A method, apparatus, equipment and medium for assessing the multiphase production capacity of oil and gas wells.

Abstract

This application discloses a method, apparatus, equipment, and medium for assessing the multiphase production capacity of oil and gas wells. The method preprocesses the raw data of the oil and gas well to obtain dimensionless data. Then, it uses natural gas wellhead instruments to collect the gas phase flow rate, oil phase flow rate, and water phase flow rate after separation by the wellhead splitter in real time to determine the wellhead production gas-liquid ratio, thereby calculating the bottom-hole liquid water cut. Combining the dimensionless data, productivity index coefficient, and wellhead production gas-liquid ratio, the productivity index of the oil and gas well is calculated. Finally, the production capacity of the oil and gas well is assessed based on the productivity index, enabling the assessment of production capacity under high gas-liquid ratio conditions caused by CO2 flooding. This improves the accuracy of the assessment, provides assessment results for production reduction caused by liquid accumulation in oil and gas wells, and extends the lifespan of oil and gas wells.

Description

Technical Field

[0001] This application relates to the field of oil and gas well development technology, and in particular to a method, apparatus, equipment and medium for assessing the multiphase production capacity of oil and gas wells. Background Technology

[0002] As the development of complex continental oil and gas reservoirs in my country enters its middle and late stages, a large number of gas wells and high-gas-content oil wells are facing problems such as wellbore fluid accumulation, decreased pump efficiency, and declining production. In recent years, CO2 flooding technology has become a new method for removing fluid from gas wells. CO2 flooding leads to an increase in the gas-liquid ratio, which is typically 100-200 m³ at the bottom of conventional oil wells. 3 / m 3 After CO2 flooding, the wellhead production gas-liquid ratio can reach 3000m³. 3 / m 3 Currently, the industry mainly uses two methods to determine the liquid accumulation status of oil and gas wells: The first method indirectly determines whether liquid accumulation has occurred based on the predicted critical liquid-carrying flow rate of the oil and gas well. However, the critical liquid-carrying flow rate model used in this method has significant discrepancies in the definition of "critical liquid-carrying," resulting in a lack of cross-comparison of the accuracy of different models. Furthermore, in practical applications, this method is difficult to corroborate the wellbore liquid accumulation status based on the relationship between actual gas volume and critical liquid-carrying flow rate. The critical liquid-carrying flow rate can only define the specific moment when liquid accumulation affects gas well production, and it is difficult to cover the time range of liquid accumulation impact. The second method determines the liquid accumulation status of oil and gas wells by directly calculating the amount of liquid accumulation. However, this method relies on parameters that are difficult to obtain on-site, such as formation porosity, gas content, brittle mineral content, Young's modulus, Poisson's ratio, and fracture pressure, and ignores the gas-liquid ratio, a core parameter affecting the amount of liquid accumulation. The evaluation accuracy is limited under three-phase flow of oil, gas, and water, and high gas-liquid ratio production conditions. Both of the above methods are less effective in high gas-liquid ratio situations, especially those caused by CO2 flooding at 3000m³. 3 / m 3 Under the above conditions of three-phase flow of oil, gas and water, it is impossible to accurately assess the fluid accumulation in the wellbore and its production capacity. Summary of the Invention

[0003] This application provides a method, apparatus, equipment, and medium for assessing the multiphase production capacity of oil and gas wells. It abandons the single "critical flow rate" judgment and solves the problems of existing critical liquid-carrying flow rate models and liquid accumulation models failing in scenarios with high gas-liquid ratios and three-phase flow of oil, gas, and water, as well as the difficulty in obtaining liquid accumulation model parameters. It establishes a dimensionless multiphase production capacity assessment method based on readily available field parameters (such as reservoir pressure, reservoir temperature, gas flow rate, bottom hole flowing pressure, and tubing diameter of the oil and gas well under test). By calculating the dimensionless oil / water / gas production capacity, it determines the type of liquid accumulation (oil accumulation, water accumulation, or mixed accumulation), generates an assessment result of the risk of production reduction due to liquid accumulation, thereby guiding production adjustments and ultimately preventing production reductions caused by liquid accumulation in oil and gas wells. This method is particularly suitable for high gas-liquid ratio environments caused by CO2 flooding (where the gas-liquid ratio can reach 3000 m³ / s). 3 / m 3 This method provides a production capacity assessment under certain conditions, overcoming the shortcomings of traditional models that are inaccurate in such environments.

