temperature cannot be higher than 100°C. Inappropriate pressure and temperature values ​​may affect the stability of hydrogen foam 3 and cause the foam to burst. In addition, hydrogen is flammable and explosive, and excessively high temperature values ​​may affect the efficiency and safety of hydrogen storage.

[0058] Preferably, the front carbon dioxide foam plug 4 is mainly used to displace oil and reduce the contact between the residual crude oil 5 and the hydrogen foam 3. The hydrogen foam 3 mainly occupies most of the space in the depleted oil reservoir to complete geological hydrogen storage.

[0059] Preferably, after the foam flooding is completed, the injection well 1 is closed for three to five days to allow the foam to fully diffuse in the reservoir and flood the oil.

[0060] Compared with the prior art, the above measures have the following advantages: continuous injection of carbon dioxide foam can ensure the continuous distribution and plugging effect of the foam in the oil reservoir, and the hydrogen foam 3 is injected alternately, that is, according to the above gas-liquid ratio and injection amount, the foaming agent for preparing hydrogen foam 3 (the foaming agent for preparing hydrogen foam 3 is a mixture of foaming agent, foam stabilizer, regulator and solvent) is first injected into the oil reservoir, and then the hydrogen for preparing hydrogen foam 3 is injected to form a complete injection cycle, and then the process is repeated. In this way, the injection pressure can be reduced, and the swept volume and plugging effect of the foam can be increased. This method combines the advantages of carbon dioxide foam flooding and hydrogen foam 3 flooding, and can make up for the shortcomings of each when used alone. Carbon dioxide foam flooding mainly utilizes the sand carrying capacity of the foam and the displacement effect on the residual crude oil 5. The foam can carry sand particles into the formation fractures and increase the permeability of the formation; at the same time, the carbon dioxide in the foam can dissolve in the residual crude oil 5, reduce the viscosity of the residual crude oil 5, and improve the fluidity of the residual crude oil 5, thereby achieving the purpose of flooding. The pre-placed carbon dioxide foam segment plug 4 greatly reduces the negative impact of residual crude oil 5 on the stability of hydrogen foam 3, and effectively avoids the defoaming phenomenon of hydrogen foam 3 when entering the formation. Hydrogen foam 3 can enter the high-permeability formation of the reservoir and gradually complete the plugging of the high-permeability layer by using its Jamin effect. With the continuous injection of foam, the foam under high pressure will enter the small pores and advance evenly therein. The plugging effect of the foam can adjust the water absorption profile of the injection well 1 and improve the oil recovery efficiency of the reservoir.

[0061] Step 3: Hydrogen storage stage:

[0062] When all the residual crude oil 5 in the reservoir is mined, the hydrogen storage stage begins. The injection pressure and injection rate are maintained unchanged, and the hydrogen foam 3 is continuously injected through the injection well 1, so that the carbon dioxide foam is displaced to the vicinity of the production well 2 and mined until there is no carbon dioxide foam in the reservoir. When the injected hydrogen foam 3 reaches the preset hydrogen storage volume or the pressure value inside the reservoir reaches the maximum bearing pressure of the reservoir, the injection well 1 and the production well 2 are closed, and the injection of hydrogen foam 3 is stopped.

[0063] Preferably, geological hydrogen storage involves high-pressure, flammable and explosive hydrogen, so safety is the primary consideration. The temperature and pressure values ​​in the reservoir are monitored in real time by the temperature and pressure monitoring device 6 .

[0064] Preferably, the injection temperature when injecting the hydrogen foam 3 is generally at room temperature, and the injection temperature will affect the density, compressibility and storage efficiency of hydrogen.

[0065] Compared with the existing technology, the above measures have the following advantages: by injecting hydrogen foam 3 into the depleted oil reservoir, the low viscosity and low density characteristics of gaseous hydrogen are improved, the problem of effective utilization of upper residual crude oil 5 caused by gravity separation in conventional water injection development is solved, and the hydrogen capture efficiency in porous media is improved, so that high-density and safe long-term hydrogen storage can be achieved. Experiments show that compared with the injection of pure hydrogen, the injection of hydrogen foam 3 increases the hydrogen storage rate by more than two times, see Figure 5 .

