Fractured-vuggy reservoir exploitation method and system based on density selective water plugging and plugging agent system

Abstract

The invention relates to the technical field of oil and gas field development engineering, in particular to a fracture-cavity type oil reservoir exploitation method and system based on density selective water plugging and a plugging agent system. According to the Stokes law, the density of a plugging agent is set to be between that of formation crude oil and that of formation water, and the plugging agent is spontaneously migrated in a targeted mode and enriched in an oil-water transition zone and a water channeling dominant channel through the early-stage, middle-stage and later-stage three-stage gradient injection technology and the gravitational differentiation effect; then solidifying and shaping to form a three-dimensional plugging network; bottom water inrush is effectively blocked, and liquid flow is forced to flow to an unaffected oil-containing area, so that the water content of a production well is remarkably reduced, the daily oil production is improved, and finally the recovery efficiency of the fracture-vug type oil reservoir is greatly improved. A matched temperature-resistant salt-resistant density-adjustable plugging agent system and an integrated mining system guarantee effective implementation of the method.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development engineering technology, and in particular to a method, system and plugging agent system for the exploitation of fractured-vuggy reservoirs based on density-selective water shut-off. Background Technology

[0002] Fractured-vuggy reservoirs are a special type of reservoir characterized by large caverns, network fractures, and dissolution pores as the main storage spaces and seepage channels. Their formation involves multiple phases of tectonic movement and paleokarstification, resulting in highly heterogeneous and disordered spatial distribution of reservoir units. These reservoirs are typically separated by low-permeability, tight interlayers or barriers. During development, bottom water coning or ridge-like phenomena are common, meaning bottom water easily surges rapidly into the production wellbore along high-conductivity fractures or large caverns, leading to premature water breakthrough or even sudden water flooding. This causes a sharp increase in water cut, a rapid decline in crude oil production, and severely restricts the ultimate recovery rate of the oilfield.

[0003] Currently, conventional techniques for addressing this type of water channeling problem mainly rely on chemical water shut-off or profile control measures. However, these conventional measures are generally ineffective in highly heterogeneous fractured-vuggy reservoirs, and their fundamental limitation lies in: (1) When conventional water plugging agents are injected, their flow direction is mainly controlled by the reservoir permeability field. They tend to enter all high-permeability channels and cannot intelligently distinguish whether the flow is water or oil. This leads to a large amount of plugging agent entering and blocking oil-bearing fractures and cavities that still have oil production potential, resulting in an unexpected decline in oil production capacity. The water plugging effect contradicts the oil preservation target. (2) Conventional techniques mainly rely on the adsorption, retention or physical blocking of the plugging agent and the rock. Its migration path is severely constrained by the initial permeability difference and lacks an active guiding mechanism. In complex fracture-cavity networks, the plugging agent is difficult to accurately reach and block the real water channel, and has limited improvement on macroscopic reach efficiency. (3) For reservoirs with significant oil-water density differences and gravity differentiation conditions, existing water shut-off technologies have failed to effectively utilize the gravity field to achieve intelligent distribution and selective plugging of plugging agents.

[0004] Therefore, developing a novel water-blocking method that can overcome the above-mentioned defects, especially one that can utilize the physical properties of the reservoir itself to achieve the accumulation of plugging agents in the water phase channel in deep reservoirs, has become a technical problem that urgently needs to be solved to improve the recovery rate of fractured-vuggy reservoirs. Summary of the Invention

[0005] The technical problem to be solved by this invention is: in order to address the problem in the prior art mentioned above that the high heterogeneity of fractured-vuggy reservoirs makes them prone to forming water flow channels, leading to a sharp decline in oil production and a rapid increase in overall water cut in the middle and late stages, thus affecting the exploitation effect, this invention provides a density-selective water shut-off method for exploiting fractured-vuggy reservoirs. This method can effectively block water flow channels, release the remaining oil blocked by water, significantly increase the oil production of a single well, and further improve the recovery rate of fractured-vuggy reservoirs.

