Method for treating water in an active water body gas reservoir as a whole

Abstract

A kind of active water body gas reservoir overall water control method, it is characterized in that, near the boundary of gas reservoir, water dam boundary is selected, two types of boundary are selected as far as possible, one is existing closed boundary, generally fault that disconnects reservoir, two is the boundary that is easy to fracture into fracture (or the fault that can reopen, fracture), as the water plugging boundary of gas reservoir;On the boundary that is easy to fracture, adopt old well or new well, new well can be straight well or horizontal well, the length of horizontal well, the length of horizontal well includes the range of fracture development in water invasion direction or penetrates the whole structure, press open the fault and fracture on the fault of water dam boundary fracture, or form new artificial fracture, water plugging material is injected along the fault that reopens, fracture or newly formed artificial fracture, form water dam along fracture, horizontal well adopts segmented fracturing water plugging technology, straight well adopts relay pressure water plugging technology.

Description

Technical Field

[0001] The invention relates to a method for the overall water management of active water gas reservoirs, particularly a method for constructing low-permeability water-blocking dams around the gas reservoir to control the intrusion of peripheral formation water into the gas reservoir. Background Technology

[0002] Unlike oil extraction, which involves minimal volume expansion during depressurization and requires external water or artificial water injection for reservoir development, natural gas undergoes significant volume expansion during depressurization and can be extracted without external energy. In gas reservoirs with small water bodies, natural gas recovery rates can reach 60-90%. Water primarily disrupts natural gas development. In large-water, porous gas reservoirs with ample external energy, minimal pressure drop during development, and limited utilization of gas expansion energy, the reservoir after waterflooding contains residual gas saturation, resulting in natural gas recovery rates generally below 50%. Fractured gas reservoirs consist of fractures and matrix. Fractures have high permeability but low porosity, while the matrix has low permeability but high porosity. Peripheral formation water enters the gas reservoir along fractures, filling the fracture space and flowing into the matrix near the fracture surface. This significantly reduces the velocity of natural gas flowing from the matrix into the fractures. When the formation water reaches the bottom of the well, the fluid density inside the wellbore increases, and the wellhead pressure drops rapidly. When the natural gas production falls below the minimum fluid-carrying capacity, the well stops producing gas, and a large amount of natural gas cannot be extracted. The recovery rate of fractured gas reservoirs is generally only 1 / 5 to 1 / 2 that of conventional gas reservoirs. For gas reservoirs with relatively weak peripheral water bodies, drainage production is a relatively effective method. By draining water, the formation pressure is reduced, and the natural gas in the matrix expands and flows into the fractures for extraction. However, when the peripheral water body is large, the required drainage volume is large, resulting in high costs. For fractured gas reservoirs with large peripheral water bodies, drainage production has limited effect on improving the natural gas recovery rate. Purpose of the invention

[0003] This invention provides a method for constructing water-blocking dams around active water-bearing gas reservoirs at a low cost, thereby restricting formation water from entering the gas reservoir and significantly improving natural gas recovery. Summary of the Invention

[0004] The technical solution provided by this invention is as follows: Based on the study of structure, fracture, and stress, a water-blocking dam boundary is selected near the gas reservoir boundary. The water-blocking dam boundary is divided into four categories: Category I is an existing closed boundary, generally a fault that breaks the reservoir; Category II is a boundary that is easy to fracture (or a fault or fracture that can reopen). The boundaries that are easy to form fractures are, in order, faults or fractures that can be identified by earthquakes and are roughly parallel to the direction of the principal stress. When the difference between the maximum and minimum horizontal principal stresses is greater than the tensile strength of the reservoir and interlayers, a straight line parallel to the principal stress can be directly selected. When the difference between the maximum and minimum horizontal principal stresses is less than the tensile strength of the reservoir and interlayers, the fractures are easy to reopen along the existing faults and fractures. All continuous faults or large fractures can be used as water-blocking boundaries; Category III is a fracture that is nearly perpendicular to the principal stress; and Category IV is a boundary perpendicular to the principal stress with fractures without a fixed direction. Type I boundaries are left untreated; Type II boundaries are prone to fracturing along the boundary, requiring the use of old or new wells (vertical or horizontal wells are acceptable) to open faults and fractures at the boundary of the water-blocking dam, or to create new artificial fractures. Water-blocking material is then injected along the reopened faults, fractures, or newly formed artificial fractures to form a water-blocking dam along the fractures; for Type III boundaries, injection wells are placed along the boundary, using a long-term retarded plugging agent injected below the fracturing pressure; for Type IV boundaries, vertical or horizontal wells are used, with a long-term retarded plugging agent injected below the fracturing pressure. Type III and Type IV boundaries require long injection times and large quantities of plugging agent, and should be avoided as much as possible. Type I and Type II boundaries are preferred as water-blocking dam boundaries. For horizontal wells at Type II boundaries, segmented fracturing and plugging are used to form water-blocking dams; for vertical wells at Type II boundaries, relay fracturing and plugging are used to form water-blocking dams.

