Method and device for calculating production of horizontal well oil-water two-phase flow

Abstract

The application discloses a method and device for calculating the yield of oil-water two-phase flow in a horizontal well. The method comprises the following steps: obtaining the temperature parameter of a wellbore calculation unit in a target pay zone; calculating the cooling constant of the wellbore calculation unit according to the 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 a target pay zone section corresponding to the wellbore calculation unit according to the water saturation of the wellbore calculation unit; and calculating the water yield and oil yield of the target pay zone section according to the water saturation of the target pay zone section.

Description

Technical Field

[0001] This application relates to the field of oil and gas exploration technology, and in particular to a method and apparatus for calculating the production of oil-water two-phase flow in horizontal wells. Background Technology

[0002] In the oil and gas sector, calculating the production of two-phase flows (water and oil) in producing formations is fundamental to 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 assessment, resource assessment and reserve calculation, identification of abnormal production data for prevention and emergency response measures, and environmental protection.

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

[0004] However, for highly deviated or horizontal wells, production logging is difficult to implement and the repeated instrument dragging can affect measurement accuracy; the tracer method involves sampling fluid at the wellhead, which is highly random and the tracer can easily affect measurement accuracy under the influence of the complex downhole environment; the distributed fiber optic temperature global optimization algorithm requires many uncertain parameters, has a huge computational load, is very time-consuming, and is inefficient. Summary of the Invention

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

[0006] Obtain the temperature parameters of the wellbore calculation unit within the target producing formation;

[0007] The cooling constant of the wellbore calculation unit is calculated based on the temperature parameters of the wellbore calculation unit.

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

[0009] The water saturation of the wellbore calculation unit is calculated based on the cooling constant and water-oil ratio of the wellbore calculation unit.

[0010] Calculate the water saturation of the target producing zone corresponding to the wellbore calculation unit based on the water saturation of the wellbore calculation unit;

[0011] The water production and oil production of the target producing zone are calculated based on the water saturation of the target producing zone.

[0012] In some modified embodiments of the first aspect of this application, the aforementioned method for calculating the production rate of horizontal well oil-water two-phase flow, wherein the step of obtaining the temperature parameters of the wellbore calculation unit within the target production formation includes:

[0013] Temperature parameters of the wellbore computing unit within the target production formation are obtained using distributed temperature sensors.

[0014] Temperature parameters are selected based on the target sampling distance.

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

[0016] The cooling constant of the wellbore calculation unit is derived based on the temperature parameters of the wellbore calculation unit and Newton's law of cooling.

[0017] ①

[0018] The cooling constant can be derived from equation ①. The calculation formula is as follows:

[0019] ②

[0020] In the formula, in the formula, —After the second well shut-in The temperature of the optical fiber at any given time, in °C;

[0021] —Ambient temperature after the initial long-term shut-in temperature stabilizes, °C;

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

[0023] --Fluid cooling constant;

[0024] – Duration of fiber optic temperature measurement after secondary well shut-in, h.

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

[0026] The water-oil ratio of the wellbore calculation unit is calculated using linear interpolation based on the water-oil ratio and cooling constant of the first and second target points.

[0027] The first target point is the non-producing layer at the top of the producing layer, and the second target point is the pure oil point.

[0028] In some modified embodiments of the first aspect of this application, the aforementioned method for calculating the production rate of horizontal well oil-water two-phase flow includes the step of calculating the water-oil ratio of the wellbore calculation unit using linear interpolation based on the water-oil ratio and cooling constant at the first and second target points.

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

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

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

[0032] ③

[0033] In the formula: m corresponds to 0 corresponds to n corresponds to p corresponds to X is k in equation ②.

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

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

[0036] ④

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

[0038] --Water volume of the wellbore calculation unit ;

[0039] --Oil-bearing volume of the wellbore calculation unit ;

[0040] According to equation ④, we obtain

[0041] ⑤

[0042] Define the water saturation of the wellbore calculation unit. Combining equation ⑤, we can obtain:

[0043] ⑥

[0044] In the formula, For equation ③ .

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

[0046] The relationship is established based on the fact that the inflow rate of water within the wellbore calculation unit equals the outflow rate:

[0047] ⑦

[0048] We can obtain:

[0049] ⑧

[0050] In the formula, --Water saturation of the fluid flowing from production layer i into wellbore calculation unit i, %;

[0051] --The volume of the producing layer i flowing into the wellbore calculation unit i. ;

[0052] --The fluid volume flowing out of wellbore calculation unit i ;

[0053] --Water saturation of the fluid in wellbore calculation unit i, %;

[0054] --The volume of fluid flowing into wellbore calculation unit i ;

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

[0056] In some modified embodiments of the first aspect of this application, the aforementioned method for calculating the production rate of horizontal well oil-water two-phase flow includes the step of calculating the water production and oil production of the target producing zone based on the water saturation of the target producing zone, comprising:

[0057] Based on equation ⑧ and the liquid production of the producing layer Calculate the water production of the production layer Oil production :

[0058] 9

[0059] in: --Water production of product layer i ;

[0060] --Oil production of layer i .

