Calculation method and calculation device for oil-water two-phase flow yield of horizontal well

Abstract

The invention discloses a calculation method and a calculation device for the oil-water two-phase flow yield of a horizontal well. The calculation method for the oil-water two-phase flow yield of the horizontal well comprises the following steps that temperature parameters of a wellbore calculation unit in a target production layer are obtained; calculating a cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit; calculating a water-oil ratio of the wellbore calculation unit; calculating the water saturation of the wellbore calculation unit according to the cooling constant and the water-oil ratio of the wellbore calculation unit; calculating the water saturation of a target production layer section corresponding to the shaft calculation unit according to the water saturation of the shaft calculation unit; and calculating the water yield and the oil yield of the target production layer section according to the water saturation of the target production layer section.

Description

Technical Field

[0001] This application relates to the technical field of oil and gas exploration, and particularly to a method and device for calculating the production of oil-water two-phase flow in horizontal wells. Background Art

[0002] In the oil and gas field, calculating the production of two-phase flow (water and oil) in the production layer is the basis for ensuring the efficient and economical development of oil and gas resources; it can guide the optimization of production strategies and reservoir management, and is crucial for economic benefit evaluation, resource evaluation and reserve calculation, identifying abnormal production data for prevention and emergency measure formulation, and environmental protection.

[0003] Currently, the methods that can obtain the production of oil-water two-phase flow in production wells during the reservoir development stage are mainly production logging method, tracer method, and distributed fiber optic temperature global optimization algorithm.

[0004] However, for highly deviated wells or horizontal wells, the production logging method has high construction difficulty and multiple instrument drags will affect the measurement accuracy; the tracer method samples fluids at the wellhead, with large sampling randomness and the tracer is easily affected by the complex downhole environment, which will affect the measurement accuracy; the distributed fiber optic temperature global optimization algorithm requires many uncertain parameters, with extremely large computational amount, huge time consumption, and low efficiency. Summary of the Invention

[0005] The first aspect of this application provides a method for calculating the production of oil-water two-phase flow in horizontal wells, which includes the following steps

[0006] Obtain the temperature parameters of the wellbore calculation unit in the target production layer;

[0007] Calculate the cooling constant of the wellbore calculation unit according to the temperature parameters of the wellbore calculation unit;

[0008] Calculate the water-oil ratio of the wellbore calculation unit;

[0009] Calculate the water saturation of the wellbore calculation unit according to the cooling constant and water-oil ratio of the wellbore calculation unit;

[0010] Calculate the water saturation of the target production layer section corresponding to the wellbore calculation unit according to the water saturation of the wellbore calculation unit;

[0011] Calculate the water production and oil production of the target production layer section according to the water saturation of the target production layer section.

[0012] In some alternative embodiments of the first aspect of this application, for the aforementioned method for calculating the production of oil-water two-phase flow in horizontal wells, the step of obtaining the temperature parameters of the wellbore calculation unit in the target production layer includes:

[0013] Obtain the temperature parameters of the wellbore calculation unit in the target pay zone by using distributed temperature sensing;

[0014] Select the temperature parameters according to the target sampling distance.

[0015] In some modified embodiments of the first aspect of the present application, for the aforementioned calculation method of the horizontal well oil-water two-phase flow rate, the step of calculating the cooling constant of the wellbore calculation unit according to the temperature parameters of the wellbore calculation unit includes:

[0016] Derive the cooling constant of the wellbore calculation unit according to the temperature parameters of the wellbore calculation unit and Newton's law of cooling;

[0017] T t = T env +(T 0 - T env )·e -k·t ①

[0018] According to formula ①, the calculation formula of the cooling constant k can be derived:

[0019]

[0020] In the formula, T t —The optical fiber temperature at time t after the second well shut-in, °C;

[0021] T env —The ambient temperature after the first long well shut-in reaches stability, °C;

[0022] R 0 --The last optical fiber temperature after opening the well or the first optical fiber temperature after the second well shut-in, °C;

[0023] k--Fluid cooling constant;

[0024] t – The measurement duration of the optical fiber temperature after the second well shut-in, h.

[0025] In some modified embodiments of the first aspect of the present application, for the aforementioned calculation method of the horizontal well oil-water two-phase flow rate, the step of calculating the water-oil ratio of the wellbore calculation unit includes:

[0026] Calculate the water-oil ratio of the wellbore calculation unit by linear interpolation according to the water-oil ratio and cooling constant of the first target point and the second target point;

[0027] Among them, the first target point is the non-producing formation position at the top of the pay zone section, and the second target point is the pure oil point.

[0028] In some modified embodiments of the first aspect of the present application, for the aforementioned calculation method of the horizontal well oil-water two-phase flow production, the step of calculating the water-oil ratio of the wellbore calculation unit by linear interpolation according to the water-oil ratio and cooling constant of the first target point and the second target point includes:

[0029] Define the cooling constant of the first target point as the known number n, and the water-oil ratio as the known number m;

[0030] Define the cooling constant of the second target point as the known number p, and the water-oil ratio as 0;

[0031] According to the linear interpolation formula Derive the water-oil ratio of the wellbore calculation unit

[0032]

[0033] In the formula: m corresponds to K 1 , 0 corresponds to K 2 , n corresponds to X 1 , p corresponds to X 2 , and k is the k in formula ②.