[0066] Step 4: Hydrogen foam in-situ physical defoaming stage:

[0067] How to achieve efficient recovery of hydrogen foam 3 in depleted oil reservoirs is an important part of hydrogen storage technology. Considering the reuse of hydrogen stored in depleted oil reservoirs and environmental protection, in-situ physical defoaming technology is given priority. The present invention combines in-situ temperature variable defoaming method and ultrasonic defoaming method to enhance the defoaming effect.

[0068] Initial defoaming: First, use the in-situ variable temperature defoaming method to change the stability of the foam by adjusting the temperature of the hydrogen storage layer. This step can eliminate some of the foam with low stability and lay the foundation for subsequent defoaming. Turn on the electric heater 7 to increase the temperature of the hydrogen storage layer, reduce the viscosity of the liquid by increasing the temperature, and enhance the evaporation of the solvent, causing the foam to burst, thereby achieving the purpose of defoaming. However, the temperature change in the hydrogen storage layer cannot be too large to prevent excessively high or low temperatures from damaging the hydrogen storage layer and causing changes in other properties of the hydrogen storage system.

[0069] Deep defoaming: When the temperature in the hydrogen storage layer reaches between 110℃ and 120℃, the temperature is maintained unchanged. On the basis of in-situ variable temperature defoaming, ultrasonic defoaming method is introduced. Ultrasonic defoaming device 8 is placed in injection well 1 and production well 2 to emit ultrasonic waves to the hydrogen storage layer to defoam. The ultrasonic defoaming method uses the destructive characteristics of ultrasonic high-frequency vibration to promote further collapse of the foam and break the remaining foam. The ultrasonic vibration generated by the ultrasonic defoaming device 8 can act on the inside of the foam and destroy its structural stability. This step ensures a more thorough defoaming effect.

[0070] Preferably, during the use of the two defoaming methods, the pressure and temperature of the hydrogen storage layer need to be closely monitored to ensure the safety and stability of the system. At the same time, the parameters of the in-situ variable temperature defoaming and ultrasonic defoaming are adjusted in time according to the defoaming effect to achieve the best defoaming effect. The defoaming of the foam is observed in real time using the hydrogen sensor 9. If the defoaming effect is not good, the heating temperature or the heating rate can be increased by the electric heater 7, and you can also try to increase the ultrasonic intensity, increase the ultrasonic frequency or extend the action time.

[0071] Compared with the prior art, the above measures have the following advantages: Since the foam fluid has a serious Jamin effect in the porous medium and the flow resistance is extremely large, the in-situ variable temperature defoaming method is an important way to recover hydrogen at low cost and high efficiency. In addition, the in-situ variable temperature defoaming method can also maintain the stability of the geological structure and the process complexity is low. The in-situ variable temperature defoaming method and the ultrasonic defoaming method are used in geological hydrogen storage to enhance the defoaming effect. By reasonably matching these two methods, their advantages can be fully utilized to achieve a better defoaming effect. Under the condition of 110℃~120℃, the in-situ variable temperature defoaming method can quickly change the stability of the foam and make it break; it can also be applied to various types of foams without being restricted by the composition and properties of the foam; the equipment cost and maintenance cost of the in-situ variable temperature defoaming method are low. The ultrasonic defoaming device 8 will not directly damage the hydrogen storage layer and has high safety; at the same time, the ultrasonic wave has strong penetration and can effectively act on the inside of the foam to destroy its stability, and the defoaming effect is good; in addition, although the ultrasonic defoaming device 8 has a high cost, it has a long service life and low maintenance costs, and it also has certain advantages in terms of economy.

