Matching optimization method for polymer injection wellbore pipe column

Abstract

The invention provides a polymer injection wellbore tubular column matching optimization method. The polymer injection wellbore tubular column matching optimization method comprises the steps that 1, a rheological property database of polymers used by a polymer injection well is established; 2, factors of influence of the tubular column on the viscosity of the polymer are determined, and an evaluation model of the influence of each factor on the viscosity of the polymer is established; 3, determining a quantification method of the influence of the polymer injection tool and the perforation parameters of the underground tubular column on the viscosity of the polymer; and 4, an enumeration method is adopted to form an optimal polymer injection tubular column and a matched establishment process, and the method is applied to optimal design of wellbore tubular column matching of a field instance well. The polymer injection wellbore tubular column matching optimization method can improve the viscosity of a downhole polymer, improve the displacement effect, or reduce the concentration of the polymer, reduce the cost input and improve the economic benefit of a polymer injection process.

Description

Technical Field

[0001] The invention relates to the technical field of oilfield chemical flooding, and in particular to a method for optimizing the matching of polymer injection wellbore pipe strings. Background Art

[0002] The viscosity characteristics of polymer solutions are the core of the chemical flooding mechanism. The higher the polymer viscosity, the larger the swept volume and the better the oil recovery effect. The most commonly used polymer flooding agent in oil fields is HPAM, but there are still some problems in the field application of HPAM. One of them is that when the polymer is pumped from the ground through the wellbore to the bottom of the well, viscosity loss is inevitable. This is caused by many factors:

[0003] (1) Temperature: As the well depth increases, the temperature rises, which causes the molecular motion of the polymer to accelerate and the interaction force to weaken, thereby reducing the viscosity of the polymer.

[0004] (2) Salinity: A high salinity environment will affect the electrical properties of polymer molecules, weaken the intermolecular interaction force, and thus reduce the polymer viscosity.

[0005] (3) Oxidation: After the polymer is oxidized, the molecular chain structure changes and the viscosity decreases.

[0006] (4) Shear force: During the stirring, pumping and pipeline transportation processes, polymer molecules will be subjected to mechanical shear force, which will cause the molecular chains to break and shorten, reduce their interaction force, and thus lead to a decrease in viscosity.

[0007] How to retain the viscosity of the polymer to the greatest extent during the injection polymerization process has attracted much attention from experts and scholars.

[0008] Patent CN207161746U discloses a flow controller for oil field polymer injection operations, including a valve body, a valve stem and a valve core. A liquid inlet is arranged on the side of the valve body, and a liquid outlet is arranged on the bottom of the valve body. The valve stem is driven to rotate to make the valve core reciprocate along the axis of the valve body, thereby realizing flow regulation, effectively avoiding drastic changes in flow velocity and flow direction of the polymer liquid before and after entering the valve body, thereby avoiding damage to the polymer molecular chain and solving the problem of polymer viscosity loss.

[0009] Patent CN213269860U discloses a polymer injection flow regulating device, which is provided with a shell with an annular boss and a conical rubber tube, so that when the shell and the conical rubber tube move relative to each other, the shape of the conical rubber tube changes, thereby achieving the purpose of regulating the polymer flow, and effectively solving the problem of large polymer viscosity loss when the pressure difference between the inlet and outlet of the flow regulator is large.

[0010] Patent CN111592120A discloses a sulfide ecological inhibitor for reducing the viscosity loss of oilfield polymers, which is prepared from nitrates, nitrites, substrate growth promoters, and trace inorganic regulators. When used to treat oily wastewater in oilfields, it can effectively reduce the sulfide content in the wastewater system and stably exist in the oilfield wastewater system without causing the polymer to break or react, ensuring that the polymer is safe and stable during preparation and injection, and can increase the effective viscosity of the polymer solution.

[0011] Patent CN204380544U discloses a new type of low-shear static mixer for oil fields, which relies on the principles of radial rotation, convection and diffusion to achieve uniform mixing of polymer mother liquor and high-pressure sewage, avoiding the mechanical shear force of conventional mixing units, thereby reducing the polymer viscosity loss caused by the static mixer.

