Construction method for geological storage of carbon dioxide in rock salt dissolving cavity

Abstract

The invention discloses a rock salt dissolved cavity carbon dioxide geological sequestration construction method, and relates to the technical field of carbon sequestration. The rock salt dissolving cavity carbon dioxide geological storage construction method comprises the following steps that S1, a storage site is selected according to production requirements and risk assessment; s2, the original brine mining well of the dissolving cavity is evaluated, if the original brine mining well meets the construction requirement, the original brine mining well is transformed, and if the original brine mining well does not meet the construction requirement, the original brine mining well is blocked, and a new injection well is constructed; s3, cavity expanding operation and sealing transformation operation are conducted on the dissolving cavity; s4, carbon sequestration operation is conducted on the dissolving cavity through the shaft; and S5, sealing operation is conducted on the shaft. According to the rock salt dissolving cavity carbon dioxide geological storage construction method, by optimizing the construction method, the leakage risk during carbon dioxide storage under a rock salt stratum structure is reduced, and the storage efficiency and the storage reliability of carbon dioxide are improved.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of carbon sequestration, in particular to a construction method of rock salt solution cavity carbon dioxide geological sequestration. BACKGROUND

[0002] CO2 and other greenhouse gas emissions are considered to be the main cause of global warming. In order to achieve the goal of carbon neutrality, in recent years, carbon capture, utilization and sequestration (CCUS) technology has been developed. CO2 sequestration technology uses underground rock layer closed space for CO2 deep sequestration, thereby reducing the impact on the surface ecological environment, and has high safety and feasibility. However, when CO2 is sequestered, some areas do not have salt water layers, and conventional salt water layer carbon sequestration technology cannot be applied. In some areas of China such as Jiangsu and Sichuan, there are salt solution cavity rock layers, which provide a new sequestration site for carbon sequestration.

[0003] Domestic and foreign research on rock salt solution cavity for 70 years shows that, compared with other underground CO2 sequestration methods, salt cave CO2 sequestration has the following advantages: 1. The brine used to create the cavity has economic value; 2. Salt rock has low permeability, and the rock around the salt rock will also be filled with crystal salt in a certain range, and only the wellbore and the roof will become the leakage channel of CO2; 3. Salt rock has damage recovery and self-healing function; 4. Compared with other CO2 underground disposal methods, CO2 in the salt cave has more concentrated characteristics; 5. The injection and discharge rate of CO2 is not affected by the underground pore medium, only related to the capacity of the salt cave pipeline transportation system; 6. CO2 in the underground salt cave can be quickly evaluated at any time, and high-purity CO2 can be extracted in the future for utilization; 7. Even if leakage occurs, most of the CO2 will remain in the geological medium and will not suddenly enter the atmosphere; 8. The research on underground energy (oil, natural gas) storage in salt caves for nearly 70 years has accumulated a wealth of theoretical research foundation and engineering experience for CO2 sequestration in salt caves.

[0004] However, research shows that rock salt solution cavity carbon dioxide geological sequestration also has the following disadvantages: this technology is relatively advanced, how to reduce leakage during carbon dioxide sequestration, improve the sequestration efficiency and reliability of carbon dioxide, needs further research. SUMMARY

[0005] The present application aims to at least solve one of the technical problems in the related art to some extent.

[0006] To this end, the present application provides a construction method of rock salt solution cavity carbon dioxide geological sequestration, which optimizes the construction method, reduces the leakage risk of carbon dioxide sequestration under the rock salt stratum structure, and improves the sequestration efficiency and reliability of carbon dioxide.

[0007] The rock salt solution cavity carbon dioxide geological storage construction method of the embodiment of the present application comprises the following steps: S1, selecting a storage site according to production needs and risk assessment; S2, evaluating the original brine production well of the solution cavity, if the original brine production well meets the construction requirements, the original brine production well is reformed, if the original brine production well does not meet the construction requirements, the original brine production well is plugged, and a new injection well is constructed; S3, expanding the solution cavity and performing sealing reform; S4, performing carbon storage operation on the solution cavity through the wellbore; S5, performing sealing operation on the wellbore.