[0061] A second aspect of this application provides a device for calculating the production rate of oil-water two-phase flow in a horizontal well, comprising:

[0062] The acquisition unit is used to acquire the temperature parameters of the wellbore calculation unit within the target producing formation;

[0063] A cooling constant calculation unit is used to calculate the cooling constant of the wellbore calculation unit based on the temperature parameters of the wellbore calculation unit.

[0064] A water-oil ratio calculation unit, wherein the water-oil ratio calculation unit is used to calculate the water-oil ratio of the wellbore calculation unit;

[0065] A water saturation calculation unit is used to calculate the water saturation of the target producing section of the wellbore calculation unit corresponding to the water saturation of the wellbore calculation unit.

[0066] The target calculation unit is used to calculate the water production and oil production of the target producing zone based on the water saturation of the target producing zone.

[0067] A third aspect of this application provides a computer device including a memory, a processor, and a computer program stored in the memory, wherein the processor executes the computer program to implement the aforementioned method.

[0068] A fourth aspect of this application provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements the aforementioned method.

[0069] A fifth aspect of this application provides a computer program product, which includes a computer program that, when executed by a processing unit, implements the aforementioned method.

[0070] Compared with existing technologies, the method for calculating the production rate of horizontal well oil-water two-phase flow provided in this application is based on fiber optic sensing technology. It takes advantage of the difference in the physical properties of oil and water to cause different heating or cooling rates, and uses the relationship between the cooling constant and the water-oil ratio to calculate the water saturation of the producing layer, thereby achieving the purpose of quantitatively calculating the production rate of horizontal well oil-water two-phase flow. It has fast calculation speed, high resolution and high reliability. Attached Figure Description

[0071] The above and other objects, features, and advantages of exemplary embodiments of this application will become readily understood by reading the following detailed description with reference to the accompanying drawings. In the drawings, several embodiments of this application are illustrated by way of example and not limitation, with the same or corresponding reference numerals denoteing the same or corresponding parts, wherein:

[0072] Figure 1 A flowchart illustrating the method for calculating the production rate of horizontal well oil-water two-phase flow provided in this embodiment is shown schematically.

[0073] Figure 2 A schematic diagram of the wellbore calculation unit is shown.

[0074] Figure 3 A schematic diagram illustrating the oil and water production of the producing layer is shown.

[0075] Figure 4 The diagram illustrates the calculated oil and water production results for well B1.

[0076] Figure 5 The illustration schematically shows a comparison of the calculation results of the calculation method and the tracer testing method of this embodiment for well B1;

[0077] Figure 6 A schematic diagram of the structure of the calculation device for the production rate of horizontal well oil-water two-phase flow provided in an embodiment of this application is shown.

[0078] The attached figures are labeled as follows: Unit 1 for data acquisition, Unit 2 for cooling constant calculation, Unit 3 for water-oil ratio calculation, Unit 4 for water saturation calculation, and Unit 5 for target calculation. Detailed Implementation

[0079] Exemplary embodiments of the present disclosure will now be described in more detail with reference to the accompanying drawings. While exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure may be implemented in various forms and should not be limited to the embodiments set forth herein. Rather, these embodiments are provided so that this disclosure will be thorough and complete, and will fully convey the scope of the disclosure to those skilled in the art.

[0080] It should be noted that, unless otherwise stated, the technical or scientific terms used in this application shall have the ordinary meaning as understood by one of ordinary skill in the art to which this application pertains.

[0081] Currently, the main methods for obtaining the production rate of oil-water two-phase flow in production wells during the reservoir development stage are production logging, tracer method, and distributed fiber optic temperature global optimization algorithm.

[0082] Production logging is a crucial technique for monitoring oil-water two-phase flow production, primarily encompassing conventional production logging and flow scanning imaging (FSI). Conventional production logging measures parameters such as well temperature, fluid density, water holdup, and flow rate to determine the two-phase flow production of the producing formation, and is widely used in vertical or low-angle wells with multi-stage production. However, in highly deviated and horizontal wells, the unique well structure and the complexity of horizontal multiphase flows limit the dynamic monitoring capabilities of conventional production logging. For complex well configurations, flow scanning imaging can achieve high-precision measurements and is suitable for dynamic monitoring of highly deviated and horizontal wells. However, it requires a favorable wellbore environment; poor wellbore conditions, coupled with the back-and-forth movement of the instrument, can cause significant fluid disturbance, directly impacting the measurement results. Furthermore, the difficulty, low success rate, and high cost of transporting measuring instruments in horizontal wells limit its widespread application in production monitoring.

