Judgment method and experimental device for types and main control factors of injection well blockage

Abstract

The application provides a judgment method and experimental device for the plugging type and main control factor of a polymer injection well, and relates to the technical field of oil and gas exploitation. The judgment method comprises the following steps: obtaining the process parameters of the actual construction process of the polymer injection well; obtaining the reservoir parameters corresponding to the polymer injection well; establishing an indoor experimental device according to the process parameters and the reservoir parameters; performing water injection development simulation, polymer injection development simulation, profile control and displacement operation simulation and comprehensive operation simulation according to the process parameters and the indoor experimental device to obtain simulation data; and judging the plugging type and the main control factor of the polymer injection well by using the simulation data. The application also provides an experimental device for the judgment method. The judgment method and experimental device for the plugging type and main control factor of the polymer injection well can quickly analyze and judge the plugging type and main control factor of the polymer injection well indoors, and provide theoretical and technical support for the next step of research and development of plugging removal technology.

Description

Technical Field

[0001] This application relates to the field of oil and gas extraction technology, and in particular to a method and experimental apparatus for determining the type of blockage and the main controlling factors in polymer injection wells. Background Technology

[0002] In the production and development of oil and gas fields, injection well blockage significantly impacts production and development outcomes. For example, it can prevent the injected fluid from being evenly distributed to the target formation, hindering its effective propulsion of oil into the production well. It can also disrupt the injection-production balance, preventing the injected fluid from smoothly entering the reservoir and thus affecting reservoir pressure maintenance and control. Therefore, injection well blockage is a problem that requires attention and resolution. However, the causes of injection well blockage are numerous, with the most severe blockage occurring in polymer flooding injection wells or injection wells employing profile control and displacement techniques.

[0003] To effectively improve and solve the problem of well blockage in injection wells, many scholars have conducted relevant research and analysis on the blockage mechanism. Almost all of these studies begin with the analysis of the composition of the blockage material, using this composition to determine the blockage mechanism. However, for polymer injection wells, polymer-induced blockage is inherently a complex physicochemical process. Analysis of the blockage material composition can only demonstrate the final state of the blockage from the end result, ignoring the changes during the process. Yang Xinhui, Tang Hongming, and others, through scale sample analysis, demonstrated that the blockage of JZ9-3 was divided into hard agglomerate blockage mainly composed of inorganic components such as iron salts, calcium salts, fluorosilicates, and fluoroaluminates, plus soft and hard combined particulate blockage of "organic (partially hydrolyzed dilute amide micelles) + inorganic (quartz, calcium carbonate)". They speculated that during polymer flooding, polymer molecules adsorbed and flocculated clay minerals, suspended solids, and other particles, forming agglomerates with a certain deformability; polymers cross-linked with high-valence metal cations to form organic micelle blockage; and inorganic scale such as secondary precipitation from acidification intertwined with heavy components of crude oil and polymers, exacerbating the degree of reservoir blockage (Analysis of the composition and causes of blockage in polymer flooding benefit wells in Jinzhou 9-3 oilfield [J]. Modern Chemical Industry, 2020, 40(04): (658-663). Cui Bo et al., from the perspectives of water injection quality, reservoir sensitivity, and process measures, theoretically combined with experiments, discussed the blockage of SZ36-1 wells caused by water injection quality (particle size, solid content, bacterial concentration, scaling, oil pollution), reservoir sensitivity, and process measures (polymer injection profile control, acidizing). They did not specify which type of blockage was the main controlling factor, but only indicated the possibility of blockage (Analysis of the causes and countermeasures of blockage in water injection wells of Suizhong 36-1 oilfield [J]. Offshore Petroleum, 2012, 32(02): 64-70.). These findings only demonstrated the current type of blockage in wells from the perspective of scale sample results of single wells, without explaining the specific main controlling factors of blockage in the polymer flooding process. The analysis method of scale samples is extremely dependent on the acquisition of scale samples. Each acquisition of scale samples requires a major workover operation, which is time-consuming and expensive, thus limiting the scientific research work on systematically analyzing the blockage type and main controlling factors of polymer injection wells.

[0004] Therefore, it is necessary to develop a method for determining the type and controlling factors of polymer injection well blockage in indoor analysis. Summary of the Invention

[0005] The purpose of this application is to provide a method for judging the type of blockage and the main controlling factors of polymer injection wells. The judgment results are more accurate and effective, and are more conducive to providing theoretical and technical support for the research and development of polymer injection and production and unblocking technologies.

[0006] This application also provides an experimental apparatus for determining the type and main controlling factors of polymer injection well blockage.

[0007] For the purposes mentioned above, this application provides the following technical solution:

[0008] In a first aspect, embodiments of this application provide a method for determining the type of blockage and the main controlling factors in polymer injection wells, including the following steps:

[0009] Obtain the process parameters of the actual construction process of the polymer injection well; obtain the reservoir parameters corresponding to the polymer injection well;

[0010] Based on the aforementioned process parameters and reservoir parameters, an indoor experimental setup was established.