[0008] The rock salt solution cavity carbon dioxide geological storage construction method of the embodiment of the present application optimizes the construction method, reduces the leakage risk of carbon dioxide storage in the rock salt stratum structure, and improves the carbon dioxide storage efficiency and storage reliability.

[0009] In some embodiments, when the original brine production well is evaluated, the gas injection displacement, the well body quality and the sealing condition are included, if the original brine production well meets the production requirements, and the cementing quality near the cap rock and the wellbore sealing meet the requirements, the original brine production well is reformed.

[0010] In some embodiments, when the original brine production well is plugged, the stratum is analyzed to determine the positions of the main cap rock and the secondary cap rock, and the upper part of the cap rock is plugged by forging milling, hole expanding, and squeezing special cement, the inside of the casing is plugged by segmented cement, and the upper part is injected with non-corrosive completion protection fluid.

[0011] In some embodiments, when the new injection well is constructed, the surface casing, the technical casing and the production casing are sequentially lowered at the drilling position, the technical casing is cemented after passing through the upper part of the potential secondary cap rock, the lower end of the production casing is determined according to the brine production and cavity forming requirements, the lower end of the production casing is deeper than the depth of the main cap rock, the gas injection string and the downhole packer are finally lowered, and the gap between the gas injection string and the production casing is plugged by the downhole packer.

[0012] In some embodiments, when the new injection well is constructed, the distance between the wellbore of the new injection well and the wellbore of the original brine production well is not less than 5m.

[0013] In some embodiments, in step S3, when the solution cavity expansion operation is performed, the injection pipe is used to inject the solution into the solution cavity, the solution dissolves the salt mine to form brine, the back discharge pipe is used to discharge the brine in the solution cavity, and the volume of the brine discharged by the back discharge pipe is not greater than the volume of the solution injected into the solution cavity by the injection pipe.

[0014] In some embodiments, when injecting the solution into the solution cavity, the backflow pipe is intermittently closed, the pressure in the solution cavity is intermittently raised to a set value, and the solution cavity is subjected to pressure holding operation, and the pressure holding operation time is not less than 0.5 h.

[0015] In some embodiments, after the solution cavity expansion operation in step S3 is completed, a sealing modification operation is performed, an oil liquid or a film forming agent with a set layer thickness and used for floating on the brine is injected into the solution cavity, carbon dioxide gas is introduced into the solution cavity through the injection pipe, and the carbon dioxide gas drives the brine in the solution cavity to flow out along the backflow pipe.

[0016] In some embodiments, the layer thickness of the oil liquid or the film forming agent is monitored and quantitatively supplemented, so that the layer thickness of the oil liquid or the film forming agent is not less than 5 mm.

[0017] In some embodiments, in step S4, the liquefied carbon dioxide to be sealed is injected into the solution cavity under an injection pressure of 10-15 MPa, and the pressure value in the solution cavity is continuously measured, the injection is stopped when the pressure value exceeds 15 MPa, and the liquefied carbon dioxide injection operation is repeated when the pressure value in the solution cavity is less than 10 MPa. BRIEF DESCRIPTION OF DRAWINGS

[0018] Figure 1 is a flowchart of a rock salt solution cavity carbon dioxide geological sealing construction method of an embodiment of the present application.

[0019] Figure 2 is a schematic diagram of a solution cavity carbon dioxide geological sealing construction method of an embodiment of the present application.

[0020] Figure 3 is a schematic diagram of a solution cavity carbon dioxide geological sealing construction method of an embodiment of the present application.

[0021] Figure 4 is a schematic diagram of a solution cavity carbon dioxide geological sealing construction method of an embodiment of the present application.

[0022] REFERENCE NUMERALS Solution cavity 1; original brine well 2; new injection well 3; main cap rock 4; secondary cap rock 5; bridge plug 6; primary sealing layer 7; secondary sealing layer 8; lower surface casing 9; technical casing 10; production casing 11; gas injection string 12; downhole packer 13; completion protection fluid 14. DETAILED DESCRIPTION

[0023] The embodiments of the present application are described in detail below, and examples of the embodiments are shown in the accompanying drawings. The embodiments described below with reference to the accompanying drawings are exemplary and are intended to explain the present application, and cannot be understood as a limitation of the present application.