[0083] The tracer method is a technique that involves adding specific oil and water phase tracers at the end of staged fracturing of a reservoir. During the flowback and production stages, wellhead fluid sampling and laboratory analysis are used to monitor the production of the two-phase flow in each section of the reservoir. This method is particularly suitable for long horizontal wells with complex staged fracturing and where running production logging instruments is difficult. However, the tracer method also has some limitations in practical applications: Firstly, because the downhole reservoir sections are in a dynamic production state for a long time, the production distribution is often uneven due to reservoir pressure fluctuations and reservoir heterogeneity. This leads to changes in the concentration of oil and water tracers remaining in the reservoir, and the sampling and analysis results are highly sensitive to concentration changes, directly affecting the accuracy of the measurement results. Secondly, the wellhead fluid sampling process has a large degree of randomness, making it difficult to fully reflect the true production of the reservoir, further reducing the accuracy of the two-phase flow production measurement. Therefore, the tracer method needs to be combined with other technical means to improve measurement accuracy and reliability.

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

[0085] For highly deviated and horizontal wells, conventional production logging operations are quite challenging. The wellbore must be clean, the borehole regular, and the casing undeformed; otherwise, issues such as incomplete insertion or instrument jamming may occur. Repeated back-and-forth instrument dragging during measurement causes significant disturbance to the horizontal wellbore, affecting the accuracy of oil-water two-phase flow measurements. Tracer-based wellhead fluid sampling is highly random, and the tracers entering the reservoir exist for extended periods in the high-temperature, high-pressure downhole environment. The concentration and physicochemical properties of the tracers may change, significantly impacting the accuracy of oil-water two-phase flow measurements. Distributed fiber optic temperature global optimization algorithms suffer from large computational loads, long processing times, and low efficiency. For example, optimizing production monitoring data for a 1000m horizontal section takes 4-5 hours, and the heat transfer and conductivity parameters of different rocks are uncertain, requiring extensive parameter adjustments, trial calculations, and multiple optimizations to meet requirements.

[0086] The technical solution of this application embodiment is to solve the above-mentioned technical problems, and the idea is as follows:

[0087] Example 1

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

[0089] S1. Obtain the temperature parameters of the wellbore calculation unit within the target producing formation;

[0090] It is understandable that a wellbore calculation unit refers to the basic unit used to simulate and analyze fluid flow, heat transfer, and mechanical behavior inside a wellbore. A wellbore calculation unit can be created by dividing the wellbore into multiple small segments or units to perform detailed calculations and analyses of the physical processes within each unit. In this embodiment, the wellbore calculation unit is each small segment of the wellbore formed by dividing the horizontal wellbore into segments according to target intervals or target distances. For example, refer to the attached diagram. Figure 2 The horizontal wellbore can be divided into four sections, each of which is a wellbore calculation unit. The left side of the diagram represents the downhole side, and the right side represents the downhole direction. The production direction is from right to left in the diagram. The length of each wellbore calculation unit can be designed and adjusted according to actual needs, for example, based on the temperature parameter acquisition distance, and can be, but is not limited to, 0.5-1 mm. Temperature parameters can include, but are not limited to, the temperature at a certain moment after well shut-in, the temperature after well stabilization, the temperature after well opening, the temperature at a certain moment after a second well shut-in, etc. In this embodiment, fiber optic profiling monitoring can be performed on the wellbore calculation unit, that is, using fiber optic sensing technology to detect the formation production at different depths in the horizontal well in real time. This can be, but is not limited to, using distributed fiber optic sensing, multimode fiber optic sensing, etc. This detection method can efficiently acquire temperature parameters within the horizontal well. This detection method is easily understood and implemented by those skilled in the art, for example: refer to the attached diagram. Figure 4In the fiber optic temperature waterfall plot, the horizontal axis represents time and the vertical axis represents depth, showing the temperature change of a wellbore at a certain depth over time from left to right. Temperature values ​​can be obtained based on the target sampling distance, which 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 upon here. The target producing layer is the producing layer within the length range of the selected horizontal well.