[0034] In some modified embodiments of the first aspect of the present application, for the aforementioned calculation method of the horizontal well oil-water two-phase flow production, the step of calculating the water saturation of the wellbore calculation unit according to the cooling constant and water-oil ratio of the wellbore calculation unit includes:

[0035] Define the water-oil ratio of the wellbore calculation unit

[0036]

[0037] In the formula, -- Water-oil ratio of the wellbore calculation unit;

[0038] V w -- Water volume of the wellbore calculation unit, m 3 ;

[0039] V o -- Oil volume of the wellbore calculation unit, m 3 ;

[0040] According to formula ④, obtain

[0041]

[0042] Define the water saturation of the wellbore calculation unit Combined with formula ⑤, it can be obtained:

[0043]

[0044] In the formula, for

[0045] In some modified embodiments of the first aspect of the present application, for the calculation method of the horizontal well oil-water two-phase flow production, the step of calculating the water saturation of the target pay zone corresponding to the wellbore calculation unit according to the water saturation of the wellbore calculation unit includes:

[0046] Establish a relationship based on the fact that the fluid inflow of water in the wellbore calculation unit is equal to the fluid outflow:

[0047]

[0048] It can be obtained that:

[0049]

[0050] In the formula, S wi -- the water saturation of the fluid flowing into the wellbore calculation unit i from pay zone i, %;

[0051] q i -- the volume of the fluid flowing into the wellbore calculation unit i from pay zone i, m 3 ;

[0052] Q i -- the volume of the fluid flowing out of the wellbore calculation unit i, m 3 ;

[0053] -- the water saturation of the fluid flowing out of the wellbore calculation unit i, %;

[0054] Q i-1 -- the volume of the fluid flowing into the wellbore calculation unit i, m 3 ;

[0055] -- the water saturation of the fluid flowing into the wellbore calculation unit i, %

[0056] In some modified embodiments of the first aspect of the present application, for the calculation method of the horizontal well oil-water two-phase flow production, the step of calculating the water production and oil production of the target pay zone according to the water saturation of the target pay zone includes:

[0057] According to formula ⑧ and the liquid production q i calculate the water production q w , oil production q o :

[0058] q w = q i ·S wi

[0059] q o = q i ·(1 - S wi ) ⑨

[0060] Where: q w -- Water production of pay zone i, m 3 ;

[0061] q o -- Oil production of pay zone i, m 3 .

[0062] The second aspect of the present application provides a device for calculating the production of horizontal well oil - water two - phase flow, which includes an acquisition unit for acquiring the temperature parameter of the wellbore calculation unit in the target pay zone;

[0063] A cooling constant calculation unit for calculating the cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit;

[0064] A water - oil ratio calculation unit for calculating the water - oil ratio of the wellbore calculation unit;

[0065] An aqueous saturation calculation unit for calculating the aqueous saturation corresponding to the target pay zone section of the wellbore calculation unit;

[0066] A target calculation unit for calculating the water production and oil production of the target pay zone section according to the aqueous saturation of the target pay zone section.

[0067] The third aspect of the embodiments of the present application provides a computer device, which includes a memory, a processor, and a computer program stored on the memory, and the processor executes the computer program to implement the foregoing method.

[0068] The fourth aspect of the embodiments of the present application provides a computer - readable storage medium, on which a computer program is stored, and when the computer program is executed by a processor, the foregoing method is implemented.

[0069] The fifth aspect of the embodiments of the present application provides a computer program product, which includes a computer program, and when the computer program is executed by a processor, the foregoing method is implemented.

[0070] Compared with the prior art, the calculation method for the production rate of horizontal well oil-water two-phase flow provided by this application is based on fiber optic sensing technology. According to the differences in the physical properties of oil and water fluids, the heating or cooling rates are different. By using the relationship between the cooling constant and the water-oil ratio, the water saturation of the pay zone is converted and calculated, thereby achieving the purpose of quantitatively calculating the production rate of horizontal well oil-water two-phase flow. The calculation speed is fast, and the resolution and reliability are high. BRIEF DESCRIPTION OF THE DRAWINGS

[0071] By referring to the following detailed description with reference to the accompanying drawings, the above and other objects, features, and advantages of the exemplary embodiments of this application will become easily understandable. In the drawings, several embodiments of this application are shown in an exemplary rather than restrictive manner, and the same or corresponding reference numerals represent the same or corresponding parts, where:

[0072] Figure 1 Schematically shows the flowchart of the calculation method for the production rate of horizontal well oil-water two-phase flow provided by this embodiment;

[0073] Figure 2 Schematically shows the schematic diagram of the wellbore calculation unit;

[0074] Figure 3 Schematically shows the schematic diagram of the oil and water production rates in the pay zone;

[0075] Figure 4 Schematically shows the calculation result diagram of the oil and water production rates of Well B1;

[0076] Figure 5 Schematically shows the comparison of the calculation results of the calculation method and the tracer test method of this embodiment for Well B1;

[0077] Figure 6 Schematically shows the structural schematic diagram of the calculation device for the production rate of horizontal well oil-water two-phase flow provided by the embodiment of this application;

[0078] Explanation of the reference numerals in the drawings: Acquisition unit 1, Cooling constant calculation unit 2, Water-oil ratio calculation unit 3, Water saturation calculation unit 4, Target calculation unit 5. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0079] The following will describe the exemplary embodiments of the present disclosure in more detail with reference to the accompanying drawings. Although the exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments described herein. On the contrary, these embodiments are provided so that the present disclosure can be more thoroughly understood and the scope of the present disclosure can be fully conveyed to those skilled in the art.

[0080] It should be noted that, unless otherwise specified, the technical terms or scientific terms used in this application should have the common meanings understood by technicians in the field to which this application belongs.

[0081] At present, the methods that can obtain the oil-water two-phase flow production of production wells in the reservoir development stage are mainly production logging method, tracer method, and distributed optical fiber temperature global optimization algorithm.