[0011] Based on the process parameters and the indoor experimental setup, simulations were performed for water injection development, polymer injection development, regulation and drive operation, and comprehensive operation to obtain simulation data.

[0012] The type of blockage and the main controlling factors of the polymer injection well are determined using simulation data;

[0013] The indoor experimental apparatus includes an injection system, a simulation system, a product collection system, and an information acquisition system. The injection system injects fluid into the simulation system, and the product collection system collects the fluid discharged from the simulation system. The simulation system includes a constant temperature and pressure chamber and at least four core sample tubes housed within the chamber, with the injection and discharge of fluid in each core sample tube controlled separately. The information acquisition system collects parameters from each core sample tube during the simulation process to obtain simulation data.

[0014] Furthermore, in some embodiments of this application, the reservoir parameters include actual reservoir particle composition, actual porosity, actual permeability, actual reservoir temperature, and actual reservoir pressure.

[0015] The core sample tube includes a core sample formed by filling with sand. The sand filling material used in the core sample is selected according to the particle composition of the reservoir. The difference between the permeability and porosity of the core sample and the actual porosity and actual permeability is not higher than 5% of the actual porosity and actual permeability, respectively.

[0016] Furthermore, in some embodiments of this application, the process parameters include well completion type, development process, and injection fluid parameters;

[0017] The well completion type is selected from any one of perforated well completion, open hole well completion, perforated gravel packing well completion, and perforated wire-wound screen packing well completion.

[0018] The development process includes development stages and injection fluid types. The development stages are selected from any one of water injection development stage, polymer injection development stage, and regulation and drive stage. The injection fluid type includes the type of injection fluid, injection volume, and injection rate.

[0019] The injected fluid parameters include the fluid's formulation, viscosity, and rheological parameters.

[0020] Furthermore, in some embodiments of this application, the fluid injected in the water injection development simulation is formation water;

[0021] The fluid injected in the polymer injection development simulation is a polymer system containing polymer;

[0022] The fluid injected in the simulated controlled-drive operation is a controlled-drive agent system;

[0023] The flow rate and velocity of the injected formation water in the water injection development simulation are adjusted according to the flow rate and velocity of the formation water calculated using the planar radial flow formula based on the type of injected fluid in the water injection development stage; the formulation, viscosity, and rheological parameters of the injected formation water in the water injection development simulation are obtained based on the parameters of the injected fluid in the water injection development stage.

[0024] The flow rate and velocity of the polymer system injected in the polymer injection development simulation are adjusted according to the flow rate and velocity of the polymer system calculated using the planar radial flow formula based on the type of injected fluid in the polymer injection development stage; the formulation, viscosity, and rheological parameters of the polymer system injected in the polymer injection development simulation are obtained based on the injected fluid parameters in the polymer injection development stage;

[0025] The flow rate and velocity of the modulating agent system injected in the modulating operation simulation are adjusted according to the flow rate and velocity of the modulating agent system calculated based on the planar radial flow formula according to the type of injected fluid in the modulating stage; the formulation, viscosity and rheological parameters of the modulating agent system injected in the modulating operation simulation are obtained according to the injected fluid parameters in the modulating stage.

[0026] Furthermore, in some embodiments of this application, the planar radial flow formula is determined based on the planar radial flow model; the planar radial flow model is selected based on the well completion type.

[0027] Furthermore, in some embodiments of this application, when the completion type is perforated completion, the planar radial flow model used is:

[0028]

[0029] When the well completion type is open-hole completion, the planar radial flow model used is:

[0030]

[0031] The well completion type is perforated wire-wound screen packing completion, and the planar radial flow model used is:

[0032]

[0033] Where Q represents flow rate, in meters (m³). 3 / (m·d); C is the degree of opening, unit: %; h is the total thickness of the oil layer, unit: m; n is the perforation density, unit: number of holes; r is the distance the fluid travels, unit: m; v is the seepage velocity, unit: m / d.

[0034] Furthermore, in some embodiments of this application, water injection development simulation, polymer injection development simulation, flow regulation operation simulation, and comprehensive operation simulation are performed based on the process parameters and the indoor experimental apparatus, including:

[0035] Step (1): Keep the fluid inlet and outlet of one of the core sample tubes open, and close the fluid inlet and outlet of the other core sample tubes. Inject the formation water into one of the core sample tubes at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates.

[0036] Step (2): Keep the fluid inlet and outlet of one core sample tube that has not been injected with the formation water open, and close the fluid inlet and outlet of the other core sample tubes. Inject the polymer system into one core sample tube at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates.

[0037] Step (3): Keep the fluid inlet and outlet of one core sample tube that has not been injected with the formation water and the polymer system open, and close the fluid inlet and outlet of the other core sample tubes. Inject the modulator system into one core sample tube at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates.

[0038] Step (4): Keep the fluid inlet and outlet of the core sample tube that has not been injected with the formation water, the polymer system, or the modulator system open, and close the fluid inlet and outlet of the other core sample tubes; inject formation water, polymer system, and modulator system into a core sample in sequence according to the injection flow rate and injection flow rate in steps (1) to (3); then inject formation water again, and obtain the permeability of the core sample before and after each fluid injection.