[0091] S2. Calculate the cooling constant of the wellbore calculation unit based on the temperature parameters of the wellbore calculation unit;

[0092] It is understandable that the cooling constant of the wellbore calculation unit can be derived from the temperature parameters of the wellbore calculation unit and Newton's law of cooling. ;

[0093] ①

[0094] The cooling constant can be derived from equation ①. The calculation formula is as follows:

[0095] ②

[0096] In the formula, —After the second well shut-in The temperature of the optical fiber at any given time, in °C;

[0097] —Ambient temperature after the initial long-term shut-in temperature stabilizes, °C;

[0098] --The temperature of the first optical fiber after the last well opening or the first after the second well closing, in °C;

[0099] --Fluid cooling constant;

[0100] – Duration of fiber optic temperature measurement after secondary well shut-in, h;

[0101] In this embodiment, the optical fiber can be lowered into the well and then shut in for an extended period initially, such as 10 hours, to obtain [data / information]. The specific shut-in time can be set based on experience or adjusted based on real-time temperature monitoring. For example, if the monitored temperature remains constant or fluctuates only slightly, it indicates that the downhole ambient temperature has stabilized. This temperature is the ambient temperature after the initial long shut-in period has stabilized. Then, well drilling and fluid production were carried out to obtain... After well opening, a fluid containing water and oil is produced from the wellbore. The temperature measured by the optical fiber during this process is the flow temperature. Once the flow temperature stabilizes, a second well shut-in can be performed. The first temperature data measured after well shut-in is the last optical fiber temperature after well opening or the first temperature measured after the second well shut-in. After a period of time following the second well shut-in, The secondary shut-in time can be designed and adjusted according to actual needs. This means it can be shorter than the initial long shut-in time, in order to obtain temperature rise and fall data caused by the fluid properties within the wellbore. For example, after 3 hours, the temperature at this point is the temperature after the secondary shut-in. fiber optic temperature at time The time from the second well shut-in to the acquisition of this temperature point is the fiber optic temperature measurement time after the second well shut-in. 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 shut-in duration, and there is no restriction on the order of shut-in. The duration of the first long well shut-in is longer than the duration of the second well shut-in.

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

[0103] It is understood that in this embodiment, the water-oil ratio of the wellbore calculation unit can be calculated using linear interpolation based on the water-oil ratio and cooling constant of the first and second target points.

[0104] The first target point is the non-producing zone at the top of the producing 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 zone at the top of the producing section. No fluid is produced at this location or above, for example, at the top of the transition zone between a vertical and horizontal well. Therefore, the water-to-oil ratio at this point is low. The water-oil ratio measured at the wellhead is the same and is recorded as a known quantity. The cooling constant at that point It can be calculated using formula ②, and is denoted as the known quantity. Correspondingly, if the producing formation is entirely oil-producing and the wellbore calculation unit contains no water, it can be defined as a pure oil point, and the water-to-oil ratio at the pure oil point is... The cooling constant is equal to 0 for the pure oil point. It can be obtained through ground sampling, or it can be calculated using the following formula (10), which is assumed to be determined here. ;

[0105] Table 1 Water-oil ratio With cooling constant relation

[0106]

[0107] Furthermore, in order to calculate Based on the above discussion, the water-oil ratio in the wellbore can be determined using linear interpolation. The calculation formula is as follows:

[0108] The linear interpolation formula is According to Table 1 above, m corresponds to 0 corresponds to n corresponds to p corresponds to Then it can be deduced that

[0109] ③

[0110] In this formula, X is k in formula ②, thus obtaining the quantitative correspondence between the cooling constant and the water-oil ratio corresponding to the wellbore calculation unit.

[0111] Accordingly, in this embodiment, the cooling constant of the pure oil point can also be obtained in the following manner. :

[0112] According to the conventional definition, the cooling constant of a fluid Its magnitude is determined by its own physical properties and is related to factors such as the fluid's thermal properties, surface area, and environmental conditions. Under normal temperature and pressure... It can be determined by experimental methods using the following formula:

[0113] ⑩

[0114] In the formula, --Height of the wellbore calculation unit ;

[0115] --Surface area of ​​the wellbore calculation unit ;

[0116] --The wellbore calculation unit contains the mass of the fluid. ;

[0117] --Specific heat capacity, ;

[0118] Meanwhile, for different wellbore calculation units, the surface area ,high Same, containing fluid mass They are basically the same, therefore The size depends on the specific heat capacity The size of the wellbore and the specific heat capacity of the oil and water two-phase flow. The values ​​vary considerably, generally by a factor of 2 to 5, depending on factors such as temperature and pressure. Therefore, it is possible to determine the appropriate values ​​based on these factors. The size indicates the amount of oil and water; the more water... The smaller, the less water. The larger.

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

[0120] Understandably, the water-oil ratio in a wellbore calculation unit is defined according to conventional methods. :

[0121] ④

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

[0123] --Water volume of the wellbore calculation unit ;

[0124] --Oil-bearing volume of the wellbore calculation unit ;

[0125] According to equation ④, we obtain

[0126] ⑤

[0127] The water saturation of the wellbore calculation unit is defined as follows: Combining equation ⑤, we can obtain:

[0128] ⑥

[0129] In the formula, For equation ③ This leads to the quantitative correspondence between the overall water saturation of the wellbore calculation unit and the water-oil ratio.