[0082] Production logging is an important technical means to monitor the production of oil-water two-phase flow, mainly including conventional production logging and flow scanning imaging (FSI). Conventional production logging obtains the two-phase flow production of the production layer by measuring parameters such as well temperature, fluid density, water holdup and flow rate, and is widely used in vertical wells or low-angle wells with multi-layer production. However, in highly deviated wells and horizontal wells, due to the limitations of the special wellbore structure and the complexity of horizontal multiphase flow, conventional production logging is difficult to meet the dynamic monitoring needs. For complex well types, flow scanning imaging can achieve high-precision measurement and is suitable for dynamic monitoring of highly deviated wells and horizontal wells, but it has high requirements for the wellbore measurement environment. If the wellbore conditions are not good, coupled with the back-and-forth dragging of the instrument, it will cause large fluid disturbances, which will directly affect the measurement results. In addition, the difficulty of conveying measurement instruments in horizontal wells, the low success rate, and the high cost limit the widespread use of this method in horizontal well output monitoring.

[0083] The tracer method is a technology that monitors the oil-water two-phase flow production of each section of the reservoir by adding specific oil and water phase tracers at the end of the reservoir stage fracturing and transformation, and sampling and laboratory analysis of wellhead fluids during the flowback and production stages. This method is particularly suitable for horizontal wells with long lengths, complex staged fracturing, and high difficulty in inserting production logging instruments. However, the tracer method also has some limitations in practical applications: on the one hand, since each section of the reservoir downhole is in a dynamic production state for a long time, affected by reservoir pressure fluctuations and reservoir heterogeneity, the output distribution is often uneven, which will cause changes in the concentration of oil and water tracers retained in the reservoir, and the sampling and analysis results are highly sensitive to concentration changes, which directly affects the accuracy of the measurement results; on the other hand, there is a large randomness in the wellhead fluid sampling process, which makes it difficult to fully reflect the actual output of the reservoir, further reducing the accuracy of the two-phase flow output measurement. Therefore, the tracer method needs to be combined with other technical means to improve the measurement accuracy and reliability.

[0084] The distributed optical fiber temperature global optimization algorithm constructs a wellbore model by combining parameters such as temperature, pressure, fluid properties, production information, reservoir physical properties, and thermal conductivity. The algorithm continuously adjusts the production and water-oil ratio of each producing layer, inverts the temperature curve and compares it with the measured temperature curve. In theory, the smaller the error, the more accurate the calculated production and oil-water ratio. However, the algorithm requires a large number of input parameters and is extremely sensitive to the division of producing layers. The calculation process is complex and time-consuming, especially for horizontal wells. The low calculation efficiency and large uncertainty in the calculation results are the biggest disadvantages of this method.

[0085] For highly deviated wells and horizontal wells, conventional production logging construction is difficult. The wellbore must be clean, the wellbore must be regular, and the casing must not be deformed. Otherwise, the wellbore may not be properly lowered or the measuring instrument may get stuck. The instrument must be dragged back and forth many times during measurement, which greatly disturbs the horizontal wellbore, affecting the measurement accuracy of the oil-water two-phase flow. The tracer method has a large degree of randomness in wellhead fluid sampling, and the tracer that is chased into the reservoir exists in the high-temperature and high-pressure environment of the well for a long time. The concentration and physical and chemical properties of the tracer may change, which will have a great impact on the measurement accuracy of the oil-water two-phase flow. The global optimization algorithm of distributed optical fiber temperature has a large amount of data calculation, a long time consumption, and too low processing efficiency. For example, the optimization of the production monitoring data of a 1000m horizontal section takes 4-5h at a time, and the heat transfer and thermal conductivity parameters of different rocks are uncertain. It takes a lot of time to adjust the parameters and perform multiple optimizations to meet the requirements.

[0086] The technical solution of the embodiment of the present application is to solve the above technical problems, and the ideas are as follows:

[0087] Example 1

[0088] Reference Figure 1 The method for calculating the oil-water two-phase flow production of a horizontal well provided in the embodiment of the present application may include the following steps:

[0089] S1. Obtaining temperature parameters of a wellbore calculation unit in a target production layer;

[0090] It can be understood that the wellbore calculation unit refers to the basic unit used to simulate and analyze the fluid flow, heat transfer and mechanical behavior inside the wellbore. The wellbore calculation unit can be obtained by dividing the wellbore into multiple small sections or units to perform detailed calculations and analyses on the physical processes in each unit. In this embodiment, the wellbore calculation unit is each small section of the wellbore formed by segmenting the horizontal wellbore according to the target interval or target distance. For example, refer to the attached Figure 2, the horizontal wellbore can be divided into 4 sections, and each section is a wellbore calculation unit. The left side in the figure is the downhole side, the right side is the in-well direction, and the liquid production direction is from right to left in the figure; the length of each wellbore calculation unit can be designed and adjusted according to actual needs. For example, according to the acquisition distance of temperature parameters, it can be, but is not limited to, 0.5 - 1 mm. The temperature parameters can include, but are not limited to, the temperature at a certain moment after shut-in, the temperature after shut-in stabilization, the temperature after well opening, the temperature at a certain moment after secondary shut-in, etc. In this embodiment, the production profile of different depths of the horizontal well can be monitored by means of optical fiber production profile monitoring of the wellbore calculation unit, that is, the real-time detection of the production situation of the formation at different depths of the horizontal well by using optical fiber sensing technology, which can be, but is not limited to, using distributed optical fiber sensing, multimode optical fiber sensing, etc. Under this detection method, the temperature parameters in the horizontal well can be efficiently obtained, and this detection method can be easily understood and implemented by those skilled in the art. For example, refer to the appendix Figure 4 , in the optical fiber temperature waterfall diagram, the abscissa is time and the ordinate is depth. From left to right, it shows the temperature change of a wellbore at a certain depth over time. The temperature value can be obtained corresponding to the target sampling distance, and the target sampling distance here corresponds to the length of the wellbore calculation unit. This method is well-known to those skilled in the art and will not be elaborated here. The target pay zone is the pay zone within the length range of the selected horizontal well.

