Offshore double extra-high oilfield chemical flooding reservoir working viscosity calculation method

Abstract

The invention discloses an offshore double extra-high oilfield chemical flooding reservoir working viscosity calculation method, which comprises the following steps of: collecting working field data information; based on an oil-water two-phase plane radial flow formula, improving the oil-water two-phase plane radial flow formula by utilizing an oil-water distribution rule of a dual extra-high oil field and a chemical flooding seepage theory to obtain a water and chemical agent two-phase plane radial flow formula; performing calculus simplification processing on a water and chemical agent two-phase plane radial flow formula; a chemical flooding agent reservoir working viscosity calculation formula is obtained through fitting; and the working viscosity of the chemical flooding medicament reservoir is tracked in real time, the rationality of chemical flooding parameters is quantitatively evaluated, and chemical flooding injection-production parameters are optimized in time. The method provided by the invention is convenient in data acquisition, strong in intuition and capable of realizing quantitative evaluation, has the advantages of strong timeliness and high accuracy, and overcomes the defect that the working viscosity of the dual extra-high oilfield chemical flooding reservoir is not researched yet at the present stage.

Description

Technical Field

[0001] The invention belongs to the technical field of chemical flooding for oilfield development, and in particular relates to a method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-super-high oilfield. Background Art

[0002] Double-high-pressure oilfields refer to oilfields with high water content and high recovery rates. At this stage, most reservoirs are severely waterlogged, with low water injection efficiency and dispersed residual oil distribution. Conventional waterflooding methods are difficult to achieve effective economic returns, especially in offshore oilfields. Oilfield development experience shows that chemical flooding technology can significantly improve resource utilization and recovery rates, making it a key method for the efficient development and lifespan extension of onshore double-high-pressure oilfields. The reservoir working viscosity of chemical flooding agents plays a crucial role in their effectiveness, making accurate knowledge of the reservoir working viscosity crucial for chemical flooding oilfield management.

[0003] Currently, there are numerous studies on the surface (wellhead) viscosity of chemical flooding agents used in dual-hypertension oilfields, both domestically and internationally. Most of these studies focus on the impact of various factors on viscosity, but little research has been conducted on the reservoir working viscosity of chemical flooding agents in dual-hypertension oilfields. Currently, empirical methods for calculating reservoir working viscosity in dual-hypertension oilfields are often used. This method uses 1 / 4 to 1 / 3 of the wellhead viscosity as the reservoir working viscosity, but does not consider the impact of other reservoir and wellbore surface processes and chemical system conditions. In practice, due to significant differences in injection technology, system performance, and injection well completion techniques (perforation / openhole completion) between onshore oilfields and offshore oilfields (perforation completion + gravel pack + high-quality screens), the viscosity of chemical solutions at the same concentration is lower than that in onshore oilfields. Therefore, empirical methods for calculating reservoir working viscosity are not applicable to offshore oilfields. Although the reservoir working viscosity can be obtained by injection well flowback sampling, due to the secondary shear during flowback and the difficulty of implementing it in offshore oil fields due to the influence of operating space, flowback sampling cannot be used in a timely and effective manner to calculate the working viscosity of chemical flooding reservoirs in offshore oil fields.

[0004] Therefore, it is necessary to conduct research on reservoir working viscosity for double-ultra-high chemical flooding oil fields to effectively solve the problem of relying solely on experience to evaluate reservoir working viscosity, so as to timely and efficiently guide oil fields to adjust injection and production parameters and evaluate effects. Summary of the Invention

[0005] The problem to be solved by the present invention is to provide a method for calculating the working viscosity of chemical flooding reservoirs in offshore double-ultra-high oil fields. The method is based on the classical two-phase plane radial flow and introduces the chemical flooding seepage theory to improve it. By calculating the working viscosity of the reservoir, the rationality of the chemical flooding injection concentration can be quickly tracked and accurately evaluated. According to the changes in the working viscosity of the chemical flooding reservoir, problems can be discovered in time, and on-site optimization of chemical flooding injection and production parameters and injection technology can be guided to improve the chemical flooding effect.