[0006] The technical solution adopted by this invention to solve its technical problem is: a method for exploiting fractured-vuggy oil reservoirs based on density-selective water shut-off, comprising the following steps: S1. Reservoir Screening: Select fractured-vuggy reservoirs with a burial depth < 3500m, oil layer thickness > 25m, and underground crude oil viscosity < 20. The density of underground crude oil is <0.9. The matrix permeability is <5mD, and the permeability of the high-conductivity fractures is >2100mD; S2. Well layout: Drill production wells in the middle of the oil layer and injection wells at the bottom of the oil layer. The production wells are 10-15m away from the bottom of the oil layer, and the injection wells are 2-4.5m away from the bottom of the oil layer. The vertical distance between the two wells is 5-10m. S3. Staged Injection of Plugging Agent: Plugging agents of different densities, dosages, and properties are injected in early, middle, and late stages of development. The agent density is between that of crude oil and formation water, with a temperature resistance >130℃ and a salt resistance >100,000. Density range: 0.85–1.05 Initial viscosity 30-80 After gelation, the strength is >0.5MPa; S4. Formation of plug: After the injection pressure rises rapidly to the preset threshold, stop the injection and shut in the well for more than 3 days to allow the plugging agent to solidify and form a plug. S5. Reproduction: Detect the location of the plug and the remaining oil saturation, drill a new well above the plug or adjust the production system to produce oil.

[0007] The mining method of this invention constructs a complete mining process based on density-selective water shut-off, which fundamentally changes the migration and plugging logic of the plugging agent, changing from passively relying on the permeability field to actively utilizing the gravity field, so that the plugging agent can spontaneously tend to the oil-water transition zone and water channel.

[0008] Furthermore, the early injection density in S3 is 0.85–0.90. Low-viscosity pre-block plug, dosage 1000–3000 ; The intermediate-term injection density is 0.92–0.98. The gel-based blockade, with a dosage of 4000–7000. ; The injection density in the later stages was 0.98–1.05. High-strength plugging agent, dosage 1000-2500 .

[0009] Through the synergistic effect of early low-density slug floating and fine adjustment, mid-term transition density slug forming a network in the middle, and late-term near-water density slug sinking and strong sealing, the entire wellbore longitudinal space was sealed step by step and precisely, improving longitudinal sweep efficiency and effectively suppressing water channeling patterns at each stage.

[0010] Furthermore, the plugging agent is a density-adjustable gel polymer or inorganic particulate plugging agent, the density of which is adjusted by adding water-soluble salts.

[0011] By using gel polymers or inorganic particles and supplementing them with water-soluble salts to adjust the density, the plugging agent system is ensured to have the necessary temperature and salt resistance, controllable rheological properties, and the ability to achieve the preset density differentiation behavior downhole, thus ensuring feasibility and adaptability in the field.

[0012] Furthermore, in the early injection stage, the initial injection pressure is controlled to be ≤70% of the formation pressure; in the intermediate injection stage, the injection pressure is monitored to rise to above 16.8 MPa; and in the late injection stage, the preset injection pressure threshold is ≥18 MPa.

[0013] By monitoring the pressure changes from a slow rise to a significant rise to above 16.8 MPa and then to reaching the threshold of ≥18 MPa, the effect is to achieve precise diagnosis and control of the plugging agent migration and gelation sealing process, avoid blind injection, and ensure the effectiveness and safety of the sealing operation.

[0014] Furthermore, the density of the plugging agent in S3 is selected based on Stokes' law, so that the plugging agent particles can selectively migrate and plug in the oil and water phases based on the density difference.

[0015] The theoretical basis for selecting plugging agent density is Stokes' Law, which transforms the plugging agent density from empirical screening to precise calculation based on physical laws, ensuring that plugging agent particles can generate the expected floating or sinking speed in a specific reservoir fluid.

[0016] Furthermore, the formula for Stokes' Law is: , Where v is the settling / floating velocity of the plugging agent particles. The density of the plugging agent particles; ρ is the density of the underground fluid; g is the acceleration due to gravity; r is the radius of the plugging agent particles. The viscosity of the underground fluid; when >0, v is a positive value, and the particles sink; when If the value is less than 0, v is negative, and the particles float.

[0017] The Stokes Law formula is given, which allows the particle size and density of the plugging agent to be quantitatively set according to the crude oil density, formation water density and viscosity of the target reservoir, thereby improving the reproducibility and adaptability of the method in different reservoirs.

[0018] Furthermore, in S4, the well-clogging time is 3–5 days, and the density of the final plugging body formed by the plugging agent is >0.98. .

[0019] By limiting the well-closing time and the density of the final sealing material, the formed sealing barrier is ensured to have sufficient strength and stability. Sufficient settling time and a high-density final sealing material guarantee that the sealing wall can effectively withstand bottom water pressure for a long period, preventing breaches during subsequent production and thus achieving long-term stable production.