[0091] S2. Calculate the cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit;

[0092] It can be understood that the cooling constant k of the wellbore calculation unit can be derived according to the temperature parameter of the wellbore calculation unit and Newton's cooling law;

[0093] T t = T env +(T 0 - T env )·e -k·t ①

[0094] According to formula ①, the calculation formula of the cooling constant k can be derived:

[0095]

[0096] In the formula, T t —The optical fiber temperature at time t after secondary shut-in, °C;

[0097] T env —The ambient temperature after the first long shut-in temperature stabilizes, °C;

[0098] T 0 --The last optical fiber temperature after well opening or the first optical fiber temperature after secondary shut-in, °C;

[0099] k--Fluid cooling constant;

[0100] t – The duration of fiber optic temperature measurement after the second well shut-in, h;

[0101] In this embodiment, the fiber optic cable can be lowered into the well and then the first long-term well shut-in can be carried out for a long time. For example, a well shut-in of 10 h can be carried out to obtain T env , and the specific well shut-in time can be set according to experience or adjusted according to real-time temperature detection. For example, when the detected temperature remains unchanged or fluctuates little, it indicates that the downhole environmental temperature has stabilized. At this time, the temperature is the environmental temperature T after the first long well shut-in stabilizes; env ; Then, the well is opened to produce fluid to obtain T 0 . After the well is opened, a fluid containing water and oil is produced outwards in the wellbore. The temperature measured by the fiber optic cable during this process is the flowing temperature. After the flowing temperature stabilizes, the second well shut-in can be carried out. The first temperature data measured after the well shut-in is the last temperature after the well is opened or the first fiber optic temperature after the second well shut-in T 0 ; After the second well shut-in for a period of time, T t is obtained. The duration of the second well shut-in can be designed and adjusted according to actual needs. It can be understood that this duration can be less than the duration of the first long well shut-in to obtain the temperature rise and fall data caused by the influence of fluid physical properties in the wellbore. For example, 3 h. At this time, the temperature is the fiber optic temperature T at the t moment after the second well shut-in. t The duration from the second well shut-in to the acquisition of this temperature point is the duration t of fiber optic temperature measurement after the second well shut-in. Then, it is not difficult to understand that the difference between the first long well shut-in and the second well shut-in described in this embodiment lies in the well shut-in duration, and the order of the well shut-ins is not restricted. The duration of the first long well shut-in is greater than the duration of the second well shut-in.

[0102] S3. Calculate the water-oil ratio of the wellbore calculation unit;

[0103] It can be understood that in this embodiment, the water-oil ratio of the wellbore calculation unit can be calculated by linear interpolation according to the water-oil ratio and cooling constant of the first target point and the second target point;

[0104] Among them, the first target point is the non-producing formation position at the top of the producing formation section, and the second target point is the pure oil point; Referring to Table 1 below, the first target point is located at the non-producing formation position at the top of the producing formation section. No fluid is produced in this position and the well section above it. For example, the top of the transition area between the vertical well and the horizontal well. Therefore, the water-oil ratio at this point is the same as the water-oil ratio measured at the wellhead, denoted as the known quantity m, and the cooling constant k at this point can be calculated by formula ②, denoted as the known quantity n; Correspondingly, if the producing formation produces all oil and the wellbore calculation unit does not contain water, it can be defined as a pure oil point. The water-oil ratio of the pure oil point is equal to 0. For the cooling constant k of the pure oil point, it can be obtained by ground sampling or calculated by the following formula ⑩. Here, it is assumed to be determined as p;

[0105] Table 1 Water-oil ratio Relationship with cooling constant k

[0106]

[0107] Furthermore, in order to calculate the representative formula of, the water-oil ratio in the wellbore can be determined by linear interpolation through the above discussion The calculation formula of:

[0108] The linear interpolation formula is Corresponding to Table 1 above, it can be seen that m corresponds to K 1 , 0 corresponds to K 2 , n corresponds to X 1 , p corresponds to X 2 , then it can be deduced that

[0109]

[0110] The k in this formula is the k in formula ②, and then the quantitative correspondence relationship between the cooling constant corresponding to the wellbore calculation unit and the water-oil ratio is obtained.

[0111] Correspondingly, in this embodiment, the cooling constant k of the pure oil point can also be obtained by the following method:

[0112] According to the conventional definition, the cooling constant k of a fluid is determined by its own physical properties, and its magnitude is related to factors such as the thermophysical properties, surface area, and environmental conditions of the fluid. Under normal temperature and pressure, k can be determined by the experimental method through the following formula:

[0113]

[0114] In the formula, h--the height of the wellbore calculation unit, m;

[0115] A--the surface area of the wellbore calculation unit, m 2 ;

[0116] m--the mass of the fluid contained in the wellbore calculation unit, kg;

[0117] c p --specific heat capacity, J / (kg·K);

[0118] At the same time, for different wellbore calculation units, the surface area A and height h are the same, and the mass m of the contained fluid is basically the same. Therefore, the magnitude of k depends on the magnitude of the specific heat capacity c p The specific heat capacity c of the oil-water two-phase flow in the wellbore p is related to factors such as temperature and pressure, and the values differ greatly, generally about 2-5 times. Therefore, the oil and water can be distinguished according to the magnitude of k. The more water there is, the smaller k is, and the less water there is, the larger k is.

[0119] S4. Calculate the water saturation of the wellbore calculation unit according to the cooling constant and water-oil ratio of the wellbore calculation unit;

[0120] It can be understood that according to the conventional definition, the water-oil ratio of the wellbore calculation unit

[0121]

[0122] In the formula, -- Water-oil ratio of the wellbore calculation unit;

[0123] V w -- Water-containing volume of the wellbore calculation unit, m 3 ;

[0124] V o -- Oil-containing volume of the wellbore calculation unit, m 3 ;

[0125] According to formula ④, we get

[0126]

[0127] Define the water saturation of the wellbore calculation unit as Combined with formula ⑤, we can get:

[0128]

[0129] In the formula, is in formula ③ Furthermore, a quantitative correspondence relationship between the overall water saturation of the wellbore calculation unit and the water-oil ratio is obtained.