[0004] In a first aspect, embodiments of this application provide a method for evaluating the multiphase production capacity of oil and gas wells, including: S10: Obtain the raw data of the oil and gas well to be tested, and preprocess the raw data to obtain dimensionless data; S20: The gas phase flow rate, oil phase flow rate and water phase flow rate after separation by the wellhead splitter are collected in real time through the natural gas wellhead instrument, and the wellhead production gas-liquid ratio is determined based on the gas phase flow rate, the oil phase flow rate and the water phase flow rate; S30: Obtain the tubing parameters of the oil and gas well to be tested and, in conjunction with the wellhead gas-liquid production ratio, determine the productivity index coefficient; S40: Obtain the bottom liquid phase water cut, and combine it with the dimensionless data, the wellhead production gas-liquid ratio and the productivity index coefficient, and call the productivity index calculation formula to calculate the current productivity index of the oil and gas well to be tested; S50: Evaluate the production capacity of the oil and gas well to be tested based on the current productivity indicators, and obtain the production capacity evaluation results.

[0005] In conjunction with the first aspect, in one possible implementation, acquiring the raw data of the oil and gas well to be tested and preprocessing the raw data to obtain dimensionless data includes: If the original data includes the original reservoir temperature, the original reservoir pressure, and the original bottom hole flowing pressure, then the original reservoir temperature is processed to obtain a dimensionless reservoir temperature. Based on the original reservoir pressure and the original bottom hole flowing pressure, the current gas flow rate entering the wellbore steady state from the current formation is calculated using the production capacity equation, and the current gas flow rate entering the wellbore steady state from the current formation is processed into a dimensionless value to obtain the current dimensionless gas flow rate. The dimensionless reservoir temperature and the current dimensionless gas flow rate are used as dimensionless data.

[0006] In conjunction with the first aspect, in one possible implementation, acquiring the raw data of the oil and gas well to be tested and preprocessing the raw data to obtain dimensionless data includes: If the original data only includes the original reservoir temperature, the average gas flow rate is added to the original data as the initial formation gas flow rate into the wellbore steady state to update the original data; An optimization step is performed based on the updated original data. The optimization step includes: Based on the updated raw data, perform steps S10 to S40 to obtain the current productivity index; Obtain the target historical productivity index, and calculate the difference between the current productivity index and the target historical productivity index as the index difference; When the difference between the indicators is greater than or equal to the preset deviation, the target historical productivity indicator is updated based on the current productivity indicator, the gas production capacity in the target historical productivity indicator is obtained as the target gas production capacity, and the gas phase flow rate of the current formation entering the wellbore steady state is determined by combining the average value of the gas phase flow rate. The current formation gas flow rate entering the wellbore steady state is used as the new initial formation gas flow rate entering the wellbore steady state and added to the original data to update the original data. The optimization steps are repeated until the index difference is less than the preset deviation. Then, the corresponding original data is obtained and the original data is preprocessed to obtain dimensionless data.

[0007] In conjunction with the first aspect, in one possible implementation, determining the wellhead production gas-liquid ratio based on the gas phase flow rate, the oil phase flow rate, and the water phase flow rate includes: Calculate the average values ​​of the gas phase flow rate, the oil phase flow rate, and the water phase flow rate; The average flow rate of the oil phase and the average flow rate of the water phase are added together to obtain the average liquid production rate. The wellhead gas-liquid ratio is determined by the ratio of the average gas flow rate to the average liquid production rate.