[0024] As Figure 1 and Figure 2 The rock salt solution cavity 1 carbon dioxide geological storage construction method of the embodiment of the present application comprises the following steps: S1, selecting a storage site according to production needs and risk assessment; Specifically, when selecting a site, the principle is to meet the target reservoir effective storage capacity, safety, economy and comply with the general construction project environmental protection site selection conditions, and not be affected by external adverse geological factors. The site selection technology should adopt a multi-scale target approximation method. The site selection procedure includes two stages of planning site selection and engineering site selection. The engineering site selection aims to determine the target area, conduct comprehensive geological investigation, drilling and perfusion test, and select the site through multi-factor ranking comprehensive evaluation. After the selection, optimization and selection stages, a good engineering site is finally selected. The risk assessment is a comprehensive assessment of the entire storage project. The spatial range of the assessment includes the capture, transportation, storage site and the site extension of 2 kilometers. The time range of the assessment includes the pre-storage environmental background value monitoring period, the capture period, the transportation period, the injection period, the closed period and the 50-year period after the closure.

[0025] S2, evaluating the original brine well 2 of the solution cavity 1. If the original brine well 2 meets the construction requirements, the original brine well 2 is modified. If the original brine well 2 does not meet the construction requirements, the original brine well 2 is plugged, and a new injection well 3 is constructed. Specifically, after driving the solution cavity 1, the original brine well 2 of the solution cavity 1 needs to be evaluated. The main factors to be considered include the carbon dioxide injection displacement requirement and the wellbore quality and sealing condition of the original brine well 2. Through sealing evaluation, the sealing of the underground solution cavity 1 is qualified, and the well cementing quality near the cap layer and the wellbore sealing meet the production requirements. Under the premise that the production casing of most original brine wells 2 is not a gas-tight casing, the wellbore of the original brine well 2 that is better can be modified into a short-term carbon dioxide injection well. For the original brine well 2 with poor wellbore condition or unable to meet the injection requirement, the original brine well 2 with poor wellbore quality is effectively plugged through segmented forging and milling, hole enlargement, plugging and other technologies, and a new injection well 3 is constructed to communicate with the storage target layer, so as to change the target layer into a reservoir suitable for storing carbon dioxide.

[0026] S3, expanding the cavity and sealing the solution cavity 1; Specifically, when expanding the solution cavity 1, the solution is injected into the solution cavity 1 through the injection pipe, the salt is dissolved in the solution to form brine, the brine in the solution cavity 1 is discharged through the back discharge pipe, and the volume of the brine discharged through the back discharge pipe is not greater than the volume of the solution injected into the solution cavity 1 through the injection pipe.

[0027] After the expansion of the cavity 1 is completed, a sealing modification is carried out. An oil or film-forming agent of a set thickness is injected into the cavity 1 to float above the brine. Carbon dioxide gas is introduced into the cavity 1 through the injection pipe. The carbon dioxide gas drives the brine in the cavity 1 to be discharged along the return pipe above the oil or film-forming agent.

[0028] Due to the high viscosity of the oil and film-forming agent, when the brine is discharged by carbon dioxide, the liquid-blocking layer formed by the oil or film-forming agent above the brine descends with the discharge of the brine, forming an isolation layer on the inner wall of the solution cavity 1 and on the pipes and equipment within the solution cavity 1. When there are cracks or interlayers within the solution cavity 1, the pressure of carbon dioxide injects the oil or film-forming agent into the cracks or interlayers. The adsorption properties of the clay adsorb the oil or film-forming agent, which can seal the seepage channels within the cracks or interlayers and prevent the supercritical carbon dioxide and brine solution from corroding the cracks or interlayers. This protects the cracks or interlayers and improves the safety and sealing of the supercritical carbon dioxide storage in the rock salt solution cavity 1.