[0130] S5. Calculate the water saturation of the target pay zone corresponding to the wellbore calculation unit according to the water saturation of the wellbore calculation unit;

[0131] It can be understood that for the wellbore calculation unit, its final liquid production includes the liquid production from the previous wellbore calculation unit and the liquid production from the target pay zone corresponding to its own wellbore calculation unit. Moreover, for the liquid production of the target pay zone, the fiber optic temperature sensing technology can be used to obtain it, and the final wellbore liquid production can also be obtained through ground data. Then, referring to Appendix Figure 3 , a relational expression can be established based on the fact that the fluid inflow in the wellbore calculation unit is equal to the fluid outflow:

[0132]

[0133] We can get:

[0134]

[0135] In the formula, Swi -- Water saturation of the fluid in the calculation unit i where the production layer i flows into the wellbore, %;

[0136] q i -- Volume of the calculation unit i where the production layer i flows into the wellbore, m 3 ;

[0137] Q i -- Volume of the fluid flowing out of the calculation unit i of the wellbore, m 3 ;

[0138] -- Water saturation of the fluid flowing out of the calculation unit i of the wellbore, %;

[0139] Q i-1 -- Volume of the fluid flowing into the calculation unit i of the wellbore, m 3 ;

[0140] -- Water saturation of the fluid flowing into the calculation unit i of the wellbore, %;

[0141] It is not difficult to understand that and can both be obtained through Equation ⑥ to obtain the quantitative correspondence relationship between S wi and the water-oil ratio.

[0142] S6. Calculate the water production and oil production of the target production layer section according to the water saturation of the target production layer section;

[0143] It can be understood that finally, according to Equation ⑧ and the liquid production rate q i of the target production layer section, calculate the water production rate q w and oil production rate q o of the target production layer section:

[0144] q w = q i ·S wi

[0145] q o = q i (1 - S wi ) ⑨

[0146] Where: q w -- Water production rate of the production layer i, m 3 ;

[0147] q o -- Oil production rate of the production layer i, m 3 ;

[0148] The liquid production rate q iThis is obtained by using the fiber optic temperature sensing technology in step S5 and will not be elaborated here;

[0149] The production formation S of the wellbore calculation unit i wi is related to the wellbore calculation unit i - 1, so the calculation of S wi for a horizontal well is from bottom to top; when i = 1, there is no production at the bottom of the wellbore calculation unit (the pocket part of the production well), and the production rate of the production formation corresponding to the wellbore calculation unit i is equal to the liquid outflow rate of the wellbore calculation unit i. Therefore, Q i-1 = 0, Q 1 = q 1 , and the initial value of the wellbore calculation unit i can be determined by formula ⑧ According to formula ⑧ and the production rate q of the target production formation section i then the water production rate q w and oil production rate q o of the target production formation section can be obtained; further, the water production rate and oil production rate of multiple consecutive production formation sections can be calculated respectively to obtain the water production rate and oil production rate of the entire target production formation, that is, the two - phase flow production rate.

[0150] According to the above, the calculation method of the horizontal well oil - water two - phase flow production rate provided by the embodiment of the present application uses fiber optic temperature sensing and Newton's cooling law to calculate the cooling constant k of the wellbore calculation unit, and quantitatively scales the water - oil ratio of the wellbore calculation unit through k Based on this, the water saturation of the wellbore calculation unit i is obtained and then the water saturation S of the target production formation section corresponding to the wellbore calculation unit i is calculated wi as well as the water production rate and oil production rate in the target production formation, achieving the purpose of quantitatively distinguishing the oil - water two - phase flow production rate in the target production formation by using fiber optic temperature sensing. The embodiment of the present application uses the method of analyzing the wellbore fluid temperature recovery to avoid the problem that the accuracy and multi - solution problem of the results are affected by the values of many unknown parameters of the rocks in the horizontal well section. By calculating the fluid production rate at small intervals through fiber optic temperature sensing, the resolution of the fluid two - phase flow production rate is improved, and the data processing efficiency is increased, significantly enhancing the application and promotion of the continuous oil - filled optical fiber.

[0151] The term "and / or" in this article is merely a description of the association relationship of associated objects, indicating that there can be three relationships. For example, A and / or B is specifically understood as: it can include both A and B at the same time, A can exist alone, or B can exist alone, and it can have any of the above three situations.

[0152] Embodiment 2

[0153] Taking Well B1 as an example, Well B1 is a development well in an oilfield. After three months of fracturing backflow, oil was seen and production started. The open-hole horizontal section is below Point A of this well, and the length of the horizontal well is 713 m (3192 - 4005 m). Above Point A is cased completion. The outer diameter of the production casing is 139.7 mm, and the inner diameter is 118.6 mm. After production, the daily liquid production of this well is 89 m 3 / d, among which the water production is 60.6 m 3 / d, and the oil production is 28.4 m 3 / d. To explore the water and oil production distribution in the horizontal section, fiber-optic production profile monitoring was carried out on this well, that is, fiber-optic sensing technology was implemented for monitoring, and the monitoring system is shown in Table 2.