[0020] Furthermore, during the re-production in S5, the sealing effect is assessed by monitoring the decrease in water content and the increase in daily oil production.

[0021] The quantitative correlation between extraction results and plugging operations demonstrates that the method of this invention can not only seal water but also effectively release crude oil and improve recovery rate.

[0022] A plugging agent system for density-selective water shut-off in fractured-vuggy reservoir development, applicable to the above-mentioned scheme, is also provided, the plugging agent system comprising: Gel polymer or inorganic particulate plugging agent as the main agent; And, formate-based water-soluble salt additives used to adjust the density of the plugging agent main component; The plugging agent formed by mixing the main component and additives has the following properties: temperature resistance > 130℃, salt resistance > 100,000℃. Density between 0.85 and 1.05 Adjustable within a certain range, initial viscosity 30-80 The strength after gelation is >0.5MPa.

[0023] The density-selective water-blocking system is solidified in product form. This water-blocking system, through the setting of the main agent and density-adjusting additives, ensures that the method of the present invention can be executed with high quality and high efficiency.

[0024] A density-selective water shut-off system for fractured-vuggy reservoir development, as described above, is also provided, comprising: Injection wells and production wells: production wells are drilled in the middle of the oil layer, and injection wells are drilled at the bottom of the oil layer. The production well is 10-15m from the bottom of the oil layer, and the injection well is 2-4.5m from the bottom of the oil layer. The vertical distance between the two wells is 5-10m. The plugging agent injection equipment is used for staged injection of plugging agents. The density of the plugging agent is between that of crude oil and formation water, and it has a temperature resistance >130℃ and a salt resistance >100,000. Density range: 0.85–1.05 Initial viscosity 30-80 After gelation, the strength is >0.5MPa; The monitoring and control unit is used to monitor the injection pressure in real time, adjust the injection parameters, and stop the injection when the pressure reaches the threshold. It also includes logging equipment for detecting the location of the plug and the remaining oil saturation, as well as drilling equipment for drilling new wells above the plug.

[0025] This system integrates well placement, plugging agent injection equipment, intelligent monitoring and control units, and supporting logging and drilling equipment, ensuring that the entire technical solution can be applied on-site on a large scale, in a standardized and efficient manner.

[0026] The beneficial effects of this invention are: This invention precisely sets the density of the plugging agent to be between that of formation crude oil and formation water, and scientifically regulates it according to Stokes' Law. During the injection process, the plugging agent, relying on gravity differentiation, can spontaneously and selectively migrate and accumulate in the oil-water transition zone and high-permeability water channels with high water saturation, rather than indiscriminately entering all high-permeability zones. This allows the plugging agent to accurately seal water channels, effectively inhibit bottom water inrush, and avoid mis-sealing oil-bearing fractures with production potential. It successfully solves the problem of conventional water plugging measures blocking both water and oil. Through early, middle and late stage density gradient injection, the vertical space of the reservoir was sealed step by step and in three dimensions. The early stage low density slug floated up to fine-tune the flow field, the middle stage transition density slug formed a three-dimensional network of sealing in the oil-water coexistence zone, and the late stage high density slug strongly sealed the bottom deep dominant channels. In a coordinated and effective manner, the fluid flow path was changed, forcing the subsequent driving fluid to turn to the previously unaffected medium and low permeability oil-bearing area. This improved the vertical utilization of the reservoir, controlled the sharp rise in water cut, and created favorable conditions for the stability and improvement of crude oil production. This invention uses injection pressure as a real-time monitoring and control indicator, establishing a correlation between pressure changes at different injection stages and downhole plugging effects. This provides clear and quantifiable operational guidelines for on-site construction, achieving process controllability and predictable results. Simultaneously, the developed specialized plugging agent system possesses excellent temperature and salt resistance and density adjustability, enabling it to adapt to the harsh formation conditions commonly found in fractured-vuggy reservoirs. The accompanying production system enables closed-loop intelligent control from well placement, injection, monitoring to adjustment, collectively ensuring the high adaptability, operability, and repeatability of this technical solution in highly heterogeneous and complex fractured-vuggy reservoirs. Attached Figure Description

[0027] The present invention will be further described below with reference to the accompanying drawings and embodiments.

[0028] Figure 1 This is a flowchart of the mining method of the present invention.

