Controllable zonal viscosity-reducing closed-loop synergistic recovery method for heavy oil reservoir

Abstract

The application discloses a controllable partition viscosity reduction closed-loop coordinated exploitation method for a heavy oil reservoir, and comprises the following steps: S1, based on target production well dynamic and static data, a partition model is established according to well spacing, permeability heterogeneity and pressure drop distribution, the reservoir is divided into a near-well zone, a transition zone and a far-well zone, and target parameters are determined; S2, a first viscosity reduction system is injected to preferentially act on the near-well zone, and the viscosity reduction amplitude is controlled within a preset amplitude range; S3, a second viscosity reduction system with post-migration activation characteristics and / or time sequence release characteristics is injected to gradually produce viscosity reduction effect in the transition zone or the far-well zone; S4, monitoring data are acquired in the production stage and compared with the target parameters; S5, an injection system is dynamically adjusted according to deviation; S6, continuous production is carried out after the injection is stopped, and S2 to S5 are repeated when the deviation is out of the target range. Through the cooperation of partition differential viscosity reduction and closed-loop regulation, the application realizes spatial balance in the viscosity reduction process, inhibits the dominant channel, improves the producing degree and swept volume of the far-well zone, and prolongs the stable production period.

Description

Technical Field

[0001] This invention relates to the field of petroleum extraction technology, specifically to a controlled zone viscosity reduction closed-loop collaborative extraction method for heavy oil reservoirs. Background Technology

[0002] Heavy oil reservoirs have high crude oil viscosity and poor fluidity, making conventional cold extraction difficult to start. Oilfield production often employs technologies such as steam huff and puff, steam drive, steam-assisted gravity drainage (SAGD), solvent-assisted thermal recovery, and chemical viscosity reduction for extraction.

[0003] Existing research focuses primarily on improving heat sources, solvent systems, or viscosity reducer formulations. For example, patents CN121064818B ("A viscosity reducer for heavy oil with gum as the main viscosity contributing component and its preparation method") and CN121203641A ("An oil-soluble viscosity reducer composition and its preparation method and use") mainly optimize the viscosity-reducing components based on viscosity-contributing substances in heavy oil. In practice, both are typically applied using a combination of conventional injection and thermal well shut-off.

[0004] However, in actual viscosity reduction and production enhancement operations, the viscosity reduction process of heavy oil often exhibits obvious spatial and temporal non-equilibrium characteristics. This is mainly manifested in the following ways: the viscosity reduction effect is significant near the wellbore, in fractures, or in high-permeability zones, forming advantageous low-viscosity channels where injected media and energy can easily short-circuit along these channels; however, the far-well area (i.e., the area far from the wellbore) may still maintain a high viscosity state for a long time, making it difficult for crude oil to flow. This results in insufficient effective viscosity reduction area, low utilization rate, and short stable production cycle in the far-well area, seriously affecting the overall development effect.

[0005] On the other hand, a long-neglected technical challenge exists in heavy oil extraction: viscosity reduction is not always better the stronger it is. Excessive viscosity reduction can damage the formation structure, increase the difficulty of crude oil displacement, and easily lead to emulsion formation, thus increasing the difficulty of subsequent surface oil-water separation. In thermal recovery, excessively low viscosity may also increase heat loss. Therefore, how to effectively extend the viscosity reduction effect to the far-wellbore area while controlling the degree of viscosity reduction in the near-wellbore area is a critical issue that urgently needs to be addressed.

[0006] In summary, it is urgent to systematically optimize the entire mining process by combining existing viscosity-reducing materials, in order to overcome the problems of the current technology, such as the simplistic approach to viscosity-reducing mining operations, uneven spatial effects, and lack of closed-loop feedback control, thereby improving the viscosity-reducing effect, the volume affected, the degree of mobilization, and extending the stable production cycle.

[0007] In view of this, the present invention is hereby proposed. Summary of the Invention

[0008] This invention proposes a controllable zoned viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs to solve the problems of the single viscosity reduction exploitation operation scheme and poor effect in the existing technology.

[0009] Specifically, the following technical solution was adopted: A controlled, zoned viscosity reduction, closed-loop, and coordinated exploitation method for heavy oil reservoirs includes: Step S1: Based on the static and dynamic production data of the reservoir controlled by the target production well, and according to the well spacing, permeability heterogeneity and pressure drop distribution, establish a radial and / or vertical zoning model centered on the target production well. The zoning model divides the reservoir into near-well zone, transition zone and far-well zone, and determines the target parameters for each zone. The target parameters include at least the target viscosity, target mobility ratio or target swept volume. Step S2: Inject the first viscosity-reducing system into the reservoir, so that the first viscosity-reducing system acts preferentially on the near-wellbore area to reduce the viscosity of the heavy oil in the near-wellbore area, and control the viscosity reduction range within a preset limit range; Step S3: After completing step S2, a second viscosity-reducing system is injected into the reservoir. The second viscosity-reducing system has post-migration activation characteristics and / or time-sequential release characteristics, so that it gradually produces a viscosity-reducing effect after migrating to the transition zone or far-well zone. Step S4: After the injection operation in steps S2 and S3 is completed, the production stage begins. Wellhead or downhole monitoring data is acquired and compared with the target parameters determined in step S1. Step S5: Based on the deviation from the comparison in Step S4, dynamically adjust the injection volume, injection sequence, injection intensity, and / or injection time of the first and second viscosity-reducing systems. Step S6: After stopping the injection, enter the continuous production stage. When the viscosity of each zone or the viscosity of the product fluid deviates from the target range, repeat steps S2 to S5.

[0010] Optionally, in the controlled zone viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs of the present invention, in step S1, the static data includes reservoir structure, reservoir properties, and fluid distribution data, wherein the reservoir structure includes interlayer distribution, the reservoir properties include permeability distribution and porosity distribution, and the fluid distribution includes the abundance of reserves in each sublayer and fluid properties; the dynamic production data includes injection-production well spacing, production pressure difference, production rate, water cut change data, production profile test data, and / or water absorption profile test data.

[0011] Optionally, in the controlled zonal viscosity reduction closed-loop collaborative production method for heavy oil reservoirs of the present invention, step S1, establishing a radial and / or vertical zonal model centered on the target production well, includes at least one of the following: Based on the permeability distribution and the pressure gradient distribution determined by the production pressure difference, the area with a pressure gradient higher than the first preset threshold is classified as the near-well zone, the area with a pressure gradient between the first preset threshold and the second preset threshold is classified as the transition zone, and the area with a pressure gradient lower than the second preset threshold is classified as the far-well zone. Based on the permeability gradient determined by the permeability distribution, and combined with the injection-production well spacing and pressure drop propagation radius, the equivalent flow unit comprehensive index is used for zoning; The preliminary zoning results are dynamically verified and corrected using the product fluid profile test data and / or water absorption profile test data. When establishing a vertical partitioning model, vertical partitioning is performed based on the vertical permeability heterogeneity determined by the permeability distribution, the interlayer distribution, and the reserve abundance of each sublayer.

[0012] Optionally, in the controlled zone viscosity reduction closed-loop co-production method for heavy oil reservoirs of the present invention, step S2 includes: The first viscosity-reducing system includes a viscosity-reducing agent, a migration-limiting control component, and a carrier fluid component. The migration-limiting control component is used to limit the migration distance of the viscosity-reducing agent so that the viscosity-reducing effect is controlled within the near-wellbore zone defined in step S1. The preset limiting range is set according to the target viscosity in the near-wellbore area determined in step S1, so that the viscosity of the heavy oil in the near-wellbore area is within the allowable deviation range of the target viscosity after viscosity reduction. The first viscosity-reducing system was injected using a pulse injection method, with the total injection volume determined based on the near-wellbore pore volume. After injection, the well was shut in for soaking.

