Method and system for carbon dioxide sequestration

Abstract

Embodiments of the present specification provide a method and system for carbon dioxide sequestration, the method comprising: for each of a plurality of blocks of a target area, determining the degree of mineralization of flowback fracturing fluid in the block; selecting a target block of which the mineralization degree is not less than a first preset threshold value from the plurality of blocks; and carbon dioxide is injected into the shale reservoir through the carbon dioxide injection well in the target block and the fracture of the shale reservoir, so that the retention fracturing fluid in the fracture reaches a supersaturated state due to gas flow evaporation of the carbon dioxide, and salt crystals are separated out to block the fracture.

Description

Technical Field

[0001] This specification relates to the field of carbon dioxide sequestration, and in particular to a method and system for carbon dioxide sequestration. Background Art

[0002] The development process of shale oil and gas reservoirs generally uses hydraulic fracturing technology to form artificial fractures in the reservoir to connect natural fractures, thereby improving the seepage capacity of oil and gas resources (such as shale gas), thereby realizing the extraction of oil and gas resources. In the field of carbon dioxide storage, the natural reservoir space of oil and gas reservoirs is usually used to store carbon dioxide. However, reservoir fractures (such as natural fractures) are key channels for the migration of oil and gas resources and potential channels for carbon dioxide to escape, resulting in the risk of leakage in the storage of carbon dioxide. Therefore, plugging reservoir fractures is a problem that needs to be solved in carbon dioxide storage operations.

[0003] Currently, plugging fractures in reservoirs often involves introducing materials from outside the reservoir. However, these materials can trigger a series of physical and chemical reactions, resulting in negative effects such as solid-phase blockage, liquid-phase blockage, and mineral precipitation, leading to reservoir damage and environmental pollution. Furthermore, plugging materials tend to settle, making it difficult for them to enter natural fractures, resulting in poor plugging effectiveness. Furthermore, given the widespread distribution of fractures in reservoirs, the large amount of plugging materials required would significantly increase the cost of CO2 storage.

[0004] Therefore, a method and system for carbon dioxide storage are provided, which can seal cracks in the reservoir while storing carbon dioxide, thereby improving the safety of carbon dioxide storage and reducing costs. Summary of the Invention

[0005] One of the embodiments of the present specification provides a method for carbon dioxide storage, comprising: determining the salinity of flowback fracturing fluid in each of a plurality of blocks in a target area; selecting a target block having a salinity not less than a first preset threshold value from the plurality of blocks; and injecting carbon dioxide into a shale reservoir through a carbon dioxide injection well in the target block and the fractures of the shale reservoir, so that the retained fracturing fluid in the fractures reaches a supersaturated state due to evaporation of the carbon dioxide gas flow, thereby precipitating salt crystals to seal the fractures.

[0006] One of the embodiments of the present specification provides a system for carbon dioxide storage, comprising: a mineralization measuring device configured to measure the mineralization of flowback fracturing fluid in each of a plurality of blocks in a target area; a processing device configured to select a target block having a mineralization not less than a first preset threshold value from the plurality of blocks; and a carbon dioxide injection device configured to inject carbon dioxide into a shale reservoir through a carbon dioxide injection well in the target block and through fractures in the shale reservoir, so that the retained fracturing fluid in the fractures reaches a supersaturated state due to evaporation of the carbon dioxide gas flow, thereby precipitating salt crystals to seal the fractures. BRIEF DESCRIPTION OF THE DRAWINGS

[0007] This specification will be further described in the form of exemplary embodiments, which will be described in detail with reference to the accompanying drawings. These embodiments are not limiting, and in these embodiments, like numbers represent like structures, wherein:

[0008] Figure 1 is a scenario diagram of a carbon dioxide storage system according to some embodiments of this specification;

[0009] Figure 2 is an exemplary flow chart of a method for carbon dioxide sequestration according to some embodiments of this specification;

[0010] Figure 3 is a schematic diagram of a method for injecting carbon dioxide according to some embodiments of this specification;

[0011] Figure 4 is a schematic diagram of another method of injecting carbon dioxide according to some embodiments of this specification;

[0012] Figure 5A is a schematic diagram of the pore size distribution before and after the shale salt crystallization experiment according to some embodiments of this specification;

[0013] Figure 5B Schematic diagram of a scanning electron microscope image after a shale salt crystallization experiment according to some embodiments of this specification. DETAILED DESCRIPTION

[0014] To more clearly illustrate the technical solutions of the embodiments of this specification, the following briefly describes the drawings required for describing the embodiments. Obviously, the drawings described below are merely examples or embodiments of this specification. Those skilled in the art can apply this specification to other similar scenarios based on these drawings without inventive effort. Unless otherwise apparent from the context or otherwise noted, the same reference numerals in the figures represent the same structure or operation.

[0015] It should be understood that the terms "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 terms can achieve the same purpose, the terms may be replaced by other expressions.

[0016] Unless the context clearly indicates otherwise, the words "a," "an," "an," and / or "the" do not refer to the singular but include the plural. Generally speaking, the terms "include" and "comprise" only indicate the inclusion of the steps and elements specifically identified, and these steps and elements do not constitute an exclusive list. A method or apparatus may also include other steps or elements.

[0017] Flowcharts are used throughout this specification to illustrate the operations performed by systems according to embodiments of this specification. It should be understood that preceding or following operations do not necessarily need to be performed in exact order. Instead, the steps may be processed in reverse order or simultaneously. Furthermore, other operations may be added to these processes, or one or more operations may be removed from these processes.

[0018] Figure 1 is a schematic diagram of a carbon dioxide storage system according to some embodiments of the present specification.

[0019] like Figure 1 As shown, the carbon dioxide sequestration system 100 may include a processing device 110 , a salinity measurement device 120 , a carbon dioxide injection device 130 , a carbon dioxide storage device 140 , and a carbon dioxide injection well 150 .

[0020] The processing device 110 can be used to analyze and / or process information and / or data in the carbon dioxide sequestration system 100. In some embodiments, the processing device 110 comprises a computer processing device. For example, the processing device 110 can include a central processing unit (CPU), an application-specific integrated circuit (ASIC), an application-specific instruction set processor (ASIP), a digital signal processor (DSP), a microcontroller unit, or any combination thereof. In some embodiments, the processing device 110 can be a single server or a server group. The server group can be centralized or distributed (e.g., the processing device 110 can be a distributed system).

[0021] The processing device 110 can be used to control one or more components of the carbon dioxide storage system 100 (such as the salinity measurement device 120, the carbon dioxide injection device 130, and the carbon dioxide storage device 140). In some embodiments, the processing device 110 can send control instructions (such as program instructions, control signals) to the carbon dioxide injection device 130 to instruct the carbon dioxide injection device 130 to inject carbon dioxide into the shale reservoir 180 through the carbon dioxide injection well 150 in the target block. More relevant information can be found elsewhere in this specification (e.g., Figure 2 ).

[0022] The salinity measurement device 120 may include a device for determining the salinity of a geological sample of a target area. The geological sample may be rock, soil, or fluid (eg, formation water, surface flowback fluid, etc.) in the target area.

[0023] The mineralization measurement device 120 may include a sampling device (such as a geological sample collection container), a conductivity meter, an ion chromatograph, and other equipment. In some embodiments, for each of the multiple blocks in the target area, the mineralization measurement device 120 may be used to determine the mineralization of the fracturing fluid in each block to determine the target block. More information about target areas, blocks, and fracturing fluids can be found elsewhere in this specification (e.g., Figure 2 ).

