A method and system for carbon dioxide sequestration

Abstract

This specification provides a method and system for carbon dioxide sequestration. The method includes: determining the salinity of the flowback fracturing fluid in each of multiple blocks in a target area; selecting a target block from the multiple blocks whose salinity is not less than a first preset threshold; injecting carbon dioxide into the 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 the evaporation of carbon dioxide gas flow, thereby precipitating salt crystals to seal the fractures.

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 Technology

[0002] The development of shale oil and gas reservoirs typically employs hydraulic fracturing technology to create artificial fractures within the reservoir, connecting them to natural fractures. This enhances the permeability of oil and gas resources (such as shale gas), thereby enabling their extraction. In the field of carbon dioxide sequestration, the natural reservoir space is usually utilized for carbon dioxide storage. However, reservoir fractures (such as natural fractures) are critical pathways for oil and gas migration and potential escape routes for carbon dioxide, posing a risk of leakage during carbon dioxide sequestration. Therefore, sealing reservoir fractures is a problem that needs to be addressed in carbon dioxide sequestration operations.

[0003] Currently, the primary method for sealing reservoir fractures is to introduce substances from outside the reservoir. However, these materials can trigger a series of physicochemical reactions, leading to negative effects such as solid-phase blockage, liquid-phase blockage, and mineral precipitation, resulting in reservoir damage or environmental pollution. Furthermore, these materials tend to settle and are difficult to penetrate natural fractures, resulting in suboptimal sealing effectiveness. Additionally, the widespread distribution of reservoir fractures necessitates the use of large quantities of sealing materials, significantly increasing the cost of carbon dioxide sequestration.

[0004] Therefore, a method and system for carbon dioxide sequestration are provided, which simultaneously seals fractures in the reservoir while performing carbon dioxide sequestration, thereby improving the safety of carbon dioxide sequestration and reducing costs. Summary of the Invention

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

[0006] One embodiment of this specification provides a system for carbon dioxide sequestration, 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 from the plurality of blocks with a mineralization not less than a first preset threshold; and a carbon dioxide injection device configured to inject carbon dioxide into the shale reservoir through a carbon dioxide injection well in the target block and fractures in the shale reservoir, so that the retained fracturing fluid in the fractures reaches a supersaturated state due to the evaporation of carbon dioxide gas flow, thereby precipitating salt crystals to seal the fractures. Attached Figure Description

[0007] This specification will be further described by way of exemplary embodiments, which will be described in detail with reference to the accompanying drawings. These embodiments are not limiting; in these embodiments, the same reference numerals denote the same structures, wherein: Figure 1 These are scene diagrams of a carbon dioxide sequestration system according to some embodiments of this specification; Figure 2 This is an exemplary flowchart of a carbon dioxide sequestration method according to some embodiments of this specification; Figure 3 This is a schematic diagram of a method for injecting carbon dioxide according to some embodiments of this specification; Figure 4 This is a schematic diagram of another method of injecting carbon dioxide according to some embodiments of this specification; Figure 5A This is a schematic diagram showing the pore size distribution before and after shale salt crystallization experiments according to some embodiments of this specification; Figure 5B This is a schematic diagram of scanning electron microscope images of shale salt crystallization experiments as shown in some embodiments of this specification. Detailed Implementation

[0008] To more clearly illustrate the technical solutions of the embodiments in this specification, the accompanying drawings used in the description of the embodiments will be briefly introduced below. Obviously, the drawings described below are merely some examples or embodiments of this specification. For those skilled in the art, these drawings can be applied to other similar scenarios without creative effort. Unless obvious from the context or otherwise specified, the same reference numerals in the drawings represent the same structures or operations.

[0009] It should be understood that the terms “system,” “device,” “unit,” and / or “module” used herein are one way to distinguish different components, elements, parts, sections, or assemblies at different levels. However, if other terms can achieve the same purpose, they may be replaced by other expressions.

[0010] Unless the context clearly indicates an exception, words such as "a," "an," "a kind," and / or "the" do not specifically refer to the singular and may also include the plural. Generally speaking, the terms "comprising" and "including" only indicate the inclusion of explicitly identified steps and elements, which do not constitute an exclusive list, and the method or apparatus may also include other steps or elements.

[0011] Flowcharts are used in this specification to illustrate the operations performed by the system according to embodiments of this specification. It should be understood that the preceding or following operations are not necessarily performed in exact order. Instead, the steps can be processed in reverse order or simultaneously. Furthermore, other operations can be added to these processes, or one or more steps can be removed from them.

[0012] Figure 1 This is a schematic diagram of a carbon dioxide storage system according to some embodiments of this specification.

[0013] like Figure 1 As shown, the carbon dioxide sequestration system 100 may include a processing device 110, a mineralization measuring device 120, a carbon dioxide injection device 130, a carbon dioxide storage device 140, and a carbon dioxide injection well 150.

[0014] Processing device 110 can be used to analyze and / or process information and / or data in carbon dioxide sequestration system 100. In some embodiments, processing device 110 includes computer processing equipment. For example, processing device 110 may include a central processing unit (CPU), application-specific integrated circuit (ASIC), application-specific instruction set processor (ASIP), digital signal processor (DSP), microcontroller unit, etc., or any combination thereof. In some embodiments, processing device 110 may be a single server or a group of servers. The server group may be centralized or distributed (e.g., processing device 110 may be a distributed system).

[0015] Processing device 110 can be used to control one or more components (such as mineralization measuring device 120, carbon dioxide injection device 130, and carbon dioxide storage device 140) in carbon dioxide sequestration system 100. In some embodiments, processing device 110 can send control commands (such as program commands or control signals) to carbon dioxide injection device 130 to instruct carbon dioxide injection device 130 to inject carbon dioxide into shale reservoir 180 through carbon dioxide injection well 150 in a target block. Further related information can be found elsewhere in this specification (e.g., Figure 2 ).

[0016] The mineralization measuring device 120 may include equipment for determining the mineralization of geological samples from a target area. The geological samples may be soil or rock, or fluids (e.g., formation water, surface runoff fluid, etc.) from the target area.

[0017] The mineralization measurement device 120 may include sampling equipment (such as a geological sample collection container), a conductivity meter, an ion chromatograph, and other equipment. In some embodiments, for each of multiple blocks in a target area, the mineralization measurement device 120 may be used to determine the mineralization of the fracturing fluid in each block to identify the target block. More information about target areas, blocks, and fracturing fluids can be found elsewhere in this specification (e.g., Figure 2 ).

[0018] In some embodiments, during carbon dioxide sequestration operations, the mineralization measurement device 120 can be used to measure the mineralization 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 carbon dioxide sequestration operation based on the mineralization. For more related content, see [link to relevant documentation]. Figure 4 And its description.