[0013] Optionally, in the controlled zone viscosity reduction closed-loop co-production method for heavy oil reservoirs of the present invention, step S3 includes: The second viscosity-reducing system includes a post-transport activation component, a threshold triggering component, a transport enhancement component, and a carrier liquid component; The activated component after migration is a slow-release pour point depressant or a precursor reaction-generated viscosity depressant. The threshold triggering component is used to delay the activation of viscosity reduction under formation conditions, so that the second viscosity reduction system gradually produces viscosity reduction after it migrates to the transition zone or far well zone. The migration-enhancing component is used to improve the migration capacity of the second viscosity-reducing system in the reservoir; The total injection volume of the second viscosity-reducing system is determined based on the pore volume of the transition zone and the far-well zone.

[0014] Optionally, in the controlled zone viscosity reduction closed-loop synergistic exploitation method for heavy oil reservoirs of the present invention, the transport enhancement component in the second viscosity reduction system is a gas component and / or a nano-dispersed enhancement material; The first viscosity-reducing system and / or the second viscosity-reducing system further include a flowability control component, wherein the flowability control component is at least one of a gel, a weak gel, a cross-linked polymer, microspheres, or a particulate profile control agent.

[0015] Optionally, in the controlled zone viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs of the present invention, in step S4: the monitoring data includes one or more of the following: production fluid viscosity, production fluid water cut, wellhead pressure, bottom hole pressure, temperature, or tracer response; When a tracer response is used, the tracer is injected before the first or second viscosity-reducing system. The tracer concentration is sampled and detected during the production stage to obtain the tracer breakthrough curve. The average arrival time of the tracer is calculated using the moment method, and the swept pore volume or swept coefficient is determined accordingly. This is compared with the target swept volume determined in step S1 to determine whether there is a short circuit in the dominant channel or insufficient utilization of the far-field.

[0016] Optionally, in the controlled zone viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs of the present invention, step S5, the dynamic adjustment includes at least one of the following: When the rate of decrease in viscosity of the product fluid exceeds a preset threshold and the rate of increase in water content exceeds a preset threshold, the injection volume and / or injection intensity of the first viscosity-reducing system are reduced, and the injection volume and / or injection intensity of the second viscosity-reducing system are increased. When the viscosity of the product fluid is found to be consistently high and the output is lower than the preset value, the injection intensity of the second viscosity-reducing system is increased and / or its activation window is extended. When the peak advance factor of the tracer is detected to exceed the preset threshold, it is determined that there is a short circuit in the dominant channel, the concentration and / or injection volume of the first viscosity-reducing system are reduced, and the proportion of the transport-limiting control component and / or the flow rate control component is increased.

[0017] Optionally, in the controlled zone viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs of the present invention, in step S5, the dynamic adjustment adopts an adaptive pulse injection control mode with differential pressure window constraints: The pressure difference between the wellhead pressure or bottom hole pressure and the injection manifold pressure is used as the injection intensity constraint. An injection pressure difference window is set, wherein the upper limit of the pressure difference does not exceed the preset proportion of the pressure difference corresponding to the formation fracture pressure, and the lower limit of the pressure difference is set as a short-circuit warning threshold based on the historical pressure decay curve. Using the pulse injection duty cycle as the control variable, the duty cycle, injection volume, injection intensity and / or injection time of the first viscosity reducing system and the second viscosity reducing system are dynamically adjusted based on the monitoring results of product viscosity, water content, pressure and / or tracer response. When the pressure difference is detected to decrease by more than a preset proportion within a continuously preset time period, the duty cycle of the first viscosity-reducing system is reduced, while the duty cycle of the second viscosity-reducing system is increased.

[0018] Optionally, the controlled zone viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs of the present invention further includes step S7: determining the well life based on the cumulative production of the target production well, and optimizing the zone model established in step S1 based on the corresponding dynamic production data, and redetermining the boundaries and / or target parameters of each zone. Furthermore, the production wells in this application are vertical wells, horizontal wells, or multi-branch wells, meaning the method of this application is applicable to various well types. When the production well is a horizontal well, near-wellbore limited viscosity reduction and mid-to-far-range compensated viscosity reduction are performed segmentally along the well section within the horizontal well.

[0019] Compared with the prior art, the beneficial effects of the present invention are as follows: The present invention discloses a controllable zoned viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs. In step S1, a zoned model is constructed to divide the reservoir into near-well zone, transition zone and far-well zone, and target parameters are determined for each zone. This gives the subsequent viscosity reduction operation clear spatial guidance and lays the foundation for achieving zoned differentiated control.

[0020] The present invention provides a controllable zoned viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs. In step S2, near-wellbore viscosity reduction is limited, and the viscosity reduction range in the near-wellbore area is controlled within a preset limit range. This avoids the formation of a dominant channel due to excessively low viscosity in the near-wellbore area, effectively suppresses short-circuit circulation of the injected medium, and promotes the spread of the subsequently injected viscosity reduction system to the mid-to-far area.

[0021] The present invention discloses a controllable zoned viscosity reduction closed-loop synergistic exploitation method for heavy oil reservoirs. In step S3, viscosity reduction is compensated in the mid-to-far zone. By utilizing the migration activation characteristics and / or time-sequential release characteristics of the second viscosity reduction system, the viscosity reduction effect is gradually generated in the transition zone or far well zone, which effectively improves the utilization of heavy oil in the far well zone and makes up for the deficiency of insufficient far-zone effect of conventional viscosity reduction methods.

[0022] The present invention discloses a controllable zoned viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs. Through closed-loop monitoring in step S4 and system adjustment in step S5, the monitoring data during the production process is compared with the target parameters, and the injection volume, injection sequence, injection intensity and / or injection time are dynamically adjusted accordingly, forming a closed-loop control of "monitoring-comparison-adjustment". This makes the entire viscosity reduction operation process controllable, can correct deviations in a timely manner, and avoids blind injection.

[0023] The present invention discloses a controlled zone viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs. By monitoring during the continuous production phase after injection is stopped in step S6, and repeating the viscosity reduction and adjustment steps when the target range is deviated, the long-term dynamic maintenance of the viscosity reduction state of the reservoir is achieved, thus extending the stable production cycle.

[0024] Overall, the controllable zonal viscosity reduction closed-loop collaborative development method for heavy oil reservoirs of the present invention, based on the zonal model, combines near-wellbore limited viscosity reduction with mid-to-far zone compensated viscosity reduction, and close-loop monitoring and dynamic adjustment to achieve spatial equilibrium control and temporal dynamic optimization of the heavy oil viscosity reduction process. This effectively increases the swept volume, improves the development performance of heavy oil reservoirs, significantly increases single-well production, slows down the rate of water cut increase, and significantly extends the stable production period. Attached Figure Description

[0025] Figure 1 This is a flowchart illustrating a controlled zone viscosity reduction and closed-loop synergistic exploitation method for heavy oil reservoirs according to an embodiment of the present invention; Figure 2 This is a schematic diagram of the radial zoning of the reservoir according to an embodiment of the present invention (taking a vertical well as an example); Figure 3 This is a schematic diagram of the closed-loop control module in an embodiment of the present invention. Detailed Implementation

[0026] To make the objectives, technical solutions, and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some embodiments of the present invention, and not all embodiments.

[0027] Therefore, the following detailed description of embodiments of the present invention is not intended to limit the scope of the claimed invention, but merely illustrates some embodiments of the invention. All other embodiments obtained by those skilled in the art based on the embodiments of the present invention without inventive effort are within the scope of protection of the present invention.

[0028] It should be noted that, unless otherwise specified, the embodiments and features and technical solutions in the present invention can be combined with each other.