[0008] In conjunction with the first aspect, in one possible implementation, the method for assessing the multiphase production capacity of oil and gas wells further includes, prior to obtaining the bottom-hole liquid phase water cut: The wellhead oil-water ratio is determined based on the ratio of the average oil phase flow rate to the average water phase flow rate. Based on the tubing inner diameter, tubing outer diameter, and wellhead gas-liquid ratio of the oil and gas well to be tested, the bottom oil-water ratio calculation coefficient table is traversed to determine the bottom oil-water ratio calculation coefficient. Based on the wellhead oil-water ratio, the wellhead gas-liquid ratio, the dimensionless data, and the bottom-hole oil-water ratio calculation coefficient, the bottom-hole oil-water ratio is determined by the bottom-hole oil-water ratio calculation formula. The bottom oil-water ratio is calculated using the formula for calculating bottom liquid phase water cut, and the bottom liquid phase water cut is obtained. The specific formula for calculating the bottom-hole oil-water ratio is as follows:

[0009] In the formula, OWR 2 indicates the oil-water ratio at the bottom of the well. OWR 1 indicates the oil-water ratio at the wellhead. D , E , F , G and H This represents the calculation coefficient for the oil-water ratio at the bottom of the well. X 2 indicates the gas-liquid ratio produced at the wellhead; X 1 and X 4 represents dimensionless data, where, X 1 represents the dimensionless reservoir temperature. X 4 represents dimensionless gas phase flow rate; The specific formula for calculating the bottom-hole liquid phase water cut is as follows:

[0010] In the formula, X 3 indicates the bottom-hole liquid water cut. OWR 2 indicates the oil-water ratio at the bottom of the well.

[0011] In conjunction with the first aspect, in one possible implementation, the formula for calculating the productivity indicator is:

[0012] In the formula, J, K, L, M, N This represents a productivity index coefficient. Y i Indicators of productivity X 1 represents the dimensionless reservoir temperature. X 2 indicates the gas-liquid ratio produced at the wellhead. X 3 indicates the bottom-hole liquid water cut. X 4 represents the dimensionless gas phase flow rate.

[0013] In conjunction with the first aspect, in one possible implementation, the current productivity indicators include current gas production capacity, current oil production capacity, and current water production capacity; the step of assessing the production capacity of the oil and gas well under test based on the current productivity indicators and obtaining the production capacity assessment result includes: Determine whether the current gas production capacity of the oil and gas well under test is within the normal production range during the production cycle. If the current gas production capacity is within the normal production range, compare the current oil production capacity and the current gas production capacity with the evaluation threshold respectively. When both the current oil production capacity and the current gas production capacity are less than the evaluation threshold, it indicates that the oil phase and water phase are accumulating simultaneously in the wellbore of the oil and gas well being tested, resulting in a production capacity evaluation result of high risk of reduced production due to wellbore fluid accumulation. When both the current oil production capacity and the current gas production capacity are greater than the evaluation threshold, it indicates that there is no liquid phase accumulation in the wellbore of the oil and gas well under test, resulting in a low-risk production capacity evaluation result of liquid accumulation leading to reduced production. If one of the current oil production capacity and the current gas production capacity is greater than the evaluation threshold and the other is less than the evaluation threshold, it indicates that oil phase accumulation or water phase accumulation has occurred in the wellbore of the oil and gas well being tested, generating a production capacity assessment result for the risk of wellbore fluid accumulation and production reduction.

[0014] Secondly, embodiments of this application provide an oil and gas well multiphase production capacity assessment device, comprising: The dimensionless data processing module is used to acquire the raw data of the oil and gas well to be tested, and to preprocess the raw data to obtain dimensionless data. The wellhead production gas-liquid ratio determination module is used to collect the gas phase flow rate, oil phase flow rate and water phase flow rate after separation by the wellhead splitter in real time through natural gas wellhead instruments, and determine the wellhead production gas-liquid ratio based on the gas phase flow rate, the oil phase flow rate and the water phase flow rate; The productivity index coefficient determination module is used to obtain the tubing parameters of the oil and gas well to be tested and, in combination with the wellhead gas-liquid production ratio, determine the productivity index coefficient. The current productivity index calculation module is used to obtain the bottom liquid phase water cut, and combine the dimensionless data, the wellhead production gas-liquid ratio and the productivity index coefficient to call the productivity index calculation formula to calculate the current productivity index of the oil and gas well to be tested. The production capacity assessment module is used to assess the production capacity of the oil and gas well under test based on the current productivity indicators and obtain the production capacity assessment results.

[0015] Thirdly, embodiments of this application provide an apparatus comprising: a processor; a memory for storing processor-executable instructions; wherein, when the processor executes the executable instructions, it implements the method as described in the first aspect or any possible implementation of the first aspect.