[0005] Type II water-blocking dams are constructed using horizontal wells. This involves designing horizontal wells near the reservoir boundary, parallel to the direction of maximum principal stress. The length of the horizontal well is included within the area of ​​fracture development in the water-invasion direction or runs through the entire structure. The horizontal section is divided into multiple segments, which are then fractured segment by segment. The fracture height is required to reach the entire reservoir height. A plugging agent is injected along the fractures to form the water-blocking dam.

[0006] For Class II water-blocking dams that are relatively short or where existing wells already exist, vertical wells are suitable for constructing water-blocking dams. To extend the fracture distance and reduce construction difficulty, a relay fracturing and water-blocking process is designed. Each stage of the construction process is as follows: Step 1, fracturing to create fractures; Step 2, injecting plugging agent, shutting in the well to allow the plugging agent to be absorbed, partially closing the fracture, which helps reduce the amount of plugging agent retained in the main fracture; Step 4, injecting separator and displacement fluid; Step 5, shutting in the well and waiting for the plugging agent to solidify; Step 6, test squeezing to assess the sealing situation. If the pressure rise rate is not fast enough, repeat step 2. Step four: When the pressure rises rapidly enough (after fracturing simulation, at maximum operating flow rate, the requirements for opening and extending the fracture are met), proceed to the next sealing section. Repeat steps one through four until the expected fracture reaches the end of the boundary. End the segmented fracturing and plugging agent operation. Finally, inject the final plugging agent according to the total length, height, and width of the main fracture. The final plugging agent may not be implemented. Step three may be combined with step four. When the plugging agent can be used as fracturing fluid, steps one and two may be combined.

[0007] To ensure effective sealing, the fracture height after fracturing is large, which can easily lead to fingering and stratification. Therefore, the plugging agent should have low viscosity and fine particle size during the extrusion process to allow it to penetrate micro-cracks. After extrusion, it should have poor mobility and retention properties, high strength after consolidation, low permeability, be able to withstand high pressure differentials, and have good stability at high temperatures to ensure long-term stability during production.

[0008] Two series of plugging agents were designed: low-density plugging agents and high-density plugging agents. The low-density plugging agent has a density similar to formation water and uses either a high-temperature, reinforced, plasticized, micro-expanding ultrafine foam inorganic plugging agent or a non-degradable inorganic modified rigid gel plugging agent. The high-density plugging agent has a density higher than formation water and uses a high-density, high-temperature, retention-oriented, micro-expanding inorganic material as its main component. When the plugging agent performance meets the requirements of the fracturing fluid, the first and second steps are combined.

[0009] When using high-density plugging agents, in order to reduce plugging agent fingering and stratification, particulate materials are used in the fracturing fluid to reduce filtration loss, or secondary cross-linked fracturing fluid is used. After fracturing is completed, the permeability of high-permeability channels is reduced, and the flow of plugging agents is restricted by the fracturing fluid. After the plugging agent is injected, a release fluid with the same density as the plugging agent is used to reduce the stratification of the release fluid in the fracture.

[0010] Secondary cross-linked fracturing fluid refers to fracturing fluid with low viscosity before reaching the formation to be fractured. Before reaching the formation, it begins to cross-link once, and the viscosity increases during fracturing. After fracturing is completed, the fracturing fluid undergoes secondary cross-linking, which further increases the viscosity of the fracturing fluid.

