Method for realizing CO2 storage and H2 injection and production by utilizing shale gas well

Abstract

The invention relates to the technical field of oil and gas field development, in particular to a method for realizing CO2 storage and H2 injection and production by utilizing a shale gas well, which comprises the following steps: acquiring geological and development data of a target shale gas well reservoir, and selecting the shale gas well suitable for CO2 storage and H2 storage as a pre-selected well; cO2 is injected into the pre-selected well to conduct fracturing transformation in the mode that the pressure is higher than the reservoir fracture pressure, and the shale gas well is soaked; shale gas production is conducted, and after shale gas production is stopped, CO2 is injected again for geological storage; h2 is injected into the pre-selected well in the mode that the pressure is not higher than the reservoir fracture pressure, and when the hydrogen storage amount reaches the preset hydrogen storage amount or the internal pressure value of the gas reservoir reaches the safety upper limit, H2 injection is stopped; and when H2 needs to be used, hydrogen is extracted for the same shale gas well, and high-purity hydrogen is obtained. According to the method, the shale gas recovery efficiency is improved by injecting CO2 into the shale gas well, and CO2 storage is achieved to the maximum extent while conversion from the shale gas reservoir to the hydrogen reservoir is achieved.

Description

Technical Field

[0001] The present invention relates to the technical field of oilfield development, and in particular to a method for realizing CO2 storage and H2 injection and production by utilizing shale gas wells. Background Art

[0002] Shale gas is a highly promising oil and gas resource and is considered an important replacement resource for conventional oil and gas. Due to the special geological characteristics and mining conditions of shale gas, there are a series of challenges and problems in its mining process. Traditional shale gas development methods mainly rely on horizontal drilling and hydraulic fracturing technology. Although certain development results have been achieved, there are still problems such as water-sensitive reservoir damage, low drainage rate, rapid production decline and low recovery rate. At the same time, with the increasing severity of global greenhouse gas emissions and climate change, it is becoming increasingly important to reduce carbon dioxide emissions and find safe and efficient methods for carbon dioxide storage.

[0003] In the field of natural gas development, unconventional natural gas, especially shale gas, has seen significant production increases and is the main force in increasing natural gas reserves and production. The development of large-scale shale gas wells is on the agenda. The replacement characteristics of CO2 can be used to improve the recovery rate of shale gas. At the same time, shale is a common cap rock type for CO2 storage, and injecting CO2 underground can also achieve on-site storage of CO2. The CO2 fracturing-displacement-replacement-storage integrated technology for shale gas reservoirs based on CO2 fracturing is known as a new generation of waterless fracturing technology. It can form a complex fracture network, absorb and replace methane, and achieve on-site storage of CO2, and has broad application prospects.

[0004] On the other hand, with the improvement of the status of hydrogen energy and the development of hydrogen production technology, the importance of large-scale hydrogen storage technology has become increasingly prominent. At present, the basic method of hydrogen storage is ground storage, including high-pressure gaseous hydrogen storage, low-temperature liquid hydrogen storage, solid hydrogen storage, etc. There are problems such as high gas storage cost, small hydrogen storage capacity, and difficulty in sealing hydrogen storage containers. From a geological point of view, underground space is suitable for storing hydrogen, especially depleted gas reservoir-type hydrogen storage, which is widely distributed and has large storage space. It has been fully explored and developed, with complete geological information, and surface and underground facilities can be reused. It can reduce initial geological exploration and infrastructure investment, and is considered to be the most promising underground hydrogen storage geological structure. In the construction of depleted gas reservoir-type hydrogen storage wells, it is often necessary to inject a certain amount of cushion gas, such as N2, CO2, CH4, etc., into the underground to isolate the water layer and maintain the formation pressure. Summary of the invention

[0005] The purpose of the present invention is to provide a method for CO2 storage and H2 injection and production using shale gas wells, so as to improve the shale gas recovery rate and realize the geological storage of CO2, while solving the technical problems in the prior art such as high hydrogen storage cost, small hydrogen storage capacity, and difficulty in sealing hydrogen storage containers.