[0016] Fourthly, embodiments of this application provide a non-volatile computer-readable storage medium, the non-volatile computer-readable storage medium including storage for storing a computer program or instructions that, when executed, cause the method described in the first aspect or any possible implementation of the first aspect to be implemented.

[0017] One or more technical solutions provided in the embodiments of this application have at least the following technical effects or advantages: This application embodiment utilizes readily available field-obtainable production parameters of the oil and gas well under test, such as reservoir pressure, reservoir temperature, gas flow rate, bottom hole flowing pressure, tubing diameter, gas flow rate, oil flow rate, and water flow rate. By calculating dimensionless oil / water / gas production capacity, it determines the type of fluid accumulation and then, based on the fluid accumulation type, determines whether gas flow enhancement fluid-carrying measures are needed to control the formation of fluid accumulation in oil and gas wells. This effectively overcomes the limitations of traditional assessment methods under high gas-liquid ratio conditions and provides a new method that can distinguish fluid accumulation types, has readily available parameters, and provides accurate assessments. Ultimately, it aims to prevent production reduction caused by fluid accumulation in oil and gas wells and extend the lifespan of oil and gas wells. Attached Figure Description

[0018] To more clearly illustrate the technical solutions of the embodiments of this application, the drawings used in the description of the embodiments of this application or the prior art will be briefly introduced below. Obviously, the drawings described below are some embodiments of the present invention. For those skilled in the art, other drawings can be obtained based on these drawings without creative effort.

[0019] Figure 1 This application provides an illustration of an application scenario for a method for evaluating the multiphase production capacity of oil and gas wells, as illustrated in the embodiments of this application. Figure 2 A flowchart of a method for evaluating the multiphase production capacity of oil and gas wells provided in this application embodiment; Figure 3 This is a schematic diagram of the structure of an oil and gas well multiphase production capacity assessment device provided in an embodiment of this application. Detailed Implementation

[0020] The technical solutions of the embodiments of this application will be clearly and completely described below with reference to the accompanying drawings. Obviously, the described embodiments are only some, not all, of the embodiments of this invention. All other embodiments obtained by those skilled in the art based on the embodiments of this invention without creative effort are within the scope of protection of this invention.

[0021] The following description of some technologies involved in the embodiments of this application is provided to aid understanding and should be considered merely exemplary. Therefore, those skilled in the art should recognize that various changes and modifications can be made to the embodiments described herein without departing from the scope and spirit of this application. Similarly, for clarity and brevity, some descriptions of well-known functions and structures are omitted in the following description.

[0022] This application provides a method for evaluating the multiphase production capacity of oil and gas wells, which is applied in applications such as... Figure 1 The application scenario diagram is shown. Figure 2 A flowchart of a method for evaluating the multiphase production capacity of oil and gas wells provided in this application embodiment includes steps S10 to S40. Wherein, Figure 1 This is merely one execution order shown in the embodiments of this application and does not represent the only execution order for a method of assessing the multiphase production capacity of oil and gas wells. Where the final result can be achieved, Figure 1 The steps shown can be performed in parallel or in reverse order.

[0023] S10: Obtain the raw data of the oil and gas well to be tested, and preprocess the raw data to obtain dimensionless data.

[0024] Among them, the oil and gas well to be tested refers to the oil and gas well that needs to be assessed for production capacity; the raw data refers to the data of the oil and gas well to be tested that is directly obtained from the field and used for subsequent production capacity assessment, including but not limited to the reservoir pressure, reservoir temperature, gas flow rate, bottom hole flowing pressure and tubing diameter of the oil and gas well to be tested. The raw data used in this embodiment are all from information that can be directly collected from the field of the oil and gas well to be tested, and do not belong to parameters that are difficult to obtain from the field, such as reservoir, which effectively reduces the difficulty and cost of data acquisition.

[0025] Specifically, if the raw data obtained from the oil and gas well to be tested includes the raw reservoir pressure P r Original reservoir temperature T r and original bottom hole flowing pressure P wf Then, regarding the original reservoir temperature T r Dimensionless processing was performed to obtain the dimensionless reservoir temperature. X 1; then based on the original reservoir pressure P r and original bottom hole flowing pressure P wf The steady-state gas flow rate entering the wellbore from the formation is calculated using the productivity equation. Q g2 Next, the gas flow rate entering the wellbore at steady state from the formation was measured. Q g2Dimensionless processing was performed to obtain the dimensionless gas phase flow rate. X 4.