[0011] Particulate material-based filtration-reducing fracturing fluid refers to fracturing fluid in which particulate materials are added. These particulate materials agglomerate and bridge in natural fractures, thereby reducing filtration loss. Conventional fracturing particulate filtration-reducing materials are generally oil-soluble, but this invention does not require oil solubility. Materials that can solidify later are preferred. Low-concentration cementitious materials are recommended because they are difficult to solidify. When they agglomerate in natural fractures, the bridging concentration increases, making solidification easier. invention

[0012] This invention designs an overall water control scheme for water-bearing gas reservoirs, combining geological engineering and designing segmented fracturing and water-blocking processes to create a long and narrow water-blocking dam. This reduces the difficulty and cost of building a water-blocking dam at the gas reservoir boundary, transforming a strong water-bearing gas reservoir into a weak water-bearing gas reservoir, and significantly improving the gas reservoir's recovery rate. Brief description of the attached diagram

[0013] Figure 1 This is a schematic diagram of the gas reservoir area and the boundary of the water-blocking dam. Figure 2 This is a schematic diagram showing the distribution of water-blocking construction wells and water-blocking dams. Figure 3 This is a schematic diagram of the crack, which is the first step in fracturing and water plugging construction. Figure 4 This is a schematic diagram of the crack and plugging agent distribution in the second step of fracturing and water plugging construction. Figure 5 This is a schematic diagram of the crack and plugging agent distribution in the third step of fracturing and water plugging construction. Figure 6 This is a schematic diagram of the crack and plugging agent distribution in the fourth step of fracturing and water plugging construction. Figure 7 This is a schematic diagram of the crack and plugging agent distribution in the first step of the second round of fracturing and water plugging construction. Figure 8 This is a schematic diagram of the crack and plugging agent distribution in the second step of the second round of fracturing and water plugging construction. Figure 9 This is a schematic diagram of the crack and plugging agent distribution in the third step of the second round of fracturing and water plugging construction. Figure 10 This is a schematic diagram of the crack and plugging agent distribution in the fourth step of the second round of fracturing and water plugging construction. Detailed Implementation (Examples)

[0014] Figure 1This is a schematic diagram of the gas reservoir area and the boundary of the water barrier. In the diagram, (1) is the gas-water boundary, (2) and (2-1) are east-west faults, (5) indicates the direction of the maximum principal stress, and (7) is a north-south fault. In this example, the maximum horizontal principal stress is northwest and southeast. The east-west fault (2) is subjected to the maximum principal stress. Faults are generally closed and can be used as the boundary of the east-west water barrier. Especially when the fault displacement is large and the reservoirs on both sides of the fault are not connected, the east-west faults (2) and (2-1) can be used as the east-west Class I boundary. The north-south fault (7) is close to the eastern boundary of the gas reservoir. The fault (7) and its extension (6) are used as the eastern boundary of the gas reservoir. The boundary of the water-blocking dam in the western part of the gas reservoir is as follows: There are no north-south faults near the western boundary of the gas reservoir. A north-south line is drawn directly between the east-west faults of the gas reservoir along the direction of principal stress as the boundary of the water-blocking dam in the western part of the gas reservoir (3). The near north-south boundaries (3), (7), and (6) are designated as Class II boundaries. A line (8) is drawn between the south east-west fault (2-1) and the north-south fault (7) as a Class IV supplementary boundary. As an alternative to the Class IV supplementary boundary, a north-south line (4) is drawn at the eastern end of the east-west fault (2-1) as a north-south Class II boundary. The reserves east of boundary (4) are abandoned. The specific scheme is subject to numerical simulation and economic evaluation.

[0015] Figure 2 This is a schematic diagram of the distribution of water-blocking construction wells and water-blocking dams. The black dots represent construction wells. The north-south water-blocking dam boundary is a Class II boundary. Construction wells (12-1, 12-1-1) are set in the middle of this Class II boundary. Construction well (12-1-1) in this Class II boundary is a horizontal well. The black dots represent wellheads. Point A is the first target point, and point B is the second target point. Multiple target points can be set according to the distribution of the target layer. The longitudinal trajectory of the horizontal wells is determined by fracturing simulation and is generally located in the lower middle part of the structure. The horizontal construction wells are constructed using a segmented fracturing and injection process. The specific construction method is basically the same as the mature shale gas segmented fracturing construction method and will not be detailed further. The vertical wells in this Class II boundary are constructed using a relay fracturing method, and the specific construction plan will be detailed later. When the reservoir cannot be completely broken at both ends of the east-west fault, there may be insufficient sealing at both ends. The boundary can be regarded as a Class III boundary. At this time, construction wells (12-3) can be set on the faults at both ends and long-term slow-setting plugging agent can be used. The injection is below the fracture pressure. The construction method is similar to the deep profile adjustment construction and will not be described in detail. The supplementary boundary (8) is a Class IV boundary. There are three treatment methods. Method 1 is to move the boundary (7) to the west to the position of the boundary (4) and change it to a Class II boundary. The segmented multi-step fracturing and squeezing process is used for construction. Method 2 is to deploy construction vertical wells at a certain interval or arrange horizontal wells along the supplementary boundary (8). Long-term slow-setting plugging agent is injected below the fracture pressure, followed by low-cost displacement fluid (formation water) to form an annular sealing zone (10) and a displacement zone (11). After the sealing zones of adjacent vertical wells are connected, a continuous sealing zone is formed. Method 3 is not treated and some liquid is allowed to flow in. The internal drainage method is used to alleviate water invasion.