[0012] Although predecessors have a deep understanding of the viscosity loss mechanism during polymer injection and have proposed some optimization methods, the factors for investigating the viscosity loss of polymers during downhole injection are relatively single, and the loss of polymer viscosity due to different injection links (tubing, injection tools and perforation holes) and different temperatures, different pipe materials and different flow rates have not been comprehensively considered to form a tubing string matching optimization method to improve the formation injection effect. For this reason, we invented a new method for optimizing the tubing string matching of polymer injection wellbores to solve the above technical problems. Summary of the invention

[0013] The purpose of the present invention is to provide a method for optimizing the matching of polymer injection wellbore pipe strings for improving the polymer injection effect of the wellbore.

[0014] The purpose of the present invention can be achieved by the following technical measures: a method for optimizing the matching of a polymer injection wellbore pipe string, the method comprising:

[0015] Step 1, establishing a database of rheological properties of polymers used in polymer injection wells;

[0016] Step 2, determining the factors that affect the viscosity of the polymer and establishing an evaluation model for the influence of each factor on the viscosity of the polymer;

[0017] Step 3, determining a quantitative method for the effect of polymer injection tool and downhole string perforation parameters on polymer viscosity;

[0018] Step 4, using the enumeration method to form the optimal polymer injection string and supporting establishment process, which is applied to the optimal design of the wellbore string supporting the field example well.

[0019] The purpose of the present invention can also be achieved by the following technical measures:

[0020] In step 1, the rheological properties of polymers are the basis and prerequisite for optimizing the design. There are many factors that affect the viscosity of polymers, mainly considering the effects of polymer type, concentration, temperature, and shear rate. A rheometer is used to test polymer solutions of different types and concentrations to clarify the effects of temperature and shear rate on polymer viscosity.

[0021] In step 1, based on the polymer viscosity test data at different temperatures and different shear rates, a fitting is performed to obtain a corresponding prediction model and establish a polymer rheological property database.

[0022] In step 1, the fitting formula is:

[0023] μ=Kγ n-1 H(T) (Formula 1)

[0024]

[0025] Where: μ—viscosity, Pa·s; K—consistency coefficient, Pa·s n ;

[0026] n—power law index; γ—shear rate, S -1 ; H(T)—temperature related function;

[0027] α—temperature correlation coefficient; T—polymer temperature, K;

[0028] T0—reference temperature.

[0029] In step 2, the factors affecting the viscosity of the polymer are divided into pipe type, size, material and wellbore fluid temperature, and the influence of each factor on the viscosity of the polymer can be established by establishing a corresponding model.

[0030] In step 2, when establishing the pipe type and size model, the common ones include round pipe and annular pipe, and the viscosity model inside the pipe is as follows:

[0031] a. Circular tube power law fluid viscosity model:

[0032]

[0033] Where: μ—viscosity, Pa·s; K—consistency coefficient, Pa·s n ;

[0034] n—power law index; v—fluid velocity, cm / s;

[0035] dt—inner diameter of the pipe, cm;

[0036] b. Annular tube power law fluid viscosity model:

[0037]

[0038] Where: K—consistency coefficient, Pa·s n ; n—power law index;

[0039] D—inner diameter of outer tube, cm; v—fluid flow rate, cm / s;

[0040] d—inner diameter of inner tube, cm;

[0041] For annular pipe, the large outer diameter of the inner pipe coupling will produce local high shear rate, which must be taken into account when calculating viscosity.

[0042] In step 2, when establishing the material model, in order to reduce pipe corrosion, different pipe materials or coatings are often used, including tungsten alloy coatings, linings and fiberglass pipes. The influence of different pipe materials on polymer viscosity can be determined by two methods. One is to measure the wall roughness of different materials and combine Fluent simulation to realize the influence of different pipe materials on polymer viscosity loss. The other is to conduct on-site long-distance pipeline transportation experiments and take samples to evaluate viscosity loss.

[0043] In step 2, when establishing the wellbore fluid temperature model, different materials, sizes and flow rates will lead to different wellbore fluid temperatures, which will affect the polymer viscosity. The polymer injection wellbore temperature field can be predicted using the following method:

[0044]

[0045] Where: θ—polymer temperature in the pipeline;

[0046] W=G f ·C f —Polymer equivalent weight, G f is the mass flow rate of injected polymer, kg / s, C f —Specific heat of polymer, J / (kg·℃); m—geothermal gradient, ℃ / m;

[0047] k l —Heat transfer coefficient per unit length between the fluid in the oil pipe and the formation, W / (m 2 ℃);

[0048] L—well depth, m; t0—surface temperature, °C; θ0—polymer injection temperature, °C;

[0049] The above model is used to calculate the temperature field of the fluid at the actual well depth scale, and combined with the viscosity-temperature characteristics of the polymer solution, the corresponding viscosity can be predicted.