[0006] In order to solve the above technical problems, the technical solution adopted by the present invention is: a method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field, comprising the following steps:

[0007] S1: Collect data on the work site;

[0008] S2: Based on the oil-water two-phase plane radial flow formula, it is improved by using the oil-water distribution law of double-high oil fields and the chemical flooding seepage theory to obtain the water + chemical agent two-phase plane radial flow formula;

[0009] S3: performing calculus simplification on the water+chemical agent two-phase plane radial flow formula;

[0010] S4: Based on the water + chemical agent two-phase plane radial flow formula, a calculation formula for the chemical flooding agent reservoir working viscosity is obtained by fitting;

[0011] S5: Real-time tracking of chemical flooding agent reservoir working viscosity, quantitative evaluation of chemical flooding parameters rationality, and timely optimization of chemical flooding injection and production parameters.

[0012] Furthermore, in S1, the data include injection parameters, daily well fluid volume, cumulative well fluid volume, reservoir permeability and thickness, tracer interpretation data, liquid absorption profile data, working viscosity of water phase in the reservoir and comprehensive water content of chemical drive well group; the reservoir permeability and thickness are obtained through logging data, the working viscosity of water phase in the reservoir is obtained through PVT experiment, the injection parameters are based on field recorded data, the cumulative well fluid volume is obtained by accumulating the daily well fluid volume, the permeability and thickness of the tracer interpretation data are obtained through interpretation results, the liquid absorption profile data is obtained through field oxygen activation test, and the comprehensive water content of the chemical drive well group is obtained through well group metering data.

[0013] Furthermore, in S2, the near injection end is the chemical flooding affected area, and the far injection end is the water flooding affected area before chemical flooding. The water + chemical flooding agent two-phase plane radial flow formula is shown in Formula 1.

[0014]

[0015] Among them, P wf is the bottom hole pressure, in MPa; Pe is the reservoir static pressure, in MPa; Q is the daily fluid volume entering the well, in m 3 / d;μ p is the chemical flooding agent reservoir working viscosity, in mPa·s; μ w is the working viscosity of the water phase in the formation, in mPa·s; r e is the well spacing, in m; r w is the wellbore radius, in m; r is the sweep radius of the chemical flooding agent, in m; K is the effective permeability of the chemical flooding liquid absorption layer, in 10 -3 μm 2 ; h is the effective thickness of the chemical flooding liquid layer, in meters.

[0016] Furthermore, the S3 includes the following steps:

[0017] S31: Since the sweep radius of chemical flooding agents is difficult to obtain, the formula 1 in S2 is simplified to obtain the formula

[0018] Formula 2 is as follows:

[0019]

[0020] Where: W i is the cumulative amount of fluid injected into the well during chemical flooding, in m 3 ;

[0021] S32: Since the injection well bottom hole pressure and wellhead oil pressure are easy to read, the wellhead oil pressure is introduced to further simplify Formula 2 in S31, and Formula 3 is obtained as follows:

[0022]

[0023] Where: P H is the wellhead oil pressure, in MPa;

[0024] S33: Integrate the differential formula 3 again to obtain the simplified formula 4 as follows:

[0025]

[0026] Furthermore, in S4, according to Formula 4, it is found that the ratio of the chemical flooding wellhead oil pressure / daily well fluid volume is linearly related to the logarithm of the cumulative well fluid volume, and the slope of the straight line segment is a parameter including the working viscosity of the chemical flooding agent reservoir. Let the slope of the straight line segment be A, and the working viscosity of the chemical flooding agent reservoir is obtained as:

[0027] μ p =μ w +108.7016AKh (Formula 5);

[0028] Where: A is the slope of the fitted straight line segment.

[0029] Furthermore, the S4 includes the following steps:

[0030] S41: Calculation lW i value;

[0031] S42: Fitting lW i The relationship is used to obtain the slope A of the straight line segment;

[0032] S43: Calculate reservoir permeability and thickness using logging data, tracer interpretation data, imbibition profile data, and the time-varying relationship between the comprehensive water cut of the chemical flooding well group and reservoir physical properties;

[0033] S44: Using formula 4 and the reservoir permeability and thickness, obtain the chemical flooding agent reservoir working viscosity.

[0034] Furthermore, in S43, when the injection well data do not have the tracer interpretation data and the imbibition profile data, the reservoir permeability and thickness are calculated based on the well logging data and combined with the time-varying relationship of the reservoir physical properties. The calculation formula is as follows:

[0035]

[0036] k c =1.0733+0.0034f w (Formula 7)

[0037] Among them, K i is the logging permeability of the i-th sand control section of the injection well, in units of 10 -3 μm 2 ;h i is the effective logging thickness of the i-th sand control section of the injection well, in m; k c is the current water-bearing reservoir permeability time-varying multiple; f w is the current comprehensive water content; n is the number of sand control sections in the injection well.