[0019] Carbon dioxide injection equipment 130 refers to equipment used in carbon dioxide sequestration operations to inject carbon dioxide into shale reservoirs. Carbon dioxide injection equipment 130 may include various devices for processing, transporting, and migrating carbon dioxide, and its design can be determined based on the specific needs of the carbon dioxide sequestration operation. For example, carbon dioxide injection equipment 130 may include delivery pipelines to facilitate the migration (e.g., directional migration) of carbon dioxide within or within a portion of the shale reservoir.

[0020] In some embodiments, the carbon dioxide injection device 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 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 process the carbon dioxide by cooling, heating, pressurizing, etc., so that the carbon dioxide meets requirements such as temperature, pressure, or phase (e.g., supercritical state).

[0021] In some embodiments, the carbon dioxide injection device 130 (such as a carbon dioxide control device) can adjust one or more control parameters (such as temperature and pressure) in response to control commands from the processing device 110. In some embodiments, the processing device 110 may be integrated into the carbon dioxide injection device 130 (such as a carbon dioxide control device).

[0022] Carbon dioxide storage device 140 is used to store carbon dioxide that needs to be sealed, and it can be various containers (such as storage tanks) or locations (such as underground temporary storage facilities). The carbon dioxide can be one or more combinations of different phases (gaseous, liquid, or supercritical state) of carbon dioxide.

[0023] The carbon dioxide storage device 140 can be determined according to the actual needs of carbon dioxide storage operations (such as capacity, material, and phase of carbon dioxide). For example, it can be an ambient temperature and pressure storage tank for storing gaseous carbon dioxide, a cryogenic and high-pressure storage tank for storing liquid carbon dioxide, or a high-temperature and high-pressure storage tank for storing supercritical carbon dioxide.

[0024] A carbon dioxide injection well 150 is a well located in the target area to connect the surface of the target area to the shale reservoir 180, thereby injecting carbon dioxide into the shale reservoir 180. One or more carbon dioxide injection wells 150 may be installed in each block of the target area. Figure 1 As shown, the carbon dioxide injection well 150 includes carbon dioxide injection well 150-1, carbon dioxide injection well 150-2, ..., carbon dioxide injection well 150-n.

[0025] Shale reservoir 180 refers to a geological structure used for carbon dioxide sequestration, 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 unminable coal seams, and basic-ultrabasic rocks. Shale reservoirs are mainly composed of low-porosity, low-permeability shale, possessing 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 degree not less than a first preset threshold, such as marine shale gas reservoirs, deep saline aquifers, etc. More information about mineralization can be found elsewhere in this specification (e.g., Figure 2 ).

[0026] In some embodiments, the layout / location of carbon dioxide injection wells 150 (such as well location, number of wells, well depth, diameter, etc.) can be determined based on reservoir-related information of the shale reservoir 180. Reservoir-related information includes information such as the depth of the shale reservoir, reservoir area, reservoir thickness, fracture pressure coefficient, and fracture distribution (such as the location distribution of natural fractures).

[0027] For example, the location of carbon dioxide injection well 150 corresponding to different blocks in the target area can be determined based on the fracture distribution of the shale reservoir corresponding to that block, so that the injected carbon dioxide can be quickly transported to the fracture concentration area of ​​the shale reservoir, thereby improving the efficiency of fracture plugging and carbon dioxide storage operations.

[0028] In some embodiments, the carbon dioxide sequestration system 100 further includes a monitoring device 160 for collecting various monitoring data or information related to the carbon dioxide sequestration operation, which can be determined according to the actual needs of the carbon dioxide sequestration operation. In some embodiments, the monitoring device 160 includes surface sensors and underground sensors.

[0029] Ground sensors refer to sensors deployed on the ground in a target area to collect ground monitoring data, including but not limited to data on temperature, humidity, air pressure, and wind speed. Accordingly, ground sensors may include thermometers, hygrometers, barometers, and anemometers. In some embodiments, the ground sensors also include carbon dioxide leak detectors (such as infrared spectrometers) to monitor for carbon dioxide leaks during carbon dioxide sequestration operations, thereby ensuring the safety of the carbon dioxide sequestration operation.

[0030] Subsurface sensors refer to sensors deployed beneath the surface of the target area to collect subsurface monitoring data during carbon dioxide sequestration operations. This subsurface monitoring data includes monitoring data from the injection well corresponding to carbon dioxide injection well 150 and monitoring data from the shale reservoir corresponding to the shale reservoir.

[0031] 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 data such as the carbon dioxide flow rate or velocity in the well, the phase state of carbon dioxide, the temperature in the well, and the gas pressure in the well.

[0032] In some embodiments, the underground sensor includes an ultrasonic flow meter deployed within the carbon dioxide injection well 150 for real-time monitoring of the instantaneous flow rate and / or velocity of carbon dioxide within the well; the underground sensor also includes a plurality of temperature sensors and pressure sensors deployed within the carbon dioxide injection well 150 for real-time monitoring of the well temperature and well pressure at multiple locations within the well.

[0033] Shale reservoir monitoring data is used to reflect the real-time situation of shale reservoirs, including but not limited to data such as carbon dioxide flow rate or velocity, reservoir temperature, and reservoir pressure in shale reservoirs (such as shale reservoir 180 shown in the figure).

[0034] In some embodiments, the underground sensors include various distributed fiber optic sensors deployed in a target area (such as one or more blocks) to acquire 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.

[0035] In some embodiments, the underground sensor further includes a distributed acoustic sensor for monitoring the flow rate or velocity of carbon dioxide transported in the shale reservoir, as well as monitoring fracture information in the shale reservoir (such as fracture distribution, fracture width, fracture propagation, or fracture plugging status (such as the plugging status of salt crystals)).

[0036] In some embodiments, the monitoring device 160 can interact with other components of the carbon dioxide sequestration system 100 for data and / or information exchange. For example, the monitoring device 160 can feed back monitoring data (such as surface monitoring data, subsurface monitoring data) to the processing device 110. As another example, the monitoring device 160 can send monitoring data to the terminal devices (such as mobile devices) of users (such as managers, engineers).

[0037] The monitoring device 160 may also include other equipment or devices. For example, the monitoring device 160 may also include seismic monitoring equipment to collect data on microseismic events that may be induced during the carbon dioxide injection operation in order to assess the safety of the carbon dioxide injection operation.

[0038] In some embodiments of this specification, monitoring equipment can be used to track the real-time status of various stages of carbon dioxide sequestration operations (such as wellhead injection, in-well migration, migration in shale reservoirs, fracture plugging, etc.) to ensure the normal progress of carbon dioxide sequestration operations.

[0039] The carbon dioxide sequestration system 100 may also include other equipment or components.