[0072] When recovering hydrogen, it is necessary to purify the hydrogen. The present invention uses pressure swing adsorption (PSA) to purify the hydrogen. The method utilizes the different selective adsorption capacities of different gases on adsorbents at different pressures, and performs adsorption and desorption through periodic changes in pressure, thereby achieving gas separation and purification. The raw gas extracted from the production well 2 is pretreated (such as dust removal, oil removal, dehydration, etc.). The pretreated hydrogen is then injected into an adsorption tower, which is equipped with an adsorbent (such as activated carbon, zeolite molecular sieve, etc.), and impurities (such as nitrogen, carbon monoxide, carbon dioxide, etc.) in the raw gas are selectively adsorbed by the adsorbent, while hydrogen flows out through the adsorption bed to become a preliminarily purified product hydrogen. Subsequently, the process of decompression, desorption, flushing, and pressure increase is repeated to further reduce the content of impurities in the hydrogen. Finally, the purified hydrogen is collected and stored in a hydrogen storage tank after drying and dust removal for subsequent use.

[0073] Preferably, in the entire process, various operating parameters such as pressure, temperature, flow rate, etc. need to be strictly controlled to ensure purification efficiency and product quality. Controlling the adsorption pressure between 0.1MPa~0.5MPa, the temperature between 150℃~200℃, and the hydrogen flow rate between 10mL / min~50mL / min can achieve better hydrogen production effect.

[0074] Preferably, the pressure swing adsorption purification device is usually designed to have multiple adsorption towers operating in parallel to achieve continuous production and improve equipment utilization.

[0075] Compared with the existing technology, the above measures have the following advantages: PSA technology is easy to operate, has less equipment investment, low energy consumption, is not demanding on impurities in the raw gas (generally no pretreatment is required), has high product purity (up to 99.99% or more), and is easy to automate and control. It is particularly suitable for small and medium-scale production and for situations where high-purity hydrogen needs to be recovered from gas mixtures.

[0076] It should be noted that the temperature and pressure monitoring device 6, the electric heater 7, the ultrasonic defoaming device 8 and the hydrogen sensor 9 in the present invention are all commercially available products. Example

[0077] This example selects the depleted oil reservoir in Songliao Basin, China as the research object. The test area is the structural high point of the depleted oil reservoir, with a permeability of 800mD and a porosity of 14%~25%, which is a reservoir with moderate permeability, high porosity and good geological stability. According to the geological and production data of the target depleted oil reservoir, the physical parameters of the reservoir are obtained, including the original geological reserves, gas storage space volume, reservoir continuity and stability, depleted formation temperature and pressure, oil saturation and water saturation, formation water intrusion under depletion state, cumulative oil production, cumulative water production and gas composition.

[0078] The first step is to select the area with a permeability of 800mD and a porosity of 14% to 25% inside the reservoir for well pattern layout according to the geological structure of the depleted oil reservoir. The first inverted seven-point well pattern is arranged according to the location of injection well 1. The stratum burial depth of the depleted oil reservoir is 100m, and the well spacing is 40m. Figure 3 shown.

[0079] In the second step, the carbon dioxide foam and hydrogen foam 3 prepared by the above method are injected into the reservoir in sequence. The carbon dioxide foam segment 4 is placed in front to reduce the negative impact of the residual crude oil 5 on the hydrogen foam 3. The hydrogen foam 3 enters the high permeability layer of the reservoir and gradually completes the plugging of the high permeability layer by using its Jamin effect. When injecting the foam, the injection pressure of the injection well 1 is set to 10.8MPa~20MPa, and the injection flow rate is set to 8m 3 / day~16m 3 / day. During the injection process, the temperature and temperature inside the reservoir should be monitored in real time using the temperature and pressure monitoring devices 6 of each well. The injection rate of the foam is adjusted to maintain a stable change in gas pressure. When the formation pressure rises too fast, the injection rate is reduced in time to slow down the pressure rise; when the formation pressure is stable or slightly decreased, the injection rate is appropriately increased to maintain or improve oil displacement and hydrogen storage efficiency. The temperature in the reservoir should not be too high.

