Method for evaluating influence degree of fluid scaling on reservoir permeability

Abstract

The invention discloses a method for evaluating the influence degree of fluid scaling on reservoir permeability, and belongs to the technical field of oil and gas production engineering.According to the method, firstly, gas displacement water replacement operation is conducted on a rock core to be in a saturated simulated formation water state, displacement operation is conducted on a rock core in an irreducible water saturation sample, and meanwhile, the gas displacement water replacement operation is conducted on the rock core in the irreducible water saturation sample; the confining pressure of the rock core is kept unchanged all the time to complete simulation of the actual reservoir environment, the damage rate of the rock core is obtained by comparing the permeability before and after scaling, and finally evaluation of the influence degree of fluid scaling on the permeability of the reservoir is completed according to the damage rate of the rock core. By adopting the method, the scaling caused by the production pressure difference of the near-well reservoir of the oil and gas well can be effectively represented, so that the influence degree of the scaling on the permeability of the reservoir after the pressure drop is evaluated; corresponding oil reservoir protection measures can be established according to the evaluation result, reservoir damage is reduced, and the oil reservoir development effect is improved; the method has extremely important economic benefits and social benefits for formulating production systems such as mining speed and the like.

Description

TECHNICAL FIELD

[0001] The present application belongs to the technical field of oil and gas production engineering, and particularly relates to a method for evaluating the influence degree of fluid scaling on reservoir permeability. BACKGROUND

[0002] The influence of scaling on reservoir permeability mainly manifests in the following aspects: firstly, scaling can plug the formation and destroy the connectivity of the oil layer, thereby reducing the reservoir permeability and causing the oil well productivity to decrease; secondly, scaling adhering to the pump cylinder can cause pump sticking, thereby shortening the pump inspection period; in addition, scaling produced from the downhole to the ground can also cause great harm to the gathering and transportation system, such as the failure of the furnace to be used normally, the reduction of the oil-water separation space, the difficulty in opening the pipe valve, the necessity of cleaning the equipment and the high cleaning cost, the reduction of the oil and gas pipeline, and the serious damage of the equipment, which all bring huge economic losses to the oil production.

[0003] Currently, the research on scaling mainly focuses on the scaling amount and scaling trend of the injection well, such as the Chinese patent with the application number CN201910098986.3 provides a wellbore scaling trend prediction method and device, which can determine the scaling trend of the well to be measured according to the corresponding phase section of the reservoir of the well to be measured; the Chinese patent with the application number CN202110034699.3 provides an oilfield dynamic scaling and scale inhibition evaluation device and method, which can quickly determine the scaling induction period time by the changes of the differential pressure and the permeability under the conditions of the simulated field temperature, pressure, flow rate and different flow state, thereby providing a technical basis for the field water injection scheme. The scaling research represented by the above patents ignores the influence of the scaling of the near-well zone reservoir caused by the pressure drop in the production process of the high-pressure oil and gas well on the reservoir permeability.

[0004] It can be seen that in the research on scaling in the production process of the high-pressure oil and gas well, the existing evaluation measures cannot effectively characterize the scaling of the near-well reservoir of the oil and gas well caused by the production pressure difference, and thus cannot evaluate the influence degree of the scaling on the reservoir permeability after the pressure drop, which leads to the failure to establish the corresponding reservoir protection measures due to the lack of evaluation results, and reduces the oil reservoir development effect. SUMMARY

[0005] The present application provides a method for evaluating the influence degree of fluid scaling on reservoir permeability and the method, so as to solve the technical problem that the existing evaluation measures cannot effectively characterize the scaling of the near-well reservoir of the oil and gas well caused by the production pressure difference, and thus cannot evaluate the influence degree of the scaling on the reservoir permeability after the pressure drop, which leads to the failure to establish the corresponding reservoir protection measures due to the lack of evaluation results, and reduces the oil reservoir development effect.