[0024] In some embodiments, during CO2 storage operations, the salinity measurement device 120 can be used to measure the salinity of geological samples (such as fracturing fluid retained in fractures) corresponding to different sampling points in the target block in real time, thereby adjusting the processing method of the CO2 storage operation based on the salinity. Figure 4 and its description.

[0025] CO2 injection equipment 130 refers to the equipment used to inject CO2 into shale reservoirs during CO2 storage operations. CO2 injection equipment 130 can include various types of equipment for processing, transporting, and moving CO2, and can be determined based on the actual requirements of the CO2 storage operation. For example, CO2 injection equipment 130 may include pipelines to enable CO2 migration (e.g., directional migration) within a shale reservoir or a portion thereof.

[0026] In some embodiments, the carbon dioxide injection equipment 130 includes a carbon dioxide control device for controlling and / or processing the carbon dioxide. For example, the carbon dioxide control device may include a high-pressure pump to deliver the carbon dioxide to the carbon dioxide injection well 150. In some embodiments, the carbon dioxide control device may include a cooling device, a heating device, and a compression device to cool, heat, pressurize, or otherwise process the carbon dioxide so that the carbon dioxide meets requirements such as temperature, pressure, or phase (e.g., supercritical state).

[0027] In some embodiments, the carbon dioxide injection device 130 (e.g., a carbon dioxide control device) can adjust one or more control parameters (e.g., temperature, pressure) in response to control instructions from the processing device 110. In some embodiments, the processing device 110 can be integrated into the carbon dioxide injection device 130 (e.g., a carbon dioxide control device).

[0028] The carbon dioxide storage device 140 is used to store carbon dioxide that needs to be sealed. It can be various containers (such as storage tanks) or locations (such as underground temporary storage). The carbon dioxide can be one or more combinations of carbon dioxide in different phases (gaseous, liquid, or supercritical).

[0029] The CO2 storage device 140 can be determined based on the actual requirements of the CO2 storage operation (e.g., capacity, material, and phase of the CO2). For example, it can be a normal temperature and pressure tank for storing gaseous CO2, a low temperature and high pressure tank for storing liquid CO2, or a high temperature and high pressure tank for storing supercritical CO2.

[0030] The carbon dioxide injection well 150 is a well set in the target area, which is used to connect the ground of the target area with the shale reservoir 180 to inject carbon dioxide into the shale reservoir 180. One or more carbon dioxide injection wells 150 can be set in each block of the target area. Figure 1 As shown, the carbon dioxide injection wells 150 include a carbon dioxide injection well 150 - 1 , a carbon dioxide injection well 150 - 2 , . . . , and a carbon dioxide injection well 150 - n .

[0031] The shale reservoir 180 refers to a geological structure used to store carbon dioxide, which may include but is not limited to oil and gas storage spaces (reservoirs) in various geological bodies such as depleted oil reservoirs, depleted gas reservoirs, deep unrecoverable coal seams, basic-ultramafic rocks, etc. Shale reservoirs are mainly composed of shales with low porosity and low permeability, and have strong oil and gas storage and seepage capabilities. In some embodiments, the shale reservoir 180 in the target area is a geological structure with a mineralization not less than a first preset threshold, for example, a marine shale gas reservoir, a deep saline layer, etc. More information about mineralization can be found elsewhere in this specification (for example Figure 2 ).

[0032] In some embodiments, the layout / site selection (e.g., well location, number of wells, well depth, caliber, etc.) of the carbon dioxide injection wells 150 can be determined based on reservoir-related information of the shale reservoir 180. The reservoir-related information includes information such as the depth, reservoir area, reservoir thickness, fracture pressure coefficient, and fracture distribution (e.g., the location distribution of natural fractures) of the shale reservoir.

[0033] For example, the locations of the carbon dioxide injection wells 150 corresponding to different blocks in the target area can be determined based on the fracture distribution of the shale reservoir corresponding to the block, so that the injected carbon dioxide can be quickly transported to the fracture-concentrated area of the shale reservoir, thereby improving the efficiency of fracture plugging and the efficiency of carbon dioxide storage operations.

[0034] In some embodiments, the CO2 storage system 100 further includes monitoring equipment 160 for collecting various monitoring data or information related to the CO2 storage operation. The monitoring equipment 160 may be determined based on the actual needs of the CO2 storage operation. In some embodiments, the monitoring equipment 160 includes surface sensors and underground sensors.

[0035] Ground sensors are sensors deployed on the ground in the target area, used to collect ground monitoring data from the target area. This ground monitoring data includes, but is not limited to, temperature, humidity, air pressure, wind speed, and other data in the target area. Accordingly, ground sensors may include thermometers, hygrometers, barometers, and anemometers. In some embodiments, ground sensors also include a carbon dioxide leak detector (such as an infrared spectrometer) to monitor for carbon dioxide leaks during the carbon dioxide storage operation, thereby ensuring the safety of the carbon dioxide storage operation.

[0036] Underground sensors are sensors deployed underground in the target area to collect underground monitoring data during CO2 storage operations. This underground monitoring data includes injection well monitoring data corresponding to CO2 injection well 150 and shale reservoir monitoring data corresponding to the shale reservoir.

[0037] The injection well monitoring data is used to reflect the real-time status of the carbon dioxide injection well 150 , including but not limited to the carbon dioxide flow rate or flow velocity in the well, the phase of carbon dioxide, the temperature in the well, the gas pressure in the well, and other data.

[0038] In some embodiments, the underground sensor includes an ultrasonic flow meter deployed in the carbon dioxide injection well 150 for real-time monitoring of the instantaneous flow rate and / or flow velocity of carbon dioxide in the well; the underground sensor also includes multiple temperature sensors and pressure sensors deployed in the carbon dioxide injection well 150 for real-time monitoring of the well temperature and well pressure at multiple locations in the well.

[0039] The shale reservoir monitoring data is used to reflect the real-time status of the shale reservoir, including but not limited to data such as the carbon dioxide flow rate or flow velocity, reservoir temperature, and reservoir pressure in the shale reservoir (such as the shale reservoir 180 shown in the figure).

[0040] In some embodiments, the subsurface sensors include various types of distributed fiber optic sensors deployed in a target area (e.g., one or more blocks) to collect shale reservoir monitoring data. For example, the distributed fiber optic sensors may include distributed temperature sensors for monitoring the temperature distribution of the shale reservoir. The distributed fiber optic sensors may also include distributed pressure sensors for monitoring the pressure distribution of the shale reservoir.

[0041] In some embodiments, the underground sensor also includes a distributed acoustic wave sensor for monitoring the flow rate or flow velocity of carbon dioxide migrating in the shale reservoir, as well as monitoring the fracture information of the shale reservoir (such as the distribution of fractures, the width of fractures, the expansion or blocking status of fractures (such as the blocking status of salt crystals)).

[0042] In some embodiments, the monitoring device 160 can exchange data and / or information with other components of the carbon dioxide sequestration system 100. For example, the monitoring device 160 can feed monitoring data (e.g., surface monitoring data, underground monitoring data) back to the processing device 110. In another example, the monitoring device 160 can send the monitoring data to a terminal device (e.g., a mobile device) of a user (e.g., a manager or engineer).

[0043] The monitoring equipment 160 may also include other equipment or devices. For example, the monitoring equipment 160 may also include seismic monitoring equipment to collect formation microseismic data that may be induced during the carbon dioxide injection operation to assess the safety of the carbon dioxide injection operation.