[0026] Furthermore, regarding the original reservoir temperature T r The dimensionless processing process is as follows: original reservoir temperature T r Except for 100℃, the specific calculation formula is as follows:

[0027] In the formula, T r Indicates the original reservoir temperature. X 1 represents the dimensionless reservoir temperature obtained after dimensionless processing of the original reservoir temperature.

[0028] The capacity equation is as follows:

[0029] In the formula, P r This indicates the original reservoir pressure of the oil and gas well being tested. P wf This represents the original bottomhole flowing pressure of the oil and gas well being tested. A and B Indicates reservoir parameters, Q g2 This represents the gas flow rate from the formation into the wellbore at steady state.

[0030] Gas flow rate into the wellbore at steady state from the formation Q g2 The dimensionless processing process is as follows: the steady-state gas flow rate entering the wellbore from the formation. Q g2 In addition to 10,000 standard cubic meters per day, the specific calculation formula is as follows:

[0031] In the formula, X 4 represents the dimensionless gas phase flow rate. Qg2 This represents the gas flow rate from the formation into the wellbore at steady state. m 3 / d This indicates standard cubic meters per day.

[0032] S20: Real-time acquisition of gas phase flow rate, oil phase flow rate and water phase flow rate after separation by the wellhead splitter through natural gas wellhead instruments, and determination of wellhead production gas-liquid ratio based on gas phase flow rate, oil phase flow rate and water phase flow rate.

[0033] The natural gas wellhead instruments in this embodiment include an oil phase flow meter, a gas phase flow meter, and a water phase flow meter.

[0034] Specifically, the wellhead diverter (i.e., the natural gas wellhead instrument collects data in real time) Figure 1 The gas phase flow rate after separation by the phase separation device in the middle Q g1 ( t Oil phase flow rate Q o1 ( t ) and water phase flow rate Q w1 ( t After that, first calculate the average value of the gas phase flow rate. Q g1 Average oil phase flow rate Q o1 and the average value of water phase flow rate Q w1 Then the average oil phase flow rate Q o1 and the average value of water phase flow rate Q w1 The average product volume is obtained by adding them together. Q l1 Finally, the average gas phase flow rate is used. Q g1 Ratio to average liquid production Q l1 Determine the gas-liquid ratio at the wellhead. X 2.

[0035] Furthermore, the average gas phase flow rate Q g1 The calculation formula is:

[0036] In the formula, Q g1 This represents the average gas phase flow rate. Q g1 ( t This indicates the real-time gas flow rate collected by the natural gas wellhead instruments. i This indicates the start time of the production cycle of the oil and gas well being tested. n This indicates the moment when the production cycle of the oil and gas well being tested ends.

[0037] Average oil phase flow rate Q o1 The calculation formula is:

[0038] In the formula, Q o1 This represents the average flow rate of the oil phase. Q o1 ( tThis indicates the real-time oil phase flow rate collected by the natural gas wellhead instruments. i This indicates the start time of the production cycle of the oil and gas well being tested. n This indicates the moment when the production cycle of the oil and gas well being tested ends.

[0039] Average value of aqueous phase flow rate Q w1 The calculation formula is:

[0040] In the formula, Q w1 This represents the average value of the aqueous phase flow rate. Q w1 ( t This indicates the real-time water flow rate collected by the natural gas wellhead instruments. i This indicates the start time of the production cycle of the oil and gas well being tested. n This indicates the moment when the production cycle of the oil and gas well being tested ends.

[0041] Average liquid production Q l1 The calculation formula is:

[0042] In the formula, Q l1 This represents the average yield of liquid produced. Q w1 This represents the average value of the aqueous phase flow rate. Q o1 This represents the average flow rate of the oil phase.

[0043] Wellhead production gas-liquid ratio X The formula for calculating 2 is:

[0044] In the formula, X 2 indicates the gas-liquid ratio produced at the wellhead. Q g1 This represents the average gas phase flow rate. Q l1 This represents the average amount of liquid produced.