[0029] It should be noted that similar labels and letters in the following figures indicate similar items. Therefore, once an item is defined in one figure, it does not need to be further defined and explained in subsequent figures.

[0030] In the description of this invention, it should be noted that the terms "upper," "lower," etc., indicate the orientation or positional relationship based on the orientation or positional relationship shown in the accompanying drawings, or the orientation or positional relationship commonly used when the product of this invention is in use, or the orientation or positional relationship commonly understood by those skilled in the art. These terms are only for the convenience of describing this invention and simplifying the description, and do not indicate or imply that the device or element referred to must have a specific orientation, or be constructed and operated in a specific orientation, and therefore should not be construed as a limitation of this invention. In addition, the terms "first," "second," etc., are only used to distinguish descriptions and should not be construed as indicating or implying relative importance.

[0031] This invention provides a controllable zoned viscosity reduction closed-loop collaborative exploitation method for heavy oil reservoirs. Its core concept lies in: establishing a zoned model centered on the target production well based on the dynamic and static data of the reservoir; dividing the reservoir into near-wellbore, transition, and far-wellbore zones; achieving collaborative operation of near-wellbore limited viscosity reduction and mid-to-far-well compensated viscosity reduction by sequentially injecting two different viscosity reduction systems; simultaneously establishing a closed-loop monitoring and dynamic control mechanism to adjust the injection regime in real time based on the comparison results of monitoring data obtained during production and target parameters; and repeating the viscosity reduction and adjustment steps during the continuous production phase after injection cessation, based on deviations, thereby maintaining a dynamic equilibrium of the reservoir's viscosity reduction state throughout the entire exploitation cycle.

[0032] like Figure 1 As shown in this embodiment, a method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs includes the following steps: Step S1: Construct the partition model.

[0033] First, based on the static and dynamic production data of the reservoir controlled by the target production well, and according to well spacing, permeability heterogeneity, and pressure drop distribution, a radial and / or vertical zoning model centered on the target production well is established. This zoning model divides the reservoir into near-wellbore zones, transition zones, and far-wellbore zones (e.g., near-wellbore zones, transition zones, and far-wellbore zones). Figure 2 As shown in the figure, the target parameters for each partition are determined, and the target parameters include at least the target viscosity, the target mobility ratio, or the target swept volume.

[0034] The static data includes reservoir structure, reservoir properties, and fluid distribution data. Specifically, the reservoir structure includes the distribution of interlayers, the reservoir properties include the distribution of permeability and porosity, and the fluid distribution includes the abundance of reserves and fluid properties of each sublayer. The dynamic production data includes injection-production well spacing, production pressure difference, production rate, water cut change data, production profile test data, and / or water absorption profile test data.

[0035] The near-wellbore zone refers to the area significantly controlled by wellbore pressure drop and prone to forming dominant channels; the transition zone refers to the main migration and spillover control zone between the near-wellbore and far-wellbore zones; the far-wellbore zone refers to the area where conventional viscosity-reducing media are difficult to reach or effectively affect. The zoning model is established using at least one of the following methods: One approach is to partition the area based on permeability distribution and pressure gradient distribution determined by the production pressure differential. Specifically, areas with pressure gradients above a first preset threshold are designated as near-wellbore zones, where pressure drop is concentrated and displacement energy is strong; areas with pressure gradients between the first and second preset thresholds are designated as transition zones, where pressure drop response changes gradually; and areas with pressure gradients below the second preset threshold are designated as far-wellbore zones, where pressure drop response is weak.

[0036] Another approach is to partition the area based on the permeability gradient determined by the permeability distribution, combined with the injection-production well spacing and pressure drop propagation radius, using the equivalent flow unit comprehensive index. The equivalent flow unit comprehensive index is a function of permeability, porosity, and distance from the wellbore, and can comprehensively reflect the fluid flow capacity at different locations.

[0037] The preliminary zoning results can also be dynamically verified and corrected using production profile test data and / or water absorption profile test data. For example, sections with production or water absorption contribution rates higher than the preset standard can be classified as the main contribution zone near the wellbore, while sections with contribution rates lower than the preset standard and exhibiting delayed response can be classified as the transition zone or the far-well zone.

[0038] When establishing a vertical zoning model, the vertical permeability heterogeneity, interlayer distribution, and reservoir abundance of each sublayer are determined by the permeability distribution. Each vertical layer is then assigned to one of the following: near-wellbore zone, transition zone, or far-wellbore zone.

[0039] The target parameters for each zone are determined based on reservoir numerical simulation or historical data fitting, combined with reservoir engineering methods. By establishing a zone model and setting target parameters, a clear spatial guide and quantitative benchmark are provided for subsequent differentiated viscosity reduction operations.

[0040] Step S2: Limit viscosity reduction in the near-wellbore area.

[0041] After the zoning model is completed, the first viscosity-reducing system is injected into the reservoir so that it can act preferentially on the near-wellbore area to reduce the viscosity of the heavy oil in the near-wellbore area, and the viscosity reduction range is controlled within the preset limit range.

[0042] The first viscosity-reducing system comprises a viscosity-reducing agent, a migration-limiting control component, and a carrier fluid component. The viscosity-reducing agent provides the viscosity-reducing function; the migration-limiting control component restricts the migration distance of the viscosity-reducing agent, ensuring that the viscosity-reducing effect is controlled within the near-wellbore zone defined in step S1; the carrier fluid component typically uses formation water, reinjected produced water, or blended water. In practical applications, the effective migration radius of the first viscosity-reducing system under formation conditions is controlled within a range that does not significantly enter the transition zone.

[0043] The first viscosity-reducing system may also include a flowability control component, which is at least one of a gel, a weak gel, a cross-linked polymer, microspheres, or a particulate profile control agent. The function of the flowability control component is to regulate the mobility of the injected fluid, reducing crude oil viscosity while inhibiting the excessive development of high-permeability channels, thereby enhancing the near-wellbore limited viscosity reduction effect.

[0044] The preset limiting range is set according to the target viscosity of the near-wellbore area determined in step S1, so that the viscosity of the heavy oil in the near-wellbore area is within the allowable deviation range of the target viscosity after viscosity reduction. The core of limited viscosity reduction is "moderate viscosity reduction", which aims to improve the flowability of crude oil in the near-wellbore area and remove near-wellbore blockage through viscosity reduction, while avoiding excessive viscosity reduction that would lead to an excessively large flow difference between the near-wellbore area and the transition zone, and prevent the injected medium from short-circuiting along the low-viscosity channel in the near-wellbore area.

[0045] The first viscosity-reducing system was injected using a pulse injection method. The advantages of pulse injection are: the pressure increases during the injection phase, allowing the system to enter the near-wellbore matrix and microfractures; the pressure drops during the shutdown phase, allowing for sufficient diffusion and reaction of the system, while avoiding excessive propulsion of the system to deeper layers by the high pressure differential maintained by continuous injection. The total injection volume was determined based on the near-wellbore pore volume. After injection, a shut-in soaking process was performed to ensure sufficient contact and reaction between the viscosity-reducing system and the near-wellbore heavy oil, ensuring that limited viscosity reduction was achieved in the near-wellbore area.

[0046] Through this step of limiting viscosity reduction, the viscosity of crude oil in the near-wellbore area is effectively reduced to a reasonable range. This not only improves the flowability of crude oil near the wellbore, providing good transport conditions for subsequent production and injection, but also suppresses the formation of dominant channels by controlling the degree of viscosity reduction, forcing the secondary viscosity reduction system injected later to spread to the mid-to-far area, thus creating favorable conditions for viscosity reduction compensation in the far area.

[0047] Step S3: Mid-to-far zone compensation for viscosity reduction.