[0006] In order to achieve the above purpose, the present application adopts the following technical contents:

[0007] A method for evaluating the influence of fluid fouling on reservoir permeability, comprising:

[0008] S1: performing a gas displacement water operation on a core in a saturated simulated formation water state to produce a bound water saturation sample;

[0009] S2: determining the permeability of the core in the bound water saturation sample to obtain a pre-fouling permeability;

[0010] S3: setting a displacement pressure and an outlet end pressure according to a near wellbore pressure drawdown funnel curve, and performing a displacement operation on the core in the bound water saturation sample according to the set displacement pressure and outlet end pressure until a threshold condition is reached to end the displacement operation;

[0011] S4: determining the permeability of the core after the displacement operation to obtain a post-fouling permeability;

[0012] S5: calculating a core damage rate according to the pre-fouling permeability and the post-fouling permeability, and completing the evaluation of the influence of fluid fouling on reservoir permeability according to the core damage rate;

[0013] During S1-S4, the confining pressure of the core is always kept unchanged.

[0014] Further, in S1, the saturation of the simulated formation water state is simulated as follows:

[0015] A simulated core is made according to the reservoir permeability or a core sample is drilled from the reservoir to obtain a core sample;

[0016] The core sample is sequentially subjected to vacuumizing and pressurized saturation of simulated formation water operation to complete the saturation of the simulated formation water state.

[0017] Further, the vacuumizing time is greater than 8h, and the pressurized saturation of simulated formation water time is greater than 24h.

[0018] Further, in S2, nitrogen is used to determine the permeability of the core in the bound water saturation sample; during the determination, the determination is completed after the differential pressure and flow rate are both stable for a preset time, and the preset time is not less than 1h.

[0019] Further, in S3, the pressure within a range of 0.5m from the wellhead is selected as the displacement pressure, and the bottom hole flowing pressure is selected as the outlet end pressure.

[0020] Further, in S3, the threshold condition is that the displacement time is not less than 2h and the pore volume is greater than 10PV.

[0021] Further, in S3, the displacement flow rate is selected according to the displacement pressure, and the core in the bound water saturation sample is subjected to the displacement operation according to the displacement flow rate.

[0022] Furthermore, the displacement velocity is determined based on the production rate per second, the producing layer area, and the core cross-sectional area, as shown in the following formula:

[0023] ν=A2×Q l / A1

[0024] Where ν represents the displacement velocity; Q l A1 represents the liquid production volume; A2 represents the area of ​​the producing layer; A3 represents the cross-sectional area of ​​the core.

[0025] Furthermore, in S4, the specific formula for calculating the core damage rate is as follows:

[0026] Core damage rate = / Permeability before scaling * 100%.

[0027] Furthermore, it also includes:

[0028] S6: Select cores from the same block or cores with similar permeability, and repeat S1-S4 to evaluate the impact of pressure drop and scaling in the near-wellbore zone on reservoir permeability during development at different production stages.

[0029] Compared with the prior art, the present invention has the following beneficial effects:

[0030] This invention provides a method for evaluating the impact of fluid scaling on reservoir permeability. The method first involves gas-drive water displacement of a core sample saturated with simulated formation water, and then performing a similar displacement operation on a core sample with bound water saturation. Simultaneously, the confining pressure of the core is kept constant to simulate the actual reservoir environment. The core damage rate is obtained by comparing the permeability before and after scaling. Finally, the impact of fluid scaling on reservoir permeability is evaluated based on the core damage rate. This method effectively characterizes scaling caused by production pressure differentials in near-wellbore reservoirs of oil and gas wells, thereby evaluating the impact of scaling on reservoir permeability after pressure drop. Furthermore, it enables the establishment of corresponding reservoir protection measures based on the evaluation results, reducing reservoir damage and improving reservoir development efficiency. This method has significant economic and social benefits for the formulation of production systems such as production rates.