[0050] In step 3, common downhole polymer injection tools include water distributors, polymer injection sleeves, and screens. After obtaining the parameters of the polymer injection tools, Fluent is used to numerically simulate the corresponding changes in the polymer viscosity of the polymer injection tool, and a quantitative evaluation equation is established.

[0051] In step 3, the downhole tubing perforation parameters, including hole diameter, hole density, and hole arrangement, are used to predict the flow viscosity at the hole using a power law fluid viscosity model in a circular tube.

[0052] In step 3, to prevent the casing perforation section from further reducing the viscosity of the polymer flowing through the downhole string, a critical perforation number parameter, N, is proposed to satisfy:

[0053]

[0054] Where: d1 is the inner diameter of the pipe; d2 is the perforation diameter.

[0055] In step 4, the current wellhead injection parameters, including flow rate, polymer concentration and temperature, are used as boundary conditions, and the possible combinations of pipe diameters, pipe types, pipe materials and configurations of oil well pipe strings are enumerated by the enumeration method. Combined with the basic data of the oil well, including the wellbore structure and geothermal gradient, the models or methods in steps 2 and 3 are used to predict the shear rate and bottom hole temperature of each combination of pipe strings. Combined with the rheological properties of the polymer established in step 1, the bottom hole polymer viscosity of each combination of pipe strings is predicted, and the highest bottom hole viscosity is screened to establish the optimal pipe string combination.

[0056] In step 4, if the bottom hole viscosity obtained by the optimal tubing combination is greater than the allowable bottom hole viscosity, the wellhead polymer viscosity can be reduced and used as a new wellhead boundary condition to repeat the above calculation steps using the established optimal tubing combination until the bottom hole viscosity is slightly greater than the allowable bottom hole viscosity.

[0057] In step 4, if the bottom hole viscosity corresponding to the optimal tubing combination is lower than the allowable bottom hole viscosity, the wellhead polymer viscosity is increased and used as a new wellhead boundary condition to repeat the above calculation steps using the established optimal tubing combination until the bottom hole viscosity is slightly greater than the allowable bottom hole viscosity.

[0058] The method for optimizing the matching of polymer injection wellbore tubing strings in the present invention comprehensively considers various links and multiple factors that affect polymer viscosity during the wellbore polymer injection process, proposes a corresponding quantitative evaluation model or method for polymer viscosity loss, takes reducing bottom hole viscosity loss or lowering polymer injection concentration as the optimization goal, forms an optimal polymer injection tubing string and matching establishment method based on enumeration method, reduces polymer injection costs, and improves the economic benefits of the polymer injection process. BRIEF DESCRIPTION OF THE DRAWINGS

[0059] Figure 1 It is a flow chart of a specific embodiment of the method for optimizing the matching of polymer injection wellbore strings of the present invention;

[0060] Figure 2 It is a rheological curve diagram corresponding to two injection concentration polymers in a specific embodiment of the present invention;

[0061] Figure 3 It is a viscosity-temperature curve diagram corresponding to two injection concentration polymers in a specific embodiment of the present invention;

[0062] Figure 4 It is a schematic diagram of characteristic parameter analysis of viscosity-temperature curve of polymer with two injection concentrations in a specific embodiment of the present invention;

[0063] Figure 5 It is a schematic diagram of the viscosity of the bottom hole polymer solution of different pipe strings and different injection concentrations in an example well in a specific embodiment of the present invention;

[0064] Figure 6 It is a schematic diagram of the viscosity of bottom hole polymer solutions of different tubing strings and different polymer injection concentrations in an example well in another specific embodiment of the present invention. DETAILED DESCRIPTION

[0065] It should be noted that the following detailed descriptions are exemplary and are intended to provide further explanation of the present invention. Unless otherwise specified, all technical and scientific terms used herein have the same meanings as those commonly understood by those skilled in the art to which the present invention belongs.

[0066] It should be noted that the terms used herein are only for describing specific embodiments and are not intended to limit exemplary embodiments according to the present invention. As used herein, unless the context clearly indicates otherwise, the singular form is also intended to include the plural form. In addition, it should be understood that when the terms "comprising" and / or "including" are used in this specification, it indicates the presence of features, steps, operations and / or combinations thereof.