[0016] Figures 3-6 This is a schematic diagram of the first stage of fracturing and plugging. Figure 3 shows the schematic diagram of the first stage fracturing fracture. After fracturing, artificial fractures are generated along the principal stress direction, or the fractures reopen. Due to formation filtration and displacement limitations, the fracture length is generally 100~200m, and the fracture width decreases with distance from the well point. Figure 4 This is a schematic diagram of the crack and sealant distribution in the second step. The shaded area represents the sealant. Figure 5 This is a schematic diagram showing the distribution of cracks and plugging agent in the third step of fracturing and water plugging construction. The cracks are closed and appear as lines. Figure 6 This is a schematic diagram of the fracture and plugging agent distribution in the fourth step of fracturing and water shut-off construction. The small fractures around the main fracture are plugged with the plugging agent, and the center of the opened fractures is filled with a fracture protectant. In the fifth step, after shutting in the well and allowing it to set, the fractures will partially close. The fracture and plugging agent distribution is shown below. Figure 5 As shown.

[0017] Figures 7-10 This is a schematic diagram of the second stage of step-by-step fracturing and sealing. Figure 7 The diagram illustrates the first step of hydraulic fracturing. After fracturing, artificial fractures are generated along the principal stress direction, or the fractures reopen. Due to formation filtration and displacement limitations, the fracture length is generally 100-200m, and the fracture width decreases with distance from the well point. Figure 8 This is a schematic diagram of the crack and sealant distribution in the second step. The shaded area represents the sealant. Figure 9 This is a schematic diagram showing the distribution of cracks and plugging agent in the third step of fracturing and water plugging construction. The cracks are closed and appear as lines. Figure 10 This is a schematic diagram of the fracture and plugging agent distribution in the fourth step of fracturing and water shut-off construction. The small fractures around the main fracture are plugging agents, and the center of the opened fractures contains fracture protectant (isolation fluid or displacement fluid). In the fifth step, after shutting in the well and allowing it to set, the fractures will partially close. The fracture and plugging agent distribution is shown below. Figure 9 As shown. Figures 7-10 The second phase of construction was carried out based on the first phase, extending both the crack length and the sealing length. Subsequent phased construction was similar to the first and second phases, and will not be described in detail here.

Claims

1. A holistic approach to water management of active water bodies and gas reservoirs, characterized in that, Select water-blocking dam boundaries near the gas reservoir boundary, preferably choosing two types of boundaries: one is an existing closed boundary, generally a fault that breaks the reservoir; the other is a boundary that is easily fractured (or a fault or fracture that can reopen) to serve as the water-blocking boundary of the gas reservoir. On the boundary that is easily fractured, use old wells or new wells. New wells can be vertical or horizontal wells. The length of the horizontal well should be included within the range of fracture development in the direction of water invasion or run through the entire structure to force open the faults and fractures on the water-blocking dam boundary fracture, or form new artificial fractures. Inject water-blocking material along the reopened faults, fractures or newly formed artificial fractures to form a water-blocking dam along the fractures.

2. The method for integrated water management of active water bodies and gas reservoirs as described in claim 1, characterized in that: Water-blocking boundaries are classified into four categories: Category I is an existing closed boundary, generally a fault that breaks the reservoir; Category II is a boundary that is easily fractured (or a fault or fracture that can reopen). Boundaries that are easy to form fractures are, in order: faults or fractures that can be identified by earthquakes and are roughly parallel to the direction of the principal stress; when the difference between the maximum and minimum horizontal principal stresses is greater than the tensile strength of the reservoir and interlayers, a straight line parallel to the principal stress can be directly selected; when the difference between the maximum and minimum horizontal principal stresses is less than the tensile strength of the reservoir and interlayers, the fracture is easy to reopen along the existing fault or fracture. All continuous faults or large fractures can be used as water-blocking boundaries; Category III is a fracture that is nearly perpendicular to the principal stress; and Category IV is a boundary perpendicular to the principal stress with fractures without a fixed direction.