[0154] Table 2 Fiber-optic Monitoring Log of Well B1

[0155]

[0156] First step, use the backhaul data of fiber-optic sensing to obtain the temperature parameters of each wellbore calculation unit of Well B1;

[0157] Monitoring starts after the production of Well B1 stabilizes. After the flowing temperature stabilizes, it is monitored for 23.8 h and then shut in. Take the last temperature curve of the stable flowing temperature as T 0 ; After shutting in, start the back-temperature monitoring. When obvious back-temperature occurs in the horizontal section, select the temperature curve at the back-temperature time t as T t . In Well B1, obvious back-temperature occurred in the horizontal section at t = 3 h after shutting in. Take the temperature curve at this time as T of Well B1 t ; Take the wellbore temperature after the temperature of this shut-in completely stabilizes as the ambient temperature T env . In Well B1, the temperature stability of the horizontal section was very good at t = 17 h after shutting in. Take the temperature at this time as the ambient temperature T of Well B1 env . In this embodiment, taking the 148th wellbore calculation unit and the 147th wellbore calculation unit as examples, Table 3 below shows the relevant temperature parameters of the two wellbore calculation units;

[0158] Table 3 Example Values and Calculation Results of Cooling Constants at t = 3 after Shutting in Well B1

[0159]

[0160] Substitute the relevant data in Table 3 into Equation ② to calculate the cooling constant k of the wellbore calculation unit;

[0161] For wellbore calculation unit i = 148:

[0162] According to the measurement data T 0 = 133.3557, T t = 132.8485, T env = 131.2237, t = 3, we can get:

[0163]

[0164] For the wellbore calculation unit i = 147, the corresponding value of k is calculated in the same way to be 0.1056.

[0165] Second, calculate the water-oil ratio of the wellbore calculation unit;

[0166] Point A is a point in the non-producing layer section above the horizontal section. Considering the random fluctuation factor of the monitored temperature, the value of point A in this well is any point within 3200 - 3280 m (refer to the stable temperature part above 3300 in the appendix Figure 4 ). No formation fluid enters this area, so the state is stable, including but not limited to the stability of temperature and cooling parameters; at the same time, due to the random fluctuation during temperature measurement, in order to ensure the relative accuracy and reasonableness of the data, in this embodiment, the cooling constant k can be calculated for all wellbore calculation units within the above range according to the above method, and the average value of all k values is taken as the cooling constant of point A. In this embodiment, the k value of point A in Well B1 is 0.12.

[0167] According to the background information of this well, the water production is 60.6 m³ / d and the oil production is 28.4 m³ / d. According to Equation ④, the water-oil ratio at point A can be obtained

[0168] For the pure oil point, its cooling constant can be an empirical value of 0.9 - 1 without experimental analysis. In this embodiment, the cooling constant of the pure oil point is taken as 0.9, and the water-oil ratio is taken as 0.

[0169] The summary of the above parameter values in this step is shown in Table 4:

[0170] Table 4 Water-oil ratio of Well B1 And the cooling constant k

[0171]

[0172] According to Equation ⑤, the water-oil ratio of the wellbore calculation unit can be calculated The calculation results are shown in Table 5.

[0173] Wellbore calculation unit i = 148:

[0174] According to the previous steps, k = 0.0906 is calculated. From Equation ⑤, we can get:

[0175]

[0176] For the wellbore calculation unit i = 147, it is calculated in the same way to get to be 2.1641.

[0177] Step 3: Calculate the water saturation of the wellbore calculation unit according to the cooling constant and water-oil ratio of the wellbore calculation unit;

[0178] Table 5 Example values and results of wellbore water-oil ratio and water saturation of Well B1

[0179]

[0180] For the wellbore calculation unit i = 148, its water saturation can be obtained from the relevant data in Table 5 and Equation ⑥ by the formula:

[0181]

[0182] Similarly, the water saturation of the wellbore calculation unit i = 147 is 0.6840.

[0183] Step 4: Calculate the water saturation of the target pay zone;

[0184] According to the fiber optic sensing analysis, the liquid production qi of the target pay zone corresponding to each sampling point position can be obtained. The liquid production data of the target pay zone corresponding to the two wellbore calculation units provided in this embodiment are shown in Table 6.

[0185] Table 6 Example values and calculation results of oil production and water production of the pay zone calculation unit of Well B1

[0186]

[0187] Calculate the water saturation of the target pay zone according to the data in Table 6 and Equation ⑧;

[0188] Wellbore calculation unit i = 148:

[0189]

[0190] Similarly, the water saturation of the target pay zone corresponding to the wellbore calculation unit i = 147 can be calculated to be 0.7025.

[0191] Step 5: Calculate the water production and oil production of the target pay zone;

[0192] According to the data of the foregoing steps and combined with Equation ⑨, for the wellbore calculation unit i = 148, it can be obtained:

[0193] q w = q i ·S wi = 0.8269×0.7016 = 0.5802

[0194] q o = q i ·(1 - S wi) = 0.8269×(1 - 0.7016) = 0.2467

[0195] Similarly, the water content of the target pay zone corresponding to the wellbore calculation unit i = 147 can be calculated as 0.3877 m 3 / d, and the oil content is 0.1642 m 3 / d.

[0196] Step 6: Comparison of calculation results

[0197] Tracer was injected during the reservoir stimulation stage of Well B1, and tracer sampling and analysis of the production of each section were also carried out during the fiber optic monitoring. The comparison was made in units of fracturing sections.

[0198] Referring to Table 7 and Figure 5 , it is found by comparison that the calculation method provided in this embodiment is basically consistent with the water-oil production evaluation results obtained by the traditional tracer method, indicating that the calculation method provided in this embodiment can fully meet the requirements for calculating the water-oil two-phase flow production of horizontal wells, and can achieve fast calculation speed, high resolution, and high reliability, and is not affected by time or the chemical properties of substances.