[0029] Figure 2 This is a schematic diagram showing the distribution of plugging agents at different injection stages in fractured-vuggy reservoirs in the extraction method of the present invention; wherein (a) represents the early injection stage, (b) represents the middle injection stage, and (c) represents the late injection stage.

[0030] Figure 3 This is a schematic diagram of the wellhead injection pressure and plugging agent density in the mining method of the present invention.

[0031] Figure 4 This is a schematic diagram comparing the bottom water distribution before and after using the mining method of the present invention. Detailed Implementation

[0032] The present invention will now be described in further detail with reference to the accompanying drawings. These drawings are simplified schematic diagrams, illustrating only the basic structure of the invention, and therefore only show the components relevant to the invention.

[0033] Example 1 like Figure 1 As shown, a method for exploiting fractured-vuggy oil reservoirs based on density-selective water shut-off is characterized by the following steps: Step 1: Reservoir Screening: Select fractured-vuggy reservoirs with a burial depth < 3500m, oil layer thickness > 25m, and underground crude oil viscosity < 20. The density of underground crude oil is <0.9. The matrix permeability is <5mD, and the permeability of the high-conductivity fractures is >2100mD; Step 2, Well Placement: Drill a production well in the middle of the oil layer and an injection well at the bottom of the oil layer. The production well should be 10-15m from the bottom of the oil layer, and the injection well should be 2-4.5m from the bottom of the oil layer. The vertical distance between the two wells should be 5-10m. Step 3: Segmented Injection of Plugging Agent: Plugging agents of different densities, dosages, and properties are injected in the early, middle, and late stages of development. The agent density is between that of crude oil and formation water, with a temperature resistance >130℃ and a salt tolerance >100,000. Density range: 0.85–1.05 Initial viscosity 30-80 After gelation, the strength is >0.5MPa; Step 4: Formation of plug: After the injection pressure rises rapidly to the preset threshold, stop the injection and shut in the well for more than 3 days to allow the plugging agent to solidify and form a plug. Step 5, Re-production: Detect the location of the plug and the remaining oil saturation, and drill a new well above the plug or adjust the production system to produce oil.

[0034] The extraction method in this embodiment fully utilizes the density difference between the oil, water, and plugging agent phases in the reservoir to achieve spontaneous separation and selective migration under the influence of gravity. In the reservoir environment, crude oil, formation water, and plugging agent can be considered as fluid phases with different densities. According to Archimedes' principle of buoyancy, a plugging agent system with a density between oil and water will experience a net upward buoyancy force or a net downward gravity force under static or low-speed flow conditions, thus spontaneously aggregating and distributing near the physical interface of the oil-water transition zone. The extraction method in this embodiment actively utilizes and enhances this natural differentiation process by precisely controlling the plugging agent density, guiding the plugging agent to intelligently target the water-phase dominant channel.

[0035] Among them, the preferred plugging agent is a temperature-resistant, salt-resistant, and density-adjustable plugging agent, such as a gel polymer or an inorganic particle with adjustable density.

[0036] like Figure 2 As shown in (a), the configuration density is 0.88 during the early injection phase. The initial pressure of the plugging agent system is typically 50%–70% of the formation pressure to ensure smooth entry of the plugging agent into the target channel. A slow pressure increase indicates uniform propagation of the plugging agent within the channel. Due to its lower density than crude oil, the plugging agent floats to the upper part of the oil phase accumulation zone in the oil-water coexistence zone under buoyancy. Under the combined control of gravity differentiation and the reservoir permeability field, the plugging agent preferentially migrates downwards along the bottom high-permeability water channel, forming a local enrichment pattern. In the figure, the black area represents rock, the red area represents crude oil, the blue area represents bottom water, and the yellow area represents the plugging agent. At this stage, the plugging agent initially constructs a low-level sealing barrier in the near-wellbore zone, effectively inhibiting bottom water coning and altering the crude oil flow path, optimizing the pressure field distribution, and thus improving the fluid flow pattern within the reservoir.