[0040] In some embodiments, the carbon dioxide sequestration system 100 also includes a network (not shown) for facilitating information and / or data exchange. The network can be a wired or wireless network. In some embodiments, one or more components of the carbon dioxide sequestration system 100 (e.g., processing device 110, carbon dioxide injection device 130, etc.) can transmit information and / or data with one or more other components of the carbon dioxide sequestration system 100 via the network. As an example only, the processing device 110 can send instructions (such as program instructions, control signals) to the carbon dioxide injection device 130 via the network to control the carbon dioxide injection device 130 to inject carbon dioxide into the shale reservoir of a target block.

[0041] In some embodiments, the carbon dioxide sequestration system 100 further includes a terminal device (not shown), such as a mobile device, tablet computer, 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., administrators, engineers). In some embodiments, the terminal device can present monitoring information related to carbon dioxide sequestration to the user. For example, the monitoring information includes, but is not limited to, the amount and rate of carbon dioxide injection, the pressure and temperature of the shale reservoir, etc., and the monitoring information can be one or more combinations of text, images, audio, and video information.

[0042] The above description is for illustrative purposes only, and actual application scenarios may vary.

[0043] 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. Those skilled in the art can make various modifications or variations based on the description in this specification. However, these modifications and variations will not depart from the scope of this specification.

[0044] Figure 2 This is an exemplary flowchart of a method for carbon dioxide sequestration according to some embodiments of this specification.

[0045] In some embodiments, process 200 can be executed by a carbon dioxide sequestration system. For example, process 200 can be executed by a processing device (such as processing device 110), or by a processing device controlling one or more components of the carbon dioxide sequestration system (such as mineralization measurement device 120, carbon dioxide injection device 130, etc.) to achieve the functions described in the steps of process 200. Figure 2 As shown, process 200 includes the following steps.

[0046] Step 210: For each of the multiple blocks in the target area, determine the salinity of the flowback fracturing fluid in the block.

[0047] The target area refers to the geographical area where carbon dioxide sequestration is required. It can be any geological body suitable for carbon dioxide sequestration. For example, the target area can be the area corresponding to a depleted oil reservoir or a depleted oil and gas reservoir.

[0048] In some embodiments, the carbon dioxide sequestration system can select a target region based on the geological characteristics of one or more candidate geographic regions. Geological characteristics include, but are not limited to, reservoir type (such as shale reservoir), reservoir area, reservoir thickness, geothermal gradient, formation pressure, porosity, permeability, fracture pressure coefficient, etc.

[0049] Carbon dioxide sequestration systems can determine target areas based on a pre-set scoring table. This table includes multiple geological features and corresponding scores for indicators such as carbon dioxide sequestration capacity, economic viability (construction difficulty), and safety (e.g., environmental pollution). Candidate geographical areas with high comprehensive scores (e.g., the sum of each indicator) can be used as target areas. For more information on shale reservoirs, see [link to relevant documentation]. Figure 1 And its description.

[0050] A block refers to a sub-region within a target area. A carbon dioxide sequestration system can divide a target area into multiple sub-regions. For example, based on the size of the target area, it can be divided into a preset number of regular (grid sub-regions) and / or irregular sub-regions, each corresponding to a block.

[0051] In some embodiments, the carbon dioxide sequestration system can divide the area into blocks based on the distribution of fractures in the formation of the target region. For example, a block can be defined as an area with a high density of fractures.

[0052] Mineralization reflects the concentration of salts in the flowback fracturing fluid of a target area or block. Salts include, but are not limited to, sodium chloride and calcium sulfate. Flowback fracturing fluid is the liquid mixture that flows back from the wellbore to the surface after hydraulic fracturing operations in oil and gas wells. It is a mixture of fracturing fluid and formation fluids (such as crude oil, natural gas, and formation water).

[0053] The carbon dioxide sequestration system can measure the salinity of flowback fracturing fluid samples from each block, and use this as the salinity for each block. For example, for a given block, the average salinity of the flowback fracturing fluid collected from different sampling points is taken as the salinity for that block.

[0054] Step 220: Select a target block from multiple blocks whose mineralization is not less than a first preset threshold.

[0055] A target block refers to a block suitable for carbon dioxide sequestration operations. For example, a target block could be a block suitable for drilling (such as deploying carbon dioxide injection wells) or for carbon dioxide transport.

[0056] In some embodiments, the target block includes blocks suitable for salt crystallization. A first preset threshold can be used to assess whether the mineralization of each block is conducive to salt crystallization, thereby facilitating salt crystallization during subsequent carbon dioxide injection into the shale reservoir and achieving fracture sealing.

[0057] The first preset threshold can be determined based on historical experience. For example, it can be determined based on the leakage situation of carbon dioxide storage in historical carbon dioxide storage operations with different mineralization levels. As an example only, the first preset threshold could be 5%, 7%, etc.

[0058] In some embodiments, the first preset threshold is 2%. This value can be obtained based on comparative experimental data from shale salt crystallization experiments. See more details... Figure 5A and Figure 5B .

[0059] In some embodiments, the carbon dioxide sequestration system can sort multiple blocks in the target area according to the mineralization degree of each block (e.g., in descending order), and select one or more blocks with a mineralization degree greater than a first preset threshold as target blocks.

[0060] Step 230: Carbon dioxide is injected into the shale reservoir through the carbon dioxide injection well in the target block and the fractures in the shale reservoir, so that the residual fracturing fluid in the fractures reaches a supersaturated state due to the evaporation of carbon dioxide gas flow, thereby precipitating salt crystals to seal the fractures.

[0061] Fractures in shale reservoirs serve as pathways for the diffusion and migration of fluids (such as oil, gas, water, and carbon dioxide) within the reservoir. Fractures can be natural or artificial (such as those created by hydraulic fracturing).

[0062] In some embodiments, for shale reservoirs corresponding to a target block, the carbon dioxide sequestration system can determine fracture information of the target block based on detection data collected by various monitoring devices (such as distributed acoustic sensors). More information about monitoring devices can be found elsewhere in this specification (e.g., Figure 1 ).

[0063] In some embodiments, the carbon dioxide sequestration system can determine fracture information using data from tracer testing. For example, after injecting a chemical / 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.

[0064] It should be noted that during carbon dioxide sequestration operations, when carbon dioxide is injected into the shale reservoir through a carbon dioxide injection well, the flowing carbon dioxide acts on the fracturing fluid with a certain degree of mineralization retained in the fractures (i.e., retained fracturing fluid). This causes the retained fracturing fluid to precipitate salt crystals after reaching a supersaturated state, thus filling the natural fractures and creating a sealing effect. The effects of the flowing carbon dioxide on the retained fracturing fluid include, but are not limited to, promoting water loss (e.g., water evaporation), changes in the temperature and pressure of the retained fracturing fluid, and changes in the solubility of salts in the retained fracturing fluid, thereby causing changes in the salt concentration of the retained fracturing fluid. For more information on carbon dioxide injection, see [link to relevant documentation]. Figure 3 and Figure 4 And its description.

[0065] In some embodiments, the location of the carbon dioxide injection well and the carbon dioxide injection parameters are related to the fracture width.