[0199] Table 7 Tracer test results and fiber optic calculation statistical results

[0200]

[0201] Example 3

[0202] Furthermore, referring to the specific implementation of the method shown in the appendix Figure 1 , the embodiment of the present application provides a calculation device for the water-oil two-phase flow production of a horizontal well. As shown in Figure 6 , the calculation device includes an acquisition unit 1, a cooling constant calculation unit 2, a water-oil ratio calculation unit 3, a water saturation calculation unit 4, and a target calculation unit 5. The acquisition unit 1 is used to acquire the temperature parameter of the wellbore calculation unit in the target pay zone; the cooling constant calculation unit 2 is used to calculate the cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit; the water-oil ratio calculation unit 3 is used to calculate the water-oil ratio of the wellbore calculation unit; the water saturation unit 4 is used to calculate the water saturation of the wellbore calculation unit and the water saturation of the target pay zone corresponding to the wellbore calculation unit; the target calculation unit 5 is used to calculate the water production and oil production of the target pay zone according to the water saturation of the target pay zone.

[0203] It should be noted that for other corresponding descriptions of each functional unit involved in the calculation device for the water-oil two-phase flow production of a horizontal well provided in the embodiment of the present application, reference can be made to Figure 1 and the corresponding description of Embodiment 1, which will not be elaborated here.

[0204] An embodiment of the present application provides a calculation device for the production of horizontal well oil-water two-phase flow, which includes a processor and a memory. The above-mentioned acquisition unit 1, cooling constant calculation unit 2, water-oil ratio calculation unit 3, water saturation calculation unit 4, and target calculation unit 5 are all stored in the memory as program units, and the processor executes the above program units stored in the memory to implement corresponding functions.

[0205] The processor contains a kernel, and the kernel retrieves the corresponding program units from the memory. One or more kernels can be set, and by adjusting the kernel parameters, aspects suitable for calculating the production of horizontal well oil-water two-phase flow can be obtained from the adjustment.

[0206] In summary, an embodiment of the present application provides a calculation device for the production of horizontal well oil-water two-phase flow. The embodiment of the present application uses fiber optic temperature sensing and Newton's cooling law to calculate the cooling constant k of the wellbore calculation unit, and quantitatively scales the water-oil ratio of the wellbore calculation unit through k. Based on this, the water saturation of the wellbore calculation unit i is obtained. Subsequently, the water saturation S of the target pay zone corresponding to the wellbore calculation unit i is calculated. wi As well as the water production and oil production in the target pay zone, realizing the purpose of quantitatively distinguishing the oil-water two-phase flow production in the target pay zone by using fiber optic temperature sensing.

[0207] An embodiment of the present application provides a computer device, which includes a memory, a processor, and a computer program stored on the memory. The processor executes the computer program to implement the steps of the method for calculating the production of horizontal well oil-water two-phase flow.

[0208] An embodiment of the present application provides a computer-readable storage medium, on which a computer program is stored. When the computer program is executed by a processor, the steps of the method for calculating the production of horizontal well oil-water two-phase flow are implemented.

[0209] An embodiment of the present application also provides a computer program product, which includes a computer program. When the computer program is executed by a processor, the steps of the method for calculating the production of horizontal well oil-water two-phase flow are implemented.

[0210] The present application is described with reference to the flowcharts and / or block diagrams of the methods, devices (systems), and computer program products according to the embodiments of the present application. It should be understood that each process and / or block in the flowchart and / or block diagram, as well as the combination of processes and / or blocks in the flowchart and / or block diagram, can be implemented by computer program instructions. These computer program instructions can be provided to the processor of a general-purpose computer, a special-purpose computer, an embedded processor, or other programmable data processing devices to generate a machine, so that the instructions executed by the processor of the computer or other programmable data processing devices generate for implementing in the process Figure 1 each process or multiple processes and / or blocksFigure 1 means for the functions specified in one or more boxes.

[0211] In a typical configuration, a device includes one or more processors (CPUs), memory, and a bus. The device may also include an input / output interface, a network interface, etc.

[0212] Memory may include non-permanent memory in the form of computer-readable media, random access memory (RAM) and / or non-volatile memory such as read-only memory (ROM) or flash memory (flash RAM), and the memory includes at least one storage chip. Memory is an example of computer-readable media.

[0213] Computer-readable media includes permanent and non-permanent, removable and non-removable media and can store information by any method or technology. The information can be computer-readable instructions, data structures, program modules, or other data. Examples of computer storage media include, but are not limited to, phase change memory (PRAM), static random access memory (SRAM), dynamic random access memory (DRAM), other types of random access memory (RAM), read-only memory (ROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other memory technologies, compact disc read-only memory (CD-ROM), digital versatile disc (DVD) or other optical storage, magnetic cassettes, magnetic tape magnetic disk storage or other magnetic storage devices, or any other non-transmission media that can be used to store information that can be accessed by a computing device. As defined herein, computer-readable media does not include transitory media such as modulated data signals and carrier waves.

[0214] It should also be noted that the term "comprising", "including" or any other variation thereof is intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements does not include only those elements but also other elements not expressly listed, or elements that are inherent to such process, method, article, or apparatus. Without further limitation, an element defined by the statement "comprising an..." does not exclude the presence of additional identical elements in the process, method, article, or apparatus that comprises the element.

[0215] Those skilled in the art should understand that the embodiments of the present application can be provided as a method, a system, or a computer program product. Therefore, the present application can take the form of a complete hardware embodiment, a complete software embodiment, or an embodiment combining software and hardware aspects. Moreover, the present application can take the form of a computer program product implemented on one or more computer-usable storage media (including but not limited to disk storage, CD-ROM, optical storage, etc.) containing computer-usable program code.

[0216] As described above, the above is only the specific implementation manner of the present application, but the protection scope of the present application is not limited thereto. Any person skilled in the art can easily think of changes or substitutions within the technical scope disclosed in the present application, and all of them should be covered by the protection scope of the present application. Therefore, the protection scope of the present application should be subject to the protection scope of the claims.