[0045] S30: Obtain the tubing parameters of the oil and gas well to be tested and combine them with the gas-liquid ratio at the wellhead to determine the productivity index coefficient.

[0046] Among them, the tubing parameters of the oil and gas well to be tested refer to the parameters related to the tubing of the oil and gas well to be tested, including but not limited to the tubing inner diameter, tubing outer diameter and wellhead gas-liquid ratio.

[0047] Specifically, based on the inner diameter of the tubing, the outer diameter of the tubing, and the gas-liquid ratio at the wellhead of the oil and gas well to be tested, the productivity index coefficients are determined by traversing the productivity index coefficient table.

[0048] The productivity index coefficient table in this embodiment is shown in Table 1.

[0049] Table 1

[0050] S40: Obtain the bottom-hole liquid phase water cut, and combine it with dimensionless data, wellhead production gas-liquid ratio and productivity index coefficient, and call the productivity index calculation formula to calculate the current productivity index of the oil and gas well to be tested.

[0051] Specifically, after obtaining the average oil phase flow rate Q o1 and the average value of water phase flow rate Q w1 Then, based on the average value of the oil phase flow rate Q o1 and the average value of water phase flow rate Q w1 The ratio of the oil to water at the wellhead is used to determine the oil-water ratio. OWR 1; Then, based on the tubing inner diameter, tubing outer diameter, and wellhead gas-liquid ratio of the oil and gas well to be tested... X 2. Traverse the bottom-hole oil-water ratio calculation coefficient table to determine the bottom-hole oil-water ratio calculation coefficient; then, based on the wellhead oil-water ratio... OWR 1. Wellhead gas-liquid ratio X 2. Dimensionless data and bottom-hole oil-water ratio calculation coefficient are used to determine the bottom-hole oil-water ratio using the bottom-hole oil-water ratio calculation formula. OWR 2; Finally, the bottom oil-water ratio was calculated using the formula for bottom liquid phase water cut. OWR 2. Calculations were performed to obtain the bottom-hole liquid phase water cut. X 3.

[0052] Among them, the oil-water ratio at the wellhead OWR The formula for calculating 1 is:

[0053] In the formula, OWR 1 indicates the oil-water ratio at the wellhead. Q o1 This represents the average flow rate of the oil phase. Q w1 This represents the average value of the water phase flow rate.

[0054] The specific formula for calculating the bottom-hole oil-water ratio is as follows:

[0055] In the formula, OWR 2 indicates the oil-water ratio at the bottom of the well. OWR 1 indicates the oil-water ratio at the wellhead. D , E , F , G and H This represents the calculation coefficient for the oil-water ratio at the bottom of the well. X 2 indicates the gas-liquid ratio produced at the wellhead; X 1 and X 4 represents dimensionless data, where, X 1 represents the dimensionless reservoir temperature. X 4 represents the dimensionless gas phase flow rate.

[0056] The specific formula for calculating the bottom liquid water cut is as follows:

[0057] In the formula, X 3 indicates the bottom-hole liquid water cut. OWR 2 indicates the oil-water ratio at the bottom of the well.

[0058] The calculation coefficient table for the bottom oil-water ratio in this embodiment is shown in Table 2.

[0059] Table 2

[0060] After determining the bottom-hole liquid phase water cut, based on the tubing inner diameter, tubing outer diameter, and wellhead production gas-liquid ratio of the oil and gas well to be tested, the bottom-hole oil-water ratio calculation coefficient table is traversed to determine the productivity index coefficient; then, the productivity index coefficient, dimensionless reservoir temperature, wellhead production gas-liquid ratio, bottom-hole liquid phase water cut, and dimensionless gas phase flow rate are calculated using the productivity index calculation formula to obtain the productivity index.

[0061] The specific formula for calculating the productivity index is as follows:

[0062] In the formula, J, K, L, M, N This represents a productivity index coefficient. Y i Indicators of productivity X 1 represents the dimensionless reservoir temperature. X 2 indicates the gas-liquid ratio produced at the wellhead. X 3 indicates the bottom-hole liquid water cut. X 4 represents the dimensionless gas phase flow rate.

[0063] In this embodiment, the productivity indicators include dimensionless oil production capacity. Y 2. Dimensionless water production capacity Y 3 and dimensionless gas production capacity Y 4.