[0066] In some embodiments, the crack is a natural crack with a width of not less than 100 nm.

[0067] Natural fractures refer to fractures that form naturally in shale reservoirs. The fracture network formed by natural fractures in shale reservoirs covers a wide area. Fracture width affects the rate and ease of salt crystallization in retained fracturing fluid, thus affecting the effectiveness of fracture plugging. Natural fractures with a width of at least 100 nm generally show better salt crystallization plugging effects. In carbon dioxide storage operations, based on the distribution of natural fractures, selecting concentrated points with a width of at least 100 nm as carbon dioxide injection points (e.g., deploying carbon dioxide injection wells) makes fracture plugging with carbon dioxide more targeted and improves the efficiency of carbon dioxide storage. For more information on fracture width and plugging effectiveness, see [link to relevant documentation]. Figure 5B And its description.

[0068] In some embodiments, the location of the carbon dioxide injection well and the carbon dioxide 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, pressure, etc.), thereby affecting the rate at which salt crystals precipitate from the retained fracturing fluid.

[0069] In some embodiments, the carbon dioxide sequestration system can determine the type of salt crystallization based on the salt composition of the retained fracturing fluid. Preferred salts include those with high solubility differences. Salts with high solubility differences are those whose solubility changes significantly with various conditions (such as temperature, pressure, and the salinity of the fracturing fluid).

[0070] In some embodiments, the salt crystals include at least one of sodium chloride or calcium sulfate. Sodium chloride solubility decreases rapidly with water loss, allowing for rapid precipitation of sodium chloride crystals to form a dense crystalline layer. Calcium sulfate solubility decreases with increasing temperature, and under the influence of high-temperature carbon dioxide, it can more rapidly precipitate high-strength calcium sulfate crystals.

[0071] In some embodiments of this specification, sodium chloride or calcium sulfate is considered as the target salt crystals, which helps the retained fracturing fluid in the fracture to crystallize more quickly, improving the efficiency of carbon dioxide sequestration. At the same time, the stronger salt crystals help to make the fracture sealing more stable and prevent carbon dioxide leakage.

[0072] In some embodiments, the carbon dioxide sequestration system can determine target injection parameters based on the geological features, fracture information, and salt crystallization information of the target block. Geological features include the reservoir area, reservoir thickness, and fracture pressure coefficient of the shale reservoir; fracture information includes the fracture distribution (e.g., location distribution) and fracture width of the shale reservoir; and salt crystallization information includes the type of salt crystals. Target injection parameters include the temperature, pressure, and injection flow rate of the carbon dioxide.

[0073] In some embodiments, the carbon dioxide sequestration 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 engineering data from historical carbon dioxide sequestration operations. For example, the injection parameter configuration table includes target blocks (or regions) corresponding to multiple historical carbon dioxide sequestration operations, the geological features, fracture information, and salt crystallization information corresponding to the target blocks, as well as reference injection parameters used in historical carbon dioxide sequestration operations at different times or project cycles. The carbon dioxide sequestration system can retrieve and match (e.g., feature matching or vector matching) the reference injection parameters from the injection parameter configuration table based on the geological features, fracture information, and salt crystallization information corresponding to the current target block, and use these as the target injection parameters.

[0074] In some embodiments, the carbon dioxide sequestration system can determine target injection parameters based on geological features, salt crystallization information, and fracture variation information using an injection parameter model. Fracture variation information refers to the differences in fracture information (such as width) over a time series, which can reflect the sealing status of the fractures. For example, fracture variation information includes the magnitude of the change in fracture width between any two adjacent time periods, which can be obtained based on monitoring equipment (such as distributed acoustic sensors).

[0075] The injected parameter model can be a model built based on a machine learning algorithm. In some embodiments, it can be a pre-trained machine learning model, such as a Long Short Term Memory (LSTM) model, or other neural network models.

[0076] In some embodiments, the inputs to the injection parameter model include geological features, salt crystallization information, and fracture change information, and the output includes predicted injection parameters for future time periods.

[0077] Crack change information can be represented based on crack information in time-series formats. For example, it can be a sequence of crack information composed of crack information from multiple preset time periods up to the current moment. The preset time periods can be determined according to the actual situation of carbon dioxide storage operations, such as 10 minutes, 20 minutes, etc.

[0078] The future time period can 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 of the carbon dioxide to be injected in the future time period.

[0079] In some embodiments, a trained injection parameter model can be obtained by iteratively training an initial model (such as an initial LSTM model). Training samples can be geological features, salt crystallization information, and fracture information based on time-series data of sample blocks from multiple historical carbon dioxide storage operations. The labels for the training samples can be the actual injection parameters for future time periods corresponding to the time-series data of samples from historical carbon dioxide storage operations. As an example, the geological features, salt crystallization information, and fracture information corresponding to T1 and T2 in a preset time-series {T1, T2} can be used as a set of training samples, and the actual injection parameters corresponding to a subsequent time-series T3 can be used as the label for that training sample. The labels can be manually annotated or labeled using other methods.

[0080] During training, the value of the loss function can be determined based on the difference between the output of the initial model and the training labels. The parameters of the initial model can be iteratively updated based on the value of the loss function until the training termination condition is met (e.g., the loss function converges, a certain number of iterations have been performed, etc.). The updated initial model can then be used as the pre-trained parameter injection model.

[0081] In some embodiments of this specification, considering the differences in geological characteristics and salt crystallization types in different regions or blocks, and the fact that fracture information (such as fracture width) in shale reservoirs changes as fractures are plugged during carbon dioxide sequestration operations, and that the injection volume of carbon dioxide still needs to consider the fracture rupture pressure and the fracture pressure of the salt crystal layer when sealing fractures through salt crystals, in order to avoid the rupture of fractures and / or the salt crystal layer affecting the sealing effect. Through the injection parameter model, the relationship between different geological characteristics, salt crystallization information, fracture changes over different time periods, and desired injection parameters can be fully learned. This makes the control and / or adjustment of carbon dioxide injection parameters more accurate and more in line with actual conditions during carbon dioxide sequestration operations, ensuring the normal operation of carbon dioxide sequestration while reducing the risk of carbon dioxide leakage.

[0082] In some embodiments, process 200 further includes steps 241 and / or 242 to further seal the crack.

[0083] Step 241: Inject a barium-containing solution into the shale reservoir to react with sulfate ions in the shale reservoir to form barium sulfate precipitate, which further seals the fractures.

[0084] In some embodiments, the barium-containing solution can be a barium chloride (BaCl2) solution with a preset barium concentration. The preset barium concentration can be 0.5% to 2%.