[0039] Furthermore, in some embodiments of this application, the type of blockage in the polymer injection well is determined based on the permeability changes obtained in steps (1) to (3);

[0040] Based on the permeability obtained in steps (1) to (4), the main control factors of blockage in polymer injection wells are determined using the grey relational analysis method.

[0041] Secondly, this application also provides an experimental device for determining the type and main controlling factors of plugging in polymer injection wells, including an injection system, a simulation system, a production collection system, and an information acquisition system; the injection system is used to inject fluid into the simulation system, and the production collection system is used to collect the fluid discharged from the simulation system; the simulation system includes a constant temperature and pressure chamber and at least four core sample tubes housed in the constant temperature and pressure chamber, and the opening and closing of fluid injection and discharge in each core sample tube are controlled separately; the information acquisition system collects the parameters of each core sample tube during the simulation process to obtain simulation data.

[0042] Furthermore, in some embodiments of this application, the information acquisition system includes multiple pressure sensors, with at least two pressure sensors provided on each core sample tube.

[0043] This application provides a method for determining the type and controlling factors of blockage in polymer injection wells. It uses simulated rock samples filled with actual reservoir physical parameters as a basis, and adjusts the simulation parameters of each fluid based on the actual development and production processes of the polymer injection well, thus improving the effectiveness of the simulated data. Furthermore, the simulation employs an orthogonal experimental design method involving experimental equipment and procedures, simulating the impact of each fluid injection on the reservoir and the combined impact of fluid injection on the reservoir, analyzing and determining the type and controlling factors of reservoir blockage. The method yields more accurate and effective results, providing theoretical and technical support for the research and development of polymer injection well production and unblocking technologies.

[0044] The experimental apparatus provided in this application for determining the type of blockage and the main controlling factors in polymer injection wells is not only simple in structure and easy to operate, but also better reduces the influence of other factors on the experimental results, making the simulation data more accurate and effective. Attached Figure Description

[0045] Figure 1 A flowchart illustrating a method for determining the type of blockage and main controlling factors in polymer injection wells, provided in some embodiments of this application;

[0046] Figure 2 This is a schematic diagram of the experimental apparatus for determining the type and main controlling factors of polymer injection well blockage, provided in some embodiments of this application.

[0047] Among them, 11-injection pump, 12-formation water container, 13-polymer system container, 14-regulation and drive system container, 21-thermal chamber, 22-core sample tube, 23-pressure sensor, 31-backpressure valve, 32-sampling container. Detailed Implementation

[0048] The technical solutions of this application will be clearly and completely described below with reference to the embodiments. Obviously, the described embodiments are only some embodiments of this application, not all embodiments. Based on the embodiments of this application, all other embodiments obtained by those skilled in the art without creative effort are within the scope of protection of this application.

[0049] Poisoning in injection wells has a significant impact on production and development, affecting not only oil and gas recovery rates but also the success of injection and production. The methods for unblocking vary greatly depending on the type of blockage and the controlling factors. Therefore, identifying the type of blockage and the controlling factors is crucial for unblocking. In existing technologies, using scale samples to determine the type of blockage is the most common method. However, this method is dependent on the quality of the scale samples, and the collection process is time-consuming and expensive. Furthermore, scale samples can only determine the type of blockage, not the controlling factors, thus providing limited technical support for unblocking. This application provides a method for determining the type of blockage and the controlling factors in polymer injection wells, including the following steps:

[0050] Obtain the process parameters of the actual construction process of the polymer injection well; obtain the reservoir parameters corresponding to the polymer injection well;

[0051] Based on the aforementioned process parameters and reservoir parameters, an indoor experimental setup was established.

[0052] Based on the process parameters and the indoor experimental setup, simulations were performed for water injection development, polymer injection development, regulation and drive operation, and comprehensive operation to obtain simulation data.

[0053] The type of blockage and the main controlling factors of the polymer injection well are determined using simulation data;

[0054] The indoor experimental apparatus includes an injection system, a simulation system, a product collection system, and an information acquisition system. The injection system injects fluid into the simulation system, and the product collection system collects the fluid discharged from the simulation system. The simulation system includes a constant temperature and pressure chamber and at least four core sample tubes housed within the chamber, with the injection and discharge of fluid in each core sample tube controlled separately. The information acquisition system collects parameters from each core sample tube during the simulation process to obtain simulation data.

[0055] The actual construction process of the polymer injection well can be obtained from the construction records of the oil and gas reservoir, providing a basis for the design of injection parameters. The specific contents include well completion type, development process, and injection fluid parameters.

[0056] The well completion type can be any one of perforated completion, open hole completion, perforated gravel packing completion, or perforated wire mesh packing completion. Because different completion methods cause changes in the seepage pattern of the injected fluid near the bottom of the well, a suitable planar radial flow model is selected based on the different completion methods to subsequently design the injection velocity and flow rate adjustment range.