[0064] Furthermore, the dimensionless period of the oil and gas well under test can also be calculated using the productivity index calculation formula of this embodiment. Y 1. After calculating the dimensionless period Y After step 1, the production cycle of the oil and gas well to be tested can also be determined using the dimensionless period calculation formula. The specific calculation process is as follows: dimensionless period Y The formula for calculating 1 multiplied by 10 days is:

[0065] In the formula, T Indicates the production cycle of the oil and gas well to be tested. Y 1 represents a dimensionless period, 10 d Indicates 10 days 。

[0066] Furthermore, the method for evaluating the multiphase production capacity of oil and gas wells provided in this embodiment also includes: When the acquired raw data only includes the raw reservoir temperature, due to the actual production process, the average gas flow rate... Q g1 Gas flow rate into the wellbore at steady state relative to the formation Q g2 Extremely close, therefore, when the original reservoir pressure cannot be obtained... P r and original bottom hole flowing pressure P wf If the production capacity equation cannot be determined, then the gas phase flow rate after separation by the wellhead splitter should be obtained in real time from the natural gas wellhead instruments. Q g1 ( t ), and calculate the average gas phase flow rate. Q g1 The average value of the gas phase flow rate Q g1 Gas flow rate as the initial formation entering the wellbore steady state The data is added to the original data to update it; then, an optimization step is performed based on the updated original data. In this embodiment, the optimization steps include: 1) Based on the updated raw data, perform steps S10 to S40 to obtain the current productivity index. Specifically, perform S10: adjust the raw reservoir temperature... T r The dimensionless processing process is as follows: original reservoir temperature T r Except for 100℃, the specific calculation formula is as follows:

[0067] In the formula, T rIndicates the original reservoir temperature. X 1 represents the dimensionless reservoir temperature obtained after dimensionless processing of the original reservoir temperature.

[0068] The average value of the gas phase flow rate is calculated using the dimensionless gas phase flow rate calculation formula. Q g1 Calculations were performed to obtain the initial dimensionless gas phase flow rate. .

[0069] The specific formula for calculating the dimensionless gas phase flow rate is as follows:

[0070] In the formula, This represents the initial dimensionless gas phase flow rate. Q g1 This represents the average value of the gas phase flow rate.

[0071] After obtaining the initial dimensionless gas phase flow rate Then, continue with steps S20-S40 to obtain the current productivity index.

[0072] After obtaining the current productivity index, the target historical productivity index is retrieved. Since there is no historical data for the initial calculation of the current productivity index, the initial target historical productivity index is 0. Here, the current productivity index refers to the productivity index calculated at the current moment. The target historical productivity index refers to the productivity index of the previous moment closest to the current moment.

[0073] 2) Calculate the difference between the current productivity index and the target historical productivity index as the index difference.

[0074]

[0075] In the formula, The difference in oil production capacity indicators. The difference in water production capacity indicators. The difference in gas production capacity indicators. Indicates the current stage. Indicates the historical stage of the target. This indicates the current oil production capacity indicator. This indicates the current water production capacity index. This indicates the current gas production capacity index. This indicates the target historical oil production capacity index. This indicates the target historical water production capacity index. This indicates the target's historical gas production capacity.

[0076] 3) When the difference between the indicators is greater than or equal to the preset deviation, the target historical productivity indicator is updated based on the current productivity indicator, the gas production capacity in the target historical productivity indicator is obtained as the target gas production capacity, and the gas phase flow rate of the current formation entering the wellbore steady state is determined by combining the average value of the gas phase flow rate.

[0077] The specific calculation formula is as follows:

[0078] In the formula, This represents the average gas phase flow rate. Indicates the target gas production capacity. This represents the gas flow rate at which the current formation enters the wellbore steady state.

[0079] 4) Add the current formation gas flow rate into the wellbore steady state as the new initial formation gas flow rate into the wellbore steady state to the original data to update the original data. Repeat the optimization steps until the index difference is less than the preset deviation. Then, obtain the corresponding original data and perform dimensionless processing on the original data to obtain dimensionless data.

[0080] To facilitate understanding, this embodiment illustrates the above processing procedure through examples.