[0130] S5. Calculate the water saturation of the target producing section corresponding to the wellbore calculation unit based on the water saturation of the wellbore calculation unit;

[0131] It is understandable that, for a wellbore calculation unit, its final production volume includes the production volume from the previous wellbore calculation unit and the production volume of the target production zone corresponding to its own wellbore calculation unit. Furthermore, the production volume of the target production zone can be obtained using fiber optic temperature sensing technology, and the final wellbore production volume can also be obtained through surface data, which can then be referenced in the appendix. Figure 3 A relationship can be established based on the fact that the fluid inflow rate within the wellbore calculation unit equals the fluid outflow rate:

[0132] ⑦

[0133] We can obtain:

[0134] ⑧

[0135] In the formula, --Water saturation of the fluid flowing from production layer i into wellbore calculation unit i, %;

[0136] --The volume of the producing layer i flowing into the wellbore calculation unit i. ;

[0137] --The fluid volume flowing out of wellbore calculation unit i ;

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

[0139] --The volume of fluid flowing into wellbore calculation unit i ;

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

[0141] It is not hard to understand that and All can be obtained through equation ⑥, to obtain The quantitative correspondence with the water-oil ratio.

[0142] S6. Calculate the water production and oil production of the target producing zone based on the water saturation of the target producing zone;

[0143] It is understandable that, finally, the production volume of the target production layer can be determined based on Equation ⑧. Calculate the water production of the target production zone. Oil production :

[0144] 9

[0145] in: --Water production of product layer i ;

[0146] --Oil production of layer i ;

[0147] Liquid production rate of the target production zone here This is the temperature obtained using fiber optic temperature sensing technology in step S5, which will not be elaborated here.

[0148] The producing layer of wellbore calculation unit i Related to wellbore calculation unit i-1, therefore The calculation for horizontal wells is bottom-up; 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 layer corresponding to wellbore calculation unit i is equal to the liquid outflow of wellbore calculation unit i, therefore , = The initial value of wellbore calculation unit i can be determined by formula ⑧. According to equation ⑧ and the output of the target production segment The water production of the target producing section can then be obtained. Oil production Furthermore, the water production and oil production of multiple consecutive producing segments can be calculated separately to obtain the water production and oil production of the entire target producing segment, i.e., the two-phase flow production.

[0149] Based on the above, the method for calculating the production rate of horizontal well oil-water two-phase flow provided in this application embodiment utilizes fiber optic temperature sensing and Newton's law of cooling to calculate the cooling constant of the wellbore calculation unit. ,pass Water-oil ratio in quantitative wellbore calculation unit Based on this, the wellbore calculation unit is obtained. water saturation Then, the corresponding wellbore calculation unit is calculated. Water saturation of the corresponding target producing layer This invention enables the quantitative differentiation of oil-water two-phase flow production within the target production layer using fiber optic temperature sensing, based on the water and oil production within the target production layer. The embodiments of this application utilize wellbore fluid recirculation analysis, avoiding the accuracy and ambiguity issues caused by the numerous unknown parameters of the rock in horizontal well sections. By employing small-pitch fluid production calculations using fiber optic temperature sensing, the resolution of the two-phase flow production is improved, and data processing efficiency is enhanced, significantly increasing the application and promotion of fiber optic systems for oil production.

[0150] In this article, the term "and / or" is merely a description of the relationship between related objects, indicating that there can be three relationships, such as A and / or B. Specifically, it can be understood as: A and B can be included at the same time, A can exist alone, or B can exist alone, and any of the above three situations can be met.

[0151] Example 2

[0152] Taking well B1 as an example, well B1 is a development well in an oilfield. After three months of fracturing and flowback, it encountered oil and was put into production. The section below point A is an open-hole horizontal section with a length of 713m (3192-4005m). The section above point A is a casing completion, with the production casing having an outer diameter of 139.7mm and an inner diameter of 118.6mm. After production, the well's daily fluid production is 89m³. 3 / d, of which 60.6m³ of water is produced. 3 / d, oil production 28.4m 3 / d, in order to investigate the distribution of water and oil production in the horizontal section, fiber optic production profile monitoring was carried out on the well, that is, monitoring was carried out using fiber optic sensing technology. The monitoring system is shown in Table 2.

[0153] Table 2 Fiber Optic Monitoring Log for Well B1

[0154]

[0155] The first step is to obtain the temperature parameters of each wellbore calculation unit in well B1 using the data transmitted back from the fiber optic sensor.