[0067] like Figure 1 As shown, Figure 1 The flowchart of the method for optimizing the matching of the polymer injection wellbore pipe string of the present invention is as follows. The method for optimizing the matching of the polymer injection wellbore pipe string comprises:

[0068] Step 1: Establish a database of rheological properties of polymers used in polymer injection wells to provide a basic database for subsequent optimization and subsequent design;

[0069] Step 2, determine the factors that affect the viscosity of the pipe string, such as pipe type, size, material and wellbore fluid temperature, and establish an evaluation model for the impact of each factor on the viscosity of the polymer;

[0070] Step 3, determining a quantitative method for the effect of polymer injection tool and downhole string perforation parameters on polymer viscosity;

[0071] Step 4, using the enumeration method to form the optimal polymer injection string and supporting establishment process, which is applied to the optimal design of the wellbore string supporting the field example well.

[0072] The following are several specific embodiments of the present invention.

[0073] Example 1

[0074] In a specific embodiment 1 of the present invention, the method for optimizing the matching of a polymer injection wellbore string of the present invention specifically includes:

[0075] Step 1: Establish a database of polymer rheological properties used in polymer injection wells to provide a basic database for subsequent optimization design. Polymer rheological properties are the basis and prerequisite for optimization design. There are many factors that affect polymer viscosity, mainly considering the effects of polymer type, concentration, temperature, and shear rate. For this purpose, a rheometer is needed to test polymer solutions of different types and concentrations to clarify the effects of temperature and shear rate on polymer viscosity.

[0076] Based on the polymer viscosity test data at different temperatures and shear rates, the following equation is used for fitting to obtain the corresponding prediction model and establish a polymer rheological properties database.

[0077] μ=Kγ n-1 H(T) (Formula 1)

[0078]

[0079] Where: K—consistency coefficient, Pa·s n ; n—power law index

[0080] γ—shear rate, S -1 ; H(T)—temperature related function;

[0081] α—temperature correlation coefficient; T—polymer temperature, K;

[0082] T0—reference temperature, generally the default is 298.15K.

[0083] Step 2: Establish the factors that affect the viscosity of the polymer and establish an evaluation model for the influence of each factor on the viscosity of the polymer. The factors that affect the viscosity of the polymer are divided into pipe type, size, material and wellbore fluid temperature. The influence of each factor on the viscosity of the polymer can be established by the following model.

[0084] ① Tube type and size:

[0085] Common ones include round pipes and annular pipes. The viscosity model inside the pipe is as follows:

[0086] b. Circular tube power law fluid viscosity model:

[0087]

[0088] Where: K—consistency coefficient, Pa·s n ; n—power law index;

[0089] v—fluid flow rate, cm / s; dt—pipe inner diameter, cm.

[0090] b. Annular tube power law fluid viscosity model:

[0091]

[0092] Where: K—consistency coefficient, Pa·s n ; n—power law index;

[0093] D—inner diameter of outer tube, cm; v—fluid flow rate, cm / s;

[0094] d—inner diameter of inner tube, cm.

[0095] For annular pipe, the large outer diameter of the inner pipe coupling will produce local high shear rate, which must be taken into account when calculating viscosity.

[0096] ②Material:

[0097] In order to reduce pipe corrosion, different pipe materials or coatings are often used, such as tungsten alloy coating, lining and fiberglass pipe. The influence of different pipe materials on polymer viscosity can be determined by two methods: one is to measure the wall roughness of different materials and use Fluent simulation to realize the influence of different pipe materials on polymer viscosity loss; the other is to conduct on-site long-distance pipeline transportation experiments and sample for viscosity loss evaluation.

[0098] ③Wellbore fluid temperature

[0099] Different materials, sizes and flow rates will lead to different wellbore fluid temperatures, which will affect polymer viscosity. The temperature field of polymer injection wellbore can be predicted by the following method:

[0100]

[0101] Where: W = G f ·C f —Polymer equivalent weight, G f is the mass flow rate of injected polymer, kg / s,

[0102] C f —Specific heat of polymer, J / (kg·℃); m—geothermal gradient, ℃ / m;

[0103] K l —Heat transfer coefficient per unit length between the fluid in the oil pipe and the formation, W / (m 2 ℃);

[0104] L—well depth, m; t0—surface temperature, ℃; θ0—polymer injection temperature, ℃.