[0048] After completing step S2, a second viscosity-reducing system is injected into the reservoir. The second viscosity-reducing system has post-migration activation characteristics and / or time-release characteristics, which allow it to gradually produce a viscosity-reducing effect after migrating to the transition zone or far-well zone.

[0049] The second viscosity-reducing system comprises a post-migration activating component, a threshold triggering component, a migration-enhancing component, and a carrier liquid component. The post-migration activating component is either a slow-release pour point depressant or a precursor-reacting viscosity-reducing agent. Slow-release pour point depressants achieve a delayed and sustained viscosity-reducing effect over time by slowly releasing the active viscosity-reducing component into the porous medium; precursor-reacting viscosity-reducing agents undergo physical or chemical transformation under specific formation conditions to generate active components with viscosity-reducing capabilities.

[0050] Threshold triggering components are used to delay the activation of viscosity reduction under formation conditions, so that the second viscosity-reducing system gradually produces viscosity reduction only after it has migrated to the transition zone or far-well zone. Threshold triggering components can be activated under threshold conditions of temperature, shear, salinity, pH, or pressure. For example, when the threshold triggering component is temperature-sensitive, it can be set to activate under the heating conditions of steam huff and puff, steam drive, or steam-assisted gravity drainage (SAGD), thereby synergizing with thermal recovery processes.

[0051] The migration-enhancing component is used to improve the migration ability of the second viscosity-reducing system in the reservoir. The migration-enhancing component is a gaseous component and / or a nano-dispersed reinforcing material, wherein the nano-dispersed reinforcing material is preferably hydrophobically modified nano-silica, and the gaseous component is preferably carbon dioxide. The hydrophobically modified nano-silica can, on the one hand, improve the dispersion state of the viscosity-reducing system in the multiphase system, reduce the oil-water interfacial tension, and change wettability, thereby increasing the effective contact efficiency of the viscosity reducer; on the other hand, it can reduce the non-productive adsorption and retention of active components in the porous medium, enhancing the long-range migration ability. The synergistic injection of carbon dioxide gas can further enhance the migration and swelling effects of the system, expanding the mid-to-long-range viscosity-reducing range.

[0052] The total injection volume of the second viscosity-reducing system was determined based on the pore volume of the transition zone and the far-wellbore zone. Since the second viscosity-reducing system does not produce a significant viscosity-reducing effect in the near-wellbore zone, but is gradually activated through threshold triggering or time-sequential release after migrating to the transition zone or far-wellbore zone, the viscosity-reducing effect is effectively shifted to the target area, making up for the shortcomings of near-wellbore zone limited viscosity reduction in the far-wellbore zone, and achieving spatially balanced viscosity reduction.

[0053] This step and step S2 form a synergistic relationship of "near-wellbore limiting - far-area compensation". In actual operation, the two can be executed by alternating injection. By alternately injecting the first viscosity-reducing system and the second viscosity-reducing system, the effects of near-wellbore limiting viscosity reduction and far-area compensation viscosity reduction are further coordinated in the time dimension, which is conducive to improving the accuracy and stability of viscosity reduction control.

[0054] Step S4: Closed-loop monitoring and comparison.

[0055] After the injection operations in steps S2 and S3 are completed, the production stage begins. Wellhead or downhole monitoring data is acquired and compared with the target parameters determined in step S1.

[0056] Monitoring data includes one or more of the following: produced fluid viscosity, produced fluid water cut, wellhead pressure, bottomhole pressure, temperature, or tracer response. Wellhead monitoring data can be obtained through wellhead pressure sensors, multiphase flow meters, or sampling viscosity measuring devices; downhole monitoring data can be obtained through downhole pressure gauges or downhole thermometers. By deploying appropriate sensing and metering devices at the wellhead and / or downhole, real-time or periodic monitoring of reservoir production dynamics can be achieved.

[0057] When tracer response is used as a monitoring method, the tracer is injected before the first or second viscosity-reducing system. During the production stage, the tracer concentration is sampled and detected at fixed intervals to obtain the tracer breakthrough curve. The average arrival time of the tracer is calculated using the moment method, and the swept pore volume or swept efficiency is determined accordingly. This is compared with the target swept volume determined in step S1 to determine whether there is a short circuit in the dominant channel or insufficient utilization of the far-field.

[0058] In addition, the equivalent viscosity of each zone can be calculated by inversion based on the viscosity of the produced fluid at the wellhead and the contribution ratio of the produced fluid in each zone. The equivalent viscosity of each zone obtained by inversion is then compared with the target viscosity of the corresponding zone determined in step S1.

[0059] By comprehensively utilizing various monitoring methods and systematically comparing them with target parameters, we can fully and promptly grasp the viscosity reduction dynamics and ripple effects of each zone, providing a reliable basis for subsequent dynamic adjustments to the injection system. Step S5: Dynamic Adjustment of the System.

[0060] Based on the deviation in step S4, the injection volume, injection sequence, injection intensity, and / or injection time of the first and second viscosity-reducing systems are dynamically adjusted.

[0061] The specific strategies for dynamic adjustment include at least one of the following: When the rate of decrease in viscosity of the produced fluid exceeds the preset threshold and the rate of increase in water cut exceeds the preset threshold, it indicates that the viscosity reduction in the near-wellbore area may be excessive and a dominant channel trend may appear. At this time, reduce the injection volume and / or injection intensity of the first viscosity reduction system and increase the injection volume and / or injection intensity of the second viscosity reduction system to transfer the viscosity reduction effect to the transition zone and the far-wellbore area.

[0062] When the viscosity of the produced fluid is consistently high and the production rate is lower than the preset value, it indicates that the viscosity reduction in the far well area is insufficient and the utilization rate is low. At this time, the injection intensity of the second viscosity reduction system should be increased and / or its activation window should be extended to extend the effective viscosity reduction effect to the transition zone and far well area, thereby activating more remaining oil.

[0063] When the peak advance factor of the tracer is detected to exceed the preset threshold, it is determined that there is a short circuit in the dominant channel. At this time, the concentration and / or injection volume of the first viscosity-reducing system are reduced, and the proportion of the transport-limiting control component and / or the flow rate control component is increased to enhance selective blocking and diversion.

[0064] To achieve refined and repeatable control of the injection system, dynamic adjustment can employ an adaptive pulse injection control method constrained by a differential pressure window. Specifically: the differential pressure between the wellhead or bottomhole pressure and the injection manifold pressure is used as the injection intensity constraint, and an injection differential pressure window is set. The upper limit of the differential pressure does not exceed a preset proportion of the differential pressure corresponding to the formation fracture pressure to ensure operational safety; the lower limit of the differential pressure is set as a short-circuit warning threshold based on historical pressure decay curves. When the differential pressure decays beyond a preset proportion within a continuous preset time period, a short-circuit trend is determined. The pulse injection duty cycle is used as the control variable. Based on the monitoring results of produced fluid viscosity, water cut, pressure, and / or tracer response, the duty cycle, injection volume, injection intensity, and / or injection time of the first and second viscosity-reducing systems are dynamically adjusted. For example, when accelerated differential pressure decay and increased water cut are detected, the duty cycle of the first viscosity-reducing system is reduced, while the duty cycle of the second viscosity-reducing system is increased, shifting the injection energy and viscosity-reducing effect from the near-wellbore area to the mid-to-far-field area.

[0065] Dynamic adjustments to the injection system, along with segmented, stratified, or alternating injections, can be implemented to improve the stability and repeatability of closed-loop control. Through this closed-loop control step, the entire viscosity reduction operation becomes engineering-controllable, avoiding blind injection and enabling real-time correction based on the actual reservoir response.