[0044] In some embodiments of this specification, monitoring equipment can be used to track the real-time status of each link of the carbon dioxide storage operation (such as wellhead injection, migration within the well, migration in the shale reservoir, fracture sealing, etc.) to ensure the normal progress of the carbon dioxide storage operation.

[0045] The carbon dioxide sequestration system 100 may further include other devices or components.

[0046] In some embodiments, the carbon dioxide sequestration system 100 further includes a network (not shown) for facilitating information and / or data exchange. The network may be a wired network or a wireless network. In some embodiments, one or more components of the carbon dioxide sequestration system 100 (e.g., processing equipment 110, carbon dioxide injection equipment 130, etc.) may transmit information and / or data to one or more other components of the carbon dioxide sequestration system 100 via the network. By way of example only, the processing equipment 110 may send instructions (such as program instructions, control signals) to the carbon dioxide injection equipment 130 via the network to control the carbon dioxide injection equipment 130 to inject carbon dioxide into the shale reservoir of the target block.

[0047] In some embodiments, the carbon dioxide storage system 100 further includes a terminal device (not shown), such as a mobile device, a tablet computer, a laptop computer, or any combination thereof. The terminal device can receive information and / or instructions (such as control instructions for the carbon dioxide injection device 130) input by a user (e.g., a manager or engineer). In some embodiments, the terminal device can present monitoring information related to carbon dioxide storage to the user. For example, the monitoring information includes, but is not limited to, the injection rate and speed of carbon dioxide, the pressure and temperature of the shale reservoir, etc. The monitoring information can be a combination of one or more of text, images, audio, and video information.

[0048] The above description is for illustrative purposes only, and actual application scenarios may vary.

[0049] It should be noted that application scenario 100 is provided for illustrative purposes only and is not intended to limit the scope of this specification. A person of ordinary skill in the art may make various modifications or variations based on the description of this specification. However, such modifications and variations will not deviate from the scope of this specification.

[0050] Figure 2 is an exemplary flow chart of a method for carbon dioxide sequestration according to some embodiments of the present specification.

[0051] In some embodiments, process 200 may be performed by a carbon dioxide storage system. For example, process 200 may be performed by a processing device (such as processing device 110), or one or more components of the carbon dioxide storage system (such as salinity measurement device 120, carbon dioxide injection device 130, etc.) may be controlled by the processing device to implement the functions described in each step of process 200. Figure 2 As shown, the process 200 includes the following steps.

[0052] Step 210 : For each of the multiple blocks in the target area, determine the salinity of the flowback fracturing fluid in the block.

[0053] The target area refers to the geographical area where carbon dioxide storage is required, which can be any geological body suitable for carbon dioxide storage. For example, the target area can be an area corresponding to a depleted oil reservoir or a depleted oil and gas reservoir.

[0054] In some embodiments, the CO2 storage system may select a target region based on the geological characteristics of one or more candidate geographic regions. The geological characteristics include, but are not limited to, reservoir type (e.g., shale reservoir), reservoir area, reservoir thickness, geothermal gradient, formation pressure, porosity, permeability, and fracture pressure coefficient.

[0055] The CO2 storage system can determine target areas based on a preset scoring table. The preset scoring table includes multiple geological characteristics and corresponding scores for indicators such as CO2 storage capacity, economic feasibility (construction difficulty), and safety (such as environmental pollution). Candidate geographical areas with high comprehensive scores (such as the sum of each indicator, etc.) can be used as target areas. For more information on shale reservoirs, see Figure 1 and its description.

[0056] A block is a sub-area within a target area. The CO2 storage system can divide the target area into multiple sub-areas. For example, the target area can be divided into a predetermined number of regular (grid-shaped) and / or irregular sub-areas based on its size, with each sub-area corresponding to a block.

[0057] In some embodiments, the carbon dioxide storage system may be divided into blocks based on the distribution of fractures in the formation of the target area. For example, an area with dense fracture distribution may be divided into a block.

[0058] Salinity reflects the concentration of salts in the flowback fracturing fluid in a target area or block. Salts include, but are not limited to, sodium chloride and calcium sulfate. Flowback fracturing fluid is a liquid mixture that flows back from the wellbore to the surface after hydraulic fracturing in an oil or gas well. It is a mixture of fracturing fluid and formation fluids (such as crude oil, natural gas, and formation water).

[0059] The CO2 storage system can measure the salinity of flowback fracturing fluid samples from each block, using this as the salinity for each block. For example, for a given block, the average salinity of flowback fracturing fluid collected at different sampling points is used as the salinity for that block.

[0060] Step 220 : Select a target block having a mineralization not less than a first preset threshold from the plurality of blocks.

[0061] A target block is an area suitable for CO2 storage operations. For example, a target block may be suitable for drilling (such as placing a CO2 injection well) or for CO2 migration.

[0062] In some embodiments, the target blocks include blocks suitable for salt crystallization. The first preset threshold can be used to assess whether the salinity corresponding to each block is conducive to salt crystallization, thereby facilitating the formation of salt crystals and sealing fractures when subsequent carbon dioxide is injected into the shale reservoir.

[0063] The first preset threshold can be determined based on historical experience. For example, in historical CO2 storage operations, the first preset threshold can be determined based on the leakage of CO2 stored at different salinities. For example, the first preset threshold can be 5%, 7%, or the like.

[0064] In some embodiments, the first preset threshold is 2%. This value can be obtained based on shale salt crystallization experiments and comparative experimental data. Figure 5A and Figure 5B .

[0065] In some embodiments, the carbon dioxide storage system may sort multiple blocks in the target area according to the mineralization corresponding to each block (eg, in descending order), and select one or more blocks having a mineralization greater than a first preset threshold as target blocks.

[0066] Step 230 , injecting carbon dioxide into the shale reservoir through the carbon dioxide injection wells in the target block and the fractures of the shale reservoir, so that the retained fracturing fluid in the fractures reaches a supersaturated state due to the evaporation of the carbon dioxide gas flow, thereby precipitating salt crystals to seal the fractures.

[0067] Fractures in shale reservoirs serve as pathways for the diffusion and migration of fluids (such as oil, gas, water, and carbon dioxide) within the shale reservoir. Fractures can be natural or artificial (such as those created by hydraulic fracturing).

[0068] In some embodiments, for the shale reservoir corresponding to the target block, the carbon dioxide storage system can determine the fracture information of the target block based on the detection data collected by various monitoring equipment (such as distributed acoustic sensors). More information about monitoring equipment can be found elsewhere in this manual (for example, Figure 1 ).

[0069] In some embodiments, the CO2 storage system can determine fracture information using tracer testing data. For example, after injecting a chemical or radioactive tracer (such as a fluorescent dye) into the fluid, the distribution of fractures (such as their location, length, and width) can be determined based on the fluid's migration path within the shale reservoir.

[0070] It should be noted that during the carbon dioxide storage operation, when carbon dioxide is injected into the shale reservoir through the carbon dioxide injection well, the flowing carbon dioxide acts on the fracturing fluid with a certain degree of mineralization (i.e., retained fracturing fluid) retained in the fractures, causing the retained fracturing fluid to precipitate salt crystals after reaching a supersaturated state, thereby filling the natural fractures and forming a plugging effect. Among them, the effects of the flowing carbon dioxide on the retained fracturing fluid include but are not limited to promoting the loss of water in the retained fracturing fluid (such as water evaporation), changes in the temperature and pressure of the retained fracturing fluid, changes in the solubility of salts in the retained fracturing fluid, etc., which promote changes in the salt concentration of the retained fracturing fluid. For more information on carbon dioxide injection, please refer to Figure 3 and Figure 4 and its description.