[0105] The above model is used to calculate the temperature field of the fluid at the actual well depth scale, and combined with the viscosity-temperature characteristics of the polymer solution, the corresponding viscosity can be predicted.

[0106] Step 3, determine the quantitative method of the effect of polymer injection tool and downhole string perforation parameters on polymer viscosity.

[0107] Common downhole polymer injection tools include water distributors, polymer injection sleeves, screens, etc. After obtaining the parameters of the polymer injection tools, Fluent can be used to numerically simulate the corresponding changes in the viscosity of the polymer flowing through the polymer injection tool and establish a quantitative evaluation equation.

[0108] Downhole tubing perforation parameters include hole diameter, hole density, hole arrangement method, etc. The power law fluid viscosity model in a circular tube (Equation 3) can be used to predict the flow viscosity at the hole.

[0109] In order to prevent the casing perforation section from further reducing the viscosity of the polymer flowing through the downhole pipe string, a critical perforation number parameter, N, is proposed to satisfy:

[0110]

[0111] Where: d1 is the inner diameter of the pipe; d2 is the perforation diameter.

[0112] Step 4, using the enumeration method to form the optimal polymer injection string and supporting establishment process, which is applied to the optimal design of the wellbore string supporting the field example well.

[0113] Considering all the links or factors that affect the viscosity of the bottom hole polymer (such as flow rate, pipe type, pipe diameter, material, temperature, etc.), combined with the models or methods in steps 1, 2, and 3, the bottom hole polymer viscosity can be predicted. With the reduction of bottom hole polymer viscosity loss or wellhead injection polymer concentration as the optimization goal, the enumeration method can be used to form the optimal polymer injection string and the supporting establishment process, as shown in the following example. Figure 1 Shown based on Figure 1 The process shown is used to compile corresponding programs and apply them to the optimal design of the tubing and supporting equipment of the field example well.

[0114] By integrating various links and multiple influencing factors of the wellbore polymer injection process, a corresponding quantitative evaluation model and method for polymer viscosity loss are proposed. With the reduction of bottom hole viscosity loss or wellhead polymer injection concentration as the optimization goal, an optimal polymer injection string and a supporting establishment method based on enumeration method are formed, which can increase bottom hole polymer viscosity, improve displacement effect, or reduce polymer concentration, reduce cost investment, and improve the economic benefit of polymer injection process.

[0115] Example 2

[0116] In a specific embodiment 2 of the present invention, the method of the present invention is described by taking the optimization design of the pipe string matching of a polymer injection well in a certain oil field as an example.

[0117] Reservoir depth 2977m, formation surface temperature 16℃, geothermal gradient 0.024℃ / m, polymer injection flow rate 260m 3 / d, polymer wellhead temperature 10℃, perforation diameter 11mm, total number of perforations 234, polymer injection string combination material is tungsten alloy, string size 73mm, bottom hole permissible viscosity 10.4mPa·s, current polymer injection concentration 2600ppm. String materials include tungsten alloy coated pipe, lined pipe and fiberglass.

[0118] In step 1, the rheological properties of the polymer type used on site at different injection concentrations were established. The polymer solution of corresponding concentration was prepared by using the on-site polymerized wastewater and aerating it. Its rheological properties and viscosity-temperature properties were tested. See attached. Figures 2 to 4 . Figure 2 It is a rheological curve diagram corresponding to two injection concentration polymers in a specific embodiment of the present invention; Figure 3 It is a viscosity-temperature curve diagram corresponding to two injection concentration polymers in a specific embodiment of the present invention; Figure 4 It is a schematic diagram of characteristic parameter analysis of viscosity-temperature curve of polymer with two injection concentrations in a specific embodiment of the present invention.

[0119] In step 1, use

[0120] μ=Kγ n-1 H(T) (Formula 1)

[0121]

[0122] The rheological characteristic parameters of the polymer solution with the corresponding concentration were obtained by fitting analysis, as shown in Table 1. For other concentrations, the linear difference of the relevant parameters between the two concentrations can be used to obtain the parameters.

[0123] Table 1 Polymer solution characteristic parameters

[0124]

[0125] In step 2, it was determined that the main factors affecting polymer viscosity are column size, material, and temperature.