[0037] like Figure 2 As shown in (b), during the intermediate injection stage, appropriate concentrations of water-soluble salts such as formate are added. Through precise calculations and real-time measurements, the plugging agent density was adjusted to approximately 0.95. The pressure increased significantly (from 9.0 MPa to 16.8 MPa), indicating that the dominant channels were blocked and the flow field shifted to a medium-low permeability region, placing its density between the oil and water phases, in the oil-water transition zone. Under these density conditions, the plugging agent could effectively reach the oil-water coexistence zone, which was difficult for traditional plugging agents to access. Utilizing the complex pore-crack-cavity network in the fracture-cavity system, the plugging agent achieved multi-path transport and three-dimensional diffusion, significantly expanding its distribution range. Its morphology evolved from early localized enrichment to a complex network structure penetrating fracture-cavity units, thus effectively blocking and controlling the central oil-water mixing zone.

[0038] like Figure 2 As shown in (c), in the later injection stage, an appropriate amount of water-soluble formate salt is further added to increase the plugging agent density to approximately 1.00. The density of the plugging agent is brought close to that of water. When the pressure rapidly rises to a preset threshold (20 MPa), injection must be stopped to prevent the formation of new cracks or damage to the existing sealing system. During this stage, the plugging agent gradually reaches a dynamic equilibrium, and its macroscopic distribution stabilizes, forming a spatial sealing system with good lateral continuity. This system effectively blocks the dominant channels for water flow at the bottom, achieving comprehensive control over the water at the bottom of the entire crack / cavity unit.

[0039] Early low-density slugs identify and initially control the top oil flow channels through their upward movement, while simultaneously paving the way for subsequent plugging agents. Mid-term transitional density slugs, through their density, allow them to remain in complex oil-water mixing zones, achieving regional water control through three-dimensional networking and effectively expanding the swept volume. Late-term high-density slugs penetrate deep into the bottom water channels for targeted plugging, ultimately forming a three-dimensional barrier from the bottom to the middle of the oil layer. These three stages are closely related, achieving a synergistic enhancement from micro-selectivity to macro-level overall plugging.

[0040] like Figure 3 As shown, changes in wellhead injection pressure directly reflect the downhole plugging dynamics. A slow rise in pressure indicates that the plugging agent is steadily advancing and initially lodging within the main channel. A significant rise in pressure signifies that the plugging agent is bridging, accumulating, and gelling at the throat of the dominant channel, leading to a sharp increase in seepage resistance, indicating that the main flow channel has been effectively blocked. A rapid rise in pressure to the threshold indicates that the plugging system is nearly complete, and continued injection may lead to system rupture or diversion into ineffective spaces. Therefore, injection control with pressure as the key feedback signal is essentially a closed-loop optimization process to achieve efficient and economical plugging.

[0041] The density selection is based on Stokes' Law, ensuring that the plugging agent particles selectively migrate and plug in the oil-water two-phase system based on the density difference; the formula for Stokes' Law is: , Where v is the settling / floating velocity of the plugging agent particles. The density of the plugging agent particles; ρ is the density of the underground fluid (oil or water); g is the acceleration due to gravity; r is the radius of the plugging agent particles. The viscosity of the underground fluid; when >0, v is a positive value, and the particles sink; when If the value is less than 0, v is negative, and the particles float.

[0042] Figure 4(a) The bottom water distribution state before implementing the method of the present invention. Under conventional production conditions, due to the strong heterogeneity of the reservoir and the effect of gravity, the bottom water (indicated in blue) mainly enters rapidly along channels such as large fractures or caves with high conductivity, forming ineffective circulation. This water channeling phenomenon causes the production wells to be flooded prematurely, and the water cut rises sharply. At the same time, a large amount of crude oil (indicated in red) is blocked in low-permeability matrix, complex pore systems, or isolated fractures and cavities surrounded by water, and cannot be effectively driven to the production wells, resulting in the enrichment of residual oil and low crude oil recovery rate.

[0043] Figure 4 (b) To illustrate the bottom water distribution after implementing the method of this embodiment and reproducing, a density-selective plugging agent (represented by the yellow area of ​​the final plugging body) is injected. Under gravity differentiation, the plugging agent solidifies and forms an effective three-dimensional plugging network within the dominant water channel and oil-water transition zone at the bottom. The plugging body raises the flow direction of subsequent driving water, forcing the bottom water to be unable to advance along the original dominant channel. Furthermore, because the main water channel is blocked, subsequent injected water or natural energy is forced to redirect to previously unaffected or less affected medium- and low-permeability oil-bearing areas, activating previously untapped residual oil. Under the new flow field, the plugged residual oil is effectively driven and converges towards the adjusted production well or the new production section of the original production well. The figure clearly shows that the red crude oil area originally blocked by water has decreased, indicating effective crude oil recovery and achieving the dual goals of reducing water cut and increasing oil production.