[0071] In some embodiments, the siting of the CO2 injection wells and the CO2 injection parameters are related to the fracture width of the fracture.

[0072] In some embodiments, the crack is a natural crack having a width of not less than 100 nm.

[0073] Natural fractures refer to fractures formed naturally in shale reservoirs. The fracture network formed by natural fractures in shale reservoirs covers a wide range. The fracture width will affect the rate and difficulty of salt crystallization of the retained fracturing fluid, thereby affecting the effect of fracture plugging. Among them, the salt crystallization corresponding to natural fractures with a width of not less than 100nm has a better plugging effect. In carbon dioxide storage operations, based on the distribution of natural fractures, the concentrated distribution points of natural fractures with a width of not less than 100nm are selected as carbon dioxide injection points (such as the layout of carbon dioxide injection wells), so that the plugging of fractures by carbon dioxide is more targeted and the efficiency of carbon dioxide storage is improved. For more information on fracture width and plugging effect, see Figure 5B and its description.

[0074] In some embodiments, the location of the CO2 injection well and the CO2 injection parameters are related to the type of salt crystals that can be precipitated from the retained fracturing fluid. Different types of salt components have different solubilities under different external conditions (such as temperature and pressure), thereby affecting the rate at which salt crystals are precipitated from the retained fracturing fluid.

[0075] In some embodiments, the CO2 storage system can determine the type of salt crystals based on the salt composition of the retained fracturing fluid. Preferred salts include salts with high solubility differentials. High solubility differential salts are salts whose solubility varies significantly with various conditions (e.g., temperature, pressure, and salinity of the fracturing fluid).

[0076] In some embodiments, the salt crystals include at least one of sodium chloride and calcium sulfate. The solubility of sodium chloride decreases rapidly with water loss, allowing for rapid precipitation of sodium chloride crystals, thereby forming a dense crystalline layer. The solubility of calcium sulfate decreases with increasing temperature, and the injection of high-temperature carbon dioxide allows for faster precipitation of stronger calcium sulfate crystals.

[0077] In some embodiments of this specification, sodium chloride or calcium sulfate is considered as the target salt crystal, which helps to make the retained fracturing fluid in the fracture crystallize more quickly, thereby improving the efficiency of carbon dioxide storage. At the same time, salt crystals with higher strength help to make the fracture sealing more stable and prevent carbon dioxide leakage.

[0078] In some embodiments, the CO2 storage system can determine target injection parameters based on the geological characteristics, fracture information, and salt crystallization information of the target block. Geological characteristics include the reservoir area, thickness, and fracture pressure coefficient of the shale reservoir; fracture information includes fracture distribution (e.g., location distribution) and width; and salt crystallization information includes the type of salt crystals. Target injection parameters include CO2 temperature, pressure, and injection flow rate.

[0079] In some embodiments, the carbon dioxide storage system can determine the injection parameters (such as temperature, pressure, and flow rate) of carbon dioxide at different times based on a preset injection parameter configuration table. The injection parameter configuration table can be determined based on the engineering data of historical carbon dioxide storage operations. For example, the injection parameter configuration table includes target blocks (or areas) corresponding to multiple historical carbon dioxide storage operations, geological characteristics, fracture information, and salt crystallization-related information corresponding to the target blocks, and reference injection parameters adopted by historical carbon dioxide storage operations at different times or engineering cycles. The carbon dioxide storage system can retrieve and match (such as feature matching or vector matching) the reference injection parameters in the injection parameter configuration table based on the geological characteristics, fracture information, and salt crystallization-related information corresponding to the current target block, as target injection parameters.

[0080] In some embodiments, the CO2 storage system can determine target injection parameters using an injection parameter model based on geological characteristics, salt crystallization information, and fracture variation information. Fracture variation information refers to differences in fracture information (e.g., width) across a sequence of time periods, which can be used to reflect the sealing status of the fractures. For example, fracture variation information includes the change in fracture width between any two adjacent time periods, which can be collected using monitoring equipment (e.g., distributed acoustic wave sensors).

[0081] The injection parameter model can be a model built based on a machine learning algorithm. In some embodiments, it can be a trained machine learning model, such as a long short-term memory model (LSTM) or other neural network models.

[0082] In some embodiments, the inputs to the injection parameter model include geological characteristics, salt crystallization information, and fracture variation information, and the output includes predicted injection parameters for future time periods.

[0083] Fracture change information can be represented based on fracture information over a time series. For example, it can be a sequence of fracture information consisting of fracture information over multiple preset time periods up to the current moment. The preset time period can be determined based on the actual conditions of the CO2 storage operation, for example, 10 minutes, 20 minutes, etc.

[0084] The future time period may be one or more preset time periods after the current moment, such as the next 10 minutes. The predicted injection parameters include the temperature, pressure, and injection flow rate parameters of the carbon dioxide to be injected in the future time period.

[0085] In some embodiments, a trained injection parameter model can be obtained by iteratively training an initial model (such as an initial LSTM model). The training samples can be sample geological characteristics, sample salt crystallization information, and sample fracture information based on a sample time period sequence corresponding to a sample block in multiple historical carbon dioxide storage operations. The labels corresponding to the training samples can be the actual injection parameters of the sample future time periods corresponding to the sample time period sequence during the historical carbon dioxide storage operation. As an example only, the sample geological characteristics, sample salt crystallization information, and sample fracture information corresponding to T1 and T2 in the sample preset time period sequence {T1, T2} can be used as a group of training samples, and the actual injection parameters corresponding to a sample time period T3 after the sample preset time period sequence can be used as the label of the training sample. The label can be manually labeled or labeled in other ways.

[0086] During training, the loss function value can be determined based on the difference between the initial model's output and the training labels. The initial model's parameters can be iteratively updated based on the loss function value until the training termination criteria are met (e.g., the loss function converges, a specific number of iterations have been performed, etc.). The updated initial model can then be used as the trained parameter injection model.

[0087] In some embodiments of this specification, the differences in geological characteristics and salt crystal types in different regions or blocks are taken into account. At the same time, during the carbon dioxide storage operation, the fracture information (such as fracture width) in the shale reservoir will change as the fractures are blocked. In addition, when the fractures are blocked by salt crystals, the injection volume of carbon dioxide still needs to consider the fracture rupture pressure and the rupture pressure of the salt crystal layer to avoid the fracture and / or salt crystal layer from affecting the blocking effect. Through the injection parameter model, it is possible to fully learn the relationship between different geological characteristics, salt crystal information, fracture change information in different time periods, and the desired injection parameters, so that during the carbon dioxide storage operation, the control and / or adjustment of the carbon dioxide injection parameters are more accurate and more in line with the actual situation, while ensuring the normal operation of the carbon dioxide storage operation, reducing the risk of carbon dioxide leakage.

[0088] In some embodiments, the process 200 further includes the following step 241 and / or step 242 to further seal the crack.

[0089] In step 241 , a solution containing barium ions is injected into the shale reservoir to generate barium sulfate precipitates with sulfate ions in the shale reservoir, thereby further sealing the fractures.