[0038] Furthermore, in S43, when the injection well data only include the liquid absorption profile data, calculation is performed based on the well logging permeability, effective thickness, liquid absorption profile data, and the time-varying relationship of reservoir physical properties. The reservoir permeability and thickness calculation formulas are as follows:

[0039]

[0040] Among them, α i The injection well suction profile is used to test the amount of sand control suction; β i is the coefficient of the injection well participating in the calculation of the formation coefficient, and is related to the sand control liquid absorption α i related.

[0041] Furthermore, in S43, when the injection well does not have the liquid absorption profile data but only has the tracer interpretation data, the formation coefficient is calculated based on the original well logging permeability, effective thickness, tracer interpretation data, and the time-varying relationship of reservoir physical properties. The reservoir permeability and thickness calculation formula is as follows:

[0042]

[0043] Among them, K it The permeability of the high permeability layer is explained in data, the unit is 10 -3 μm2;h it The thickness of the high permeability layer is explained in the data, in m.

[0044] Furthermore, in S43, when the injection well has the tracer interpretation data and the imbibition profile data, calculations are performed based on the original well logging permeability, effective thickness, tracer interpretation data, imbibition profile data, and the time-varying relationship of reservoir physical properties. The reservoir permeability and thickness calculation formulas are as follows:

[0045]

[0046] The advantages and positive effects of the present invention are:

[0047] 1. The present invention is based on the classic oil-water two-phase plane radial flow, introduces the oil-water distribution law of double-ultra-high oil fields and the chemical flooding seepage theory for improvement, simplifies and corrects it in combination with actual data, derives the calculation formula for the working viscosity of chemical flooding agent reservoirs, and establishes a new method that can track and evaluate the working viscosity of chemical flooding agent reservoirs and the chemical flooding effect. This method is not only convenient for data acquisition and highly intuitive, and can realize quantitative evaluation, but also has the advantages of strong timeliness and high accuracy, which makes up for the deficiency that there has been no research on the working viscosity of chemical flooding reservoirs in double-ultra-high oil fields at this stage.

[0048] 2. The new method proposed in the present invention for real-time tracking and accurate evaluation of the working viscosity and chemical flooding effect of chemical flooding reservoirs in double-ultra-high oil fields can timely discover problems based on changes in the working viscosity of chemical reservoirs, guide on-site optimization of chemical flooding injection and production parameters, and continuously improve chemical flooding effects, which has broad practical application value. BRIEF DESCRIPTION OF THE DRAWINGS

[0049] Figure 1 It is a schematic diagram of the overall process of an embodiment of the present invention.

[0050] Figure 2 This is a relative position diagram of the oil and water wells in the INJ01 well group according to a specific embodiment of the present invention.

[0051] Figure 3This is a diagram showing the logging interpretation results of each sand control section of the INJ01 well according to a specific embodiment of the present invention.

[0052] Figure 4 This is a tracer-interpreted permeability distribution diagram of the second sand control section of Well INJ01 according to a specific embodiment of the present invention.

[0053] Figure 5 This is a test diagram of the liquid absorption profile of the INJ01 well according to a specific embodiment of the present invention.

[0054] Figure 6 It is a linear diagram of the parameters of the INJ01 well injection chemical according to a specific embodiment of the present invention.

[0055] Figure 7 This is the injection curve of the INJ01 well in a specific embodiment of the present invention. DETAILED DESCRIPTION

[0056] The technical solution of the present invention will be clearly and completely described below with reference to the accompanying drawings. Obviously, the embodiments described are only some embodiments of the present invention, not all embodiments. All other embodiments obtained by ordinary technicians in this field based on the embodiments of the present invention without making any creative efforts shall fall within the scope of protection of the present invention.

[0057] The embodiments of the present invention are further described below with reference to the accompanying drawings:

[0058] like Figure 1 As shown, a method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field includes the following steps.

[0059] S1: Collect on-site data. Specifically, this data includes injection well oil pressure, daily well fluid volume, cumulative well fluid volume, reservoir permeability and thickness, tracer interpretation data, fluid absorption profile data, working viscosity of water in the reservoir, and the comprehensive water content of the chemical flooding well group.