[0126]

[0127] The viscosity of the fluid in the circular column is calculated by

[0128]

[0129] The bottom hole temperature was calculated. Combined with the long-distance transport test experiment, the viscosity loss of the tungsten alloy coating was obtained to be ~2% / km. Combining the shear rate in the circular tube, the bottom hole temperature, (Formula 1) and the data in Table 1, the bottom hole polymer viscosity was predicted, and the injection effect analysis table 2 was obtained.

[0130] Table 2 Analysis of current polymer injection effect

[0131]

[0132] Table 2 shows that the current bottom hole viscosity is higher than the permitted viscosity. The bottom hole viscosity prediction of different pipe strings (tungsten alloy, fiberglass and liner pipe) at the current concentration (2600ppm) is carried out, and the calculation of the corresponding relevant models and known parameters in steps 2 and 3 is repeated. The bottom hole polymer viscosity under different pipe strings is calculated through step 4. The relevant results are shown in the attached Figure 5 As shown in the figure, the tungsten alloy coated pipe is the best pipe among the optional pipes, and the bottom hole polymer viscosity is the highest. And different polymer concentrations can be set on this basis, and steps 2, 3 and 4 can be repeated to optimize the concentration. The relevant results are shown in the attached Figure 5 As shown in the figure, under the premise of ensuring that the bottom hole viscosity exceeds 10.4mPa·s, the use of tungsten alloy coated pipe can reduce the injection concentration to 2444ppm and still meet the bottom hole requirement of 10.4mPa·s.

[0133] Therefore, the optimization suggestion is: use tungsten alloy coated pipes for the three types of pipe strings, which can reduce the polymer injection concentration by about 6% while ensuring the allowable viscosity at the bottom of the well.

[0134] In a specific embodiment of the present invention, the following steps are included:

[0135] 1. Use a rheometer to test polymer solutions of different concentrations to clarify the effects of temperature and shear rate on polymer viscosity. Use the equation form in step 1 to fit the solution, obtain the corresponding prediction model, and establish a polymer rheological properties database.

[0136] 2. The individual effects of tubing size, material, and temperature on viscosity are obtained through the corresponding related models and known parameters in steps 2 and 3. The viscosity of bottom hole polymer can be predicted by considering various links or factors affecting the viscosity of bottom hole polymer in step 4, combined with the models or methods in steps 1, 2, and 3.

[0137] 3. Select a tubing string combination, repeat steps 1, 2, 3, and 4 to obtain the corresponding bottom hole polymer viscosity, select the optimal tubing string, and optimize the polymer concentration under the premise of ensuring the bottom hole permissible viscosity to reduce the injection cost.

[0138] Example 3

[0139] In the specific embodiment 3 of the application of the present invention, the method of the present invention is explained by taking the optimization design of the pipe string matching of a polymer injection well in a certain oil field as an example.

[0140] Reservoir depth 1120m, formation surface temperature 16℃, geothermal gradient 0.039℃ / m, polymer injection flow rate 50m 3 / d, polymer wellhead temperature 10℃, perforation diameter 11mm, total number of perforations 80, polymer injection string combination material is liner pipe, string size inner diameter 55mm, bottom hole permissible viscosity 40.0mPa·s, current polymer injection concentration 2800ppm. String materials include tungsten alloy coated pipe, liner pipe and fiberglass.

[0141] Using the same polymer solution rheological property data and calculation steps as in Example 1, we can obtain the current injection polymerization effect analysis table 3.

[0142] Table 3 Analysis of current polymer injection effect

[0143]

[0144] Table 3 shows that the current bottom hole viscosity is higher than the permitted viscosity. The bottom hole viscosity prediction of different pipe strings (tungsten alloy, fiberglass and liner pipe) at the current concentration (2800ppm) is carried out, and the calculation of the corresponding relevant models and known parameters in steps 2 and 3 is repeated. The bottom hole polymer viscosity under different pipe strings is calculated through step 4. The relevant results are shown in the attached Figure 6 As shown in the figure, the tungsten alloy coated pipe is the best pipe among the optional pipes, and the bottom hole polymer viscosity is the highest, 41.68mPa·s. And different polymer concentrations can be set on this basis, and steps 2, 3 and 4 can be repeated to optimize the concentration. The relevant results are shown in the attached Figure 6 As shown in the figure, under the premise of ensuring that the bottom hole viscosity exceeds 40.0 mPa·s, the use of tungsten alloy coated pipe can reduce the injection concentration to 2744 ppm and still meet the bottom hole requirement of 40.0 mPa·s.