[0085] Based on the formation of salt crystals (such as sodium chloride or calcium sulfate) in step 230, the carbon dioxide sequestration system can inject a barium-containing solution into the shale reservoir through carbon dioxide injection wells and fractures in the shale reservoir within the target block. The barium-containing solution penetrates the salt crystallization zone within the fractures and reacts with sulfate ions in the formation water (…). The reaction produces barium sulfate. Barium sulfate precipitate is used to fill the pores of salt crystals, forming a double-sealing structure for cracks.

[0086] In some embodiments, the carbon dioxide sequestration system can acquire the content or concentration of sulfate ions in formation water collected by monitoring equipment, and adjust the concentration of 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... The concentration of the injected BaCl2 solution is 1000 mg / L, and the concentration can be adjusted to 1.2%.

[0087] In some embodiments of this specification, the formation of barium sulfate precipitate can reduce the permeability of the salt crystal layer in the crack, while further enhancing the strength of the salt crystal layer and preventing the salt crystal layer from cracking and causing carbon dioxide leakage.

[0088] Step 242: Inject urease-producing microorganisms into the shale reservoir so that their metabolic products react with calcium ions in the shale reservoir to form carbonate minerals, which further seal the fractures.

[0089] The metabolism of urease-producing microorganisms can produce carbonate minerals (such as calcite), which fill the interstitial spaces of salt crystals and enhance the resistance of the salt crystals to dissolution. In some embodiments, the urease-producing microorganism can be *Bacillus pasteurellii*, whose metabolites include carbonate ions (…). ) and ammonium ions ( Among them, carbonate ions and calcium ions in the cracks ( The combination of these elements produces calcite (CaCO3), which can fill the pores of salt crystals; ammonium ions can increase the pH value of the fracturing fluid, thereby enhancing the stability of calcite.

[0090] In some embodiments, the carbon dioxide sequestration system can inject a solution containing urease-producing microorganisms into the shale reservoir through carbon dioxide injection wells and fractures in the shale reservoir within the target block. Microbial concentration CFU / mL, accounting for 3% to 5% of the fracturing fluid in the fracture.

[0091] In some embodiments, the carbon dioxide sequestration system can also collect the pH value of the fracturing fluid in the fracture through monitoring equipment and periodically inject a solution containing urease-producing microorganisms to maintain the pH value of the fracturing fluid at 8.5 to 9.0.

[0092] 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 groundwater dissolving salt crystals, improve the strength of the salt crystal sealing layer, and prevent carbon dioxide leakage caused by the rupture of the salt crystal sealing layer.

[0093] In some embodiments of this specification, carbon dioxide injection induces the high-salinity fracturing fluid trapped in the fractures of shale reservoirs to transform into salt crystals, which then seal the fractures, improving the safety of carbon dioxide sequestration in the shale reservoir. Simultaneously, it reduces reservoir damage caused by the introduction of substances outside the reservoir (such as solid / liquid plugging materials). Furthermore, it lowers the cost of carbon dioxide sequestration operations.

[0094] Figure 3 This is a schematic diagram of a method for injecting carbon dioxide according to some embodiments of this specification.

[0095] In some embodiments, the carbon dioxide sequestration 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 stage, a second-stage injection stage, and a third-stage injection stage performed sequentially. As will be stated below... Figure 3 Steps 310, 320, and 330 shown correspond to the first-stage injection, second-stage injection, and third-stage injection phases, respectively. The injection of carbon dioxide and / or other fluids in these three stages can be achieved through carbon dioxide injection wells and fractures in the shale reservoir within the target block.

[0096] Step 310: Inject the first carbon dioxide into the shale reservoir.

[0097] In some embodiments, the carbon dioxide sequestration system can inject first carbon dioxide into the shale reservoir based on a first temperature and a first pressure through a carbon dioxide injection well in the target block and fractures in the shale reservoir to remove free water from the fractures.

[0098] The first carbon dioxide refers to the carbon dioxide injected in the first-stage injection phase, which can be gaseous carbon dioxide that meets the low-temperature and low-pressure conditions. The low-temperature and low-pressure conditions refer to the conditions that the first temperature and first pressure must meet, 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 (such as formation temperature, formation fracturing pressure, etc.).

[0099] 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.

[0100] The first carbon dioxide under the first temperature and first pressure state can be used to pre-cool the surface of natural fractures, slow down the evaporation rate of water in fracturing fluid, promote the migration of salt crystals to the depth of the fracture, and expand the coverage of subsequent fracturing fluid evaporation.

[0101] In some embodiments of this specification, a one-stage injection process can expand the sealing range and remove free water from the fractures, making room for subsequent high-mineralization fracturing fluid.

[0102] Step 320: Inject fracturing fluid with a mineralization degree higher than the first preset threshold into the shale reservoir.

[0103] In some embodiments, the carbon dioxide sequestration system can inject fracturing fluid with a mineralization higher than a first preset threshold into the shale reservoir.

[0104] Fracturing fluid with a salinity higher than a first preset threshold can be called high-salinity fracturing fluid. This can be determined based on the composition of the fracturing fluid in the target block (such as fracturing fluid flowback to the surface, fracturing fluid retained in the reservoir fractures) (e.g., It is obtained through configuration (such as adding industrial salt, evaporation and concentration).

[0105] 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.

[0106] More information about the first preset threshold and fracturing fluid can be found elsewhere in this manual (e.g., Figure 1 , Figure 2 ).

[0107] In some embodiments, a carbon dioxide injection well may include two delivery pipelines. One pipeline is used to deliver carbon dioxide (such as first carbon dioxide and second carbon dioxide), and the other pipeline is used to deliver high-salinity fracturing fluid.

[0108] In some embodiments of this specification, injecting high-mineralization fracturing fluid facilitates rapid salt crystallization in the subsequent three-stage injection process.

[0109] In some embodiments, step 320 (i.e., the two-stage injection process) may be omitted.

[0110] Step 330: Inject a second carbon dioxide into the shale reservoir.

[0111] In some embodiments, the carbon dioxide sequestration system can inject a second carbon dioxide into the shale reservoir based on a second temperature and a second pressure.

[0112] The second carbon dioxide injection refers to the carbon dioxide injected in the three-stage injection process, and it 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 lower than a second temperature threshold, and the second pressure is lower than a second pressure threshold. The second temperature and the second pressure can be determined based on the actual conditions of the target block and the parameters of the first carbon dioxide injection (such as the temperature, pressure, and formation fracturing pressure of the first carbon dioxide injection). For example, the second temperature can be set higher than the first temperature; the second pressure can be set higher than the first pressure but lower than the formation fracturing pressure.

[0113] In some embodiments, the second temperature is in the range of 60~80°C and the second pressure is in the range of 12~15 MPa, at which point the second carbon dioxide is in a supercritical state. Supercritical carbon dioxide ( Supercritical carbon dioxide is a special fluid state that forms 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 rather possesses characteristics of both, exhibiting unique physicochemical properties. Supercritical carbon dioxide has strong diffusion capabilities, which can accelerate the evaporation of water in fracturing fluids.