[0090] In some embodiments, the solution containing barium ions may be a barium chloride (BaCl 2 ) solution having a predetermined barium concentration, wherein the predetermined barium concentration may be 0.5% to 2%.

[0091] Based on the formation of salt crystals (such as sodium chloride or calcium sulfate) in step 230, the carbon dioxide storage system can inject a solution containing barium ions into the shale reservoir through the carbon dioxide injection wells in the target block and the cracks in the shale reservoir. The barium ion solution penetrates into the salt crystal area in the cracks and reacts with sulfate ions (SO4 2- ) reacts to form barium sulfate (BaSO4) precipitate. The barium sulfate precipitate is used to fill the pores of the salt crystals, forming a double-sealing structure for the cracks.

[0092] In some embodiments, the carbon dioxide storage system can obtain the content or concentration of sulfate ions in the formation water collected by the monitoring equipment and adjust the concentration of the barium chloride solution based on a preset relationship table to ensure sufficient reaction. The preset relationship table can be generated based on historical data or experiments. For example, if the formation water SO4 2- The concentration is 1000 mg / L, and the concentration of the injected BaCl2 solution can be adjusted to 1.2%.

[0093] In some embodiments of the present specification, by forming barium sulfate precipitation, the permeability of the salt crystal layer in the crack can be reduced, and at the same time, the strength of the salt crystal layer can be further improved to prevent the salt crystal layer from rupturing and thus causing carbon dioxide leakage.

[0094] In step 242, urease-producing microorganisms are injected into the shale reservoir to generate carbonate minerals from their metabolic products and calcium ions in the shale reservoir, thereby further sealing the fractures.

[0095] The metabolism of urease-producing microorganisms can produce carbonate minerals (such as calcite), which fill the gaps between salt crystals and enhance the anti-dissolution ability of salt crystals. In some embodiments, the urease-producing microorganism can be Bacillus pasteurianus, whose metabolic products include carbonate (CO3 2- ) and ammonium ions (NH4 + Among them, carbonate ions and calcium ions (Ca 2+ ) combines to form calcite (CaCO3), which can fill the pores of salt crystals; ammonium ions can increase the pH value of the fracturing fluid and enhance the stability of calcite.

[0096] In some embodiments, the carbon dioxide storage system can inject a solution containing urease-producing microorganisms into the shale reservoir through the carbon dioxide injection wells in the target block and the fractures of the shale reservoir. 6 CFU / mL, accounting for 3% to 5% of the fracturing fluid in the fracture.

[0097] In some embodiments, the carbon dioxide storage system may also collect the pH value of the fracturing fluid in the fractures through monitoring equipment, and periodically inject a solution containing urease-producing microorganisms to maintain the pH value of the fracturing fluid at 8.5-9.0.

[0098] In some embodiments of this specification, calcite is generated by injecting a solution containing urease-producing microorganisms, which can reduce damage to the salt crystal sealing layer caused by salt crystallization dissolved in groundwater, improve the strength of the salt crystal sealing layer, and avoid carbon dioxide leakage caused by rupture of the salt crystal sealing layer.

[0099] In some embodiments of this specification, carbon dioxide injection is used to induce the conversion of highly salinized fracturing fluid trapped in the fractures of shale reservoirs into salt crystals. These salt crystals then seal the fractures, improving the safety of the shale reservoir for CO2 storage. This also reduces reservoir damage caused by the introduction of extraneous materials (such as solid / liquid plugging materials). Furthermore, it can reduce the cost of CO2 storage operations.

[0100] Figure 3 is a schematic diagram of a method for injecting carbon dioxide according to some embodiments of the present specification.

[0101] In some embodiments, the carbon dioxide storage system can control the injection of carbon dioxide and / or other fluids through a three-stage injection process. The three-stage injection process includes a first-stage injection phase, a second-stage injection phase, and a third-stage injection phase that are implemented in sequence. Figure 3 Steps 310, 320, and 330 correspond to the first, second, and third stages of injection. In each of the three stages, injection of carbon dioxide and / or other fluids can be achieved through the carbon dioxide injection wells and fractures in the shale reservoir in the target block.

[0102] Step 310: inject a first carbon dioxide into the shale reservoir.

[0103] In some embodiments, the carbon dioxide storage system may inject a first carbon dioxide into the shale reservoir through a carbon dioxide injection well in the target block and the fractures of the shale reservoir at a first temperature and a first pressure to remove free water in the fractures.

[0104] The first CO2 refers to the CO2 injected during the first injection phase. It can be gaseous CO2 that meets low-temperature and low-pressure conditions. These conditions refer to the first temperature and first pressure that must be met, such as the first temperature being less than a first temperature threshold and the first pressure being less than a first pressure threshold. The first temperature and first pressure can be determined based on the actual conditions of the target block (e.g., formation temperature, formation fracture pressure, etc.).

[0105] In some embodiments, the first temperature is in the range of 25-40° C., and the first pressure is in the range of 8-10 MPa.

[0106] The first carbon dioxide at the first temperature and first pressure state can be used to pre-cool the surface of the natural fracture, slow down the evaporation rate of water in the fracturing fluid, promote the migration of salt crystals to the deep part of the fracture, and expand the coverage of the subsequent fracturing fluid evaporation effect.

[0107] In some embodiments of the present specification, a one-stage injection link can expand the plugging range and, at the same time, remove free water in the fractures to make room for subsequent high-mineralization fracturing fluid.

[0108] Step 320: injecting a fracturing fluid having a salinity higher than a first preset threshold into the shale reservoir.

[0109] In some embodiments, the carbon dioxide storage system may inject a fracturing fluid having a salinity higher than a first preset threshold into the shale reservoir.

[0110] The fracturing fluid with a salinity higher than the first preset threshold value can be called a high-mineralization fracturing fluid, which can be determined based on the composition (such as Na + 、Cl - , Ca 2+ 、SO4 2- ) configuration (such as adding industrial salt, evaporation concentration, etc.)

[0111] In some embodiments, the injection pressure of the high-salinity fracturing fluid can be set to be lower than the first pressure during the first carbon dioxide injection, for example, it can be in the range of 7 to 9 MPa.

[0112] More information about the first preset threshold and fracturing fluid can be found elsewhere in this specification (e.g. Figure 1 、 Figure 2 ).

[0113] In some embodiments, the carbon dioxide injection well may include two pipelines: one pipeline is used to transport carbon dioxide (such as the first carbon dioxide and the second carbon dioxide), and the other pipeline is used to transport high-salinity fracturing fluid.

[0114] In some embodiments of this specification, the injection of high-mineralization fracturing fluid facilitates rapid salt crystallization in the subsequent three-stage injection process.

[0115] In some embodiments, step 320 (ie, the second-stage injection step) may be omitted.

[0116] Step 330: inject a second carbon dioxide into the shale reservoir.

[0117] In some embodiments, the carbon dioxide sequestration system may inject a second carbon dioxide into the shale reservoir based on a second temperature and a second pressure.

[0118] The second carbon dioxide refers to the carbon dioxide injected in the three-stage injection link, which can be carbon dioxide that meets the high temperature and high pressure conditions. The high temperature and high pressure conditions refer to the conditions required for the second temperature and the second pressure. For example, the second temperature is less than the second temperature threshold, and the second pressure is less than the second pressure threshold. The second temperature and the second pressure can be determined according to the actual situation of the target block and the parameters of the first carbon dioxide (such as the temperature, pressure, formation fracture pressure, etc. of the first carbon dioxide). For example, the second temperature is set to be higher than the first temperature; the second pressure is set to be higher than the first pressure and less than the formation fracture pressure.