[0060] Among them, the permeability and thickness of the chemical flooding fluid reservoir are obtained through logging data; the working viscosity of the water phase in the reservoir is obtained through PVT experiments; the injection parameters are based on field recorded data; the cumulative well fluid volume is obtained by accumulating the daily well fluid volume; the permeability and thickness of the tracer interpretation data are obtained through the interpretation results; the fluid absorption profile data is obtained through on-site oxygen activation tests; and the comprehensive water cut of the chemical flooding well group is obtained through the well group metering data.

[0061] S2: Based on the oil-water two-phase plane radial flow formula, it is improved by using the oil-water distribution law of double-ultra-high oil fields and the chemical flooding seepage theory to obtain the water+chemical agent two-phase plane radial flow formula.

[0062] Because the oil-water two-phase plane radial flow formula is an important means to evaluate the effect of water flooding development, but the formula is not very adaptable to the chemical flooding injection end of the double-ultra-high oil field, it is therefore improved. Specifically, in view of the characteristics of high water flow near the injection well of the double-ultra-high water flooding development oil field, the remaining oil saturation is close to the residual oil saturation and is dispersed, the oil-water two-phase radial flow is improved. Among them, the near injection end is the chemical flooding affected area, and the far injection end is the water flooding affected area before chemical flooding. The water + chemical flooding agent two-phase plane radial flow formula is shown in Formula 1.

[0063]

[0064] Among them, P wf is the bottom hole pressure, in MPa; P e is the reservoir static pressure, in MPa; Q is the daily fluid volume entering the well, in m 3 / d;μ p is the chemical flooding agent reservoir working viscosity, in mPa·s; μ w is the working viscosity of the water phase in the formation, in mPa·s; r e is the well spacing, in m; r w is the wellbore radius, in m; r is the sweep radius of the chemical flooding agent, in m; K is the effective permeability of the chemical flooding liquid absorption layer, in 10 -3 μm 2 ; h is the effective thickness of the chemical flooding liquid layer, in meters.

[0065] S3: Simplify the water + chemical two-phase plane radial flow formula by calculus. Specifically, S3 includes the following steps:

[0066] S31: Since the sweep radius of chemical flooding agents is difficult to obtain, formula 1 in S2 is simplified to obtain formula 2 as follows:

[0067]

[0068] Where: W i is the cumulative amount of fluid injected into the well during chemical flooding, in m 3 .

[0069] S32: In the injection well of this embodiment, the bottomhole flowing pressure is mainly composed of three parts: wellhead oil pressure, hydrostatic column pressure, and friction pressure loss along the injection well. The hydrostatic column pressure is related to the well depth and is a constant value. The friction pressure loss along the injection well is small and basically a constant value and can be ignored. Although the reservoir pressure is a variable value, it can be regarded as a constant value for oil fields where the reservoir pressure remains high. Therefore, the formula can be further simplified as follows:

[0070]

[0071] Since the injection well bottom hole pressure is related to the wellhead oil pressure and is easy to read, the wellhead oil pressure is introduced to further simplify Formula 2 in S31, and the differentiated Formula 3 is integrated again to obtain the simplified Formula 4 as follows:

[0072]

[0073] Where: P H is the wellhead oil pressure, in MPa.

[0074] S4: Based on the simplified water + chemical agent two-phase plane radial flow formula, the calculation formula for the chemical flooding agent reservoir working viscosity is obtained by fitting.

[0075] According to formula 3, the ratio of chemical flooding wellhead oil pressure to daily well fluid volume is linearly related to the logarithm of the cumulative well fluid volume, and the slope of the straight line segment is a parameter that includes the working viscosity of the chemical flooding agent reservoir. Let the slope of the straight line segment be A, and the working viscosity of the chemical flooding agent reservoir is obtained as:

[0076] μ p =μ w +108.7016AKh (Formula 5);

[0077] Where: A is the slope of the fitted straight line segment.

[0078] Specifically, S4 includes the following steps:

[0079] S41: Calculation lW i value.

[0080] S42: Fitting lW i The relationship is used to obtain the slope A of the straight line segment.