[0006] The embodiments of the present invention are implemented by the following technical solutions:

[0007] The present invention provides a method for realizing CO2 storage and H2 injection and production by using shale gas wells, which comprises the following steps:

[0008] S1. Shale gas well geological assessment stage: obtain the geological and development data of the target shale gas well reservoir, and select shale gas wells suitable for CO2 storage and H2 storage as pre-selected wells;

[0009] S2, shale gas well fracturing stage: inject CO2 into the pre-selected wells at a pressure higher than the reservoir fracture pressure for fracturing and shut down the shale gas wells;

[0010] S3, shale gas well production stage: shale gas production, and after shale gas production stops, CO2 is injected for geological storage;

[0011] S4, hydrogen injection stage: inject H2 into the pre-selected well in a manner not higher than the reservoir fracture pressure. When the hydrogen storage reaches the preset hydrogen storage or the internal pressure of the gas reservoir reaches the safety upper limit, stop injecting H2;

[0012] S5. Hydrogen extraction stage: When H2 is needed, hydrogen is extracted from the same shale gas well to obtain high-purity hydrogen.

[0013] Furthermore, the wellbore trajectory of the preselected well in S1 should be consistent with the minimum horizontal ground stress in the reservoir; the gas saturation is higher than 50%; the distance between the selected fracturing well section and the fault is greater than 1.3 km; the calcite content in the rock minerals is less than 10%, the pyrite content is less than 1%; the content of methanogenic archaea in the formation water is less than 1×10 -4 g / L; reservoir temperature is not higher than 90℃.

[0014] Furthermore, in S2, supercritical CO2 fracturing fluid and low-density proppant are used to form a fracture grid.

[0015] Furthermore, the low-density proppant in S2 includes: 40% to 50% low-density ceramsite, 30% to 60% quartz sand, and 10% to 30% 3A molecular sieve material.

[0016] Furthermore, the S3 further includes the following sub-steps:

[0017] S31, producing shale gas and monitoring the shale gas production in the wellbore;

[0018] S32, when the cumulative gas production reaches the maximum, stop the shale gas production;

[0019] S33. Inject CO2 into the wellbore at a pressure not exceeding the reservoir fracture pressure for geological storage.

[0020] Furthermore, the maximum cumulative gas production of shale gas in S32 is calculated by the following formula:

[0021] P a =0.3515+0.0010713×D

[0022]

[0023] Among them, P a is the abandoned pressure of the gas reservoir; D is the well depth; G C is the controlled reserves of shale gas wells; A is the transformed area; H is the average effective thickness; is the average effective porosity; S g is the average gas saturation; P i is the original formation pressure; T sc is the standard temperature; P sc is the standard pressure; T i is the original formation temperature; Z i is the gas deviation coefficient under the original formation pressure; ρ is the rock density; C x G is the adsorbed gas content per unit mass of shale; e is the maximum cumulative gas production; Z a is the gas deviation coefficient at the abandoned formation pressure.

[0024] Furthermore, the amount of CO2 injected in S33 is 40-60% of the hydrogen storage reservoir capacity;

[0025] The storage capacity of the hydrogen storage tank is calculated by the following formula:

[0026] G K =G e -G H

[0027] Among them, G K is the storage capacity of the hydrogen storage tank; G e is the maximum cumulative gas production; G H is the injection volume of CO2 during the fracturing stage.

[0028] Furthermore, the safety upper limit pressure in S4 is calculated by the following formula:

[0029]

[0030] Among them, P i is the original formation pressure; P c is the uniaxial compressive strength, determined by rock mechanics tests; P h is the fault plane pressure when the fault closure coefficient is 1.