[0119] In some embodiments, the second temperature is in the range of 60 to 80°C, and the second pressure is in the range of 12 to 15 MPa, at which point the second carbon dioxide is in a supercritical state. Supercritical carbon dioxide (SC-CO2) is a special fluid state formed when carbon dioxide is above its critical temperature (31.1°C) and critical pressure (7.38 MPa). At this point, carbon dioxide is neither a typical gas nor a liquid, but has characteristics of both, with unique physical and chemical properties. The second carbon dioxide in a supercritical state has a strong diffusion capacity and can accelerate the evaporation of water in the fracturing fluid.

[0120] In some embodiments, the carbon dioxide storage system may heat the second carbon dioxide using a heating device in the carbon dioxide injection well and monitor its temperature change to maintain the second carbon dioxide in a supercritical state.

[0121] In some embodiments of the present specification, based on the previous one-stage injection link and the two-stage injection link, the second carbon dioxide in the three-stage injection link can accelerate the rapid evaporation of the fracturing fluid in the natural fractures to accelerate the formation of salt crystals, thereby improving the sealing efficiency.

[0122] In some embodiments, before carbon dioxide is injected into the shale reservoir or after a portion of carbon dioxide is injected into the shale reservoir, a first sodium sulfate solution with a first concentration is injected through the carbon dioxide injection well in the target block and the fractures of the shale reservoir.

[0123] In some embodiments, the first sodium sulfate solution is injected before the first carbon dioxide injection and before the second carbon dioxide injection.

[0124] like Figure 3 As shown, before executing step 310, that is, before the first-stage injection phase, the carbon dioxide storage system can execute step 301 to inject a first sodium sulfate solution of a first concentration through the carbon dioxide injection well and the fractures of the shale reservoir. Step 301 can be referred to as a pre-injection phase.

[0125] The first sodium sulfate solution refers to the sodium sulfate solution injected into the front injection link, which can be a low-concentration sodium sulfate solution with a first concentration.

[0126] In some embodiments, the first concentration is in the range of 1% to 3% by mass.

[0127] Mass fraction is a concentration expression used to describe the mass ratio of a solute (e.g., sodium sulfate) to a solution or solvent. The CO2 storage system can inject a first sodium sulfate solution configured based on a first concentration into a shale reservoir through a CO2 injection well.

[0128] By injecting the first sodium sulfate solution of the first concentration to 2 +The reaction generates CaSO4 precipitate, which can initially block the nano-scale pores.

[0129] In some embodiments, after the carbon dioxide is injected, a second sodium sulfate solution with a second concentration is injected through the carbon dioxide injection well in the target block and the fractures of the shale reservoir, and the first concentration is less than the second concentration.

[0130] In some embodiments, the second sodium sulfate solution is injected after the second carbon dioxide.

[0131] like Figure 3 As shown, after step 330 is executed, that is, after the three-stage injection phase, the carbon dioxide storage system can execute step 305 to inject a second sodium sulfate solution of a second concentration through the carbon dioxide injection well and the fractures of the shale reservoir. Step 305 can be referred to as a post-injection phase.

[0132] The second sodium sulfate solution refers to the sodium sulfate solution injected in the post-injection link. It can be a sodium sulfate solution with a higher concentration than the first sodium sulfate solution.

[0133] In some embodiments, the second concentration is in the range of 5% to 8% by mass.

[0134] The carbon dioxide storage system can inject a second sodium sulfate solution configured based on a second concentration into the shale reservoir through a carbon dioxide injection well.

[0135] By injecting the second sodium sulfate solution of the second concentration, the high-concentration sodium sulfate solution can supplement and seal the residual pores in the cracks, further ensuring the sealing effect.

[0136] In some embodiments, the first sodium sulfate solution is mixed with a fracturing fluid having a salinity higher than a first preset threshold and then injected into the shale reservoir.

[0137] like Figure 3 As shown, when step 320 is executed, that is, in the second-stage injection link, the carbon dioxide storage system can execute step 303 to inject a mixture of the first sodium sulfate solution and the fracturing fluid with a salinity higher than a first preset threshold through the carbon dioxide injection well.

[0138] It should be noted that the implementation of the pre-injection link, the three-stage injection process (the first-stage injection link, the second-stage injection link and the third-stage injection link), and the post-injection link have an independent sequence in terms of timing, thereby avoiding direct mixing of the carbon dioxide sodium sulfate solution (such as the first sodium sulfate solution and the second sodium sulfate solution) and reducing chemical interference.

[0139] Figure 4is a schematic diagram of another method of injecting carbon dioxide according to some embodiments of the present specification.

[0140] In some embodiments, the CO2 storage system can adjust or manipulate CO2 injection parameters based on the salinity of different areas within the target region. Injection parameters include, but are not limited to, CO2 temperature, pressure, gas phase, additive type (e.g., barium ion-containing solution, urease-producing microorganisms, sodium sulfate solution, etc.), and CO2 injection timing.

[0141] In some embodiments, the CO2 storage system may be configured with a pre-defined salinity grading table. The salinity grading table includes multiple salinity levels, each corresponding to a different salinity range, and one or more injection parameters. The salinity levels may be expressed as numerical values (e.g., 1, 2, 3) or in other formats.

[0142] In some embodiments, the plurality of mineralization grades include a first grade, a second grade, and a third grade.

[0143] The first level is also called the low salinity level, which can be set to a salinity range less than or equal to a first preset threshold. The first level indicates that the salt concentration of the fracturing fluid is insufficient, making it difficult to effectively precipitate salt crystals to seal the cracks.

[0144] The second level, also known as the medium salinity level, can be set within a salinity range greater than the first preset threshold and less than the second preset threshold. This level indicates that the fracturing fluid has sufficient salt concentration to effectively precipitate salt crystals to seal the fractures, but requires optimization of fracture sealing uniformity and dissolution resistance.

[0145] The third level represents a high salinity level, which can be set to a salinity range greater than or equal to the second preset threshold. The third level indicates that the fracturing fluid has sufficient salt concentration and can quickly and effectively precipitate salt crystals to seal the fractures, without the need for additional treatment such as injecting additional additives.

[0146] The second preset threshold is greater than the first preset threshold. The second preset threshold can be determined based on experimental data. In some embodiments, the second preset threshold can be set to 5%.

[0147] The carbon dioxide storage system can determine the mineralization level corresponding to the mineralization of the block based on the mineralization classification table and then perform corresponding treatment.

[0148] In some embodiments, when the salinity corresponding to a block (e.g., a target block) is greater than a first preset threshold and less than a second preset threshold, at least one of a solution containing barium ions and a urease-producing microorganism is injected into the shale reservoir. Figure 4As shown, if the mineralization corresponding to the block is at the second level, the CO2 storage system can execute step 420 to inject CO2 into the shale reservoir. Simultaneously, a solution containing barium ions and / or urease-producing microorganisms can be injected into the shale reservoir. Injecting CO2 into the shale reservoir can be performed based on step 230, while injecting the solution containing barium ions and injecting urease-producing microorganisms can be performed based on steps 241 and 242, respectively.

[0149] In some embodiments, when the salinity corresponding to the block (such as the target block) is not less than the second preset threshold, the barium ion-containing solution and the urease-producing microorganisms do not need to be injected into the shale reservoir. Figure 4 As shown, if the mineralization corresponding to the block belongs to the third level, the carbon dioxide storage system can execute step 430 to inject carbon dioxide into the shale reservoir to achieve fracture sealing.