[0057] When the well completion type is perforated well completion, the planar radial flow model used is:

[0058] (1)

[0059] When the well completion type is open-hole completion, the planar radial flow model used is:

[0060] (2)

[0061] The well completion type is perforated wire-wound screen packing completion, and the planar radial flow model used is:

[0062] (3)

[0063] Where Q represents flow rate, in meters (m³). 3 / (m·d); C is the degree of opening, unit: %; h is the total thickness of the oil layer, unit: m; n is the perforation density, unit: number of holes; r is the distance the fluid travels, unit: m; v is the seepage velocity, unit: m / d.

[0064] The development process refers to the types of injected fluids at different stages. Defining the stages and types of injected fluids is essential for determining the parameters for indoor simulation. These stages are typically divided into: water injection development stage, polymer injection development stage, and flow control operation stage.

[0065] The type of injected fluid in each stage depends on the actual type of fluid injected. For example, in the water injection development stage, the injected fluid is usually formation water, but other types are also possible. In the polymer injection development stage, the injected polymer system can be a hydrophilic polymer system or an oleophilic polymer system. In the profile control operation stage, the injected fluid can be a gel-based profile control system, a resin-based profile control system, or a weak gel-based profile control system, etc. In addition, some profile control agents may also be added in the water injection or polymer injection stages, which are also taken into account when determining the indoor simulation parameters.

[0066] The type of injected fluid also includes the injection volume and injection rate. For example, the first phase is water injection development for 3-5 years, with a daily injection volume of 120m³. 3 / d; The second phase is polymer injection development for 4-5 years, with a daily polymer injection volume of 70m³. 3 / d.

[0067] By substituting the fluid type, fluid injection rate, and fluid injection volume into the corresponding planar flow model according to different well completion types, the range of injected fluid rate and injection volume for the simulated core sample tube can be calculated.

[0068] The parameters of the fluid injected into the core sample tube used in the simulation should be similar to or the same as those of the fluid used in the actual construction process. These parameters include, but are not limited to, the fluid's formulation, viscosity, and rheological parameters.

[0069] Among them, the parameters of the fluids injected during the water injection development stage, such as formation water, include the material composition and apparent viscosity of the formation water; the parameters of the polymer system injected during the polymer injection stage include the type of polymer system and rheological parameters; and the parameters of the modulating agent injected during the modulating stage include the type of modulating agent and rheological parameters.

[0070] The reservoir parameters corresponding to the polymer injection well include the actual reservoir particle composition, actual porosity, actual permeability, actual reservoir temperature, and actual reservoir pressure; these can be obtained through well logging data, etc. The reservoir particle composition also includes the clay mineral composition and the particle size range of the rock grains.

[0071] The process of filling and forming core samples is based on the actual reservoir particle composition, actual porosity, and actual permeability in the reservoir parameters, so that the reservoir particle composition, porosity, and permeability of the core sample tube formed are infinitely close to the actual reservoir particle composition, actual porosity, and actual permeability, thereby improving the effectiveness of the simulation.

[0072] For example, the sand filling material used in the core sample is selected according to the particle composition of the reservoir, and the difference between the permeability and porosity of the core sample and the actual porosity and actual permeability is not higher than 5% of the actual porosity and actual permeability, respectively.

[0073] The core sample tube includes a shell; the shell has a receiving cavity.

[0074] A simulated core sample is placed inside a containment cavity; one side of the shell is provided with an injection port for injecting fluid, and the other side is provided with a sampling port for discharging fluid.

[0075] The shell structure can be cubic or cylindrical, preferably cubic or cylindrical. The shell thickness can be set according to requirements, preferably high-strength glass or stainless steel with a thickness of not less than 5mm, preferably transparent high-strength glass to facilitate observation of fluid flow inside the shell.

[0076] In some embodiments, the fluid injected in the water injection development simulation is formation water;

[0077] The fluid injected in the polymer injection development simulation is a polymer system containing polymer;

[0078] The fluid injected in the simulated controlled-drive operation is a controlled-drive agent system;

[0079] The flow rate and velocity of the injected formation water in the water injection development simulation are adjusted according to the flow rate and velocity of the formation water calculated using the planar radial flow formula based on the type of injected fluid in the water injection development stage; the formulation, viscosity, and rheological parameters of the injected formation water in the water injection development simulation are obtained based on the parameters of the injected fluid in the water injection development stage.

[0080] The flow rate and velocity of the polymer system injected in the polymer injection development simulation are adjusted according to the flow rate and velocity of the polymer system calculated using the planar radial flow formula based on the type of injected fluid in the polymer injection development stage; the formulation, viscosity, and rheological parameters of the polymer system injected in the polymer injection development simulation are obtained based on the injected fluid parameters in the polymer injection development stage;

[0081] The flow rate and velocity of the modulating agent system injected in the modulating operation simulation are adjusted according to the flow rate and velocity of the modulating agent system calculated based on the planar radial flow formula according to the type of injected fluid in the modulating stage; the formulation, viscosity and rheological parameters of the modulating agent system injected in the modulating operation simulation are obtained according to the injected fluid parameters in the modulating stage.