[0044] The feasibility of the mining method in this embodiment will be further illustrated below with specific examples. Specific Implementation Example 1 Oilfield 1 reservoir is buried at a depth of 2450m, with an oil layer thickness of 35m and an underground crude oil viscosity of 18. The density of underground crude oil is 0.86. The matrix permeability is 4.8 mD, and the permeability of highly conductive fractures is 3150 mD. The original formation pressure is approximately 25.3 MPa. The reservoir meets the following conditions: it is a fractured-vuggy reservoir, the oil layer is a medium-deep reservoir, the burial depth is <3500m, the oil layer thickness is >25m, and the viscosity of the underground crude oil is <20. The density of underground crude oil is <0.9. The matrix permeability is <5mD, and the permeability of the high-conductivity fractures is >2100mD.

[0046] Drill an injection well at the bottom of the oil layer and a production well in the middle of the oil layer. The production well is 13.6m from the bottom of the oil layer and 8.8m vertically from the injection well. The location of the production well will be changed later as the bottom water rises. During the early water breakthrough stage, pump in a low-viscosity, high-flowability polymer pre-plug, with the dosage controlled at 2000... The concentration is 500 ppm, and the injection volume is 10. The slug preferentially enters the high-permeability fractured channel, initially adjusting the flow field distribution, and the wellhead injection pressure slowly increases from 8.0 MPa to 9.5 MPa; during the middle stage of rapid water cut increase, a polymer gel slug is injected at a dose of 5000... Concentration 3000ppm, injection rate reduced to 8 The gelation time of this system is controllable, forming a stable gel sealing barrier within the crack channels. The injection pressure significantly increased from 9.0 MPa to 16.8 MPa, indicating that the dominant flow channels were effectively blocked. In the later stages of development, to address deep flow, 1500... High-strength composite plugging agent, injection displacement controlled at 5 The density of the plugging agent was precisely adjusted to 0.93. Located between crude oil and formation water, it selectively enters the bottom water phase channel through gravity differentiation. Injection was stopped when the injection pressure rapidly increased from 15.0 MPa to 18.4 MPa.

[0047] After the plugging agent is injected, the well is shut in and left to stand for 3 days to ensure that the plugging agent fully solidifies and forms a three-dimensional sealing network in the deep fractures. After the plugging agent solidifies into a wall, the sealing position is checked and the remaining oil saturation at the top of the wall is tested. Monitoring after the well is put into production shows that the water cut has steadily decreased from 92% before the measures to 75%.

[0048] The block implemented a density-selective water shut-off method to enhance oil recovery in fractured-vuggy reservoirs, resulting in a 220% reduction in daily water production. Daily oil production increased from 60 before implementation Rising to the current 89 This represents an increase of 48.31%. The recovery rate of fractured-vuggy reservoirs has significantly improved after implementation. Specific Implementation Example 2 The reservoir is a high-temperature, high-pressure fractured-vuggy reservoir, currently in the middle to late stages of extraction. The oil layer is a deep reservoir with a burial depth of [missing information]. 4500m oil layer thickness 40m Formation temperature 145℃, original formation pressure 50 MPa Viscosity of underground crude oil 15 underground crude oil density 0.87 Matrix permeability 3.5mD High conductivity fractures develop, permeability 2800mD .

[0050] Drill a production well in the middle of the oil layer and an injection well at the bottom of the oil layer. The production well is located at a distance from the bottom of the oil layer. 12m The injection well is located at the bottom of the oil layer. 3m The vertical distance between the two wells is 8m The wellbore utilizes high-temperature and high-pressure resistant materials and completion techniques to ensure injection and production safety. A plugging agent is injected. Preferred plugging agents with further enhanced performance: Temperature resistance >150℃ , Salt resistance >150,000 Density range: 0.85–1.05 Adjustable, initial viscosity 40-60 The strength after gelation at 145℃ >0.8MPa In the early injection phase The injection density is 0.88 Pre-implantation plug, dose 2500 , injection displacement 12 The initial wellhead pressure was 20 MPa. The low-density slug effectively floated and preferentially entered the bottom high-permeability channel even at high temperatures, allowing the injection pressure to slowly rise to 22 MPa, thus achieving fine-tuning of the flow field. During the intermediate injection phase... The injection density was adjusted to 0.95 The main gel segment plug, with a dosage of 6000 The injection displacement was reduced to 10. Utilizing its thermal stability, a stable mesh-like seal is formed in the oil-water transition zone, significantly increasing the injection pressure to 35 MPa. In the later injection stage... The injection density is 1.02 High-strength plugging agent, dosage 2000 The injection displacement is controlled at 6. A strong seal is formed in the near-wellbore area and deep passages, when the injection pressure at the wellhead continues to rise rapidly to... 48MPa Stop the injection immediately when the level approaches the safety threshold.