[0031] Furthermore, obtaining high-purity hydrogen in S5 includes the following sub-steps:

[0032] S51, discharge the hydrogen back to the surface through a pipeline;

[0033] S52. After the gas undergoes secondary separation by PSA, high-purity hydrogen is obtained.

[0034] The technical solution of the embodiment of the present invention has at least the following advantages and beneficial effects:

[0035] (1) During shale gas extraction, CO2 is injected at a pressure higher than the formation fracture pressure to perform fracturing, forming a complex fracture network that absorbs and replaces shale gas, achieving CO2 storage while maximizing shale gas output;

[0036] (2) Using supercritical CO2 fracturing fluid and low-density proppants to form a complex fracture network to store hydrogen. Adding 3A molecular sieve material to the low-density proppants can serve as both fracture proppants and subsequent hydrogen adsorbents, which is beneficial to the storage of hydrogen;

[0037] (3) CO2 can not only be used as fracturing fluid, but also as cushion gas for subsequent hydrogen storage. While realizing the transformation of shale gas reservoirs into hydrogen reservoirs, it can also achieve the maximum storage of CO2. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings required for use in the embodiments of the present invention are briefly introduced below. It should be understood that the following drawings only show certain embodiments of the present invention and therefore should not be regarded as limiting the scope. For ordinary technicians in this field, other related drawings can be obtained based on these drawings without creative work.

[0039] Figure 1 A flow chart for achieving CO2 storage and H2 injection and production in a shale gas well provided in Example 1 of the present invention. DETAILED DESCRIPTION

[0040] In order to make the purpose, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions in the embodiments of the present invention will be clearly and completely described below in conjunction with the drawings in the embodiments of the present invention. Obviously, the described embodiments are part of the embodiments of the present invention, not all of the embodiments. Generally, the components of the embodiments of the present invention described and shown in the drawings here can be arranged and designed in various different configurations.

[0041] It should be understood that the "system", "device", "unit" and / or "module" used herein are a method for distinguishing different components, elements, parts, portions or assemblies at different levels. However, if other words can achieve the same purpose, the words can be replaced by other expressions.

[0042] As shown in this specification and claims, unless the context clearly indicates an exception, the words "a", "an", "an" and / or "the" do not refer to the singular and may also include the plural. Generally speaking, the terms "comprise" and "include" only indicate the inclusion of the steps and elements that have been clearly identified, and these steps and elements do not constitute an exclusive list. The method or device may also include other steps or elements.

[0043] Flowcharts are used in this specification to illustrate the operations performed by the system according to the embodiments of this specification. It should be understood that the preceding or following operations are not necessarily performed precisely in order. Instead, the steps may be processed in reverse order or simultaneously. At the same time, other operations may also be added to these processes, or one or more operations may be removed from these processes.

[0044] The ultimate goal of the present invention is to utilize shale gas wells to inject CO2, thereby achieving the maximum geological storage of CO2 and improving the recovery rate of shale gas. At the same time, CO2 can also be used as a cushion gas for later hydrogen storage.

[0045] In view of this, an embodiment of the present invention provides a method for realizing CO2 storage and H2 injection and production by using shale gas wells. During shale gas production, CO2 is injected at a pressure higher than the formation fracture pressure for fracturing to form a complex fracture network, which adsorbs and replaces CH4, thereby realizing the storage of CO2 and maximizing the output of CH4. After the shale gas well is exhausted, H2 is stored in the fracture space formed by CO2 fracturing. During the hydrogen injection and production process, CO2 is first injected at a pressure not higher than the formation fracture pressure for geological storage. At the same time, CO2 can also inhibit the flow of formation water, maintain a certain pressure and volume in the hydrogen storage reservoir, and realize the injection and production of hydrogen and the storage of CO2.

[0046] Embodiment 1:

[0047] For details, please refer to Figure 1 As shown, an embodiment of the present invention provides a method for realizing CO2 storage and hydrogen injection and production by using shale gas horizontal wells:

[0048] Step 1, shale gas well geological assessment stage: obtain the geological and production data of the target shale gas well reservoir, and select shale gas wells suitable for CO2 storage and H2 storage as pre-selected wells.