[0081] S43: Calculate reservoir permeability and thickness using logging data, tracer interpretation data, liquid absorption profile data, the time-varying relationship between the comprehensive water cut of the chemical flooding well group and reservoir physical properties. Specifically, the formulas for calculating reservoir permeability and thickness based on different data are as follows:

[0082] When the injection well data do not have the tracer interpretation data and the imbibition profile data, the reservoir permeability and thickness are calculated based on the well logging data and combined with the time-varying physical properties. The calculation formula is as follows:

[0083]

[0084] k c =1.0733+0.0034f w (Formula 7)

[0085] Among them, K iis the logging permeability of the i-th sand control section of the injection well, in units of 10 -3 μm 2 ;h i is the effective logging thickness of the i-th sand control section of the injection well, in m; k c is the current water-bearing reservoir permeability time-varying multiple; f w is the current comprehensive water content; n is the number of sand control sections in the injection well.

[0086] When the injection well data only include the liquid absorption profile data, the calculation is performed based on the well logging permeability, effective thickness, liquid absorption profile data and time-varying physical properties. The calculation formulas for the reservoir permeability and thickness are as follows:

[0087]

[0088] Among them, α i The injection well suction profile is used to test the amount of sand control suction; β i is the coefficient of the injection well participating in the calculation of the formation coefficient, and is related to the sand control liquid absorption α i related.

[0089] When there is no such liquid absorption profile data for the injection well, but only the tracer interpretation data, the formation coefficient is calculated based on the original logging permeability, effective thickness, tracer interpretation data and time-varying physical properties. The reservoir permeability and thickness calculation formulas are as follows:

[0090]

[0091] Among them, K it The permeability of the high permeability layer is explained in data, the unit is 10 -3 μm2;h it The thickness of the high permeability layer is explained in the data, in m.

[0092] When the injection well has the tracer interpretation data and the imbibition profile data, the reservoir permeability and thickness are calculated based on the original well logging permeability, effective thickness, imbibition profile data, tracer interpretation data and time-varying physical properties. The calculation formula is as follows:

[0093]

[0094] S44: Using formula 4 and the reservoir permeability and thickness, the reservoir working viscosity of the chemical flooding agent is obtained.

[0095] S5: Real-time tracking of chemical flooding agent reservoir working viscosity, quantitative evaluation of chemical flooding parameters rationality, timely optimization of chemical flooding injection and production parameters, and improvement of chemical flooding effects.

[0096] It is worth noting that the chemical reservoir working viscosity changes continuously during polymer flooding. The chemical reservoir working viscosity, obtained by fitting the straight line segment after chemical flooding, can be compared with the reservoir design requirements to evaluate the chemical flooding effect. If the reservoir working viscosity after chemical flooding obtained through parameter fitting is higher than the design viscosity, the current injection concentration can be appropriately reduced. Otherwise, the current injection concentration should be increased to ensure that the reservoir working viscosity meets the design requirements.

[0097] The present invention will be described in detail below with reference to specific embodiments:

[0098] The target reservoir conditions involved in this embodiment are as follows: the offshore double-ultra-high oilfield B was put into production in 2000, and has gone through three stages: initial high production, production decline, and stable production. The current recoverable reserves have been recovered to 86.8%, with a comprehensive water cut of 94.9%, making it a double-ultra-high oilfield.

[0099] Since the field's development, formation pressure has only dropped by 1.5 MPa, remaining essentially stable. Platform facilities do not support significant fluid pumping, and potential for infill adjustments is limited. Interlayer inconsistencies are prominent, and remaining oil is dispersed. The well pattern is highly developed, with good injection-production connectivity, meeting the requirements for chemical flooding.

[0100] In April 2023, chemical flooding trial will be started (1 injection and 3 production), and the scale of chemical flooding will be expanded at an appropriate time according to the injection situation. Figure 2 The injection concentration of the INJ01 well is 1200 mg / L, and the design requires that the chemical reservoir working viscosity be greater than 8.0 mPa·s.

[0101] The method for calculating the working viscosity of a chemical flooding reservoir according to this method specifically includes the following steps:

[0102] S1: Collect relevant data of the water injection well INJ01, where the well logging interpretation of INJ01 is as follows: Figure 3 As shown, the tracer interpretation results are as follows Figure 4 As shown in Table 1, the test results of liquid absorption profile are as follows Figure 5 As shown in the figure, the formation water viscosity is 0.6 mPa·s, the injection pressure is read daily by the wellhead pressure gauge, and the daily and cumulative well fluid inflow volumes are read by the wellhead metering device.