[0066] like Figure 3 As shown, in this embodiment, steps S4 and S5 are executed through a closed-loop control module, which includes: The monitoring module collects wellhead / downhole data, including industrial viscosity, water cut, pressure, temperature, and tracer information.

[0067] The target comparison and judgment module performs comparisons with target parameters; determines target viscosity / fluidity ratio / sweeping volume; and analyzes dominant channel trends and far-field utilization.

[0068] The control output module adjusts the injection regime, including: injection volume / injection sequence / system strength; shut-in soaking time / driving differential pressure, etc.

[0069] The on-site execution module acquires the output results from the control output module and feeds the data back to the monitoring module.

[0070] Step S6: Monitoring and repeated adjustments during continuous production.

[0071] After injection is stopped, the continuous production phase begins. During this phase, if the viscosity of each zone or the viscosity of the product fluid deviates from the target range, steps S2 to S5 are repeated.

[0072] During the continuous production phase, as the reservoir continues to produce oil, the viscosity of each zone may gradually deviate from the target range due to factors such as fluid migration and energy decay. By establishing a long-term monitoring mechanism, once a deviation is detected, a new round of viscosity-reducing injection and adjustment can be initiated in a timely manner, forming a long-term dynamic cycle of "monitoring—deviation identification—viscosity reduction adjustment—production recovery".

[0073] In this stage, in addition to directly repeating the complete S2 to S5 steps, a small slug correction injection method can also be used. Specifically, when a sudden decrease in produced fluid viscosity and a rapid increase in water cut are detected, or when the tracer advance factor exceeds the threshold, correction injection is carried out using a non-stop well or short shut-in method, following the sequence of "first viscosity-reducing system small slug - push slug - second viscosity-reducing system small slug". This method can quickly suppress the near-wellbore short-circuit trend and promote viscosity reduction and utilization in the mid-to-far zone. It can quickly correct deviations without restarting the complete injection cycle, which is beneficial for further extending the stable production cycle and improving the uniformity of the impact.

[0074] Through step S6, the present invention achieves long-term dynamic maintenance of the viscosity reduction state of the reservoir, ensuring coordinated utilization of the near-wellbore and far-wellbore areas throughout the entire production cycle of the reservoir, and overcoming the problem of difficulty in stabilizing production in the later stage of traditional methods.

[0075] Step S7: Dynamic optimization of the partition model.

[0076] As a further optimization scheme, the present invention also includes step S7: determining the well life based on the cumulative production of the target production well, and optimizing the partition model established in step S1 based on the corresponding dynamic production data, and redetermining the boundaries and / or target parameters of each partition.

[0077] As the reservoir continues to be developed, recoverable reserves gradually decrease, and dynamic conditions such as remaining oil distribution, formation pressure, and fluid saturation all change. The original zoning model boundaries and target parameters may no longer be applicable to the current production stage. By periodically updating the zoning model using the latest dynamic production data, or when cumulative production reaches a preset milestone, the boundaries of the near-wellbore zone, transition zone, and far-wellbore zone are recalibrated, and the target parameters for each zone are adjusted. This ensures that the entire technical solution can adapt to different stages of reservoir development, maintaining long-term applicability and control accuracy. This step embodies the closed-loop optimization concept of the zoning model and forms a two-tiered closed-loop management system with the injection system closed-loop control in steps S4 and S5.

[0078] In summary, this invention provides a controllable, zoned viscosity reduction, closed-loop, and coordinated development method for heavy oil reservoirs. It achieves spatially differentiated regulation through the construction of a zoned model, spatially balanced utilization through coordinated near-wellbore limited viscosity reduction and mid-to-far zone compensatory viscosity reduction, engineering control through closed-loop monitoring and dynamic adjustment, and long-term management throughout the entire lifecycle through dynamic maintenance during the continuous production phase and iterative optimization of the zoned model. These steps work together synergistically to effectively solve problems in existing technologies such as spatial imbalance in viscosity reduction operations, insufficient utilization in distant areas, and short stable production cycles, significantly improving the development efficiency of heavy oil reservoirs.

[0079] In this application, to better reflect the zonal viscosity reduction effect, based on the conventional steam thermodynamic effects, the radial range of the near-wellbore zone is limited to 0–10 m, the radial range of the transition zone to 5–50 m, and the radial range of the far-wellbore zone to 50–200 m. In specific implementation, the viscosity reduction in the near-wellbore zone is controlled to reduce the viscosity to 1 / 5–1 / 8 of the current level. The effective migration radius of the first viscosity reduction system under formation conditions is less than 5–30 m, and the second viscosity reduction system only begins to produce a significant viscosity reduction effect after migrating to a distance of 10–200 m from the wellbore.

[0080] Based on the above requirements, the first viscosity-reducing system in this application, by mass percentage, includes 0.1% to 10% of a viscosity-reducing main agent, preferably PetroChina's DQ series petroleum sulfonates or Baker Hughes' THERMA-THIN series viscosity reducers; 0.05% to 5% of a migration-limiting control component, preferably cross-linked polymer microspheres with a particle size of 1 to 10 μm, whose expansion radius under formation conditions is less than or equal to 1 / 3 of the pore throat diameter, such as Sinopec's KX-3 series or Halliburton's ELK series; 0.1% to 2% of a mobility control component, preferably Sinopec's WJG series weak gel. Of course, in some actual implementation processes, considering that the gel may block the channels and cause difficulties in the diffusion of the pour point depressant, polymer microspheres containing grafted viscosity-reducing functional groups can also be added for synergistic use or replaced and used alone; the remaining balance is a carrier fluid component, usually formation water, reinjected produced water, or blending water.

[0081] In this system, microspheres are used in conjunction with viscosity reduction to ensure that viscosity reduction does not cause short circuits, thereby achieving a better effect of suppressing dominant channels and better balancing the impact on more distant areas. At the same time, the combination of microspheres and weak gels can form a three-dimensional profile control system, which can achieve deeper flow redirection and push the effect of flow redirection to deeper reservoirs, affecting more remaining oil-rich areas.

[0082] The second viscosity-reducing system, by mass percentage, includes 0.1% to 8% of a post-migration activating component, typically a slow-release pour point depressant (a viscosity-reducing component with slow-release or delayed-release properties) or a precursor reaction-generated viscosity-reducing component (an active component with viscosity-reducing ability generated after physical or chemical transformation under specific formation conditions). Considering the specific requirements of this application in conjunction with thermal recovery, this embodiment preferably uses Halliburton's STEALTH series, which has a better long-lasting effect. The threshold triggering component is 1% to 5%, typically a thermosensitive polymer with an activation temperature of 80-120℃, but can also be a pH-sensitive polymer, preferably from Dow Chemical. UCAR™ series thermosensitive polymers or Chinese Academy of Sciences TP-80 series; 0.5% to 10% transport enhancement component, usually light hydrocarbon / solvent-assisted enhancement component, gas-assisted enhancement component, or nano-dispersion enhancement material, etc., generally hydrophobically modified nano-silica with a particle size of 20-100nm and a dispersion stability of more than 20 days. In this embodiment, Evonik Aerosil series nano-silica is preferred. Of course, carbon dioxide can be injected in conjunction during the operation injection process to further improve the transport effect; the remaining balance is the carrier liquid component, and the composition of the carrier liquid component can be consistent with that used in the first viscosity reduction system.

[0083] In addition, the second viscosity-reducing system uses hydrophobically modified nano-silica, which improves the effective contact efficiency of the viscosity reducer by improving the dispersion state of the viscosity-reducing system in the multiphase system, reducing the oil-water interfacial tension and changing the wettability. On the other hand, it can enhance the long-range transport capability by reducing the non-productive adsorption and retention of active components in the porous medium.