[0114] In some embodiments, the carbon dioxide sequestration system can heat the second carbon dioxide using a heating device in the carbon dioxide injection well and monitor its temperature changes to maintain it in a supercritical state.

[0115] In some embodiments of this specification, based on the preceding first-stage injection stage and the second-stage injection stage, the second carbon dioxide in the third-stage injection stage can accelerate the rapid evaporation of fracturing fluid in natural fractures, thereby accelerating the formation of salt crystals and thus improving the efficiency of plugging.

[0116] In some embodiments, a first concentration of sodium sulfate solution is injected through a carbon dioxide injection well in the target block and through fractures in the shale reservoir before or after a portion of the carbon dioxide is injected into the shale reservoir.

[0117] In some embodiments, the first sodium sulfate solution is injected before the first carbon dioxide is injected and before the second carbon dioxide is injected.

[0118] like Figure 3 As shown, before step 310 is executed, i.e., before the first-stage injection phase, the carbon dioxide sequestration system can execute step 301 to inject a first concentration of sodium sulfate solution through the carbon dioxide injection well and the fractures in the shale reservoir. Step 301 can be referred to as the pre-injection phase.

[0119] The first sodium sulfate solution refers to the sodium sulfate solution injected in the pre-injection stage, which can be a low-concentration sodium sulfate solution with a first concentration.

[0120] In some embodiments, the first concentration is in the range of 1% to 3% by mass.

[0121] Mass fraction is a concentration expression used to describe the mass ratio of a solute (such as sodium sulfate) to the solution or solvent in a solution. A carbon dioxide sequestration system can inject a pre-concentrated sodium sulfate solution into a shale reservoir via a carbon dioxide injection well.

[0122] By injecting a first concentration of sodium sulfate solution, to react with the formation water The reaction produces CaSO4 precipitate, which can initially seal nanoscale pores.

[0123] In some embodiments, after carbon dioxide injection, a second concentration of sodium sulfate solution of a second concentration is injected through a carbon dioxide injection well in the target block and through fractures in the shale reservoir, wherein the first concentration is less than the second concentration.

[0124] In some embodiments, a second sodium sulfate solution is injected after the second carbon dioxide.

[0125] like Figure 3 As shown, after step 330 is executed, that is, after the three-stage injection phase, the carbon dioxide sequestration system can execute step 305 to inject a second concentration of sodium sulfate solution through the carbon dioxide injection well and the fractures in the shale reservoir. Step 305 can be referred to as the post-injection phase.

[0126] The second sodium sulfate solution refers to the sodium sulfate solution injected in the subsequent injection stage. It can be a sodium sulfate solution with a higher concentration than the first sodium sulfate solution.

[0127] In some embodiments, the second concentration is in the range of 5% to 8% by mass.

[0128] The carbon dioxide sequestration system can inject a second sodium sulfate solution, prepared at a second concentration, into the shale reservoir through a carbon dioxide injection well.

[0129] By injecting a second concentration of sodium sulfate solution, the high concentration of sodium sulfate solution can supplement and seal the residual pores in the cracks, further ensuring the sealing effect.

[0130] In some embodiments, a first sodium sulfate solution is mixed with fracturing fluid with a mineralization degree higher than a first preset threshold and then injected together into the shale reservoir.

[0131] like Figure 3 As shown, when step 320 is executed, that is, in the two-stage injection stage, the carbon dioxide storage system can execute step 303 to inject a mixture of a first sodium sulfate solution and fracturing fluid with a salinity higher than a first preset threshold through the carbon dioxide injection well.

[0132] It should be noted that the pre-injection stage, the three-stage injection process (first-stage injection stage, second-stage injection stage, and third-stage injection stage), and the post-injection stage are implemented in an independent sequence to avoid direct mixing of the carbon dioxide sodium sulfate solution (such as the first sodium sulfate solution and the second sodium sulfate solution) and reduce chemical interference.

[0133] Figure 4 This is a schematic diagram illustrating another method of injecting carbon dioxide according to some embodiments of this specification.

[0134] In some embodiments, the carbon dioxide sequestration system can adjust or process the carbon dioxide injection parameters according to the mineralization of different blocks in the target area. Injection parameters include, but are not limited to, carbon dioxide temperature, pressure, gas phase, type of additives (such as barium ion-containing solutions, urease-producing microorganisms, sodium sulfate solutions, etc.), and carbon dioxide injection timing.

[0135] In some embodiments, the carbon dioxide sequestration system may be pre-set with a mineralization grading table. The mineralization grading table includes multiple mineralization levels, each corresponding to a different mineralization range, and one or more injection parameters. The mineralization levels may be numerical (e.g., 1, 2, 3) or other forms of representation.

[0136] In some embodiments, the multiple mineralization levels include a first level, a second level, and a third level.

[0137] The first level, also known as the low mineralization level, can be set to a mineralization 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 fracture.

[0138] The second level, also known as the medium mineralization level, can be set to a mineralization range greater than the first preset threshold and less than the second preset threshold. The second level indicates that the salt concentration of the fracturing fluid is sufficient to effectively precipitate salt crystals to seal the fracture, but the uniformity and resistance to dissolution of the fracture sealing need to be optimized.

[0139] The third level indicates a high mineralization level, which can be set to a mineralization range greater than or equal to the second preset threshold. The third level indicates that the salt concentration of the fracturing fluid is sufficient and can quickly and effectively precipitate salt crystals to seal the fracture, without the need for additional additives or other treatments.

[0140] 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%.

[0141] The carbon dioxide sequestration system can determine the mineralization level of a block based on a mineralization grading table and then perform the corresponding processing.

[0142] In some embodiments, when the mineralization of a block (such as a target block) is greater than a first preset threshold and less than a second preset threshold, at least one of a barium-containing solution and a urease-producing microorganism is injected into the shale reservoir. Figure 4 As shown, if the mineralization level of the block is at level two, the carbon dioxide sequestration system can execute step 420 to inject carbon dioxide into the shale reservoir. Simultaneously, it can inject a barium-containing solution and / or urease-producing microorganisms into the shale reservoir. Specifically, injecting carbon dioxide into the shale reservoir can be achieved based on step 230, while injecting a barium-containing solution and urease-producing microorganisms can be achieved based on steps 241 and 242, respectively.

[0143] In some embodiments, when the mineralization of a block (such as a target block) is not less than a second preset threshold, barium-containing solutions and urease-producing microorganisms do not need to be injected into the shale reservoir. Figure 4 As shown, if the mineralization of the block is at level three, the carbon dioxide sequestration system can execute step 430 to inject carbon dioxide into the shale reservoir, thereby sealing the fractures.