[0103] Table 1 Tracer interpretation results before polymer injection in well INJ01

[0104] See agent layer See the well number Thickness of water channel cm <![CDATA[Permeability of water channeling path × 10 -3 μm 2 > By type Second sand control section P01 21.3 3949 Hypertonic layer

[0105] According to the requirements of S2, S3, and S4, the logarithmic relationship between wellhead oil pressure / daily well fluid volume and cumulative well fluid volume is fitted, and the slope of the straight line segment A = 0.0047 is obtained. The fitting results are as follows Figure 6 shown.

[0106] The formation coefficient was calculated by combining the existing tracer and liquid absorption profile test data with the original reservoir physical property data. The details are shown in Table 2.

[0107] Table 2 Formation coefficient calculation results of well INJ01

[0108]

[0109] Combining the formation water viscosity, the slope A of the straight line segment, and the formation coefficient, the chemical reservoir working viscosity is obtained to be 9.72 mPa·s.

[0110] S5: Comparing the calculated chemical reservoir working viscosity with the viscosity required by the scheme design, the current injection viscosity meets and exceeds the scheme design requirements, indicating that the current injection process, downhole tubing technology, injection parameters, etc. are basically consistent with the scheme design. The scale of injection can be gradually expanded according to production needs.

[0111] By analyzing the working viscosity of the chemical reservoir and combining it with the actual injection situation on site, the injection concentration can be appropriately reduced to ensure that the working viscosity of the chemical reservoir is reduced to 8.0mPa·s, thereby improving the injection capacity. Based on the analysis results, in August 2023, the INJ01 well reduced the injection concentration (1200↘1000mg / L), and the injection pressure decreased steadily. The injection curve of the INJ01 well is shown in Figure 2. Figure 7 shown.

[0112] The advantages and positive effects of the present invention are:

[0113] 1. The present invention is based on the classic oil-water two-phase plane radial flow, introduces the oil-water distribution law of double-ultra-high oil fields and the chemical flooding seepage theory for improvement, simplifies and corrects it in combination with actual data, derives the calculation formula for the working viscosity of chemical flooding agent reservoirs, and establishes a new method that can track and evaluate the working viscosity of chemical flooding agent reservoirs and the chemical flooding effect. This method is not only convenient for data acquisition and highly intuitive, and can realize quantitative evaluation, but also has the advantages of strong timeliness and high accuracy, which makes up for the deficiency that there has been no research on the working viscosity of chemical flooding reservoirs in double-ultra-high oil fields at this stage.

[0114] 2. The new method proposed in the present invention for real-time tracking and accurate evaluation of the working viscosity and chemical flooding effect of chemical flooding reservoirs in double-ultra-high oil fields can timely discover problems based on changes in the working viscosity of chemical reservoirs, guide on-site optimization of chemical flooding injection and production parameters, and continuously improve chemical flooding effects, which has broad practical application value.

[0115] The above is a detailed description of an embodiment of the present invention. However, the content described is only a preferred embodiment of the present invention and should not be considered to limit the scope of the present invention. All equivalent changes and improvements made within the scope of the present invention should still fall within the scope of the patent coverage of the present invention.

Claims

1. A method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field, characterized by: The following steps are included: S1: Collect data on the work site; S2: Based on the oil-water two-phase plane radial flow formula, it is improved by using the oil-water distribution law of double-high oil fields and the chemical flooding seepage theory to obtain the water + chemical agent two-phase plane radial flow formula; S3: performing calculus simplification on the water+chemical agent two-phase plane radial flow formula; S4: Based on the water + chemical agent two-phase plane radial flow formula, a calculation formula for the chemical flooding agent reservoir working viscosity is obtained by fitting; S5: Real-time tracking of chemical flooding agent reservoir working viscosity, quantitative evaluation of chemical flooding parameters rationality, and timely optimization of chemical flooding injection and production parameters.

2. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 1, characterized in that: In S1, the data include injection parameters, daily well fluid volume, cumulative well fluid volume, reservoir permeability and thickness, tracer interpretation data, liquid absorption profile data, working viscosity of water phase in the reservoir and comprehensive water content of chemical flooding well group; the reservoir permeability and thickness are obtained through well logging data, the working viscosity of water phase in the reservoir is obtained through PVT experiment, the injection parameters are based on field recorded data, the cumulative well fluid volume is obtained by accumulating the daily well fluid volume, the permeability and thickness of the tracer interpretation data are obtained through interpretation results, the liquid absorption profile data is obtained through field oxygen activation test, and the comprehensive water content of the chemical flooding well group is obtained through well group metering data.

3. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 1 or 2, characterized in that: In S2, the near injection end is the chemical flooding affected area, and the far injection end is the water flooding affected area before chemical flooding. The water + chemical flooding agent two-phase plane radial flow formula is shown in Formula 1. Among them, P wf is the bottom hole pressure, in MPa; P e is the reservoir static pressure, in MPa; Q is the daily fluid volume entering the well, in m 3 / d;μ p is the chemical flooding agent reservoir working viscosity, in mPa·s; μ w is the working viscosity of the water phase in the formation, in mPa·s; r e is the well spacing, in m; r w is the wellbore radius, in m; r is the sweep radius of the chemical flooding agent, in m; K is the effective permeability of the chemical flooding liquid absorption layer, in 10 -3 μm 2 ; h is the effective thickness of the chemical flooding liquid layer, in meters.

4. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 3, characterized in that: Said S3 comprises the following steps, S31: Since the sweep radius of chemical flooding agents is difficult to obtain, formula 1 in S2 is simplified to obtain formula 2 as follows: Where: W i is the cumulative amount of fluid injected into the well during chemical flooding, in m 3 ; S32: Since the injection well bottom hole pressure and wellhead oil pressure are easy to read, the wellhead oil pressure is introduced to further simplify Formula 2 in S31, and Formula 3 is obtained as follows: Where: P H is the wellhead oil pressure, in MPa; S33: Integrate the differential formula 3 again to obtain the simplified formula 4 as follows:

5. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 4, characterized in that: In S4, according to Formula 4, it is found that the ratio of the chemical flooding wellhead oil pressure / daily well fluid volume is linearly related to the logarithm of the cumulative well fluid volume, and the slope of the straight line segment is a parameter including the working viscosity of the chemical flooding agent reservoir. Let the slope of the straight line segment be A, and the working viscosity of the chemical flooding agent reservoir is obtained as: μ p =μ w +108.7016AKh (Formula 5); Where: A is the slope of the fitted straight line segment.

6. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 5, characterized in that: Said S4 comprises the following steps, S41: Calculation lW i value; S42: Fitting lW i The relationship is used to obtain the slope A of the straight line segment; S43: Calculate reservoir permeability and thickness using logging data, tracer interpretation data, imbibition profile data, and the time-varying relationship between the comprehensive water cut of the chemical flooding well group and reservoir physical properties; S44: Using formula 4 and the reservoir permeability and thickness, obtain the chemical flooding agent reservoir working viscosity.

7. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 6, characterized in that: In S43, when the injection well data do not have the tracer interpretation data and the imbibition profile data, the reservoir permeability and thickness are calculated based on the well logging data and combined with the time-varying relationship of the reservoir physical properties. The calculation formula is as follows: k c = 1.0733 + 0.0034f w (Formula 7) Among them, K i is the logging permeability of the i-th sand control section of the injection well, in units of 10 -3 μm 2 ;h i is the effective logging thickness of the i-th sand control section of the injection well, in m; k c is the current water-bearing reservoir permeability time-varying multiple; f w is the current comprehensive water content; n is the number of sand control sections in the injection well.

8. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 6, characterized in that: In S43, when the injection well data only include the liquid absorption profile data, calculation is performed based on the well logging permeability, effective thickness, liquid absorption profile data, and the time-varying relationship of reservoir physical properties. The reservoir permeability and thickness calculation formulas are as follows: Among them, α i The injection well suction profile is used to test the amount of sand control fluid; β i is the coefficient of the injection well participating in the calculation of the formation coefficient, and is related to the sand control liquid absorption α i related.

9. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 6, characterized in that: In S43, when there is no liquid absorption profile data for the injection well and only the tracer interpretation data is available, the formation coefficient is calculated based on the original well logging permeability, effective thickness, tracer interpretation data, and the time-varying relationship of reservoir physical properties. The reservoir permeability and thickness calculation formulas are as follows: Among them, K it The permeability of the high permeability layer is explained in data, the unit is 10 -3 μm2;h it The thickness of the high permeability layer is explained in the data, in m.

10. The method for calculating the working viscosity of a chemical flooding reservoir in an offshore double-high oil field according to claim 6, characterized in that: In S43, when the injection well has the tracer interpretation data and the imbibition profile data, calculations are performed based on the original well logging permeability, effective thickness, tracer interpretation data, imbibition profile data, and the time-varying relationship of reservoir physical properties. The reservoir permeability and thickness calculation formulas are as follows:

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