[0049] For a shale gas well, the relevant parameters are: the wellbore trajectory in the reservoir is consistent with the minimum horizontal stress; the reservoir porosity is 4.87% and the reformed area is 35×10 4 m 2 The total thickness of the gas reservoir is 20m, and the adsorbed gas content of shale per unit mass is 2.02m 3 / t, rock density 2.6t / m 3 The original formation pressure is 34.7MPa, the gas reservoir depth is 3200m, the gas saturation is 66.2%, the gas reservoir temperature is 80.92℃, the fault is more than 2km away from the fracturing section, the fracturing does not connect the fault, the formation water does not contain methanogenic archaea, and the calcite content in the reservoir minerals is 5%. It is judged to be a shale gas well suitable for CO2 storage and H2 storage.

[0050] Step 2, shale gas well fracturing stage: inject CO2 into the pre-selected well at a pressure higher than the reservoir fracture pressure for fracturing transformation, and shut down the shale gas well;

[0051] Specifically, the CO2 fracturing method in step 2 is mainly supercritical CO2 fracturing fluid and low-density proppant, and the number of fracturing stages of shale gas horizontal wells is about 30. Under ideal conditions, all of them are transformed with CO2 fracturing fluid, and a single fracturing stage uses about 500m 3 , which is equivalent to about 15000m 3 , calculated based on an average sand ratio of 20%, inject 3000m of proppant 3 , of which low-density ceramsite is calculated as 40%, about 1200m 3 , quartz sand is calculated as 30%, about 900m 3 , 3A molecular sieve is calculated as 30%, about 900m 3 .

[0052] Specifically, in this embodiment, 70 / 140 mesh quartz sand is added first, and then 40 / 70 mesh ceramsite is added, and the 3A molecular sieve is evenly mixed in the quartz sand and the ceramsite.

[0053] Furthermore, in step 2, the well is kept shut down for 15 days in order to allow CO2 to compete with methane for adsorption and thus increase the shale gas recovery rate.

[0054] Step 3, shale gas well production stage: after the well is shut down, shale gas production is carried out, and the shale gas production in the wellbore is monitored at the same time. When the cumulative gas production reaches the maximum, the shale gas production is stopped, and then CO2 is injected into the wellbore at a pressure not higher than the reservoir fracture pressure for geological storage;

[0055] Specifically, the cumulative maximum gas production in step 3 is calculated by the following formula:

[0056] P a=0.3515+0.0010713×D

[0057]

[0058] Where D is the well depth, which is 3200m. The abandoned pressure of the gas reservoir P is calculated as a is 3.78MPa. A is the transformation area, which is 35×10 4 m 2 ; H is the average effective thickness, which is 42m; is the average effective porosity, which is 0.0487; S g is the average gas saturation, which is 0.662; P i is the original formation pressure, which is 34.7MPa; T sc is the standard temperature, 293.15K; P sc is the standard pressure, take 0.101MPa; T i is the original formation temperature, which is 354.07K; Z i is the gas deviation coefficient under the original formation pressure, which is approximately 1; ρ is the rock density, which is 2.6×10 3 kg / m 3 , C x The adsorbed gas content of shale per unit mass is 2.02×10 -3 m 3 / kg, and the controlled reserves of shale gas wells G are calculated. C 2.12×10 8 m 3 . Z a is the gas deviation coefficient under the abandoned formation pressure, which is approximately 1; the maximum cumulative gas production G e 1.89×10 8 m 3 .

[0059] Specifically, the amount of CO2 injected in step 3 is 50% of the capacity of the hydrogen storage reservoir, the purpose of which is to carry out geological storage of CO2 while maintaining reservoir pressure, preventing water intrusion, and maintaining the stability of the hydrogen storage reservoir.