[0150] In some embodiments, as Figure 4 As shown, when the mineralization corresponding to the block is less than or equal to the first preset threshold value, the carbon dioxide storage system can proceed to step 410 to improve the mineralization of the block. Among them, the treatment of improving the mineralization includes but is not limited to injecting high-salinity fluid, heating or negative pressure evaporation of return fluid, etc. After step 410, the carbon dioxide storage system can determine the mineralization of the block again through monitoring equipment and / or mineralization measuring equipment to further determine whether its mineralization reaches the second level or the third level. When the mineralization of the block reaches the second level or the third level, the block can be used as a target area for salt crystallization and crack plugging. For example, the water body of the block can be sampled in real time to determine the actual mineralization after step 410. If it reaches the second level, step 420 can be performed; if it reaches the third level, step 430 can be performed; otherwise, step 410 can be continued to improve the mineralization.

[0151] For different blocks in the target area, different CO2 injection strategies can be determined based on their salinity, thereby improving the targeting and effectiveness of CO2 storage operations, reducing operational complexity and saving engineering costs.

[0152] Figure 5A It is a schematic diagram of the pore size distribution before and after the shale salt crystallization experiment shown in some embodiments of this specification.

[0153] The effect of sealing natural fractures in target area reservoirs (such as shale reservoirs) by means of salt crystallization (hereinafter referred to as fracture sealing effect) can be evaluated through control experiments on experimental samples.

[0154] Experimental samples include geological samples. Geological samples can be one or a combination of rocks, fluids, minerals, and other substances used in control experiments. They can be collected using various collection equipment (such as exploration equipment) at different sampling locations in the target area (such as the surface, reservoirs, etc.).

[0155] In some embodiments, the geological sample includes a shale sample and a fracturing fluid sample from the target area. The shale sample can be selected from shale with a pore distribution structure. The pore distribution structure of the shale sample reflects relevant information about the natural fractures in the shale reservoir (such as the number of fractures, fracture connectivity paths, fracture width, and pores). The fracturing fluid sample can be selected from surface flowback fracturing fluid with different salinities and / or fracturing fluid retained in the fractures of the reservoir.

[0156] In some embodiments, geological samples corresponding to different blocks in the target area can be collected separately to obtain shale samples with different pore distributions and fracturing fluid samples with different salinities. Shale samples with different pore distributions can be combined with fracturing fluid samples with different salinities to obtain multiple groups of experimental samples for multiple control experiments.

[0157] The experimental samples may also include other substances, for example, salt additives such as sodium chloride solution, to be used for control experiments simulating more scenarios (such as fracturing fluids with higher mineralization).

[0158] The control experiment is used to determine the changes in the geological samples before and after the salt crystallization experiment. In some embodiments, for a set of experimental samples (such as shale samples and fracturing fluid samples), the control experiment includes the following steps.

[0159] Step 510: Before performing a crystallization experiment, the shale sample is dried to obtain a first shale sample.

[0160] Then, the permeability of the first shale sample is determined by a pulse method or the like, and the pore size distribution of the first shale sample is determined by a mercury injection method or the like, thereby obtaining original data such as the permeability and pore size distribution of the first shale sample before the crystallization experiment.

[0161] Then, a salt crystallization experiment is performed based on the following steps 520 to 540:

[0162] In step 520 , a core vacuum saturation device is used to perform plug saturation treatment on the first shale sample with a fracturing fluid sample of a certain salinity to obtain a second shale sample.

[0163] In step 530, a second shale sample is placed in a core holder and subjected to a dynamic evaporation-induced salt crystallization experiment using gas phase displacement by injecting carbon dioxide. During the carbon dioxide injection process, salt crystals precipitate from the fracturing fluid sample in the second shale sample, filling pore structures (e.g., pores and cracks). At this point, a third shale sample is obtained.

[0164] In step 540, the third shale sample is dried, and the permeability of the third shale sample is determined by a pulse method or the like, and the pore size distribution of the third shale sample is determined by a mercury injection method or the like, thereby obtaining experimental data on the permeability and pore size distribution of the third shale sample after the crystallization experiment.

[0165] Experimental data can be used to reflect the blocking effect of salt crystallization on pores, for example, cracks are filled and pore diameters are reduced.

[0166] Figure 5B Schematic diagram of a scanning electron microscope image after a shale salt crystallization experiment according to some embodiments of this specification.

[0167] In some embodiments, the experimental data further includes a scanning electron microscope image, which can be obtained by scanning the third shale sample using a scanning electron microscope. The scanning electron microscope image can be used to observe the morphology of salt crystals in the fractures.

[0168] like Figure 5B As shown, salt crystals formed in the shale samples after the salt crystallization experiment. These crystals were distributed along the pores of the shale samples (such as the third shale sample), forming salt crystal lines and covering the cracks and / or pores. This indicates that the injected CO2 has a good sealing effect on the cracks in the shale samples after the salt crystallization experiment.

[0169] It should be noted that the shale samples before and after the experiment are based on the same shale sample in the same experimental sample group. The comparative data of this group of experimental samples reflects the differences between the original data before the experiment and the experimental data after the experiment, for example, changes in permeability and pore size distribution.

[0170] Multiple sets of comparative data can be obtained by repeating steps 510 to 540 using multiple sets of experimental samples. For example, another shale sample and a fracturing fluid sample with another salinity are used as another set of experimental samples, and comparative data for this set of experimental samples is obtained based on steps 510 to 540.

[0171] According to comparative data (e.g., permeability change comparison data), before the experiment, the salinity of the fracturing fluid samples was 1.8% and 2.2%, respectively. After the experiment, the permeability reduction rates of the shale samples were 69.97% and 85.45%, respectively. This comparative data indicates that when the salinity of the fracturing fluid sample is greater than 2%, salt crystals are more likely to form. Therefore, in some embodiments, the first preset threshold value may be 2%.

[0172] Figure 5A Shown is a graph of one set of comparative data. The curve corresponding to the circular legend is the pore size distribution data of the shale sample before the salt crystallization experiment, and the curve corresponding to the triangle legend is the pore size distribution data of the shale sample after the salt crystallization experiment.

[0173] like Figure 5A As shown, the horizontal axis of the curve is used to represent the pore size of the shale sample (such as 10nm, 100nm, etc.). The size of the pore size represents the width of the crack.

[0174] The vertical axis of the curve represents the staged mercury injection volume. Cracks of different pore sizes can accommodate different amounts / volumes of mercury. The staged mercury injection volume reflects the total volume / total capacity of pores (cracks) within different pore size ranges (e.g., 1-10 nm, 10-20 nm, etc.).

[0175] Salt crystallization can block fractures (i.e., pores), reducing pore size and, consequently, pore volume, which in turn reduces the amount of mercury the pores can accommodate. Comparing the mercury injection rates before and after the crystallization experiment reveals the effectiveness of blocking fractures of different pore sizes within the shale sample. Therefore, by analyzing the differences in mercury injection rates before and after the experiment for different pore size ranges, we can determine the pore size range with the optimal blocking effect.

[0176] For example, Figure 5A As shown in the graph, for pore sizes greater than 100 nm on the horizontal axis, the amount of mercury injected during each stage changes significantly before and after the experiment, while for pore sizes less than 100 nm, the amount of mercury injected during each stage changes little before and after the experiment. This indicates that salt crystals are more likely to block cracks larger than 100 nm.