[0051] Forming a blockade After stopping injection, shut down both the injection well and the production well, and then shut off the wells. 5 days (The gelation reaction may be slightly faster at high temperatures, but to ensure sufficient strength formation, the well-clogging time should be appropriately extended.) The plugging agent fully solidifies and sets under high temperature and high pressure, forming an effective bottom water-retaining wall. The final density of the plugging agent is... Around 1.00 about Reproduction After the well was shut off, the residual oil saturation was checked to confirm that the barrier wall formed by the plugging agent had been effectively established and that the upper part of the barrier wall was enriched with residual oil. Drilling was then carried out in the oil-rich zone above the barrier wall. New production well High-temperature resistant oil pumps were used for production. After the measures were implemented, the water cut of the well decreased from 95% to 73%, and the daily oil production increased significantly, successfully realizing the efficient tapping of the potential of high-temperature, high-pressure fractured-vuggy reservoirs.

[0052] Example 2 A plugging agent system applicable to the density-selective water shut-off method for fracture-vuggy reservoir development in Example 1, the plugging agent system comprising: Gel polymer or inorganic particulate plugging agent as the main agent; And, formate-based water-soluble salt additives used to adjust the density of the plugging agent main component; The plugging agent formed by mixing the main component and additives has the following properties: temperature resistance > 130℃, salt resistance > 100,000℃. Density between 0.85 and 1.05 Adjustable within a certain range, initial viscosity 30-80 The strength after gelation is >0.5MPa.

[0053] In the plugging agent system, the density of the mixed plugging agent system can be linearly and precisely adjusted by changing the concentration of the formate-based water-soluble salt additive. This additive has good compatibility with gel polymers or inorganic particulate main agents and does not affect their gelation stability or particle dispersibility, thus ensuring that the plugging agent has adjustable density while its plugging performance is not affected.

[0054] Example 3 An embodiment of a density-selective water shut-off fracture-vuggy reservoir production system includes: Injection wells and production wells: production wells are drilled in the middle of the oil layer, and injection wells are drilled at the bottom of the oil layer. The production well is 10-15m from the bottom of the oil layer, and the injection well is 2-4.5m from the bottom of the oil layer. The vertical distance between the two wells is 5-10m. The plugging agent injection equipment is used for staged injection of plugging agents. The density of the plugging agent is between that of crude oil and formation water, and it has a temperature resistance >130℃ and a salt resistance >100,000. Density range: 0.85–1.05 Initial viscosity 30-80 After gelation, the strength is >0.5MPa; The monitoring and control unit is used to monitor the injection pressure in real time, adjust the injection parameters, and stop the injection when the pressure reaches the threshold. It also includes logging equipment for detecting the location of the plug and the remaining oil saturation, as well as drilling equipment for drilling new wells above the plug.

[0055] Based on the above-described preferred embodiments of the present invention, and through the foregoing description, those skilled in the art can make various changes and modifications without departing from the inventive concept. The technical scope of this invention is not limited to the contents of the specification, but must be determined according to the scope of the claims.

Claims

1. A method for exploiting fractured-vuggy oil reservoirs based on density-selective water shut-off, characterized in that, Includes the following steps: S1. Reservoir Screening: Select fractured-vuggy reservoirs with a burial depth < 3500m, oil layer thickness > 25m, and underground crude oil viscosity < 20. The density of underground crude oil is <0.