[0060] Furthermore, the storage capacity of the hydrogen storage reservoir in step 3 is calculated by the following formula:

[0061] G K =G e -G H

[0062] Among them, G K is the storage capacity of the hydrogen storage tank; G e is the maximum cumulative gas production, which is 1.89×10 8 m 3; G H is the injection volume of CO2 during the fracturing stage, which is 15000m 3 The calculated geological storage capacity of CO2 can reach 0.94×10 8 m 3 The density of CO2 is about 1.98 kg / m 3 , converted into weight, the geological storage capacity of CO2 can reach 18×10 4 t.

[0063] Step 4, hydrogen injection phase: inject H2 into the wellbore in a manner not higher than the reservoir fracture pressure. When the hydrogen storage capacity reaches the preset hydrogen storage capacity or the internal pressure value of the gas reservoir reaches the safety upper limit, stop injecting H2.

[0064] Furthermore, the safety upper limit pressure in step 4 can be calculated by the following formula:

[0065]

[0066] Among them, P i is the original formation pressure, which is 34.7MPa; P c is the uniaxial compressive strength, which is 65.5MPa as determined by rock mechanics tests; P h The fault plane pressure when the fault closure coefficient is 1 is 36.6MPa. The minimum of the three is the original formation pressure of 34.7MPa, that is, during the hydrogen injection process, when the pressure returns to the original formation pressure of 34.7MPa, the hydrogen injection is stopped.

[0067] Step 5, hydrogen production stage: When hydrogen is needed, hydrogen is produced from the same shale gas well to obtain high-purity hydrogen.

[0068] Specifically, the step of obtaining high-purity hydrogen in step 5 is: the hydrogen is discharged back to the surface through a pipeline, the gas is subjected to secondary separation by PSA to obtain high-purity hydrogen, and the separated methane gas and CO2 gas can be used for dry reforming to produce hydrogen.

[0069] The basic concepts have been described above. Obviously, for those skilled in the art, the above detailed disclosure is only for example and does not constitute a limitation of this specification. Although not explicitly stated here, those skilled in the art may make various modifications, improvements and corrections to this specification. Such modifications, improvements and corrections are suggested in this specification, so such modifications, improvements and corrections still belong to the spirit and scope of the exemplary embodiments of this specification.

[0070] At the same time, this specification uses specific words to describe the embodiments of this specification. For example, "one embodiment", "an embodiment", and / or "some embodiments" refer to a certain feature, structure or characteristic related to at least one embodiment of this specification. Therefore, it should be emphasized and noted that "one embodiment" or "an embodiment" or "an alternative embodiment" mentioned twice or more in different positions in this specification does not necessarily refer to the same embodiment. In addition, certain features, structures or characteristics in one or more embodiments of this specification can be appropriately combined.

[0071] Similarly, it should be noted that in order to simplify the description disclosed in this specification and thus help understand one or more embodiments of the invention, in the above description of the embodiments of this specification, multiple features are sometimes combined into one embodiment, figure or description thereof. However, this disclosure method does not mean that the features required by the subject matter of this specification are more than the features mentioned in the claims. In fact, the features of the embodiments are less than all the features of the single embodiment disclosed above.

[0072] Finally, it should be understood that the embodiments described in this specification are only used to illustrate the principles of the embodiments of this specification. Other variations may also fall within the scope of this specification. Therefore, as an example and not a limitation, alternative configurations of the embodiments of this specification may be considered consistent with the teachings of this specification. Accordingly, the embodiments of this specification are not limited to the embodiments explicitly introduced and described in this specification.