[0177] It should be noted that the above description of the relevant processes is for illustration and purpose only and does not limit the scope of application of this specification. For those skilled in the art, various modifications and changes can be made to the processes under the guidance of this specification. However, such modifications and changes are still within the scope of this specification.

[0178] While the basic concepts have been described above, it will be apparent to those skilled in the art that the detailed disclosure is merely illustrative and does not limit this specification. Although not explicitly stated herein, various modifications, improvements, and revisions to this specification may be made by those skilled in the art. Such modifications, improvements, and revisions are suggested in this specification and remain within the spirit and scope of the exemplary embodiments of this specification.

[0179] This specification also uses specific terms to describe the embodiments of this specification. For example, "one embodiment," "an embodiment," and / or "some embodiments" refer to a feature, structure, or characteristic associated with at least one embodiment of this specification. Therefore, it should be emphasized and noted that references to "one embodiment," "an embodiment," or "an alternative embodiment" two or more times in different locations in this specification do not necessarily refer to the same embodiment. Furthermore, certain features, structures, or characteristics of one or more embodiments of this specification may be appropriately combined.

[0180] In addition, unless expressly stated in the claims, the order of the processing elements and sequences, the use of alphanumeric characters, or the use of other names described in this specification are not intended to limit the order of the processes and methods of this specification. Although the above disclosure discusses some of the invention embodiments currently considered useful through various examples, it should be understood that such details are for illustrative purposes only, and the appended claims are not limited to the disclosed embodiments. On the contrary, the claims are intended to cover all modifications and equivalent combinations that are consistent with the spirit and scope of the embodiments of this specification. For example, although the system components described above can be implemented by hardware devices, they can also be implemented only by software solutions, such as installing the described system on an existing server or mobile device.

[0181] Similarly, it should be noted that, in order to simplify the presentation of this specification and thus facilitate understanding of one or more embodiments of the invention, the foregoing descriptions of the embodiments of this specification sometimes combine multiple features into a single embodiment, figure, or description thereof. However, this disclosure method does not imply that the subject matter of this specification requires more features than those recited in the claims. In fact, an embodiment may have fewer features than all of the features of a single disclosed embodiment.

[0182] In some embodiments, numbers are used to describe the quantity of components and attributes. It should be understood that such numbers used in the description of the embodiments are modified by the modifiers "about", "approximately" or "substantially" in some examples. Unless otherwise stated, "about", "approximately" or "substantially" indicate that the numbers are allowed to vary by ±20%. Accordingly, in some embodiments, the numerical parameters used in the description and claims are approximate values, which may change according to the required characteristics of individual embodiments. In some embodiments, the numerical parameters should take into account the specified significant digits and adopt the general method of retaining digits. Although the numerical domains and parameters used to confirm the breadth of their range in some embodiments of this specification are approximate values, in specific embodiments, the settings of such numerical values are as accurate as possible within the feasible range.

[0183] Each patent, patent application, patent application publication, and other materials, such as articles, books, specifications, publications, and documents, cited in this specification is hereby incorporated by reference in its entirety. This includes application history documents that are inconsistent with or conflict with the content of this specification, as well as documents (currently or subsequently attached to this specification) that limit the broadest scope of the claims of this specification. It should be noted that if the descriptions, definitions, and / or terminology used in the accompanying materials are inconsistent or conflicting with the content of this specification, the descriptions, definitions, and / or terminology used in this specification will control.

[0184] Finally, it should be understood that the embodiments described in this specification are intended only to illustrate the principles of the embodiments of this specification. Other variations may also fall within the scope of this specification. Therefore, by way of example and not 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 described and illustrated in this specification.

Claims

1. A method for carbon dioxide sequestration, characterized in that: The method comprises: For each of a plurality of blocks in a target area, determining the salinity of the flowback fracturing fluid in the block; Selecting a target block having a mineralization not less than a first preset threshold from the plurality of blocks; Carbon dioxide is injected into the shale reservoir through the carbon dioxide injection wells in the target block and the cracks in the shale reservoir, so that the retained fracturing fluid in the cracks reaches a supersaturated state due to the evaporation of the carbon dioxide gas flow, thereby precipitating salt crystals to seal the cracks.

2. The method according to claim 1, characterized in that The first preset threshold is 2%.

3. The method according to claim 1, characterized in that The crack is a natural crack with a width of not less than 100 nm.

4. The method according to claim 1, wherein The salt crystals include at least one of sodium chloride or calcium sulfate.

5. The method according to claim 1, wherein The method further comprises: Before the carbon dioxide is injected into the shale reservoir or after a portion of the carbon dioxide is injected into the shale reservoir, injecting a first sodium sulfate solution with a first concentration through the carbon dioxide injection well in the target block and the fractures of the shale reservoir; and After injecting the carbon dioxide, a second sodium sulfate solution with a second concentration is injected through the carbon dioxide injection well in the target block and the fractures of the shale reservoir, wherein the first concentration is lower than the second concentration.

6. The method according to claim 1, characterized in that The step of injecting carbon dioxide into the shale reservoir through the carbon dioxide injection well in the target block and the fractures in the shale reservoir comprises: Through the carbon dioxide injection wells and fractures in the shale reservoir in the target block, injecting a first carbon dioxide into the shale reservoir based on a first temperature and a first pressure to remove free water in the fracture; injecting a fracturing fluid having a salinity higher than the first preset threshold into the shale reservoir; A second carbon dioxide is injected into the shale reservoir based on a second temperature and a second pressure, wherein the first temperature is lower than the second temperature, and the first pressure is lower than the second pressure.

7. The method according to claim 6, characterized in that: The first temperature is in the range of 25-40° C., and the first pressure is in the range of 8-10 MPa; The second temperature is in the range of 60 to 80° C., the second pressure is in the range of 12 to 15 MPa, and the second carbon dioxide is in a supercritical state.

8. The method according to claim 1, characterized in that The method further comprises: injecting a solution containing barium ions into the shale reservoir through the carbon dioxide injection wells in the target block and the fractures in the shale reservoir to form barium sulfate precipitates with sulfate ions in the shale reservoir, thereby further plugging the fractures; and / or Urease-producing microorganisms are injected into the shale reservoir through the carbon dioxide injection wells in the target block and the cracks in the shale reservoir, so that their metabolites react with sulfate calcium ions in the shale reservoir to generate carbonate minerals, further sealing the cracks.

9. The method according to claim 8, characterized in that In response to the salinity corresponding to the target block being less than a second preset threshold, at least one of the barium ion-containing solution and the urease-producing microorganism is injected into the shale reservoir, wherein the second preset threshold is greater than the first preset threshold; or In response to the salinity corresponding to the target block being no less than a second preset threshold, the barium ion-containing solution and the urease-producing microorganism do not need to be injected into the shale reservoir.

10. A system for carbon dioxide storage, characterized in that: include: a salinity measurement device configured to measure the salinity of the flowback fracturing fluid in each of a plurality of blocks in the target area; A processing device configured to select a target block having a mineralization not less than a first preset threshold from the plurality of blocks; The carbon dioxide injection equipment is configured to inject carbon dioxide into the shale reservoir through the carbon dioxide injection wells in the target block and the cracks in the shale reservoir, so that the retained fracturing fluid in the cracks reaches a supersaturated state due to the evaporation of the carbon dioxide gas flow, thereby precipitating salt crystals to seal the cracks.

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