[0084] Based on the specific components of the above system, during implementation, if data analysis and comparison reveal a potential short-circuit situation due to excessive viscosity reduction in the near-wellbore area, the following specific measures can be taken: reduce the injection volume and / or concentration of the first viscosity reduction system, or shorten the soaking / steaming time; increase the proportion of the migration control component (microspheres) and / or weak gel to enhance selective plugging and diversion; adopt segmented / layered / pulsed injection methods to weaken the maintenance of dominant channels caused by continuous injection; and correspondingly increase the proportion of the second viscosity reduction system or extend its activation window to transfer the viscosity reduction effect to the transition zone / far-well zone.

[0085] When insufficient viscosity reduction in the far region is found, the following specific measures can be taken: increase the injection intensity of the second viscosity reduction system, or increase the proportion of activated components after migration; adjust the activation temperature window or triggering conditions of the threshold triggering component to match the vapor heating zone; increase the migration enhancement component (such as hydrophobic nano silica or gas-assisted) to expand the effective migration range in the far region.

[0086] Furthermore, in addition to optimizing the selection of zoning parameters and the performance of the viscosity-reducing system, an alternating injection method is adopted in actual operation. By alternately injecting the first and second viscosity-reducing systems, the effects of near-wellbore limited viscosity reduction and far-wellbore compensated viscosity reduction are further coordinated in the time dimension, which is beneficial to improving the accuracy of viscosity reduction control. At the same time, in step S2, after injecting the first viscosity-reducing system, a shut-in soaking time or a well-steaming time is set, and this time is optimized to be 2 to 6 days in combination with the steam drive process.

[0087] In this application, the wellhead pressure data required for monitoring can be obtained through wellhead pressure sensors, injection manifold pressure gauges, pressure monitoring devices, etc. A rapid drop in wellhead pressure can indicate the formation of a dominant channel in the near-wellbore area. The production flow rate and water cut are obtained through multiphase flow meters or well test metering and separation devices, etc. The production viscosity is mainly measured by sampling and measuring the apparent viscosity, thereby determining whether the viscosity reduction is excessive or insufficient.

[0088] Downhole monitoring data, including bottomhole pressure and temperature, are primarily measured using downhole pressure gauges and thermometers. One or more monitoring data points are input into the system via on-site recording or remote transmission for comparison with target parameters. This enables closed-loop control of the injection regime as described earlier. The equivalent viscosity of each zone can be calculated by inversion based on the wellhead production fluid viscosity and the contribution ratio of each zone's production fluid. On-site execution can be performed using communication-controlled equipment such as injection pumps, or manually according to calculations.

[0089] In comparison, tracer monitoring is more intuitive and efficient in this context. In practice, it is preferable to determine the contribution of the dominant channel based on the tracer response. By analyzing the tracer arrival time, peak occurrence time, and peak intensity changes, the migration depth and sweep range of the viscosity-reducing system and the displacing medium can be quickly and intuitively determined. That is, based on the response characteristics of the tracer in different zones, the relative viscosity level of each zone is characterized, and the injection regime is adjusted accordingly. In the specific calculation process, the sweep pore volume is quickly determined using the moment method based on the tracer breakthrough curve, and then compared with the target sweep volume for judgment.

[0090] Furthermore, in the system adjustment step S5, the injection pressure differential window (Δpmin, Δpmax) can be used to constrain the injection intensity, while the pulse injection duty cycle D is used as the injection execution quantity, as detailed below: When a rapid drop in wellhead pressure or an accelerated decay of Δp is detected, accompanied by a water cut increase rate exceeding a preset threshold, it is preferable to reduce the duty cycle D of the first viscosity-reducing system, while shortening the pump start-up injection time ton or extending the pump stop time toff, and increasing the ratio of microspheres to weak gel to enhance restricted transport and diversion.

[0091] When insufficient viscosity reduction or a low sweep efficiency is detected in the far-field region, it is preferable to increase the duty cycle D of the second viscosity reduction system and extend its activation window, so that the effective viscosity reduction effect is transferred to the transition zone / far-well region. Of course, this control method can also be implemented in conjunction with segmented injection, layered injection, or alternating injection to improve the stability and repeatability of closed-loop control.

[0092] In the production stage of step S6, when a target deviation occurs, in addition to directly repeating steps S2 to S5, a small slug correction injection method can also be used: proceeding in the sequence of "first viscosity-reducing system small slug - push slug - second viscosity-reducing system small slug", thereby achieving the purpose of quickly suppressing short circuits in the near-wellbore area and promoting viscosity reduction and utilization in the mid-to-far area. It can quickly correct deviations without restarting the complete injection cycle, which is conducive to further extending the stable production cycle and improving the uniformity of the impact.

[0093] refer to Figures 1 to 3 The controllable zone viscosity reduction closed-loop synergistic development method for heavy oil reservoirs, as shown, is applied to the production of the following reservoirs, as detailed below: Example

[0094] It is used for the production of heavy oil reservoir A, where the reservoir formation temperature is 50-70℃, the crude oil formation viscosity is 10000-30000 mPa•s, the production well is a vertical well, and the completion method is conventional perforation completion (the perforated section covers the main producing layer). The wellhead is equipped with pressure sensors and metering devices, and it has the conditions for injection and flowback conversion.

[0095] The first step, based on field data and reservoir data, including injection-production well spacing and dynamic data, is to divide the control radius of the production well into: near-well zone 0–5m; transition zone 5–30m; and far-well zone 30–120m. Target parameters are set: near-well zone viscosity to be reduced to at least 1 / 5 of its original value; far-well zone viscosity to be reduced to at least 1 / 3 of its original value.

[0096] The second step is to inject the preferred first viscosity-reducing system into the partitioned volume using a pulse injection method. In this embodiment, the first viscosity-reducing system consists of 2% DQ series sulfonate, 0.5% adhesive polymer microspheres with a particle size of about 5 μm, 0.3% WJG weak gel, and the remainder is reinjected water.

[0097] During the operation, pre-flushing with reinjected water is performed first to remove contaminants from the wellbore and near-well area and establish a good injection channel. Then, injection is carried out using the following pulse method, with each pulse lasting 1–3 m. 3 The pulse interval is 0.5–2 hours; the total injection volume is determined based on 0.05–0.2 PV of the near-wellbore pore volume, with the main control required being the injection intensity: injection displacement 0.2–1.0 m³ / h. 3 / h, the wellhead pressure shall not exceed 0.8 times the formation fracture pressure.

[0098] After the injection operation is completed, the well is shut in and soaked for 2 to 3 days to ensure that the near-wellbore area has completed restricted viscosity reduction.

[0099] The third step involves injecting a second viscosity-reducing system, which gradually releases active components in the transition zone / far-well zone, causing the viscosity of the heavy oil in the far-well zone to gradually decrease and be activated. The preferred second viscosity-reducing system in this step includes 2% STEALTH series pour point depressant, 2% thermosensitive polymer, 0.8% hydrophobically modified nano-silica, and the balance being the carrier fluid, which is also reinjected water.

[0100] During the operation, after completing the soaking in the second step, the second viscosity-reducing system can be injected at a rate of 0.2–1.0 m. 3 The injection rate is calculated as 0.02–0.1 PV, based on the sum of the pore volumes in the transition zone and the far-wellbore zone. During implementation, 50–200 Nm³ of synergistic injection is performed according to site conditions. 3 / d of carbon dioxide further enhances the migration and swelling effects.