Claims

1. A method for calculating the production of oil-water two-phase flow in a horizontal well, characterized in that: It includes the following steps: Obtain temperature parameters of the wellbore calculation unit in the target production layer; Calculating a cooling constant of the wellbore calculation unit according to a temperature parameter of the wellbore calculation unit; Calculating the water-oil ratio of the wellbore calculation unit; Calculating the water saturation of the wellbore calculation unit according to the cooling constant and the water-oil ratio of the wellbore calculation unit; Calculating the water saturation of the target production layer section corresponding to the wellbore calculation unit according to the water saturation of the wellbore calculation unit; The water production and oil production of the target production layer section are calculated according to the water saturation of the target production layer section.

2. The method for calculating the oil-water two-phase flow production of a horizontal well according to claim 1, characterized in that: The step of obtaining the temperature parameter of the wellbore calculation unit in the target production layer includes: Use distributed temperature sensors to obtain temperature parameters of wellbore computing units in target production layers; The temperature parameters are selected according to the target sampling distance.

3. The method for calculating the production of oil-water two-phase flow in a horizontal well according to claim 1, characterized in that: The step of calculating the cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit comprises: Derivation of a cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit and Newton's cooling law; T t =T env +(T0-T env )·e -k·t ① According to formula ①, the calculation formula of the cooling constant k can be derived: Where, T t —Fiber temperature at time t after the second shut-in, °C; T env —Ambient temperature after the first long shut-in temperature stabilizes, °C; T0 - the last fiber temperature after well opening or the first fiber temperature after second well closing, °C; k--fluid cooling constant; t – Fiber optic temperature measurement duration after the second well shut-in, h.

4. The method for calculating the oil-water two-phase flow production of a horizontal well according to claim 3, characterized in that: The step of calculating the water-oil ratio of the wellbore calculation unit comprises: Calculate the water-oil ratio of the wellbore calculation unit by linear interpolation method according to the water-oil ratio and cooling constant of the first target point and the second target point; Among them, the first target point is the non-producing layer position at the top of the producing layer section, and the second target point is the pure oil point.

5. The method for calculating the oil-water two-phase flow production of a horizontal well according to claim 4, characterized in that: The step of calculating the water-oil ratio of the wellbore calculation unit by linear interpolation method according to the water-oil ratio of the first target point and the second target point and the cooling constant includes: Define the cooling constant of the first target point as the known number n, water-oil ratio is a known number m; Define the cooling constant of the second target point as the known number p, water-oil ratio is 0; According to the linear interpolation formula: Derivation of the water-oil ratio of the wellbore calculation unit In the formula: m corresponds to K1, 0 corresponds to K2, n corresponds to X1, p corresponds to X2, and k is the k in formula ②.

6. The method for calculating the oil-water two-phase flow production of a horizontal well according to claim 5, characterized in that: The step of calculating the water saturation of the wellbore calculation unit according to the cooling constant and the water-oil ratio of the wellbore calculation unit comprises: Define the water-oil ratio of the wellbore calculation unit In the formula, --Water-oil ratio of wellbore calculation unit; V w --Water-containing volume of wellbore calculation unit, m 3 ; V o --Oil-bearing volume of wellbore calculation unit, m 3 ; According to formula ④, we can get Define the water saturation of the wellbore calculation unit Combining formula ⑤, we can get: In the formula, is the 7. The method for calculating the oil-water two-phase flow production of a horizontal well according to claim 6, characterized in that: The step of calculating the water saturation of the target production layer section corresponding to the wellbore calculation unit according to the water saturation of the wellbore calculation unit comprises: The relationship is established based on the fluid inflow in the wellbore calculation unit being equal to the fluid outflow: We can get: In the formula, S wi --water saturation of fluid flowing into wellbore calculation unit i from production layer i, %; q i --The volume of production layer i flowing into wellbore calculation unit i, m 3 ; Q i --The volume of fluid flowing out of wellbore calculation unit i, m 3 ; --water saturation of the fluid flowing out of wellbore calculation unit i, %; Q i-1 --The volume of fluid flowing into wellbore calculation unit i, m 3 ; --Water saturation of fluid flowing into wellbore calculation unit i, %.

8. The method for calculating the oil-water two-phase flow production of a horizontal well according to claim 7, characterized in that: The step of calculating the water production and oil production of the target production layer section according to the water saturation of the target production layer section comprises: According to formula ⑧ and the production layer liquid production q i Calculate the water production of the production layer q w , oil production q o : q w =q i ·S wi q o =q i ·(1-S wi ) ⑨ Where: q w --water production of production layer i, m 3 ; q o --Oil production of production layer i, m 3 .

9. A device for calculating the production of oil-water two-phase flow in a horizontal well, characterized in that: It includes: An acquisition unit, the acquisition unit is used to acquire temperature parameters of a wellbore calculation unit in a target production layer; a cooling constant calculation unit, the cooling constant calculation unit being used to calculate a cooling constant of the wellbore calculation unit according to a temperature parameter of the wellbore calculation unit; A water-oil ratio calculation unit, the water-oil ratio calculation unit is used to calculate the water-oil ratio of the wellbore calculation unit; A water saturation calculation unit, the water saturation unit is used to calculate the water saturation of the wellbore calculation unit and the water saturation of the target production layer section corresponding to the wellbore calculation unit; A target calculation unit is used to calculate the water production and oil production of the target production layer segment according to the water saturation of the target production layer segment.

10. A computer device, characterized in that: It includes: A memory, a processor and a computer program stored in the memory, wherein the processor executes the computer program to implement the method according to any one of claims 1 to 8.

11. A computer-readable storage medium, characterized in that: The computer-readable storage medium stores a computer program, and when the computer program is executed by a processor, the method according to any one of claims 1 to 8 is implemented.

12. A computer program product, characterized in that It includes: A computer program, which, when executed by a processor, implements the method according to any one of claims 1 to 8.

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