[0031] Preferably, in this invention, a simulated core is first prepared based on the reservoir permeability, or a core sample is obtained by drilling from the reservoir. Then, the core sample is subjected to vacuuming and pressurization to saturate the simulated formation water, thus simulating the saturated simulated formation water state. This ensures the accuracy and repeatability of the experimental conditions. By vacuuming and pressurizing to saturate the simulated formation water, the underground reservoir environment can be simulated more realistically, improving the reliability of the experimental results.

[0032] Further preferably, in the present application, the vacuum time is greater than 8h, and the pressurized saturation simulated formation time is greater than 24h, so that by stipulating the vacuum time and the pressurized saturation simulated formation water time, the core sample can be ensured to reach saturation state sufficiently, the experimental error is reduced, and the experimental precision is improved.

[0033] Preferably, in the present application, nitrogen is used as the measuring medium, and the permeability is determined after the differential pressure and the flow rate are stabilized, so that the real permeability of the core can be more accurately reflected, and the stability and reliability of the measurement results are ensured by the preset time.

[0034] Preferably, in the present application, the displacement pressure and the outlet end pressure are set according to the actual pressure conditions of the wellhead and the well bottom, so that the experimental conditions are closer to the actual production environment, and the practicality and reference value of the experimental results are improved.

[0035] Preferably, in the present application, the displacement time and the pore volume are used as threshold conditions, so that the sufficiency and effectiveness of the displacement operation are ensured, and the experimental error caused by insufficient or excessive displacement is avoided.

[0036] Preferably, in the present application, the displacement flow rate is selected according to the displacement pressure, and a specific calculation formula is given, so that the displacement operation is more scientific and reasonable; and the reasonable displacement flow rate is helpful to simulate the fluid flow in the actual production, and improve the accuracy of the experimental results.

[0037] Further preferably, in the present application, the displacement flow rate considers multiple factors in the actual production, such as the liquid production, the producing layer area, and the core cross-sectional area, so that the rationality of the displacement flow rate is ensured.

[0038] Preferably, in the present application, by selecting different cores in the same block and cores with similar permeability and repeating the experimental process, the influence degree of the pressure drop and scaling in the near wellbore of the reservoir in different production periods on the permeability of the reservoir can be evaluated, which is helpful to understand the change rule of the reservoir performance with the development time, and provides an important reference for long-term development and maintenance of the oilfield. BRIEF DESCRIPTION OF DRAWINGS

[0039] Figure 1 A flow chart of a method for evaluating the influence degree of fluid scaling on the permeability of a reservoir according to the present application is provided.

[0040] Figure 2 A structural schematic diagram of a simulation device for the influence degree of fluid scaling on the permeability of a reservoir according to the present application is provided.

[0041] Figure 3 A structural schematic diagram of a simulation system for the influence degree of fluid scaling on the permeability of a reservoir according to the present application is provided.

[0042] Figure 4The A2 well near-wellbore pressure drawdown funnel curve provided by the present application.

[0043] Reference signs:

[0044] Core device-1, pump-2, multi-way valve-3, pressurized saturation container-4, back pressure valve-5, produced fluid-6, dry tube-7, gas flow meter-8;

[0045] Sleeve-101; fluid inlet end-102; fluid outlet end-103; confining pressure channel-104; confining pressure liquid-105; resin coating-106; core-107; sealing ring-108. DETAILED DESCRIPTION

[0046] In order to make the technical problems solved by the present application, the technical solutions and beneficial effects clearer, the following specific embodiments are used to further describe the present application. It should be understood that the specific embodiments described herein are only used to explain the present application, and are not used to limit the present application.

[0047] In order to make the purpose, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be described clearly and completely in combination with the drawings in the embodiments of the present application. Obviously, the described embodiments are part of the embodiments of the present application, rather than all the embodiments. The components of the embodiments of the present application described and shown in the drawings can be arranged and designed in various different configurations.