[0080] In the third step, when the residual crude oil 5 is extracted, the injection well 1 is closed for three to five days to allow the foam to fully diffuse and drive oil in the reservoir. After the well is closed, hydrogen foam 3 is continuously injected into the injection well 1 for hydrogen storage. The injection temperature is generally at room temperature, and the injection temperature affects the density, compressibility and storage efficiency of hydrogen.

[0081] The fourth step is to combine the in-situ temperature-variable defoaming method and the ultrasonic defoaming method to complete the in-situ physical defoaming of hydrogen foam and hydrogen recovery. First, the temperature of the hydrogen storage layer is increased by the electric heater 7, and the liquid viscosity is reduced by the temperature increase, and the solvent evaporation is enhanced, resulting in the foam bursting, thereby achieving the purpose of defoaming. Subsequently, the ultrasonic defoaming device 8 emits ultrasonic waves to the hydrogen storage layer, and the destructive characteristics of high-frequency acoustic vibration are used to promote the further collapse of the foam, so that the remaining foam is broken.

[0082] The fifth step is to purify the recovered hydrogen using pressure swing adsorption (PSA). Different gases have different selective adsorption capacities on adsorbents at different pressures, and adsorption and desorption are carried out through periodic changes in pressure, thereby achieving gas separation and purification. First, the hydrogen extracted from the hydrogen storage layer is pretreated, such as dust removal, oil removal, and dehydration. Then, pressure swing adsorption is used to purify the hydrogen. Finally, the adsorbent is restored to its adsorption capacity by reducing pressure, evacuating or flushing.

[0083] In summary, the method adopted by the present invention significantly improves the crude oil recovery rate in the oil displacement process and the hydrogen storage efficiency in the hydrogen storage process. Figure 4 The crude oil recovery rate diagram of hydrogen foam flooding and geological hydrogen storage integration is shown. Figure 5 The diagram of hydrogen storage efficiency of integrated hydrogen foam flooding and geological hydrogen storage is shown. The results show that the oil recovery rate can reach 50% by using the pre-placed carbon dioxide foam segment 4 and hydrogen foam 3 to flood the depleted oil reservoir, while the recovery rate by using pure hydrogen is only 35%, an increase of 15%. The hydrogen storage efficiency of injecting hydrogen foam 3 in this depleted oil reservoir can reach 42%, which is three times that of injecting pure hydrogen.

[0084] Obviously, the above embodiments of the present invention are only examples for clearly explaining the present invention, and are not intended to limit the implementation methods of the present invention, and the present invention is not limited to the above examples. For ordinary technicians in the relevant field, other different forms of changes or modifications can be made based on the above description. It is impossible to list all the implementation methods here. All obvious changes or modifications derived from the technical solution of the present invention are still within the scope of protection of the present invention.