[0101] The fourth step involves closed-loop monitoring and adaptive adjustments, monitoring the produced fluid viscosity, wellhead pressure, water cut, and tracer response. Initial thresholds for viscosity decrease rate, target water cut increase, and tracer peak advance coefficient can be set, and these can be compared through monitoring. When the viscosity of the produced fluid decreases too rapidly and the water cut increases rapidly, it is determined that there is a dominant channel trend. The injection volume of the first viscosity-reducing system is reduced and the proportion of the second viscosity-reducing system is increased. When the viscosity of the produced fluid is high for a long period of time and the production is low, the injection intensity of the second viscosity-reducing system is increased or the activation window is extended. When the peak advance coefficient threshold of the tracer is exceeded, it is determined that a short-circuit trend may be formed. Similarly, the concentration / volume of the first viscosity-reducing system can be reduced or the well stagnation period can be shortened; or the proportion of microspheres / weak gels can be increased.

[0102] To facilitate understanding, the specific operation of characterizing the tracer is further explained here. Before injecting into the viscosity-reducing system, the tracer is injected, generally at a concentration of 50–500 mg / L. During the extraction process, the concentration is sampled and detected at fixed intervals to obtain the breakthrough curve.

[0103] The mean arrival time is then calculated using the method of moments. Under discrete sampling conditions, a summation approximation method is generally used to obtain the equivalent swept pore volume. By comparing this with the target pore volume, the sweep efficiency can be obtained. At the same time, a breakthrough advance coefficient can be defined. By comparing it with the set advance coefficient threshold, it can be determined whether there is a short-circuit trend or insufficient sweep efficiency.

[0104] In addition, in order to improve the engineering controllability of closed-loop control, this embodiment adopts the adaptive pulse injection control method of "differential pressure window and duty cycle" as described above during injection.

[0105] Specifically, the pressure difference Δp between the injection manifold pressure and the wellhead pressure (or bottom hole pressure) is used as the injection intensity constraint, and Δpmax is set to 0.75 times the pressure difference corresponding to the fracture pressure. A short-circuit warning threshold Δpmin is set (mainly selected based on historical well curves; for example, a warning is determined when Δp decays by more than 10-25% over 6-12 consecutive hours). Simultaneously, the pulse injection duty cycle D=ton / (ton+toff) is used as the main execution reference, where ton is the pump start-up injection time within a single pulse cycle, and toff is the pump stop-down time within a single pulse cycle.

[0106] For example, in the second step, when the first viscosity-reducing system is used for near-wellbore limited viscosity reduction, a low duty cycle pulse method with short injection and long stop injection is preferred: ton=1h, toff=2h, with a corresponding D=0.33, and the D value is further reduced when Δp approaches Δpmax or when Δp decays faster.

[0107] In the third step, when using the second viscosity-reducing system for viscosity compensation in the transition zone / far-well zone, it is preferable to use a combination of a medium duty cycle and a delayed activation window: ton=2h, toff=1h, with a corresponding D=0.65. When the sweep efficiency calculated by the tracer moment method is lower than the target value or the viscosity of the produced fluid is consistently high, the D of the second system should be increased or its stop-activation window should be extended. For example, the stop-activation window can be extended to 3-10 days and the flowback pressure differential can be controlled to allow the effective viscosity-reducing effect to migrate to the transition zone and far-well zone.

[0108] During the injection process, the time of ton is mainly determined based on the amount of injection required for a single pulse, while toff is mainly determined based on the pressure drop and the action time of the corresponding viscosity-reducing system. By adopting the above injection regime, the stability and short-circuit resistance of the injection regime can be improved without changing the partition model and viscosity-reducing system framework, further improving the uniformity of the impact and extending the stable production cycle.

[0109] Steps two through four are repeated every 15 to 60 days to achieve stable production. Compared with production wells under similar conditions in the same block, the production of a single well increases by about 10 to 20%, the rate of increase in water cut slows down, and the stable production cycle is also extended. Example

[0110] The viscosity of heavy oil reservoir B is approximately 18,000 mPa•s, the temperature within the reservoir is approximately 80℃, and the well spacing is 200m.

[0111] The first step is to divide the area into: near-wellbore zone: 0-8m; transition zone: 8-40m; far-wellbore zone: 40-150m. Similarly, the target parameters are set as follows: the viscosity in the near-wellbore zone should be reduced to no less than 1 / 5 of the original value; and the viscosity in the far-wellbore zone should be reduced to at least 1 / 3 of the original value.

[0112] The second step involves using a first viscosity-reducing system for limited viscosity reduction. The components are similar to those in Example 1. 12m³ of the first viscosity-reducing system is injected. 3 The concentration was 3%, and the well was shut in and soaked for 2 days. Results: The near-wellbore viscosity was reduced to approximately 5200 mPa•s by inverting the production fluid viscosity and the contribution ratio of different zones, and no rapid increase in water cut was observed.

[0113] Step 3: Inject the second viscosity-reducing system for far-range compensation. Inject the second viscosity-reducing system for 20m. 3 After soaking for 6 days, the viscosity in the far region decreased to 9000 mPa•s.

[0114] After several adjustments, using the same method as in Example 1, once the production stabilized, the daily oil production per well increased by about 25%, while the contribution of the dominant channel decreased by about 15%. Example

[0115] The viscosity of the heavy oil reservoir C is about 12000 mPa•s, the initial water cut is 32%, it is also a vertical well, and the production temperature is 60-85℃.

[0116] The first step is to divide the area into three zones: near-wellbore zone (0–6 m), transition zone (6–35 m), and far-wellbore zone (35–140 m). The target parameters are that the viscosity in the near-wellbore zone should not be less than 1 / 5 of the original, and the viscosity in the far-wellbore zone should be reduced to at least 1 / 2 to 1 / 3 of the original. Closed-loop thresholds are set as follows: viscosity decrease rate threshold is 10% / d, water cut increase rate threshold is 3% / d, and tracer advance coefficient threshold is 1.2.

[0117] The initial injection regimen uses the general components and proportions as in Example 1 to prepare the first and second viscosity-reducing systems. The injection volume of both the first and second viscosity-reducing systems is 15 mg / L. 3 During the operation, the distance was 0.3–1.0m. 3 The product was injected at a flow rate of / h, and soaked for 2–3 days after the first viscosity-reducing system was injected; and soaked for 4–10 days after the second viscosity-reducing system was injected. Monitoring results showed that the viscosity of the product liquid decreased too rapidly and the water content rose to 55%, indicating the formation of a dominant channel and a clear short-circuiting trend.

[0118] Based on the monitoring results, adjustments were made to the operation during the second cycle, changing the first viscosity-reducing system from 15m... 3 Reduced to 8m 3 Furthermore, the viscosity-reducing strength was lowered and the diversion was enhanced: the content of the main viscosity-reducing agent in the first viscosity-reducing system was adjusted to 1.0-1.5%, the content of adhesive polymer microspheres to 0.6-0.8%, the content of weak gel to 0.4-0.6%, and the remainder as carrier liquid; at the same time, a pulse injection method was preferred (1-2 m³ per pulse, 0.5-2 h interval); in addition, the second viscosity-reducing system consisted of 15 m 3 Rise to 22m 3It also enhances far-field transport and delayed onset of action: for example, after transport, the activating component is adjusted to 2.5-3.0%, the thermosensitive polymer is adjusted to 1.5-2.5%, the hydrophobically modified nano-silica is 0.8-1.2%, and the balance is the carrier liquid. If necessary, carbon dioxide can also be injected at the same time to improve the synergistic effect.

[0119] In this embodiment, to avoid restarting the complete injection cycle after a deviation occurs, an online small slug correction injection method is adopted during the stable production stage. Specifically, when a sudden drop in the viscosity of the produced fluid is detected and the water cut increases by more than 5 to 15 percentage points within 1 to 3 days, or the tracer advance coefficient exceeds the threshold (set value 1.2), correction injection is carried out by stopping the well or short shutting in the well. The sequence is: correction slug A (first viscosity-reducing system small slug) + push slug + correction slug B (second viscosity-reducing system small slug).