[0048] Therefore, the following detailed description of the embodiments of the present application provided in the drawings is not intended to limit the scope of the claimed present application, but only represents selected embodiments of the present application. All other embodiments obtained by those of ordinary skill in the art based on the embodiments in the present application without creative labor are within the scope of protection of the present application.

[0049] It should be noted that: similar reference signs and letters represent similar items in the following drawings, therefore, once an item is defined in one drawing, it does not need to be further defined and explained in subsequent drawings.

[0050] In the description of the embodiments of the present application, it should be noted that, if the orientation or position relationship indicated by the terms "upper", "lower", "horizontal", "inner" and the like is based on the orientation or position relationship shown in the drawings, or is the orientation or position relationship when the product of the present application is usually placed, and is only for the convenience of describing the present application and simplifying the description, and therefore cannot be understood as indicating or implying that the indicated device or element must have a particular orientation, be constructed and operated in a particular orientation, and therefore cannot be understood as limiting the present application. In addition, the terms "first", "second" and the like are only used to distinguish the description, and cannot be understood as indicating or implying relative importance.

[0051] Furthermore, the use of the term "horizontal" does not imply that the component must be absolutely horizontal, but rather that it can be slightly tilted. For example, "horizontal" simply means that its direction is more horizontal than "vertical," and does not mean that the structure must be completely horizontal, but can be slightly tilted.

[0052] In the description of the embodiments of the present invention, it should also be noted that, unless otherwise explicitly specified and limited, the terms "set," "install," "connect," and "link" should be interpreted broadly. For example, they can refer to a fixed connection, a detachable connection, or an integral connection; they can refer to a mechanical connection or an electrical connection; they can refer to a direct connection or an indirect connection through an intermediate medium; and they can refer to the internal connection of two components. Those skilled in the art can understand the specific meaning of the above terms in the present invention according to the specific circumstances.

[0053] The present invention will now be described in further detail with reference to the accompanying drawings:

[0054] Example 1

[0055] As described in the background section, current research on scaling neglects the impact of scaling caused by pressure drop in the near-wellbore reservoir during the production process of high-pressure oil and gas wells on reservoir permeability. Existing evaluation methods cannot effectively characterize scaling caused by production pressure differential in the near-wellbore reservoir of oil and gas wells, and therefore cannot evaluate the degree of impact of scaling on reservoir permeability after pressure drop. Consequently, due to the lack of evaluation results, it is impossible to establish corresponding reservoir protection measures, which reduces the effectiveness of reservoir development.

[0056] To address the aforementioned issues, this embodiment provides a method for evaluating the impact of fluid scaling on reservoir permeability. This method effectively simulates the test environment before and after core scaling, thereby effectively evaluating the impact of fluid scaling on reservoir permeability. Based on the evaluation results, corresponding reservoir protection measures can be established to minimize reservoir damage and improve reservoir development efficiency.

[0057] like Figure 1 As shown in the figure, this embodiment provides a method for evaluating the impact of fluid scaling on reservoir permeability, specifically including:

[0058] S1: Core 107, which is in a saturated simulated formation water state, is subjected to gas-driven water displacement operation to obtain a bound water saturation sample.

[0059] S2: The permeability of core 107 in the bound water saturation sample was measured to obtain the permeability before scaling.

[0060] S3: According to the near-wellbore pressure drawdown funnel curve, the displacement pressure and the outlet end pressure are set, and the core 107 in the irreducible water saturation sample is operated for displacement until the threshold condition is reached to end the displacement operation.

[0061] S4: The permeability of the core 107 after the displacement operation is measured to obtain the permeability after scaling.

[0062] S5: The core damage rate is calculated according to the permeability before scaling and the permeability after scaling, and the evaluation of the influence degree of fluid scaling on the reservoir permeability is completed according to the core damage rate.

[0063] During S1-S4, the confining pressure of the core 107 is always kept unchanged.