[0082] In some embodiments, water injection development simulation, polymer injection development simulation, flow regulation operation simulation, and integrated operation simulation are performed based on the process parameters and the indoor experimental apparatus, including:

[0083] Step (1): Keep the fluid inlet and outlet of one of the core sample tubes open, and close the fluid inlet and outlet of the other core sample tubes. Inject the formation water into one of the core sample tubes at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates.

[0084] Step (2): Keep the fluid inlet and outlet of one core sample tube that has not been injected with the formation water open, and close the fluid inlet and outlet of the other core sample tubes. Inject the polymer system into one core sample tube at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates.

[0085] Step (3): Keep the fluid inlet and outlet of one core sample tube that has not been injected with the formation water and the polymer system open, and close the fluid inlet and outlet of the other core sample tubes. Inject the modulator system into one core sample tube at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates.

[0086] Step (4): Keep the fluid inlet and outlet of the core sample tube that has not been injected with the formation water, the polymer system, or the modulator system open, and close the fluid inlet and outlet of the other core sample tubes; inject formation water, polymer system, and modulator system into a core sample in sequence according to the injection flow rate and injection flow rate in steps (1) to (3); then inject formation water again, and obtain the permeability of the core sample before and after each fluid injection.

[0087] Taking a core sample tube configuration of four tubes, designated A, B, C, and D, as an example, each core sample tube has an injection port connected to an injection tube, and each injection tube is equipped with a control valve to control the fluid injection into each core sample tube. For instance, the injection tube connected to tube A is equipped with valve A, the injection tube connected to tube B is equipped with valve B, the injection tube connected to tube C is equipped with valve C, and the injection tube connected to tube D is equipped with valve D.

[0088] Each core sample tube has a sampling port connected to a sampling tube. In some embodiments, each sampling tube is equipped with a backpressure valve to control the pressure of the core sample tube during injection and sampling. Additionally, each core sample tube is equipped with a pressure sensor to collect the pressure within that core sample tube. All core sample tubes are placed in a temperature-adjustable device, such as a constant temperature chamber, to adjust the simulated temperature.

[0089] Step (1): During the simulation, keep valves A, B, C, and D closed, and also close all back pressure valves. Adjust the temperature of the constant temperature chamber to keep it within ±2℃ of the temperature to be simulated. Then, keep valves B, C, D, and the back pressure valve closed, open valve A, and inject fluid, such as formation water, into pipe A. Simultaneously, collect the pressure in pipe A. When the pressure rises to the required pressure, open the back pressure valve to discharge the fluid. Calculate the permeability of the core sample at this flow rate after the fluid is injected. Adjust the flow rate of the injected fluid and repeat the above steps to calculate the permeability of the core sample at different flow rates.

[0090] Step (2): Then close valve A, keep valves A, B, C, and D closed, and also close all back pressure valves. Keep valves A, C, D, and back pressure valves closed at the same temperature. Open valve B and inject fluid, such as a polymer system, into pipe B. Simultaneously, collect the pressure in pipe B. When the pressure rises to the required pressure, open the back pressure valve to discharge the fluid. Calculate the permeability of the core sample at this flow rate after the fluid is injected. Adjust the flow rate of the injected fluid and repeat the above steps to calculate the permeability of the core sample at different flow rates.

[0091] Step (3): Close valve B again, keep valves A, B, C, and D closed, and close all back pressure valves. Keep valves A, B, D, and back pressure valves closed at the same temperature. Open valve C and inject fluid into pipe C, such as the displacement agent system. At the same time, collect the pressure in pipe C. When the pressure rises to the required pressure, open the back pressure valve and discharge the fluid. Calculate the permeability of the core sample at this flow rate after the fluid is injected. Adjust the flow rate of the injected fluid and repeat the above steps to calculate the permeability of the core sample at different flow rates.

[0092] Step (4): Close valve C again, keep valves A, B, C, and D closed, and close all back pressure valves. Keep valves A, B, C, and back pressure valves closed at the same temperature. Open valve D and inject formation water into pipe D. At the same time, collect the pressure in pipe D. When the pressure rises to the required pressure, open the back pressure valve and discharge the fluid. Then, inject the fluids of each stage in sequence, such as the polymer system, the displacement agent system, and formation water. Calculate the permeability of the core sample at this flow rate after injecting all the fluids. Adjust the flow rate of the injected fluid and repeat the above steps to calculate the permeability of the core sample at different flow rates.

[0093] The permeability was calculated using Darcy's formula. The Darcy formula used is shown below:

[0094] (4).

[0095] K represents permeability, in dB; Q represents injection flow rate, in cm³. 3 / s; A is the cross-sectional area of ​​the core, in cm². 2 AP is the pressure difference between the two ends of the core, in MPa; μ is the fluid viscosity, in mPa·s; L is the core length, in cm.