[0144] In some embodiments, such as Figure 4 As shown, when the mineralization of a block is less than or equal to a first preset threshold, the carbon dioxide sequestration system can proceed to step 410 to enhance the mineralization of the block. This enhancement includes, but is not limited to, injecting high-mineralization fluid, heating, or negative-pressure evaporation of the return liquid. After step 410, the carbon dioxide sequestration system can re-determine the mineralization of the block using monitoring equipment and / or mineralization measurement equipment to further determine whether it reaches a second or third level. When the mineralization of a block reaches a second or third level, the block can be used as a target area for salt crystallization and crack sealing. For example, the water in 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 executed; if it reaches the third level, step 430 can be executed; otherwise, step 410 can continue to enhance the mineralization.

[0145] For different blocks in the target area, different carbon dioxide injection strategies can be adopted according to their mineralization, thereby improving the targeting and effectiveness of carbon dioxide sequestration operations, reducing operational complexity and saving engineering costs.

[0146] Figure 5A This is a schematic diagram showing the pore size distribution of shale salt crystallization before and after the experiment, according to some embodiments of this specification.

[0147] The effectiveness of sealing natural fractures in target reservoirs (such as shale reservoirs) by salt crystallization (hereinafter referred to as fracture sealing effect) can be evaluated through control experiments on experimental samples.

[0148] Experimental samples include geological samples. Geological samples can be one or a combination of substances such as rocks, fluids, and minerals used for control experiments. They can be collected by various collection devices (such as exploration equipment) at different sampling locations in the target area (such as the surface, reservoirs, etc.).

[0149] In some embodiments, the geological samples include shale samples and fracturing fluid samples from the target area. The shale samples can be selected from shale with a porous structure. The porous structure of the shale samples reflects information about the natural fractures in the shale reservoir (such as the number of fractures, fracture connectivity paths, fracture widths, and pore sizes). The fracturing fluid samples can be surface flowback fracturing fluids with different mineralization and / or fracturing fluids retained in the reservoir fractures.

[0150] In some embodiments, geological samples can be collected from different blocks within the target area to obtain shale samples with different pore distributions and fracturing fluid samples with different mineralization. Shale samples with different pore distributions can be combined with fracturing fluid samples with different mineralization to obtain multiple sets of experimental samples for multiple control experiments.

[0151] Experimental samples may also include other substances, such as salt additives like sodium chloride solution, to be used in control experiments simulating more scenarios (such as fracturing fluids with higher mineralization).

[0152] Control experiments are used to determine the changes in geological samples before and after salt crystallization experiments. In some embodiments, for a set of experimental samples (such as shale samples and fracturing fluid samples), control experiments include the following steps.

[0153] Step 510: Before conducting the crystallization experiment, the shale sample is dried to obtain the first shale sample.

[0154] Then, the permeability of the first shale sample was determined by methods such as pulse method, and the pore size distribution of the first shale sample was determined by methods such as mercury porosimetry, so as to obtain the original data such as permeability and pore size distribution of the first shale sample before the crystallization experiment.

[0155] Then, based on steps 520 to 540, a salt crystallization experiment is performed: Step 520: Using a core vacuum saturation device, the first shale sample is saturated with a fracturing fluid sample of a certain mineralization to obtain the second shale sample.

[0156] Step 530: The second shale sample is placed in a core holder, and a dynamic evaporation-induced salt crystallization experiment is conducted by injecting carbon dioxide. During the carbon dioxide injection process, salt crystals precipitate from the fracturing fluid sample in the second shale sample and fill the pore structure (such as voids and fractures). At this point, the third shale sample is obtained.

[0157] Step 540: Dry the third shale sample and determine its permeability using methods such as pulse method and its pore size distribution using methods such as mercury intrusion porosimetry, thereby obtaining experimental data on the permeability and pore size distribution of the third shale sample after the crystallization experiment.

[0158] Experimental data can be used to reflect the sealing effect of salt crystallization on pores. For example, cracks are filled, and pore size decreases.

[0159] Figure 5B This is a schematic diagram of scanning electron microscope images of shale salt crystallization experiments as shown in some embodiments of this specification.

[0160] In some embodiments, the experimental data also include scanning electron microscopy (SEM) images, which can be obtained by scanning the third shale sample with an SEM. The SEM images can be used to observe the morphology of salt crystals in the fractures.

[0161] like Figure 5B As shown, salt crystals were 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), exhibiting a salt crystal pattern that covered the fissures and / or pores. This indicates that the injected carbon dioxide, after the salt crystallization experiment, had a good sealing effect on the cracks in the shale samples.

[0162] It should be noted that the shale samples before and after the experiment were based on the same shale sample from the same experimental sample group. The comparative data obtained reflects the differences between the original data before the experiment and the experimental data after the experiment. For example, changes in permeability and changes in pore size distribution.

[0163] Multiple sets of comparative data can be obtained by repeating steps 510 to 540 above using multiple sets of experimental samples. For example, another shale sample and a fracturing fluid sample with a different mineralization can be used as another set of experimental samples, and comparative data for this set of experimental samples can be obtained based on steps 510 to 540.

[0164] Based on comparative data (such as comparative data on permeability changes), 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 samples is greater than 2%, salt crystals are more likely to form. Therefore, in some embodiments, the first preset threshold can be 2%.

[0165] Figure 5AThe graph shown is a 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.

[0166] like Figure 5A As shown, the horizontal axis of the curve represents the pore size of the shale sample (e.g., 10 nm, 100 nm, etc.). The pore size characterizes the width of the fracture.

[0167] The vertical axis of the curve is used to represent the amount of mercury introduced in stages. Different pore sizes of cracks can accommodate different amounts / volumes of mercury. The amount of mercury introduced in stages is used to reflect the total volume / capacity of pores (cracks) within different pore size ranges (such as 1-10nm, 10-20nm, etc.).

[0168] Salt crystallization can seal fractures (i.e., pores), reducing pore size and thus pore volume, consequently decreasing the amount / volume of mercury that the pores can hold. By comparing the amount of mercury introduced before and after the crystallization experiment, the effectiveness of sealing fractures of different pore sizes in shale samples can be reflected. Therefore, for different pore size ranges, the difference in mercury introduction before and after the experiment can be analyzed to evaluate the pore size range with the optimal sealing effect.

[0169] For example, such as Figure 5A As shown, for pore sizes greater than 100 nm on the horizontal axis, the amount of mercury introduced in stages changed significantly before and after the experiment, while for pore sizes less than 100 nm, the amount of mercury introduced in stages changed less. This indicates that salt crystallization is more likely to block cracks larger than 100 nm.

[0170] It should be noted that the above description of the process is for illustrative purposes only and does not limit the scope of this specification. Those skilled in the art can make various modifications and changes to the process under the guidance of this specification. However, these modifications and changes remain within the scope of this specification.

[0171] The basic concepts have been described above. Obviously, for those skilled in the art, the detailed disclosure above is merely illustrative and does not constitute a limitation of this specification. Although not explicitly stated herein, those skilled in the art may make various modifications, improvements, and corrections to this specification. Such modifications, improvements, and corrections are suggested in this specification and therefore remain within the spirit and scope of the exemplary embodiments described herein.