[0064] As shown in Figure 2 and Figure 3 In order to ensure the smooth implementation of the above evaluation method, the embodiment provides a core device 1 and a simulation system comprising the core device, and the specific scaling of the core device 1 comprises:

[0065] The simulation device (core device 1) is in the shape of a cylinder as a whole, comprising a sleeve 101, preferably a pressure-resistant metal sleeve, which not only carries the core 107, the core of the experiment, but also simulates the fluid flow and pressure environment in the formation through its unique structural design, and the specific design is as follows:

[0066] The two ends of the sleeve 101 are respectively provided with a fluid inlet and a fluid outlet, i.e. a fluid inlet end 102 and a fluid outlet end 103 of the sleeve 101; they jointly constitute a displacement flow channel penetrating through the center of the sleeve 101 and directly connected to the core 107; this design allows the experimental fluid to enter through the inlet, flow through the inside of the core 107, and finally be discharged from the fluid outlet, simulating the natural flow process of the fluid in the formation.

[0067] In order to be closer to the pressure conditions of the actual formation, a confining pressure channel 104 is ingeniously arranged between the inner wall of the sleeve 101 and the outer wall of the core 107; the confining pressure channel 104 serves as a transmission path for the confining pressure liquid, and when the confining pressure liquid 105 is injected through the confining pressure inlet, it can be uniformly and stably applied to the outside of the core, simulating the confining pressure effect of the formation on the core.

[0068] In addition, in order to ensure the tightness of the confining pressure seal, a layer of resin coating 106 is further provided on the outside of the core 107, preferably a pressure-resistant elastic rubber; this layer of rubber not only provides the necessary elasticity and sealing property, but also effectively prevents the leakage of the confining pressure liquid, ensuring the stability and controllability of the pressure environment during the experiment.

[0069] In terms of detailed design, the device also considers the sealing of fluid flow. Sealing rings 108 are installed at the connection between the fluid inlet, the fluid outlet and the core 107. The sealing rings 108 further strengthen the sealing performance of the entire flow channel system, avoid unnecessary leakage of experimental fluid during flow, and thus ensure the accuracy and reliability of experimental data.

[0070] In this embodiment, the core 107 used can be a real core cored from the target interval of the block, or an outcrop core of the same structure, or a simulated artificial core.

[0071] One end of the core device 1 is connected to an oil, gas and water displacement system. The fluid in the container is injected into the core according to the actual production through a pump 2. The pressure values at both ends of the core device are set according to the pressure drop funnel differential value of the wellbore bottom near-wellbore zone. After the valve is opened, the fluid flows in the core. Because the pressure difference between the two sides is large, there is scaling in the core. After the flow ends, the change value of the core permeability is tested to determine the influence degree of the scaling after pressure drop on the reservoir permeability.

[0072] As shown in Figure 3 The embodiment also provides a simulation system for the influence degree of fluid scaling on reservoir permeability, which comprises the core device 1 and specifically comprises:

[0073] The displacement device realizes water displacement operation on the core 107 by being connected to the fluid inlet end 102 of the core device 1. The displacement device comprises a plurality of displacement fluid containers, each of which is provided with a pump 2 to ensure that the fluid enters the core at a stable and controllable flow rate. The displacement fluid containers are flexibly connected to the fluid inlet end through a multi-way valve 3, thereby providing diversified fluid selection for the experiment.

[0074] Next, in order to simulate the pressure environment in the actual formation, the system is provided with a pressurized saturation container 4. The pressurized saturation container 4 is connected to the confining pressure channel 104 of the core device 1, can establish an initial formation water saturation environment before the experiment starts, and can apply confining pressure to the core on this basis. This design ensures that the pressure conditions borne by the core during the experiment are highly similar to the actual formation environment.