[0096] In some embodiments, the type of blockage in the polymer injection well is determined based on the permeability changes obtained in steps (1) to (3). For example, if the permeability change is not significant during the formation water injection process (e.g., the permeability change before and after injection does not exceed 5%), it indicates that there is no water-sensitive injection blockage. If the permeability change is not significant even if the formation water injection rate changes during the formation water injection process (e.g., the permeability change before and after injection flow rate changes does not exceed 5%), then the reservoir does not have water-sensitive, velocity-sensitive, or other injection blockages. If the permeability change is significant during the formation water injection process (e.g., the permeability change before and after injection exceeds 5%), it indicates that there is water-sensitive injection blockage. If the permeability change is significant during the formation water injection process (e.g., the permeability change before and after injection flow rate changes exceeds 5%), then the reservoir has water-sensitive, velocity-sensitive, or other injection blockages.

[0097] Similarly, if the permeability does not change significantly during polymer system injection (e.g., the permeability change before and after injection does not exceed 5%), it indicates that there is no polymer-sensitive injection blockage. If, during polymer system injection, even if the injection rate changes, the permeability does not change significantly (e.g., the permeability change before and after injection flow rate changes does not exceed 5%), then the reservoir does not have polymer-sensitive or polymer system-based rate-sensitive injection blockage. If the permeability changes significantly during polymer system injection (e.g., the permeability change before and after injection exceeds 5%), it indicates that there is polymer-sensitive injection blockage. If, during polymer system injection, changing the injection rate causes a significant change in permeability (e.g., the permeability change before and after injection flow rate changes exceeds 5%), then the reservoir has polymer-sensitive or polymer system-based rate-sensitive injection blockage.

[0098] If the permeability of the modulator system does not change significantly during injection (e.g., the change in permeability before and after injection does not exceed 5%), it indicates that there is no injection-induced blockage due to modulator sensitivity. If, during the injection of the modulator system, even if the injection rate is changed, the permeability does not change significantly (e.g., the change in permeability before and after injection flow rate does not exceed 5%), then the reservoir does not have injection-induced blockage due to modulator sensitivity or the rate sensitivity of the modulator system. If the permeability changes significantly during the injection of the modulator system (e.g., the change in permeability before and after injection exceeds 5%), it indicates that there is injection-induced blockage due to modulator sensitivity. If, during the injection of the modulator system, changing the injection rate causes a significant change in permeability (e.g., the change in permeability before and after injection flow rate exceeds 5%), then the reservoir has injection-induced blockage due to modulator sensitivity or the rate sensitivity of the modulator system.

[0099] Among them, the main control factor of blockage can be determined by using the grey relational analysis method based on the penetration rate obtained in steps (1) to (4).

[0100] To better illustrate the technical solution of this invention, the following uses a polymer injection well Y1 in an oilfield as an example. Its completion type is perforated completion. The development process first involved water injection (5 years), then polymer injection development (3 years), and intermediate conditioning operations. The salinity of the injected formation water was 1500 mg / L, the polymer concentration was 1500 mg / L (apparent viscosity 30 cp), and the viscosity of the conditioning system was 21042 cp. The reservoir lithology is mainly gravelly coarse sandstone and medium sandstone. The grains contain 20%–30% quartz, 20%–40% feldspar, and 20%–40% rock types, mainly intrusive rocks, acidic extrusive rocks, quartzite, and mudstone. The porosity is moderate, mainly between 18% and 25%; the average reservoir permeability is 100 × 10⁻⁶. －3 m 2 ~1000×10 －3 m 2 The primary mineral composition is kaolinite (17%), followed by illite / montmorillonite (5% and 4% respectively). The reservoir temperature is 60℃ and the formation pressure is 14MPa.

[0101] Based on the above-mentioned well completion type, development process and other process parameters and reservoir parameters, and according to the above formula (1), the water injection linear velocity range is 0.1~30mL / min, the polymer injection linear velocity range is 0.5~15mL / min, and the apparent viscosity of the polymer system is 30cp.

[0102] Clay and rock were prepared based on the aforementioned reservoir lithology, and four core sample tubes were formed by mixing and filling them. These four core sample tubes were installed in a constant temperature chamber and connected to corresponding injection and sampling tubes to prepare for the simulation experiment. The temperature was raised to the reservoir temperature to construct a reservoir simulation environment for the experiment.

[0103] (1) The indoor experiment simulated the water injection development process. The sand-filled pipes B, C, and D were closed, and the process was simulated through the sand-filled pipe A. After a long period of water drive, the permeability was calculated by different injection rates and pressures. The results are shown in Table 1 below. It can be seen that the injected water will affect the reservoir under the target reservoir conditions. In terms of the decrease in permeability, it is not enough to completely block the reservoir. However, it is normal for the injection well to be evaluated as an inefficient well.

[0104] Table 1. Permeability at different injection rates

[0105]

[0106] (2) The indoor experiment simulated the polymer injection development process. The sand filling pipe B was opened and the sand filling pipes A, C and D were closed. The real rock core of the mine was sampled to conduct a polymer adsorption and retention experiment to determine the adsorption and retention amount of 1500mg / L polymer to be 0.021mg / g. Then, based on the weight of sand filling pipe C of 740g (pore volume of 147mL), the polymer adsorption concentration of 15.54mg was calculated indoors. Based on this, 0.01L of polymer with a concentration of 1554mg / L was prepared and injected into the polymer system at the injection rate (0.068PV). The permeability change was analyzed.