[0172] Furthermore, this specification uses specific terms to describe embodiments thereof. For example, "an embodiment," "one embodiment," and / or "some embodiments" refer to a particular feature, structure, or characteristic associated with at least one embodiment of this specification. Therefore, it should be emphasized and noted that references to "an embodiment," "one embodiment," or "an alternative embodiment" in different locations throughout this specification do not necessarily refer to the same embodiment. Moreover, certain features, structures, or characteristics in one or more embodiments of this specification can be appropriately combined.

[0173] Furthermore, unless expressly stated in the claims, the order of processing elements and sequences, the use of numbers and letters, or other names described in this specification are not intended to limit the order of the processes and methods described herein. Although various examples have been discussed in the foregoing disclosure of some embodiments of the invention that are currently considered useful, it should be understood that such details are for illustrative purposes only, and the appended claims are not limited to the disclosed embodiments; rather, the claims are intended to cover all modifications and equivalent combinations that conform to the spirit and scope of the embodiments described herein. For example, while the system components described above can be implemented using hardware devices, they can also be implemented solely using software solutions, such as installing the described system on existing servers or mobile devices.

[0174] Similarly, it should be noted that, in order to simplify the description disclosed herein and thus aid in the understanding of one or more embodiments of the invention, the foregoing description of embodiments in this specification may sometimes combine multiple features into a single embodiment, drawing, or description thereof. However, this method of disclosure does not imply that the subject matter of this specification requires more features than those mentioned in the claims. In fact, the embodiments contain fewer features than all the features of a single embodiment disclosed above.

[0175] In some embodiments, numbers describing the quantity of components and attributes are used. It should be understood that such numbers used in the description of embodiments are modified in some examples with the terms "approximately," "approximately," or "generally." Unless otherwise stated, "approximately," "approximately," or "generally" indicates that the numbers are allowed to vary by ±20%. Accordingly, in some embodiments, the numerical parameters used in the specification and claims are approximate values, which may be changed depending on the characteristics required by individual embodiments. In some embodiments, numerical parameters should take into account specified significant digits and employ a general method of digit reservation. Although the numerical ranges and parameters used to confirm their breadth of range in some embodiments of this specification are approximate values, in specific embodiments, such values ​​are set as precisely as feasible.

[0176] For each patent, patent application, patent application publication, and other material such as articles, books, specifications, publications, and documents referenced in this specification, the entire contents of which are incorporated herein by reference. This excludes historical application documents that are inconsistent with or conflict with the content of this specification, as well as documents that limit the broadest scope of the claims in this specification (currently or subsequently appended to this specification). It should be noted that in the event of any inconsistency or conflict between the descriptions, definitions, and / or terminology used in the supplementary materials to this specification and the content of this specification, the descriptions, definitions, and / or terminology used in this specification shall prevail.

[0177] Finally, it should be understood that the embodiments described in this specification are merely illustrative of the principles of the embodiments described herein. Other variations may also fall within the scope of this specification. Therefore, alternative configurations of the embodiments described herein are intended to be illustrative rather than limiting, and should be considered consistent with the teachings of this specification. Accordingly, the embodiments described herein are not limited to those explicitly introduced and described herein.

Claims

1. A method for carbon dioxide sequestration, characterized in that, The method includes: For each of the multiple blocks in the target area, determine the salinity of the flowback fracturing fluid in the block; Select a target block from the plurality of blocks whose mineralization is not less than a first preset threshold; Carbon dioxide is injected into the shale reservoir through carbon dioxide injection wells and fractures in the target block, causing the retained fracturing fluid in the fractures to become supersaturated due to the evaporation of the carbon dioxide gas flow, thereby precipitating salt crystals to seal the fractures; the injection of carbon dioxide into the shale reservoir through carbon dioxide injection wells and fractures in the target block includes: Through carbon dioxide injection wells and fractures in the shale reservoirs within the target block. Based on a first temperature and a first pressure, a first carbon dioxide is injected into the shale reservoir to remove free water from the fractures; Inject fracturing fluid with a mineralization degree higher than the first preset threshold into the shale reservoir; Based on a second temperature and a second pressure, a second carbon dioxide is injected into the shale reservoir, wherein the first temperature is lower than the second temperature and the first pressure is lower than the second pressure.

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, characterized in that, The salt crystals include at least one of sodium chloride or calcium sulfate.

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

6. The method according to claim 1, characterized in that: The first temperature is in the range of 25-40℃, and the first pressure is in the range of 8-10MPa; The second temperature is in the range of 60~80℃, the second pressure is in the range of 12~15MPa, and the second carbon dioxide is in a supercritical state.

7. The method according to claim 1, characterized in that, The method further includes: A barium-containing solution is injected into the shale reservoir through carbon dioxide injection wells and fractures in the target block to react with sulfate ions in the shale reservoir to form barium sulfate precipitate, further sealing the fractures; and / or Urease-producing microorganisms are injected into the shale reservoir through carbon dioxide injection wells and fractures in the target block. Their metabolic products react with calcium sulfate ions in the shale reservoir to form carbonate minerals, which further seal the fractures.

8. The method according to claim 7, characterized in that, In response to the mineralization of the target block being less than a second preset threshold, at least one of the barium-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 mineralization degree corresponding to the target block being not less than a second preset threshold, the barium-containing solution and the urease-producing microorganisms do not need to be injected into the shale reservoir.

9. A system for carbon dioxide sequestration, characterized in that, include: A mineralization measurement device is configured to measure the mineralization of the flowback fracturing fluid in each of multiple blocks in a target area. The processing device is configured to select a target block from the plurality of blocks whose mineralization is not less than a first preset threshold. A carbon dioxide injection device is configured to inject carbon dioxide into the shale reservoir through a carbon dioxide injection well in the target block and fractures in the shale reservoir, so that the residual fracturing fluid in the fractures evaporates due to the gas flow of carbon dioxide and reaches a supersaturated state, thereby precipitating salt crystals to seal the fractures; The carbon dioxide injection device is further configured to: Through carbon dioxide injection wells and fractures in the shale reservoirs within the target block. Based on a first temperature and a first pressure, a first carbon dioxide is injected into the shale reservoir to remove free water from the fractures; Inject fracturing fluid with a mineralization degree higher than the first preset threshold into the shale reservoir; Based on a second temperature and a second pressure, a second carbon dioxide is injected into the shale reservoir, wherein the first temperature is lower than the second temperature and the first pressure is lower than the second pressure.

10. The system according to claim 9, characterized in that, It also includes carbon dioxide storage devices configured to store carbon dioxide that needs to be sealed, the carbon dioxide including one or more combinations of gaseous carbon dioxide, liquid carbon dioxide, or supercritical carbon dioxide.

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