[0145] Therefore, the optimization suggestion is: use tungsten alloy coated pipes for the three types of pipe strings. Under the premise of ensuring the allowable viscosity at the bottom of the well, the polymer injection concentration can be reduced by about 2%.

[0146] In a specific embodiment of the present invention, the following steps are included:

[0147] 1. Use a rheometer to test polymer solutions of different concentrations to clarify the effects of temperature and shear rate on polymer viscosity. Use the equation form in step 1 to fit the solution, obtain the corresponding prediction model, and establish a polymer rheological properties database.

[0148] 2. The individual effects of tubing size, material, and temperature on viscosity are obtained through the corresponding related models and known parameters in steps 2 and 3. The viscosity of bottom hole polymer can be predicted by considering various links or factors affecting the viscosity of bottom hole polymer in step 4, combined with the models or methods in steps 1, 2, and 3.

[0149] 3. Select a tubing string combination, repeat steps 1, 2, 3, and 4 to obtain the corresponding bottom hole polymer viscosity, select the optimal tubing string, and optimize the polymer concentration under the premise of ensuring the bottom hole permissible viscosity to reduce the injection cost.

[0150] Finally, it should be noted that the above is only a preferred embodiment of the present invention and is not intended to limit the present invention. Although the present invention has been described in detail with reference to the aforementioned embodiments, those skilled in the art can still modify the technical solutions recorded in the aforementioned embodiments or replace some of the technical features therein with equivalents. Any modification, equivalent replacement, improvement, etc. made within the spirit and principle of the present invention shall be included in the protection scope of the present invention.

[0151] Except for the technical features described in the specification, all other technical features are known technologies to those skilled in the art.

Claims

1. A method for optimizing the matching of polymer injection wellbore strings, characterized in that: The polymer injection wellbore string matching optimization method includes: Step 1, establishing a database of rheological properties of polymers used in polymer injection wells; Step 2, determining the factors that affect the viscosity of the polymer and establishing an evaluation model for the influence of each factor on the viscosity of the polymer; Step 3, determining a quantitative method for determining the effect of polymer injection tool and downhole string perforation parameters on polymer viscosity; Step 4, using the enumeration method to form the optimal polymer injection string and supporting establishment process, which is applied to the optimal design of the wellbore string supporting the field example well.

2. The method for optimizing the matching of polymer injection wellbore strings according to claim 1, characterized in that: In step 1, the rheological properties of polymers are the basis and prerequisite for optimizing the design. There are many factors that affect the viscosity of polymers, mainly considering the effects of polymer type, concentration, temperature, and shear rate. A rheometer is used to test polymer solutions of different types and concentrations to clarify the effects of temperature and shear rate on polymer viscosity.

3. The method for optimizing the matching of polymer injection wellbore strings according to claim 2, characterized in that: In step 1, based on the polymer viscosity test data at different temperatures and different shear rates, a fitting is performed to obtain a corresponding prediction model and establish a polymer rheological property database.

4. The method for optimizing the matching of polymer injection wellbore strings according to claim 3, characterized in that: In step 1, the fitting formula is: μ = Kγ n-1 H(T) (Equation 1) Where: μ—viscosity, Pa·s; K—consistency coefficient, Pa·s n ; n—power law index; γ—shear rate, S -1 ; H(T)—temperature related function; α—temperature correlation coefficient; T—polymer temperature, K; T0—reference temperature.

5. The method for optimizing the matching of polymer injection wellbore strings according to claim 1, characterized in that: In step 2, the factors affecting the viscosity of the polymer are divided into pipe type, size, material and wellbore fluid temperature, and the influence of each factor on the viscosity of the polymer can be established by establishing a corresponding model.

6. The method for optimizing the matching of polymer injection wellbore strings according to claim 5, characterized in that: In step 2, when establishing the pipe type and size model, the common ones include round pipe and annular pipe, and the viscosity model inside the pipe is as follows: a. Circular tube power law fluid viscosity model: Where: μ—viscosity, Pa·s; K—consistency coefficient, Pa·s n ; n—power law index; v—fluid velocity, cm / s; dt—inner diameter of the pipe, cm; b. Annular tube power law fluid viscosity model: Where: K—consistency coefficient, Pa·s n ; n—power law index; D—inner diameter of outer tube, cm; v—fluid flow rate, cm / s; d—inner diameter of inner tube, cm; For annular pipe, the large outer diameter of the inner pipe coupling will produce local high shear rate, which must be taken into account when calculating viscosity.