[0107] Table 2. Permeability at different polymerization rates

[0108]

[0109] (3) Indoor experiments simulated the construction process of water-driven operations. Real core samples from the mine were taken for adsorption and retention experiments to determine the adsorption retention rate as 0.046 mg / g. Then, based on the weight of the sand-filled pipe C (740 g, pore volume 147 mL), the polymer adsorption concentration was calculated to be 34.04 mg. 0.01 L of polymer with a concentration of 34.04 mg / L was prepared and mixed with other additives to form a system. Sand-filled pipe C was opened, and sand-filled pipes A, B, and D were closed. After injecting water into sand-filled pipe C at the highest cumulative injection rate of 2 PV (tested permeability was 1132 mD), subsequent water-driven operations were carried out at the injection rate of the water-driven system, with a subsequent water-driven rate of 1 mL / min. The change in permeability was calculated using Darcy's formula, revealing a 43% decrease in permeability. This indicates that the application of the water-driven system will cause a certain amount of blockage.

[0110] (4) The indoor experiment simulates the construction process before and after multiple stages. According to steps (1) to (3), the target injection rate is selected as 1 mL / min. First, 40 PV of water is injected, then 0.2 PV of polymer is injected, then the regulating agent system is injected, and then water is injected again. The process is simulated. The change of polymer injection pressure is observed, and the blockage is analyzed by calculating the change of permeability using Darcy's formula (see Table 3).

[0111] Table 3. Permeability Changes under Various Process Measures

[0112]

[0113] As shown in Table 3, the water injection process, the polymer injection process, and the regulation and drive process all cause some degree of blockage. Among them, the water injection process causes blockage due to water-sensitive and rate-sensitive effects leading to particle migration; while the polymer process causes blockage by combining with the migrating particles after adsorption and retention; the regulation and drive process is the same. For the comprehensive operation in step (4), the grey relational analysis based on the permeability decrease found that under the existing experimental conditions, the water injection operation accounts for 19.4% of the blockage, the polymer operation accounts for 27.8%, and the regulation and drive operation accounts for 52.8%.

[0114] Secondly, this application also provides an experimental device for determining the type and main controlling factors of polymer injection well blockage, including an injection system, a simulation system, a production collection system, and an information acquisition system; the injection system is used to inject fluid into the simulation system, and the production collection system is used to collect the fluid discharged from the simulation system; the simulation system includes a constant temperature chamber and at least four core sample tubes 22 housed in the constant temperature chamber 21, and the opening and closing of the injection and discharge of fluid in each core sample tube 22 are controlled separately; the information acquisition system collects the parameters of each core sample tube during the simulation process to obtain simulation data.

[0115] The injection system includes an injection pump 11 and fluid containers connected to the injection pump for storing fluid. The fluid containers include a formation water container 12, a polymer system container 13, and a regulating system container 14. The injection pump 11 is connected to each fluid container to provide injection pressure. Each fluid container is connected to an injection tube for communicating with a core sample tube, and each injection tube is equipped with a control valve.

[0116] The output collection system includes a liquid collection container 32 for collecting the fluid discharged from each sample tube and a liquid collection pipe connected to the liquid collection container, and a back pressure valve 31 is provided on each liquid collection pipe.

[0117] In some embodiments, the information acquisition system includes a plurality of pressure sensors 23, and at least two pressure sensors 23 are provided on each core sample tube 22.

[0118] Finally, it should be noted that the above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit them. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some or all of the technical features therein. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of the embodiments of this application.