Claims

1. A method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs, characterized in that: The method comprises the following steps: Step 1: Setting up the oil recovery and geological hydrogen storage injection and production system: Depleted oil reservoirs in the target area are identified, and an injection-production system for oil recovery and geological hydrogen storage is set up based on the geological structure parameters and injection-production process parameters of the oil reservoirs. An inverted seven-point well network is adopted, and temperature and pressure monitoring devices, electric heaters, ultrasonic defoaming devices, and hydrogen sensors are deployed in all injection wells and production wells of the inverted seven-point well network; Step 2: Foam flooding stage: First, carbon dioxide foam is continuously injected into the injection well as a pre-segment plug. When the injection volume of carbon dioxide foam reaches the preset injection volume, the injection of carbon dioxide foam is stopped. Subsequently, hydrogen foam is injected into the injection well. During the injection process, the pressure and temperature inside the reservoir are monitored in real time through a temperature and pressure monitoring device. The carbon dioxide foam and hydrogen foam injected into the formation are pushed forward in sequence to displace the residual crude oil in the reservoir to the vicinity of the production well and produced until the crude oil production of the production well drops to zero. Among them, sodium α-olefin sulfonate is selected as a foaming agent for carbon dioxide foam, modified polyethoxylated silicone is selected as a foam stabilizer for carbon dioxide foam, and water is selected as a solvent and diluent for carbon dioxide foam; Among them, sodium dodecyl sulfate is selected as the foaming agent of hydrogen foam, PEG grafted polymer is selected as the foam stabilizer of hydrogen foam, nanoparticles or inorganic salts are selected as the regulator of hydrogen foam, and water is selected as the solvent of hydrogen foam; Step 3: Hydrogen storage stage: When the residual crude oil in the reservoir is mined, the injection well is closed for three to five days for well soaking. After the well soaking is completed, hydrogen foam is continuously injected into the injection well for hydrogen storage. The hydrogen foam occupies all hydrogen storage space and displaces the residual carbon dioxide foam, so that the carbon dioxide foam is displaced to the vicinity of the production well and mined. When the injected hydrogen foam reaches the preset hydrogen storage volume or the pressure value inside the reservoir reaches the maximum bearing pressure of the reservoir, the injection well and the production well are closed, and the injection of hydrogen foam is stopped. Step 4: Hydrogen foam in-situ physical defoaming stage: Start the electric heater to increase the temperature of the hydrogen storage layer, and use the in-situ variable temperature defoaming method to perform preliminary defoaming. When the temperature in the hydrogen storage layer reaches the preset value, maintain the preset value unchanged, start the ultrasonic defoaming device, and use the ultrasonic defoaming method to perform deep defoaming. During the defoaming process, use a hydrogen sensor to detect the concentration of hydrogen in real time to determine the defoaming situation and recover the hydrogen. At this point, hydrogen foam oil recovery and geological hydrogen storage are completed.

2. The method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: It also includes the hydrogen purification stage: The recovered hydrogen is purified by pressure swing adsorption, the adsorption pressure is controlled between 0.1MPa and 0.5MPa, the temperature is controlled between 150℃ and 200℃, and the hydrogen flow rate is controlled between 10mL / min and 50mL / min; the purified hydrogen is collected and stored in a hydrogen storage tank after drying and dust removal.

3. The method of integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: The inverted seven-point well network includes at least one well group, each well group includes an injection well located at the center of a regular hexagon and production wells located at six vertices of the regular hexagon, and the distance between wells in each well group is greater than 30m and less than 50m.

4. The method of integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: The raw materials of the foaming agent used for preparing carbon dioxide foam are mixed in the following proportions by weight: 20 to 70 parts of sodium α-olefin sulfonate, 10 to 50 parts of modified polyethoxylated silicone and 10 to 70 parts of water.

5. The method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: The concentration of sodium α-olefin sulfonate in the foaming agent used to prepare carbon dioxide foam is controlled between 0.3% and 0.5%, and the optimal gas-liquid ratio of carbon dioxide foam is controlled at 2:1 or 3:

1.

6. The method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: The concentration of sodium dodecyl sulfate in the foaming agent used to prepare hydrogen foam is between 0.5% and 2%, the concentration of PEG grafted polymer is between 0.01% and 0.5%, and the gas-liquid ratio of the hydrogen foam is controlled between 2:1 and 5:

1.

7. The method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: The nanometer particles in the regulator are nanometer silicon dioxide, and the inorganic salt is sodium chloride or calcium chloride.

8. The method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: When injecting foam, the injection pressure of the injection well is set to 10.8MPa~20MPa, and the injection flow rate is set to 8m 3 / day~16m 3 / day.

9. The method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: When injecting hydrogen foam, the injection temperature is room temperature. The foaming agent used to prepare hydrogen foam is first injected into the oil reservoir, and then the hydrogen used to prepare hydrogen foam is injected, forming a complete injection cycle.

10. The method for integrating hydrogen foam flooding and geological hydrogen storage for depleted oil reservoirs according to claim 1, characterized in that: In step 4, the preset value ranges from 110°C to 120°C.

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