7. The method for optimizing the matching of polymer injection wellbore strings according to claim 5, characterized in that: In step 2, when establishing the material model, in order to reduce pipe corrosion, different pipe materials or coatings are often used, including tungsten alloy coatings, linings and fiberglass pipes. The influence of different pipe materials on polymer viscosity can be determined by two methods. One is to measure the wall roughness of different materials and combine Fluent simulation to realize the influence of different pipe materials on polymer viscosity loss. The other is to conduct on-site long-distance pipeline transportation experiments and take samples to evaluate viscosity loss.

8. The method for optimizing the matching of polymer injection wellbore strings according to claim 5, characterized in that: In step 2, when establishing the wellbore fluid temperature model, different materials, sizes and flow rates will lead to different wellbore fluid temperatures, which will affect the polymer viscosity. The polymer injection wellbore temperature field can be predicted using the following method: Where: θ—polymer temperature in the pipeline; W=G f ·C f —Polymer equivalent weight, G f is the mass flow rate of injected polymer, kg / s, C f —Specific heat of polymer, J / (kg·℃); m—geothermal gradient, ℃ / m; k l —Heat transfer coefficient per unit length between the fluid in the oil pipe and the formation, W / (m 2 ℃); L—well depth, m; t0—surface temperature, °C; θ0—polymer injection temperature, °C; The above model is used to calculate the temperature field of the fluid at the actual well depth scale, and combined with the viscosity-temperature characteristics of the polymer solution, the corresponding viscosity can be predicted.

9. The method for optimizing the matching of polymer injection wellbore strings according to claim 1, characterized in that: In step 3, common downhole polymer injection tools include water distributors, polymer injection sleeves, and screens. After obtaining the parameters of the polymer injection tools, Fluent is used to numerically simulate the corresponding changes in the polymer viscosity of the polymer injection tool, and a quantitative evaluation equation is established.

10. The method for optimizing the matching of polymer injection wellbore strings according to claim 1, characterized in that: In step 3, the downhole tubing perforation parameters, including hole diameter, hole density, and hole arrangement, are used to predict the flow viscosity at the hole using a power law fluid viscosity model in a circular tube.

11. The method for optimizing the matching of polymer injection wellbore strings according to claim 10, characterized in that: In step 3, to prevent the casing perforation section from further reducing the viscosity of the polymer flowing through the downhole string, a critical perforation number parameter, N, is proposed to satisfy: Where: d1 is the inner diameter of the pipe; d2 is the perforation diameter.

12. The method for optimizing the matching of polymer injection wellbore strings according to claim 1, characterized in that: In step 4, the current wellhead injection parameters, including flow rate, polymer concentration and temperature, are used as boundary conditions, and the possible combinations of pipe diameters, pipe types, pipe materials and configurations of oil well pipe strings are enumerated by the enumeration method. Combined with the basic data of the oil well, including the wellbore structure and geothermal gradient, the models or methods in steps 2 and 3 are used to predict the shear rate and bottom hole temperature of each combination of pipe strings. Combined with the rheological properties of the polymer established in step 1, the bottom hole polymer viscosity of each combination of pipe strings is predicted, and the highest bottom hole viscosity is screened to establish the optimal pipe string combination.

13. The method for optimizing the matching of polymer injection wellbore strings according to claim 12, characterized in that: In step 4, if the bottom hole viscosity obtained by the optimal tubing combination is greater than the allowable bottom hole viscosity, the wellhead polymer viscosity can be reduced and used as a new wellhead boundary condition to repeat the above calculation steps using the established optimal tubing combination until the bottom hole viscosity is slightly greater than the allowable bottom hole viscosity.

14. The method for optimizing the matching of polymer injection wellbore strings according to claim 12, characterized in that: In step 4, if the bottom hole viscosity corresponding to the optimal tubing combination is lower than the allowable bottom hole viscosity, the wellhead polymer viscosity is increased and used as a new wellhead boundary condition to repeat the above calculation steps using the established optimal tubing combination until the bottom hole viscosity is slightly greater than the allowable bottom hole viscosity.

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