[0075] In order to collect and analyze the liquid flowing out of the core during the experiment, the system is also provided with a collection device. The collection device is connected to the fluid outlet end 103 of the core device 1 and can effectively collect the produced fluid 6. The collection bottle is the core component of the collection device. A drying tube 7 and a gas flow meter 8 are sequentially installed on the gas outlet pipeline of the collection bottle. The drying tube 7 is used to remove water in the gas, and the gas flow meter 8 is used to accurately measure the volume of the outflowing gas. These data are crucial for subsequent experimental analysis.

[0076] In this embodiment, the system is also equipped with a data acquisition device, which is cleverly positioned between the pressurized saturated container 4 and the fluid inlet end 102, the collection device and the fluid outlet end 103, and the pressurized saturated container 4 and the confining pressure channel 104. It is mainly used to monitor and record key parameters such as fluid inlet pressure, fluid outlet pressure and confining pressure in real time, and can accurately collect the above parameters to provide a strong guarantee for the reliability and accuracy of experimental results.

[0077] To further explain the method provided by this invention, the more specific steps are as follows:

[0078] (1) Simulated cores can be made based on reservoir permeability, or reservoir cores can be drilled to obtain core samples for research.

[0079] (2) Place the core sample into the pressurized saturated container 4, evacuate for more than 8 hours, and pressurize and saturate the simulated formation water for more than 24 hours.

[0080] (3) After saturating the simulated formation water, the core sample is loaded into the core device 1, and water is driven by gas according to the direction of gas permeability measurement to prepare a bound water saturation sample.

[0081] (4) The permeability of the core in the bound water saturation sample is determined by nitrogen gas and recorded as K0. When measuring the permeability, the experiment is stopped when the differential pressure and flow rate tend to stabilize. The stabilization time is not less than 1 hour, and the confining pressure is kept constant. (Note: After the permeability K1 measurement is completed, the confining pressure is kept constant and the core is not removed from the holder).

[0082] (5) Based on the pressure drop funnel curve near the wellbore, set the displacement pressure and the outlet pressure. Alternatively, the pressure within 0.5m of the wellhead can be directly selected as the displacement pressure and the bottom hole pressure as the outlet pressure.

[0083] (6) Select an appropriate displacement velocity based on the displacement pressure. The displacement velocity can be referenced as ν=A2×Q. l / A1, after adding the units corresponding to the parameters, the formula is transformed to obtain: ν=11.6×A2×Q l / A1, where ν is the flow rate, in mL / min; Q l Liquid production volume, unit: m 3 / d; A1 is the area of ​​the producing layer, unit: cm 2 A2 represents the cross-sectional area of ​​the core sample, in cm². 2 .

[0084] (7) Keep the confining pressure constant and drive in the forward direction. The threshold condition is: the displacement time is not less than 2h and greater than 10PV (pore volume). Here, the displacement direction is the same as the nitrogen driving direction. The PV number is calculated when the liquid flows out from the outlet end.

[0085] (8) While keeping the confining pressure constant, use nitrogen gas to determine the permeability K1 after core damage. When measuring permeability with nitrogen gas, stop the experiment when the differential pressure and flow rate tend to stabilize. The stabilization time should not be less than 1 hour, and the confining pressure should be kept constant.

[0086] (9) Core damage rate (%) = (K0-K1) / K0×100. The impact of scaling on reservoir permeability after pressure drop can be evaluated based on the core damage rate.

[0087] (10) Select core samples from the same block or simulated core samples with similar permeability, and repeat the above steps (2) to (9) to obtain the degree of influence of scaling generated after pressure drop in the near-wellbore zone of the reservoir on the reservoir permeability during different production periods.

[0088] Example 2

[0089] This embodiment provides a method for evaluating the impact of fluid scaling on core porosity. The method is applied to an evaluation test of the impact of scaling on reservoir permeability in oil and gas well A2. The specific test procedure is as follows:

[0090] Oil and gas well A2 has a producing depth of 6430-6530m and a producing layer thickness of 100m. The reservoir is a fractured tight sandstone gas reservoir. In the early stage, the daily production of fluid was 2.08t and the daily production of gas was 231,600 cubic meters. Due to the continuous production and development, water has invaded high-angle fractures in the single well, and the daily production of fluid is 321t, the daily production of oil is 0 tons, the daily production of water is 321 tons, and the daily production of gas is 64,400 cubic meters. Moreover, the production capacity has shown a continuous downward trend.