[0029] S4. Carbon sequestration operation is carried out in cavity 1 through the wellbore; Specifically, under an injection pressure of 10–15 MPa, liquefied carbon dioxide to be sealed is injected into the solution chamber 1 and the pressure value inside the solution chamber 1 is continuously measured. When the pressure value exceeds 15 MPa, the injection is stopped. When the pressure value inside the solution chamber 1 is less than 10 MPa, the liquefied carbon dioxide injection operation is repeated.

[0030] S5. Perform sealing operations on the wellbore.

[0031] The construction method for carbon dioxide geological storage in rock salt cavities according to embodiments of the present invention optimizes the construction method, reduces the risk of leakage during carbon dioxide storage under rock salt strata, and improves the storage efficiency and reliability of carbon dioxide.

[0032] In some embodiments, such as Figure 3 As shown, when sealing the original brine well 2, the formation was analyzed to determine the location of the main cap layer 4 and the secondary cap layer 5. The cap layer was sealed by milling, enlarging, and injecting special cement. The casing was sealed with segmented cement, and segmented pressure testing was carried out to ensure the sealing quality of each step. Non-corrosive well completion protection fluid 14 was injected into the upper part.

[0033] A bridge plug 6 is installed at the bottom of the wellbore, and a primary sealing layer 7 is installed above the bridge plug 6 at the main cap layer 4. A secondary sealing layer 8 is installed at the secondary cap layer 5, and a non-corrosive completion protection fluid 14 is installed above the secondary sealing layer 8. By sealing the original brine well 2 in sections, the sealing reliability of each sealing section is ensured. The connection sealing and reliability between the newly filled sealing layer and the underlying structure are ensured by forging, milling, and enlarging, preventing gas leakage from the cavity 1 along the wellbore, and further ensuring the sealing performance of the original brine well 2 after sealing.

[0034] In some embodiments, such as Figure 4 As shown, when constructing the new injection well 3, the surface casing 9, the technical casing 10, and the production casing 11 are sequentially run at the drilling location. The technical casing 10 is run through the potential secondary capping layer 5 above the formation and then cemented. The run depth of the production casing 11 is determined in conjunction with the location of the cavity for brine production and cavity creation, and the depth of the production casing 11 nozzle is greater than the depth of the main capping layer 4. Finally, the gas injection string 12 and the downhole packer 13 are run in, and the gap between the gas injection string 12 and the production casing 11 is sealed by the downhole packer 13.

[0035] When constructing the new injection well 3, it is necessary to determine the location of the caprock and the potential secondary caprock 5 in the formation to ensure the proper installation of the technical casing and production pipeline. The casing size should be determined according to the carbon dioxide injection discharge requirements. The casing design strength should be determined by the influence of operating pressure and creep formation. For cases where formation pressure is unclear or formation conditions are complex, the casing design should have a design margin.

[0036] In some embodiments, such as Figure 2 As shown, when constructing the new injection well 3, the distance between the wellbore of the new injection well 3 and the wellbore of the original brine extraction well 2 should not be less than 5m. The distance can be adjusted according to the geological conditions of the construction, such as 5m, 7m or 10m, to ensure the distance between the new injection well 3 and the original brine extraction well 2, and to prevent the extension of any cracks that may exist between the new injection well 3 and the original brine extraction well 2, which would affect the sealing of the wellbore and the stability of the well wall.

[0037] In some embodiments, during the drilling of the new injection well 3, the drilling fluid discharge rate is strictly controlled. For example, when drilling the Tertiary Dainan Formation with low consolidation strength, the lower limit of the screw design discharge rate is used to reduce the erosion of the well wall by the drilling fluid; when drilling the Tertiary Funing Formation with good cementation, the upper limit of the screw design discharge rate is used to improve drilling efficiency; and grouting is carried out continuously or at regular intervals during tripping to keep the fluid level at the wellhead from dropping or dropping no more than the height of the grouting pipe.