[0156] After well B1's production stabilized, monitoring began. After the flow temperature stabilized, monitoring continued for 23.8 hours before shutting in. The last temperature curve showing stable flow temperature was taken as the baseline. After well shut-in, temperature monitoring begins. When a significant temperature rebound occurs in the horizontal section, the temperature curve at time t during the rebound is selected as the baseline. After well shut in, a significant temperature rebound occurred in the horizontal section of well B1 at t=3h. The temperature curve at that moment was taken as the temperature curve of well B1. The ambient temperature will be the wellbore temperature after the shut-in temperature has completely stabilized. After well B1 was shut in, the temperature stability of the horizontal section was very good at t=17h. The temperature at this moment was taken as the ambient temperature of well B1. In this embodiment, the 148th and 147th wellbore calculation units are used as examples. Table 3 below shows the relevant temperature parameters of the two wellbore calculation units.

[0157] Table 3. Calculation results and values ​​of the cooling constant at t=3 after well B1 is shut in.

[0158]

[0159] Substitute the relevant data from Table 3 into Equation ② to calculate the cooling constant of the wellbore calculation unit. ;

[0160] Wellbore calculation unit i=148:

[0161] According to measurement data , , Given t=3, we can obtain:

[0162]

[0163] Similarly, the corresponding value of the wellbore calculation unit i=147 is obtained. It is 0.1056.

[0164] The second step is to calculate the water-oil ratio in the wellbore calculation unit;

[0165] Point A is a point in the non-producing section at the upper part of the horizontal segment. Considering the random fluctuation of the monitored temperature, the value of point A in this well is taken as 3200-3280m (see attached figure). Figure 4 Any point within the stable temperature range above 3300°C is considered a stable region where no formation fluids enter, resulting in a stable state, including but not limited to stable temperature and cooling parameters. However, due to random fluctuations in temperature measurements, to ensure relative accuracy and reasonableness of the data, this embodiment applies the above calculation method to all wellbore calculation units within the aforementioned range. Value, and for all The average value is taken as the cooling constant at point A. In this embodiment, point A in well B1 The value is 0.12.

[0166] Based on the well's background data, the water production is 60.6 m³ / d and the oil production is 28.4 m³ / d. The water-oil ratio at point A can be obtained using formula ④. .

[0167] The cooling constant of the pure oil point can be taken as an empirical value of 0.9 to 1 when no experimental analysis is available. 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.

[0168] The values ​​of the above parameters in this step are summarized in Table 4:

[0169] Table 4 Water-oil ratio of well B1 With cooling constant

[0170]

[0171] The water-oil ratio of the wellbore calculation unit can be calculated according to equation ⑤. The calculation results are shown in Table 5.

[0172] Wellbore calculation unit i=148:

[0173] Calculated based on the aforementioned steps From formula ⑤, we can obtain:

[0174]

[0175] Similarly, the calculation for wellbore calculation unit i=147 is obtained. It is 2.1641.

[0176] The third step is to calculate the water saturation of the wellbore calculation unit based on the cooling constant and water-oil ratio of the wellbore calculation unit.

[0177] Table 5. Calculation Examples and Results of Water-Oil Ratio and Water Saturation in Well B1

[0178]

[0179] For wellbore calculation unit i=148, its water saturation can be obtained from the relevant data in Table 5 and Equation ⑥:

[0180]

[0181] Similarly, the water saturation of the wellbore calculation unit i=147 is 0.6840.

[0182] The fourth step is to calculate the water saturation of the target producing zone;

[0183] Based on fiber optic sensing analysis, the production volume of the target production layer corresponding to each sampling point can be obtained. The production data of the target producing sections corresponding to the two wellbore calculation units provided in this embodiment are shown in Table 6.

[0184] Table 6. Calculation results and values ​​for oil and water production in the production unit of Well B1.

[0185]

[0186] Calculate the water saturation of the target producing layer based on the data in Table 6 and Equation ⑧;

[0187] Wellbore calculation unit i=148:

[0188]

[0189] Similarly, the water saturation of the target producing zone corresponding to wellbore calculation unit i=147 can be calculated to be 0.7025.

[0190] Step 5: Calculate the water production and oil production of the target producing zone;

[0191] Based on the data from the preceding steps and combined with formula ⑨ for wellbore calculation unit i=148, we can obtain:

[0192]

[0193] Similarly, the water cut of the target producing zone corresponding to wellbore calculation unit i=147 can be calculated to be 0.3877 m. 3 / d, oil content is 0.1642 m 3 / d.

[0194]

[0195] Example 3

[0196] Further, see attached document. Figure 1 The specific implementation of the method shown in this application provides a calculation device for the production rate of horizontal well oil-water two-phase flow, such as... Figure 6 As shown, the computing 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 parameters of the wellbore calculation unit within the target producing layer. The cooling constant calculation unit 2 is used to calculate the cooling constant of the wellbore calculation unit based on the temperature parameters 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 producing layer corresponding to the wellbore calculation unit. The target calculation unit 5 is used to calculate the water production and oil production of the target producing layer based on the water saturation of the target producing layer.