Claims

1. A method of using shale gas wells to achieve CO 2 Storage and H 2 The method of injection, It is characterized in that The steps include: S1. Obtain the geological and development data of the target shale gas well reservoir and select the appropriate 2 Seal, H 2 The shale gas wells in storage are pre-selected wells; S2: Inject CO into the preselected well at a pressure higher than the reservoir fracture pressure. 2 Conduct fracturing transformation and shut down shale gas wells; S3: Produce shale gas and inject CO after shale gas production stops. 2 Geological storage; S4. Inject H2 into the preselected well at a pressure not exceeding the reservoir fracture pressure. 2 When the hydrogen storage capacity reaches the preset hydrogen storage capacity or the internal pressure of the gas reservoir reaches the upper limit of safety, stop injecting H 2 ; S5. When you need to use H 2 At the same time, hydrogen is produced from the same shale gas well to obtain high-purity hydrogen.

2. A method for realizing CO2 production by using shale gas wells as claimed in claim 1 2 Storage and H 2 The method of injection, It is characterized in that The wellbore trajectory of the preselected well in S1 should be consistent with the minimum horizontal stress orientation in the reservoir; the gas saturation is higher than 50%; the distance between the selected fracturing well section and the fault is greater than 1.3 km; the calcite content in the rock minerals is less than 10%, the pyrite content is less than 1%; the content of methanogenic archaea in the formation water is less than 1×10 -4 g / L; reservoir temperature is not higher than 90℃.

3. A method of using shale gas wells to achieve CO 2 Storage and H 2 The method of injection, It is characterized in that The S2 utilizes supercritical CO 2 The fracturing fluid and low-density proppant form the fracture network.

4. A method of using shale gas wells to achieve CO 2 Storage and H 2 The method of injection, It is characterized in that The low-density proppant comprises: 40% to 50% low-density ceramsite, 30% to 60% quartz sand, and 10% to 30% 3A molecular sieve material.

5. A method of using shale gas wells to achieve CO 2 Storage and H 2 The method of injection, It is characterized in that The S3 further comprises the following sub-steps: S31, producing shale gas and monitoring the shale gas production in the wellbore; S32, when the cumulative gas production reaches the maximum, stop the shale gas production; S33, inject CO into the wellbore at a pressure not exceeding the reservoir fracture pressure 2 Geological storage.

6. A method of using shale gas wells to achieve CO 2 Storage and H 2 The method of injection, It is characterized in that The maximum cumulative gas production of shale gas in S32 is calculated by the following formula: P a =0.3515+0.0010713×D Among them, P a is the abandoned pressure of the gas reservoir; D is the well depth; G C is the controlled reserves of shale gas wells; A is the transformed area; H is the average effective thickness; is the average effective porosity; S g is the average gas saturation; P i is the original formation pressure; T sc is the standard temperature; P sc is the standard pressure; T i is the original formation temperature; Z i is the gas deviation coefficient under the original formation pressure; ρ is the rock density; C x G is the adsorbed gas content per unit mass of shale; e is the maximum cumulative gas production; Z a is the gas deviation coefficient at the abandoned formation pressure.

7. A method of realizing CO2 production by using shale gas wells as claimed in claim 5. 2 Storage and H 2 The method of injection, It is characterized in that CO is injected into S33 2 The gas volume is 40-60% of the hydrogen storage capacity; The storage capacity of the hydrogen storage tank is calculated by the following formula: G K =G e -G H Among them, G K is the storage capacity of the hydrogen storage tank; G e is the maximum cumulative gas production; G H CO for the fracturing stage 2 injection volume.

8. A method for realizing CO2 production by using shale gas wells as claimed in claim 1 2 Storage and H 2 The method of injection, It is characterized in that The safety upper limit pressure in S4 is calculated by the following formula: Among them, P i is the original formation pressure; P c is the uniaxial compressive strength, determined by rock mechanics tests; P h is the fault plane pressure when the fault closure coefficient is 1.

9. A method for realizing CO2 production by using shale gas wells as claimed in claim 1 2 Storage and H 2 The method of injection, It is characterized in that Obtaining high-purity hydrogen in S5 comprises the following sub-steps: S51, discharge the hydrogen back to the surface through a pipeline; S52. After the gas undergoes secondary separation by PSA, high-purity hydrogen is obtained.

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