3. The method for integrated water management of active water bodies and gas reservoirs as described in claim 1, characterized in that, II When the length of the water-blocking dam is relatively short, or when there is an existing old well, it is suitable to build a water-blocking dam in a vertical well. In order to extend the distance of the hydraulic fracture and reduce the construction difficulty, a relay hydraulic fracturing and water plugging process is designed. The construction steps of each segment are as follows: First step, hydraulic fracturing to generate hydraulic fractures; second step, injection of plugging agent; third step, waiting for the plugging agent to be absorbed and the fracture to partially close, which helps to reduce the amount of plugging agent in the main fracture; fourth step, injection of isolation fluid and displacement fluid; fifth step, shutting in the well and waiting for solidification until the plugging agent solidifies; sixth step, test squeezing to judge the sealing situation. If the pressure rise rate is not fast enough, repeat steps two to five. When the pressure rise rate is fast enough (after hydraulic fracturing simulation, under the maximum construction displacement, the requirements for opening the fracture and extending it forward are met), proceed to the next sealing segment construction and repeat the process of steps one to four until the expected hydraulic fracture reaches the end of the boundary, and the segmented hydraulic fracturing and plugging agent construction is completed. Finally, the final plugging agent is injected according to the total length, height and width of the main fracture. The final plugging agent may not be implemented. When the plugging agent meets the requirements of fracturing fluid, the first and second steps of the process can be combined, and the third step can be combined with the fourth step.

4. The method for integrated water management of active water bodies and gas reservoirs as described in claim 1, characterized in that, II The construction process of using horizontal wells for water-blocking dams refers to designing horizontal wells near the gas reservoir boundary parallel to the direction of maximum principal stress. The length of the horizontal well is included within the range of fracture development in the direction of water intrusion or runs through the entire structure. The horizontal section is divided into multiple segments, and each segment is fractured. The fracture height is required to reach the entire reservoir height. The plugging agent is injected along the fracture to form a water-blocking dam.

5. The method for integrated water management of large water bodies and gas reservoirs as described in claim 1, characterized in that: To ensure effective plugging, the high fracture height after fracturing makes fingering and stratification prone to occur. Therefore, the plugging agent must have low viscosity, fine particle size, and be able to penetrate microfractures during the extrusion process. After extrusion, it should exhibit poor mobility and retention, high strength after consolidation, low permeability, the ability to withstand high pressure differentials, and good stability at high temperatures to ensure long-term stability during production. Low-density and high-density plugging agents are designed: Low-density plugging agents have a density similar to formation water and are primarily composed of high-temperature, reinforced, plasticized, and micro-expanding ultrafine foam inorganic materials or non-degradable inorganic modified rigid gels. High-density plugging agents have a density higher than formation water and are primarily composed of high-density, high-temperature, retention-oriented, and micro-expanding inorganic materials.

6. The method for integrated water management of large water bodies and gas reservoirs as described in claim 1, characterized in that: When using high-density plugging agents, in order to reduce plugging agent fingering and stratification, particulate material filtration-reducing fracturing fluid or secondary cross-linked fracturing fluid is used in the fracturing fluid. After fracturing is completed, the seepage capacity of high-permeability channels is reduced, and the flow of plugging agents is restricted by the fracturing fluid. After the plugging agent is injected, a release fluid with the same density as the plugging agent is used to reduce the stratification of the release fluid in the fracture. Secondary cross-linked fracturing fluid and particulate material filtration-reducing fracturing fluid can also be used in low-density plugging agent fracturing operations to reduce filtration loss during fracturing.

7. The method for integrated water management of large water bodies and gas reservoirs as described in claim 1, characterized in that, secondary... Cross-linked fracturing fluid refers to fracturing fluid with low viscosity before reaching the formation to be fractured. Before reaching the formation, it begins to cross-link once, and the viscosity increases during fracturing. After fracturing is completed, the fracturing fluid undergoes a second cross-linking, which further increases the viscosity of the fracturing fluid.

8. The method for integrated water management of large water bodies and gas reservoirs as described in claim 1, characterized in that: Particulate material-based filtration-reducing fracturing fluid refers to fracturing fluid in which particulate materials are added. These particulate materials agglomerate and bridge in natural fractures, thereby reducing filtration loss. Conventional fracturing particulate filtration-reducing materials are generally oil-soluble, but this invention does not require oil solubility. Materials that can solidify later are preferred. Low-concentration cementitious materials are recommended because they are difficult to solidify. When they agglomerate in natural fractures, the bridging concentration increases, making solidification easier.

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