[0120] Through monitoring and adjustments, the moisture content stabilized, and the production entered a stable phase, resulting in an increase of approximately 28% in yield and a significantly extended stable production period.

[0121] The above embodiments are only used to illustrate the present invention and are not intended to limit the technical solutions described herein. Although the present invention has been described in detail with reference to the above embodiments, the present invention is not limited to the specific embodiments described above. Therefore, any modifications or equivalent substitutions to the present invention, as well as all technical solutions and improvements that do not depart from the spirit and scope of the invention, are covered within the scope of the claims of the present invention.

Claims

1. A method for controlled zoned viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs, characterized in that, include: Step S1: Based on the static and dynamic production data of the reservoir controlled by the target production well, and according to the well spacing, permeability heterogeneity and pressure drop distribution, establish a radial and / or vertical zoning model centered on the target production well. The zoning model divides the reservoir into near-well zone, transition zone and far-well zone, and determines the target parameters for each zone. The target parameters include at least the target viscosity, target mobility ratio or target swept volume. Step S2: Inject the first viscosity-reducing system into the reservoir, so that the first viscosity-reducing system acts preferentially on the near-wellbore area to reduce the viscosity of the heavy oil in the near-wellbore area, and control the viscosity reduction range within a preset limit range; Step S3: After completing step S2, a second viscosity-reducing system is injected into the reservoir. The second viscosity-reducing system has post-migration activation characteristics and / or time-sequential release characteristics, so that it gradually produces a viscosity-reducing effect after migrating to the transition zone or far-well zone. Step S4: After the injection operation in steps S2 and S3 is completed, the production stage begins. Wellhead or downhole monitoring data is acquired and compared with the target parameters determined in step S1. Step S5: Based on the deviation from the comparison in Step S4, dynamically adjust the injection volume, injection sequence, injection intensity, and / or injection time of the first and second viscosity-reducing systems. Step S6: After stopping the injection, enter the continuous production stage. When the viscosity of each zone or the viscosity of the product fluid deviates from the target range, repeat steps S2 to S5.

2. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 1, characterized in that, In step S1, the static data includes reservoir structure, reservoir properties, and fluid distribution data. The reservoir structure includes the distribution of interlayers, the reservoir properties include permeability distribution and porosity distribution, and the fluid distribution includes the abundance of reserves in each sublayer and fluid properties. The dynamic production data includes injection-production well spacing, production pressure difference, production rate, water cut change data, production profile test data, and / or water absorption profile test data.

3. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 2, characterized in that, In step S1, establishing a radial and / or vertical partitioning model centered on the target production well includes at least one of the following: Based on the permeability distribution and the pressure gradient distribution determined by the production pressure difference, the area with a pressure gradient higher than the first preset threshold is classified as the near-well zone, the area with a pressure gradient between the first preset threshold and the second preset threshold is classified as the transition zone, and the area with a pressure gradient lower than the second preset threshold is classified as the far-well zone. Based on the permeability gradient determined by the permeability distribution, and combined with the injection-production well spacing and pressure drop propagation radius, the equivalent flow unit comprehensive index is used for zoning; The preliminary zoning results are dynamically verified and corrected using the product fluid profile test data and / or water absorption profile test data. When establishing a vertical partitioning model, vertical partitioning is performed based on the vertical permeability heterogeneity determined by the permeability distribution, the interlayer distribution, and the reserve abundance of each sublayer.

4. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 1, characterized in that, In step S2: The first viscosity-reducing system includes a viscosity-reducing agent, a migration-limiting control component, and a carrier fluid component. The migration-limiting control component is used to limit the migration distance of the viscosity-reducing agent so that the viscosity-reducing effect is controlled within the near-wellbore zone defined in step S1. The preset limiting range is set according to the target viscosity in the near-wellbore area determined in step S1, so that the viscosity of the heavy oil in the near-wellbore area is within the allowable deviation range of the target viscosity after viscosity reduction. The first viscosity-reducing system was injected using a pulse injection method, with the total injection volume determined based on the near-wellbore pore volume. After injection, the well was shut in for soaking.

5. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 4, characterized in that, In step S3: The second viscosity-reducing system includes a post-transport activation component, a threshold triggering component, a transport enhancement component, and a carrier liquid component; The activated component after migration is a slow-release pour point depressant or a precursor reaction-generated viscosity depressant. The threshold triggering component is used to delay the activation of viscosity reduction under formation conditions, so that the second viscosity reduction system gradually produces viscosity reduction after it migrates to the transition zone or far well zone. The migration-enhancing component is used to improve the migration capacity of the second viscosity-reducing system in the reservoir; The total injection volume of the second viscosity-reducing system is determined based on the pore volume of the transition zone and the far-well zone.

6. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 5, characterized in that, The transport-enhancing component in the second viscosity-reducing system is a gaseous component and / or a nano-dispersed reinforcing material; The first viscosity-reducing system and / or the second viscosity-reducing system further include a flowability control component, wherein the flowability control component is at least one of a gel, a weak gel, a cross-linked polymer, microspheres, or a particulate profile control agent.

7. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 1, characterized in that, In step S4: the monitoring data includes one or more of the following: production fluid viscosity, production fluid water cut, wellhead pressure, bottom hole pressure, temperature, or tracer response; When a tracer response is used, the tracer is injected before the first or second viscosity-reducing system. The tracer concentration is sampled and detected during the production stage to obtain the tracer breakthrough curve. The average arrival time of the tracer is calculated using the moment method, and the swept pore volume or swept coefficient is determined accordingly. This is compared with the target swept volume determined in step S1 to determine whether there is a short circuit in the dominant channel or insufficient utilization of the far-field.

8. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 1, characterized in that, In step S5, the dynamic adjustment includes at least one of the following: When the rate of decrease in viscosity of the product fluid exceeds a preset threshold and the rate of increase in water content exceeds a preset threshold, the injection volume and / or injection intensity of the first viscosity-reducing system are reduced, and the injection volume and / or injection intensity of the second viscosity-reducing system are increased. When the viscosity of the product fluid is found to be consistently high and the output is lower than the preset value, the injection intensity of the second viscosity-reducing system is increased and / or its activation window is extended. When the peak advance factor of the tracer is detected to exceed the preset threshold, it is determined that there is a short circuit in the dominant channel, the concentration and / or injection volume of the first viscosity-reducing system are reduced, and the proportion of the transport-limiting control component and / or the flow rate control component is increased.

9. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 8, characterized in that, In step S5, the dynamic adjustment adopts an adaptive pulse injection control method with differential pressure window constraints: The pressure difference between the wellhead pressure or bottom hole pressure and the injection manifold pressure is used as the injection intensity constraint. An injection pressure difference window is set, wherein the upper limit of the pressure difference does not exceed the preset proportion of the pressure difference corresponding to the formation fracture pressure, and the lower limit of the pressure difference is set as a short-circuit warning threshold based on the historical pressure decay curve. Using the pulse injection duty cycle as the control variable, the duty cycle, injection volume, injection intensity and / or injection time of the first viscosity reducing system and the second viscosity reducing system are dynamically adjusted based on the monitoring results of product viscosity, water content, pressure and / or tracer response. When the pressure difference is detected to decrease by more than a preset proportion within a continuous preset time period, the duty cycle of the first viscosity-reducing system is reduced, while the duty cycle of the second viscosity-reducing system is increased.

10. The method for controlled zone viscosity reduction and closed-loop coordinated exploitation of heavy oil reservoirs according to claim 1, characterized in that, It also includes step S7: determining the well life based on the cumulative production of the target production well, and optimizing the zoning model established in step S1 based on the corresponding dynamic production data, and redetermining the boundaries and / or target parameters of each zoning.

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