9. The matrix permeability is <5mD, and the permeability of the high-conductivity fractures is >2100mD; S2. Well layout: Drill production wells in the middle of the oil layer and injection wells at the bottom of the oil layer. The production wells are 10-15m away from the bottom of the oil layer, and the injection wells are 2-4.5m away from the bottom of the oil layer. The vertical distance between the two wells is 5-10m. S3. Staged Injection of Plugging Agent: Plugging agents of different densities, dosages, and properties are injected in early, middle, and late stages of development. The agent density is between that of crude oil and formation water, with a temperature resistance >130℃ and a salt resistance >100,000. Density range: 0.85–1.05 Initial viscosity 30-80 After gelation, the strength is >0.5MPa; S4. Formation of plugging: After the injection pressure rapidly rises to the preset threshold, the injection is stopped, and the well is shut in and left to stand for more than 3 days to allow the plugging agent to solidify and form a plugging body. S5. Reproduction: Detect the location of the plug and the remaining oil saturation, drill a new well above the plug or adjust the production system to produce oil.

2. The method for developing fractured-vuggy reservoirs based on density-selective water shut-off according to claim 1, characterized in that: The early injection density in S3 is 0.85–0.

90. Low-viscosity pre-block plug, dosage 1000–3000 ; The intermediate-term injection density is 0.92–0.

98. The gel-based blockade, with a dosage of 4000–7000. ; The injection density in the later stages was 0.98–1.

05. High-strength plugging agent, dosage 1000-2500 .

3. The method for developing fractured-vuggy reservoirs based on density-selective water shut-off according to claim 1 or 2, characterized in that: The plugging agent is a density-adjustable gel polymer or inorganic particulate plugging agent, the density of which is adjusted by adding water-soluble salts.

4. The method for developing fractured-vuggy reservoirs based on density-selective water shut-off according to claim 1 or 2, characterized in that: In the early injection stage, the initial injection pressure is controlled to be ≤70% of the formation pressure; in the intermediate injection stage, the injection pressure is monitored to rise to above 16.8 MPa; in the late injection stage, the preset injection pressure threshold is ≥18 MPa.

5. The method for developing fractured-vuggy reservoirs based on density-selective water shut-off according to claim 4, characterized in that: The density of the plugging agent in S3 is selected based on Stokes' law, so that the plugging agent particles can selectively migrate and plug in the oil and water phases based on the density difference.

6. The method for developing fractured-vuggy reservoirs based on density-selective water shut-off according to claim 5, characterized in that: Stokes' Law is calculated as follows: ， Where v is the settling / floating velocity of the plugging agent particles. The density of the plugging agent particles; ρ is the density of the underground fluid; g is the acceleration due to gravity; r is the radius of the plugging agent particles. The viscosity of the underground fluid; when >0, v is a positive value, and the particles sink; when If the value is less than 0, v is negative, and the particles float.

7. The method for developing fractured-vuggy reservoirs based on density-selective water shut-off according to claim 1, characterized in that: In S4, the well-clogging time is 3–5 days, and the density of the final plugging material is >0.

98. .

8. The method for developing fractured-vuggy reservoirs based on density-selective water shut-off according to claim 1, characterized in that: When S5 resumes production, the sealing effect is assessed by monitoring the decrease in water content and the increase in daily oil production.

9. A plugging agent system applicable to the density-selective water shut-off method for fractured-vuggy reservoir development according to any one of claims 1 to 8, characterized in that, The plugging agent system includes: Gel polymer or inorganic particulate plugging agent as the main agent; And, formate-based water-soluble salt additives used to adjust the density of the plugging agent main component; The plugging agent formed by mixing the main component and additives has the following properties: temperature resistance > 130℃, salt resistance > 100,000℃. Density between 0.85 and 1.05 Adjustable within a certain range, initial viscosity 30-80 The strength after gelation is >0.5MPa.

10. A fracture-vuggy reservoir development system based on density-selective water shut-off as described in any one of claims 1 to 8, characterized in that, include: Injection wells and production wells: production wells are drilled in the middle of the oil layer, and injection wells are drilled at the bottom of the oil layer. The production well is 10-15m from the bottom of the oil layer, and the injection well is 2-4.5m from the bottom of the oil layer. The vertical distance between the two wells is 5-10m. The plugging agent injection equipment is used for staged injection of plugging agents. The density of the plugging agent is between that of crude oil and formation water, and it has a temperature resistance >130℃ and a salt resistance >100,000. Density range: 0.85–1.05 Initial viscosity 30-80 After gelation, the strength is >0.5MPa; The monitoring and control unit is used to monitor the injection pressure in real time, adjust the injection parameters, and stop the injection when the pressure reaches the threshold. It also includes logging equipment for detecting the location of the plug and the remaining oil saturation, as well as drilling equipment for drilling new wells above the plug.

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