[0038] In some embodiments, when injecting solution into the solution cavity 1, the return pipe is intermittently closed, causing the pressure in the solution cavity 1 to rise intermittently to a set value, so as to perform a pressure-holding operation on the solution cavity 1. The pressure-holding operation time is less than 0.5 hours. Through the pressure-holding operation and the circulation extraction of solution in the solution cavity 1, the crystallization and precipitation of crystals in the solution cavity 1 are avoided, and the expansion efficiency of the solution cavity 1 is improved.

[0039] Preferably, the holding time is 1-2 hours.

[0040] In some embodiments, the thickness of the oil or film-forming agent is monitored and quantitatively replenished to ensure that the thickness of the oil or film-forming agent is not less than 10 mm, thereby ensuring the minimum thickness of the oil or film-forming agent layer. This ensures the continuity and reliability of the isolation layer formed on the inner wall of the solution cavity 1 and on the pipes and equipment within the solution cavity 1, ensuring the separation of high-pressure gas and brine, and ensuring the sealing of cracks or interlayers present in the solution cavity 1 by the oil or film-forming agent.

[0041] In some embodiments, after the cavity 1 is enlarged, the sealing performance of cavity 1 and the wellbore is evaluated. Nitrogen gas is injected between the production casing and the test string to bring the gas-water interface depth to a position 5-10m below the production casing shoe (entering the borehole open hole or cavity), while maintaining a constant gas pressure at the casing shoe. During the test, the depth of the gas-water interface is continuously recorded using an interface logging tool, and parameters such as wellhead pressure, fluid flow rate, and temperature are continuously recorded using surface monitoring instruments. Based on the recorded data, a curve of the gas-water interface depth change is plotted, and the trend line of the cavity leakage rate over time is calculated. The cavity sealing performance is comprehensively evaluated based on the trend of the cavity leakage rate over time and the change in gas-water interface depth. The evaluation criteria are as follows: 1. The gas leakage rate gradually decreases over time and reaches a stable value within the test period; 2. The change in gas-water interface depth is less than 1 meter within the test period. By evaluating the sealing performance of cavity 1 and the wellbore, the sealing reliability of cavity 1 is ensured.

[0042] In the description of this invention, it should be understood that the terms "center," "longitudinal," "lateral," "length," "width," "thickness," "upper," "lower," "front," "rear," "left," "right," "vertical," "horizontal," "top," "bottom," "inner," "outer," "clockwise," "counterclockwise," "axial," "radial," and "circumferential" indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings. They are used only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation. Therefore, they should not be construed as limitations on this invention.

[0043] Furthermore, the terms "first" and "second" are used for descriptive purposes only and should not be construed as indicating or implying relative importance or implicitly specifying the number of indicated technical features. Thus, a feature defined as "first" or "second" may explicitly or implicitly include at least one of that feature. In the description of this invention, "a plurality of" means at least two, such as two, three, etc., unless otherwise explicitly specified.

[0044] In this invention, unless otherwise explicitly specified and limited, the terms "installation," "connection," "linking," and "fixing," etc., should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral part; they can refer to a mechanical connection, an electrical connection, or a connection that allows communication between them; they can refer to a direct connection or an indirect connection through an intermediate medium; they can refer to the internal communication of two components or the interaction between two components, unless otherwise explicitly limited. Those skilled in the art can understand the specific meaning of the above terms in this invention according to the specific circumstances.

[0045] In this invention, unless otherwise explicitly specified and limited, "above" or "below" the second feature can mean that the first feature is in direct contact with the second feature, or that the first feature is in indirect contact with the second feature through an intermediate medium. Furthermore, "above," "over," and "on top" of the second feature can mean that the first feature is directly above or diagonally above the second feature, or simply that the first feature is at a higher horizontal level than the second feature. "Below," "below," and "under" the second feature can mean that the first feature is directly below or diagonally below the second feature, or simply that the first feature is at a lower horizontal level than the second feature.