[0091] This embodiment provides a method for evaluating the impact of scaling on reservoir permeability after pressure drop, including the following steps:

[0092] (1) Core samples were taken from the reservoir to obtain core samples for research purposes. The core samples were taken from well A2, with a depth of 6445.37 to 6563.65 m and a stratigraphic position of K1bs.

[0093] (2) Place the sample in the pressure saturation device container, evacuate for more than 8 hours, and saturate the simulated formation water for more than 24 hours.

[0094] (3) After saturating the simulated formation water, the rock sample was loaded into the core holder and water was driven by gas according to the direction of gas permeability measurement to prepare a bound water saturation sample.

[0095] (4) Use nitrogen to measure the permeability of the core and record it as K0. When measuring permeability, stop the experiment when the differential pressure and flow rate tend to stabilize. The stabilization time should not be less than 1 hour. Keep the confining pressure constant, as shown in Table 1. (Note: After the permeability K1 measurement is completed, keep the confining pressure constant and do not remove the core from the holder.)

[0096] Table 1. Results of conventional analysis of core samples from Well A2

[0097]

[0098] (5) Figure 4 As shown, based on the pressure drop funnel curve in the near-wellbore zone, the displacement pressure is set to 66 MPa and the outlet pressure to 65 MPa.

[0099] (6) Select the appropriate displacement flow rate based on the displacement pressure. The displacement velocity can be referenced as ν = 11.6 × A² × Q. l / A1≈0.1mL / min, where ν is the flow rate, in mL / min; Q l Liquid production volume, unit: m 3 / d; A1 is the area of ​​the producing layer, unit: cm 2 A2 represents the cross-sectional area of ​​the core sample, in cm². 2 .

[0100] (7) Maintain a confining pressure of 70 MPa and drive in the forward direction. The displacement time should be no less than 2 hours and greater than 10 PV (in the same direction as nitrogen driving, the PV number is calculated when the liquid flows out from the outlet end).

[0101] (8) While keeping the confining pressure constant, use nitrogen gas to determine the permeability K1 after core damage. When measuring permeability with nitrogen gas, stop the experiment when the differential pressure and flow rate tend to stabilize. The stabilization time should not be less than 1 hour, and the confining pressure should be kept constant.

[0102] (9) Core damage rate (%) = (K0-K1) / K0×100. The impact of scaling on reservoir permeability after pressure drop can be evaluated based on the core damage rate, as shown in Table 2.

[0103] Table 2. Permeability Analysis Results of Core Samples from Well A2 After Scaling

[0104]

[0105] (10) Select core samples from the same block or simulated core samples with similar permeability, and repeat the above steps (2) to (9) to obtain the degree of influence of scaling generated after pressure drop in the near-wellbore zone of the reservoir on the reservoir permeability during different production periods.

[0106] In summary, this invention provides a method for evaluating the impact of scaling on reservoir permeability after pressure drop, which has the following advantages compared to existing evaluation methods:

[0107] This invention provides a systematic and comprehensive method for evaluating the impact of fluid scaling on reservoir permeability. By simulating the reservoir environment (including saturated simulated formation water state and maintaining constant confining pressure) and precisely controlling experimental conditions (such as displacement pressure, outlet pressure, displacement time, and flow rate), the accuracy and repeatability of experimental results can be ensured. Specifically, this method first obtains a bound water saturation sample through gas-driven water displacement and measures its permeability before scaling, providing a benchmark for subsequent comparisons. Subsequently, displacement parameters are set according to the actual pressure conditions in the near-wellbore zone, and the sample is subjected to displacement operations to simulate the fluid scaling process, and the permeability after scaling is measured. By comparing the changes in permeability before and after scaling, the core damage rate is calculated, thereby quantifying the impact of fluid scaling on reservoir permeability. Furthermore, by conducting repeated experiments with cores from the same block or with similar permeability, the impact of near-wellbore pressure drop scaling on permeability at different production stages can be further evaluated, providing important reference for the long-term development and maintenance of the oilfield. These steps and measures together constitute a scientific, reasonable, and effective evaluation system, helping to more accurately understand the impact of fluid scaling on reservoir performance and providing a scientific basis for formulating effective scaling prevention and removal measures.

[0108] The above embodiments are merely one of the implementation methods for achieving the technical solution of the present invention. The scope of protection claimed by the present invention is not limited to this embodiment, but also includes any variations, substitutions and other implementation methods that can be easily conceived by those skilled in the art within the scope of the technology disclosed in the present invention.

Claims

1. A method for evaluating the impact of fluid scaling on reservoir permeability, characterized in that, include: S1: The core (107) in the saturated simulated formation water state was subjected to gas-driven water displacement operation to obtain a bound water saturation sample; S2: The permeability of the core (107) in the bound water saturation sample was measured to obtain the permeability before scaling; S3: Based on the pressure drop funnel curve in the near-wellbore zone, set the displacement pressure and the outlet pressure, and perform displacement operation on the core (107) in the bound water saturation sample according to the set displacement pressure and the outlet pressure until the threshold condition is reached and the displacement operation ends. S4: The permeability of the core (107) after the displacement operation was measured to obtain the permeability after scaling; S5: Calculate the core damage rate based on the permeability before and after scaling, and evaluate the impact of fluid scaling on reservoir permeability based on the core damage rate; During the S1-S4 process, the confining pressure of the core (107) remained constant.

2. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 1, characterized in that, In S1, the simulation steps for the saturated simulated formation water state are as follows: Based on the reservoir permeability, simulated cores are made or core samples are obtained by drilling from the reservoir. The core samples were subjected to vacuuming and pressurization to simulate formation water conditions, thus completing the simulation of the saturated formation water state.

3. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 2, characterized in that, in, The vacuuming time is greater than 8 hours; the pressurized saturation simulation formation time is greater than 24 hours.

4. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 1, characterized in that, In S2, nitrogen was used to measure the permeability of the core (107) in the bound water saturation sample. During the measurement, the measurement was completed after the differential pressure and flow rate were both stable for a preset time, which was no less than 1 hour.

5. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 1, characterized in that, In S3, the pressure within 0.5m of the wellhead is selected as the displacement pressure; the bottom hole flowing pressure is selected as the outlet pressure.

6. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 1, characterized in that, In S3, the threshold condition is that the displacement time is not less than 2 hours and the pore volume is greater than 10 PV.

7. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 1, characterized in that, In S3, the displacement velocity is selected based on the displacement pressure, and the core (107) in the bound water saturation sample is subjected to displacement operation according to the displacement velocity.

8. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 7, characterized in that, The displacement velocity is determined based on the liquid production rate per second, the producing layer area, and the core cross-sectional area, using the following formula: ν=A2×Q l / A1 Where ν represents the displacement velocity; Q l A1 represents the liquid production volume; A2 represents the area of ​​the producing layer; A3 represents the cross-sectional area of ​​the core.

9. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 1, characterized in that, In S4, the specific formula for calculating the core damage rate is as follows: Core damage rate = (permeability before scaling - permeability after scaling) / permeability before scaling * 100%.

10. The method for evaluating the impact of fluid scaling on reservoir permeability according to claim 1, characterized in that, Also includes: S6: Select cores from the same block or cores with similar permeability, and repeat S1-S4 to evaluate the impact of pressure drop and scaling in the near-wellbore zone on reservoir permeability during development at different production stages.

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