Claims

1. A method for determining the type and main controlling factors of polymer injection well blockage, characterized in that, Includes the following steps: Obtain the process parameters of the actual construction process of the polymer injection well; obtain the reservoir parameters corresponding to the polymer injection well; Based on the aforementioned process parameters and reservoir parameters, an indoor experimental setup was established. Based on the process parameters and the indoor experimental setup, simulations were performed for water injection development, polymer injection development, regulation and drive operation, and comprehensive operation to obtain simulation data. The type of blockage and the main controlling factors of the polymer injection well were determined using simulation data; The indoor experimental apparatus includes an injection system, a simulation system, a product collection system, and an information acquisition system. The injection system injects fluid into the simulation system, and the product collection system collects the fluid discharged from the simulation system. The simulation system includes a constant temperature and pressure chamber and at least four core sample tubes housed within the chamber, with the injection and discharge of fluid in each core sample tube controlled separately. The information acquisition system collects parameters from each core sample tube during the simulation process to obtain simulation data. The reservoir parameters include actual reservoir particle composition, actual porosity, actual permeability, actual reservoir temperature, and actual reservoir pressure. The core sample tube includes a core sample formed by filling with sand. The sand filling material used in the core sample is selected according to the particle composition of the reservoir. The difference between the permeability and porosity of the core sample and the actual porosity and actual permeability is not higher than 5% of the actual porosity and actual permeability, respectively. The simulations include water injection development simulation, polymer injection development simulation, flow regulation operation simulation, and comprehensive operation simulation, based on the process parameters and the indoor experimental setup. Step (1): Keep the fluid inlet and outlet of one of the core sample tubes open, and close the fluid inlet and outlet of the other core sample tubes. Inject formation water into one of the core sample tubes at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates. Step (2): Keep the fluid inlet and outlet of one core sample tube that has not been injected with the formation water open, and close the fluid inlet and outlet of the other core sample tubes. Inject the polymer system into one core sample tube at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates. Step (3): Keep the fluid inlet and outlet of one core sample tube that has not been injected with the formation water and the polymer system open, and close the fluid inlet and outlet of the other core sample tubes. Inject the modulator system into one core sample tube at different injection rates and flow rates to obtain the permeability of the core sample under different injection rates and flow rates. Step (4): Keep the fluid inlet and outlet of one core sample tube that has not been injected with the formation water, the polymer system, or the modulator system open, and close the fluid inlet and outlet of the other core sample tubes; inject formation water, polymer system, and modulator system into one core sample tube in sequence according to the injection flow rate and injection flow rate in steps (1) to (3); then inject formation water again, and obtain the permeability of the core sample before and after each fluid injection; Specifically, the type of blockage in the polymer injection well is determined based on the permeability changes obtained in steps (1) to (3), as follows: If the permeability changes significantly during formation water injection, it indicates water-sensitive injection blockage; if the permeability changes significantly with changes in the formation water injection rate, the reservoir has water-sensitive or rate-sensitive injection blockage. If the permeability changes significantly during the injection of the polymer system, it indicates that there is polymer-sensitive injection blockage; if the permeability changes significantly when the injection rate of the polymer system is changed during the injection of the polymer system, the reservoir has polymer-sensitive or polymer-sensitive injection blockage. If the permeability changes significantly during the injection of the modulator system, it indicates that there is modulator-sensitive injection blockage; if the permeability changes significantly when the injection rate of the modulator system is changed during the injection of the modulator system, then the reservoir has modulator-sensitive injection blockage or rate-sensitive injection blockage of the modulator system. Based on the permeability obtained in steps (1) to (4), the main control factors of blockage in polymer injection wells are determined using the grey relational analysis method.

2. The method for determining the type of blockage and main controlling factors in polymer injection wells according to claim 1, characterized in that, The process parameters include well completion type, development process, and injected fluid parameters; The well completion type is selected from any one of perforated well completion, open hole well completion, perforated gravel packing well completion, and perforated wire-wound screen packing well completion. The development process includes development stages and injection fluid types. The development stages are selected from any one of water injection development stage, polymer injection development stage, and regulation and drive stage. The injection fluid type includes the type of injection fluid, injection volume, and injection rate. The injected fluid parameters include the fluid's formulation, viscosity, and rheological parameters.

3. The method for determining the type of blockage and main controlling factors in polymer injection wells according to claim 2, characterized in that, The fluid injected in the water injection development simulation is formation water; The fluid injected in the polymer injection development simulation is a polymer system containing polymer; The fluid injected in the simulated controlled-drive operation is a controlled-drive agent system; The flow rate and velocity of the injected formation water in the water injection development simulation are adjusted according to the flow rate and velocity of the formation water calculated using the planar radial flow formula based on the type of injected fluid in the water injection development stage; the formulation, viscosity, and rheological parameters of the injected formation water in the water injection development simulation are obtained based on the parameters of the injected fluid in the water injection development stage. The flow rate and velocity of the polymer system injected in the polymer injection development simulation are adjusted according to the flow rate and velocity of the polymer system calculated using the planar radial flow formula based on the type of injected fluid in the polymer injection development stage; the formulation, viscosity, and rheological parameters of the polymer system injected in the polymer injection development simulation are obtained based on the injected fluid parameters in the polymer injection development stage; The flow rate and velocity of the modulating agent system injected in the modulating operation simulation are adjusted according to the flow rate and velocity of the modulating agent system calculated based on the planar radial flow formula according to the type of injected fluid in the modulating stage; the formulation, viscosity and rheological parameters of the modulating agent system injected in the modulating operation simulation are obtained according to the injected fluid parameters in the modulating stage.

4. The method for determining the type of blockage and main controlling factors in polymer injection wells according to claim 3, characterized in that, The planar radial flow formula is determined based on the planar radial flow model; the planar radial flow model is selected based on the well completion type.

5. The method for determining the type of blockage and main controlling factors in polymer injection wells according to claim 4, characterized in that, When the well completion type is perforated completion, the planar radial flow model used is: When the well completion type is open-hole completion, the planar radial flow model used is: The well completion type is perforated wire-wound screen packing completion, and the planar radial flow model used is: Where Q represents flow rate, in meters (m³). 3 / (m·d); C is the degree of opening, unit: %; h is the total thickness of the oil layer, unit: m; n is the perforation density, unit: number of holes; r is the distance the fluid travels, unit: m; v is the seepage velocity, unit: m / d.

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