[0046] In the description of this specification, the references to terms such as "one embodiment," "some embodiments," "example," "specific example," or "some examples," etc., refer to specific features, structures, materials, or characteristics described in connection with that embodiment or example, which are included in at least one embodiment or example of the present invention. In this specification, the illustrative expressions of the above terms do not necessarily refer to the same embodiment or example. Furthermore, the specific features, structures, materials, or characteristics described may be combined in any suitable manner in one or more embodiments or examples. Moreover, without contradiction, those skilled in the art can combine and integrate the different embodiments or examples described in this specification, as well as the features of different embodiments or examples.

[0047] Although embodiments of the present invention have been shown and described above, it is understood that the above embodiments are exemplary and should not be construed as limiting the present invention. Those skilled in the art can make changes, modifications, substitutions and variations to the above embodiments within the scope of the present invention.

Claims

1. A method of construction of a rock salt cavern for geological storage of carbon dioxide, characterized in that, The method comprises the following steps: S1, selecting a storage site according to production needs and risk assessment; S2, evaluating the original brine production well of the solution cavity, if the original brine production well meets the construction requirements, the original brine production well is reconstructed, if the original brine production well does not meet the construction requirements, the original brine production well is plugged, and a new injection well is constructed; S3, expanding the solution cavity and sealing the solution cavity; S4, carbon storage operation is performed on the solution cavity through the wellbore; S5, the wellbore is closed.

2. The method according to claim 1, wherein When the original brine production well is evaluated, the gas injection displacement, the wellbore quality and the sealing condition are included, if the original brine production well meets the production requirements, and the cementing quality near the cap rock and the wellbore sealing meet the requirements, the original brine production well is reconstructed.

3. The method according to claim 1, wherein When the original brine production well is plugged, the formation is analyzed to determine the positions of the main cap rock and the secondary cap rock, and the upper part of the cap rock is plugged by forging, milling, hole expansion and special cement injection, the inside of the casing is plugged by segmented cement, and the segmented pressure test is performed, and the upper part is injected with non-corrosive completion protection fluid.

4. The method according to claim 1, wherein When the new injection well is constructed, the surface casing, the technical casing and the production casing are sequentially lowered at the drilling position, the technical casing is cemented after penetrating the upper part of the potential secondary cap rock, the depth of the production casing is determined according to the brine production cavity requirement, the depth of the production casing mouth is greater than the depth of the main cap rock, finally, the gas injection pipe column and the downhole packer are lowered, and the gap between the gas injection pipe column and the production casing is plugged by the downhole packer.

5. The method according to claim 4, wherein When the new injection well is constructed, the distance between the wellbore of the new injection well and the wellbore of the original brine production well is not less than 5m.

6. The method according to claim 1, wherein When the solution cavity is expanded in step S3, the solution is injected into the solution cavity through the injection pipe, the brine is formed after the solution dissolves the salt mine, the brine in the solution cavity is discharged through the back discharge pipe, and the volume of the brine discharged by the back discharge pipe is not greater than the volume of the solution injected into the solution cavity by the injection pipe.

7. The method according to claim 6, wherein When the solution is injected into the solution cavity, the back discharge pipe is intermittently closed, the pressure in the solution cavity is intermittently increased to a set value, the solution cavity is pressure built-up, and the pressure built-up time is not less than 0.5h.

8. The method according to claim 6, wherein After the solution cavity expansion operation is completed in step S3, the sealing reconstruction operation is performed, the oil liquid or the film forming agent with a set layer thickness and used for floating on the brine is injected into the solution cavity, the carbon dioxide gas is introduced into the solution cavity through the injection pipe, and the carbon dioxide gas drives the brine in the solution cavity to be discharged along the back discharge pipe.

9. The method according to claim 8, wherein The layer thickness of the oil liquid or the film forming agent is monitored and quantitatively supplemented, so that the layer thickness of the oil liquid or the film forming agent is not less than 5mm.

10. The method according to claim 1, wherein In step S4, the liquefied carbon dioxide to be stored is injected into the solution cavity under an injection pressure of 10-15MPa, and the pressure value in the solution cavity is continuously measured, the injection is stopped when the pressure value exceeds 15MPa, and the liquefied carbon dioxide injection operation is repeated when the pressure value in the solution cavity is less than 10MPa.

Images