[0197] It should be noted that other corresponding descriptions of the functional units involved in the calculation device for the production rate of horizontal well oil-water two-phase flow provided in this application embodiment can be found in the following references. Figure 1 The corresponding description of Example 1 will not be repeated here.

[0198] This application provides a calculation device for the production rate of oil-water two-phase flow in a horizontal well, including 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. The processor executes the above-mentioned program units stored in the memory to realize the corresponding functions.

[0199] The processor contains a kernel, which retrieves the corresponding program units from memory. One or more kernels can be configured, and by adjusting kernel parameters, a suitable approach for calculating the production rate of oil-water two-phase flow in horizontal wells can be obtained.

[0200] In summary, this application provides a device for calculating the production rate of horizontal well oil-water two-phase flow. This application utilizes fiber optic temperature sensing and Newton's law of cooling to calculate the cooling constant of the wellbore calculation unit. ,pass Water-oil ratio in quantitative wellbore calculation unit Based on this, the wellbore calculation unit is obtained. water saturation Then, the corresponding wellbore calculation unit is calculated. Water saturation of the corresponding target producing layer The system also measures the water and oil production within the target production layer, enabling the quantitative differentiation of the oil-water two-phase flow production within the target production layer using fiber optic temperature sensing.

[0201] This application provides a computer device, including a memory, a processor, and a computer program stored in the memory. The processor executes the computer program to implement steps such as a method for calculating the production rate of oil-water two-phase flow in a horizontal well.

[0202] This application provides a computer-readable storage medium storing a computer program that, when executed by a processor, implements steps such as a method for calculating the production rate of a horizontal well oil-water two-phase flow.

[0203] This application also provides a computer program product, including a computer program that, when executed by a processor, implements steps such as a method for calculating the production rate of oil-water two-phase flow in a horizontal well.

[0204] This application is described with reference to flowchart illustrations and / or block diagrams of methods, apparatus (systems), and computer program products according to embodiments of this application. It will be understood that each block of the flowchart illustrations and / or block diagrams, and combinations of blocks in the flowchart illustrations and / or block diagrams, can be implemented by computer program instructions. These computer program instructions can be provided to a processor of a general-purpose computer, special-purpose computer, embedded processor, or other programmable data processing apparatus to produce a machine, such that the instructions, which execute via the processor of the computer or other programmable data processing apparatus, generate instructions for implementing the flowchart... Figure 1 One or more processes and / or boxes Figure 1 A device that provides the functions specified in one or more boxes.

[0205] In a typical configuration, the device includes one or more processors (CPUs), memory, and a bus. The device may also include input / output interfaces, network interfaces, etc.

[0206] Memory may include non-persistent memory in computer-readable media, such as random access memory (RAM) and / or non-volatile memory, like read-only memory (ROM) or flash RAM, and memory includes at least one memory chip. Memory is an example of computer-readable media.

[0207] Computer-readable media includes both permanent and non-permanent, removable and non-removable media that can store information using any method or technology. Information can be computer-readable instructions, data structures, modules of programs, 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, CD-ROM, digital versatile optical disc (DVD) or other optical storage, magnetic tape, magnetic magnetic disk storage or other magnetic storage devices, or any other non-transferable medium that can be used to store information accessible by a computing device. As defined herein, computer-readable media does not include transient computer-readable media, such as modulated data signals and carrier waves.

[0208] It should also be noted that the terms "comprising," "including," or any other variations thereof are intended to cover non-exclusive inclusion, such that a process, method, article, or apparatus that comprises a list of elements includes not only those elements but also other elements not expressly listed, or elements inherent to such process, method, article, or apparatus. Unless otherwise specified, an element defined by the phrase "comprising one..." does not exclude the presence of other identical elements in the process, method, article, or apparatus that includes that element.

[0209] Those skilled in the art will understand that embodiments of this application can be provided as methods, systems, or computer program products. Therefore, this application can take the form of a completely hardware embodiment, a completely software embodiment, or an embodiment combining software and hardware aspects. Furthermore, this application can take the form of a computer program product embodied 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.

[0210] The above description is merely a specific embodiment of this application, but the scope of protection of this application is not limited thereto. Any variations or substitutions that can be easily conceived by those skilled in the art within the scope of the technology disclosed in this application should be included within the scope of protection of this application. Therefore, the scope of protection of this application should be determined by the scope of the claims.

Claims

1. A method for calculating the production of a horizontal well for oil-water two-phase flow, characterized in that, It comprises the following steps: Obtaining the temperature parameter of the wellbore calculation unit in the target pay zone; Deriving the cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit and Newton's cooling law; According to The formula can derive cooling constant The formula of the calculation formula: In the formula, — after the second shut-in Fiber temperature at the moment, ℃ - Ambient temperature, °C, after the first long shut-in temperature stabilization; -- the last fiber optic temperature, °C, after the well is opened or the first fiber optic temperature, °C, after the well is closed a second time; -- fluid cooling constant; - the duration of the optical fiber temperature measurement after the secondary shut-in, h; 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 pay zone corresponding to the wellbore calculation unit according to the water saturation of the wellbore calculation unit; Calculating the water production and oil production of the target pay zone according to the water saturation of the target pay zone.

2. The method for calculating the production of the oil-water two-phase flow of the horizontal well according to claim 1, characterized in that, The step of obtaining the temperature parameter of the wellbore calculation unit in the target pay zone comprises: Obtaining the temperature parameter of the wellbore calculation unit in the target pay zone by using distributed temperature sensing; Selecting the temperature parameter according to the target sampling distance.

3. The method for calculating the production of the oil-water two-phase flow of the horizontal well according to claim 1, characterized in that, The step of calculating the water-oil ratio of the wellbore calculation unit comprises: Calculating the water-oil ratio of the wellbore calculation unit by linear interpolation according to the water-oil ratio and the cooling constant of the first target point and the second target point; Wherein, the first target point is a non-pay zone position at the top of the pay zone, and the second target point is a pure oil point.

4. The method for calculating the production of the oil-water two-phase flow of the horizontal well according to claim 3, characterized in that, The step of calculating the water-oil ratio of the wellbore calculation unit by linear interpolation according to the water-oil ratio and the cooling constant of the first target point and the second target point comprises: The cooling constant of the first target point is defined as a known number n, and the water-oil ratio is a known number m; The cooling constant of the second target point is defined as a known number p, and the water-oil ratio is 0. According to the linear interpolation formula is Deriving water-oil ratio for wellbore calculation unit ③ wherein: m corresponds to 0 corresponds to n corresponds to p corresponds to X is k in the formula .

5. The method for calculating the production of the oil-water two-phase flow of the horizontal well according to claim 4, 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: Defining water to oil ratio for wellbore calculation unit : In the formula, -- wellbore computational unit water-oil ratio; -- a wellbore computation unit for water-bearing volume, ; --wellbore computational unit oil volume, ; According to the formula obtained ⑤ Defining water saturation of the wellbore computation cell Combining equations (5) and (6) gives: wherein is of formula (III) .

6. The method for calculating the production of the oil-water two-phase flow of the horizontal well according to claim 5, characterized in that: 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 comprises: According to the relationship that the inflow of fluid in the wellbore calculation unit is equal to the outflow of fluid, it can be obtained that: ⑦ 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 comprises: wherein -- calculates the fluid water saturation of the reservoir i inflow wellbore unit i; -- volume of the reservoir i inflow wellbore calculation unit i, ; -- fluid volume out of the wellbore calculation unit i, ; -- fluid water saturation of the outflowing wellbore at the element i; -- fluid volume flowing into the wellbore calculation unit i, ; -- fluid water saturation entering the wellbore calculation unit i.

7. The method for calculating the production of the oil-water two-phase flow of the horizontal well according to claim 6, characterized in that: It comprises: According to Equation 7, the volume of the reservoir layer i is calculated The water production of the reservoir layer is calculated The oil production of the reservoir layer is calculated : ⑨ wherein: - water production of the producing layer i, ; -- the oil production of the layer i, .

8. A computing device for calculating the production of a two-phase oil-water flow in a horizontal well based on the method of any one of claims 1 to 7, characterized in that, An obtaining unit, the obtaining unit is used for obtaining the temperature parameter of the wellbore calculation unit in the target pay zone; A cooling constant calculation unit, the cooling constant calculation unit is used for calculating the cooling constant of the wellbore calculation unit according to the temperature parameter of the wellbore calculation unit; A water-oil ratio calculation unit, the water-oil ratio calculation unit is used for calculating the water-oil ratio of the wellbore calculation unit; A water saturation calculation unit, the water saturation calculation unit is used for calculating the water saturation of the wellbore calculation unit and the water saturation of the target pay zone corresponding to the wellbore calculation unit; A target calculation unit, the target calculation unit is used for calculating the water production and oil production of the target pay zone according to the water saturation of the target pay zone. It comprises:

9. A computer apparatus, comprising: A memory, a processor and a computer program stored on the memory, the processor executes the computer program to realize the method of any one of claims 1-7. 10.A computer readable storage medium, characterized in that: The computer readable storage medium stores a computer program, the computer program is executed by a processor to realize the method of any one of claims 1-7. It comprises:

11. A computer program product, characterised in that, A computer program, the computer program is executed by a processor to realize the method of any one of claims 1-7. ​

Images