[0081] The tubing size of a certain oil and gas well to be tested is 50.3 mm. / 60.3 The original reservoir temperature was measured to be 80℃. On a certain day, the average gas flow rate at the wellhead was calculated to be 6684.6, obtained by averaging the real-time gas flow rate after separation by the wellhead splitter collected by the natural gas wellhead instruments. (At normal temperature and pressure), the average aqueous phase flow rate is 1.5. The average oil phase flow rate is 2.1. .

[0082] Since the reservoir's productivity equation is unknown at this point, the average gas flow rate is used as the initial formation gas flow rate entering the wellbore at steady state. The data is added to the original data to update it. Then, steps S10 to S40 are performed based on the updated original data.

[0083] S10: Perform the first dimensionless gas phase flow rate calculation based on the dimensionless gas phase flow rate calculation formula to obtain the initial dimensionless gas phase flow rate. .

[0084] The specific formula for calculating dimensionless gas phase flow rate is as follows:

[0085] The initial dimensionless gas phase flow rate was calculated.

[0086] Calculated =0.8; After obtaining the initial dimensionless gas phase flow rate Then, continue with steps S20-S40 to obtain the current productivity index.

[0087] S20: Calculated

[0088]

[0089] Calculated

[0090] S30: Calculated =1.4 The specific formula for calculating the bottom-hole oil-water ratio is as follows:

[0091] The parameters in the formula for calculating the oil-water ratio at the bottom of the well are shown in Table 3.

[0092] Table 3

[0093] Calculated =1.4 Calculated =0.417

[0094] The parameters in the formula are shown in Table 4.

[0095] Table 4

[0096] Calculated =0.102, =1.012, =1.013, =0.993 Calculate the difference between the current productivity index and the target historical productivity index as the index difference. If it is greater than the preset deviation of 0.002, then repeat the optimization step. at this time =6732 m³ / d Second calculation: S10: Calculated =0.8, =0.6732 S20: Calculated =1856.83 S30: Calculated =1.4 The specific formula for calculating the bottom-hole oil-water ratio is as follows:

[0097] The parameters in the formula for calculating the oil-water ratio at the bottom of the well are shown in Table 5.

[0098] Table 5

[0099] Calculated =1.3998 Calculated =0.417

[0100] The parameters in the formula are shown in Table 6.

[0101] Table 6

[0102] Calculated =0.101, =1.013, =1.013, =0.993 At this point, the difference between the current productivity index and the target historical productivity index is calculated as the index difference. If the index difference is less than the set threshold, it indicates that the three-phase productivity index is good. and Using the raw data, and performing steps S10-S40, the current productivity indicators are obtained.

[0103] S50 assesses the production capacity of the oil and gas wells under test based on current productivity indicators and obtains the production capacity assessment results.

[0104] Specifically, after determining the current productivity indicators of the oil and gas well to be tested, the current gas production capacity of the oil and gas well to be tested within the production cycle is determined. Y 4. Whether it is within the normal production range (e.g., 0.9-1.1) and the current gas production capacity. Y 4. If the test result is within the normal production range, it indicates that the tested oil and gas well can produce smoothly within the production cycle. Further analysis based on the current oil production capacity is required. Y 2 and current gas production capacity Y3. Assess the production capacity of the oil and gas wells to be tested. The specific assessment process includes: I. Current oil production capacity Y 2 and current gas production capacity Y If all three values ​​are less than the evaluation threshold (e.g., 0.98), it indicates that both oil and water phases are accumulating in the wellbore of the oil and gas well being tested. This results in increased liquid accumulation in the wellbore, leading to a high risk of reduced production. The resulting evaluation result of "high risk of reduced production due to wellbore liquid accumulation" is used to prompt staff to adjust production parameters to enhance the gas phase's liquid-carrying capacity.

[0105] II. Current oil production capacity Y 2 and current gas production capacity Y If all three values ​​are greater than the evaluation threshold, it indicates that there is no liquid phase accumulation in the wellbore of the oil and gas well being tested, the liquid accumulation in the wellbore is reduced, the risk of production reduction is low, and an evaluation result of low risk of production reduction due to liquid accumulation is generated to remind staff that there is no need to adjust production parameters to enhance the gas phase liquid carrying capacity.

[0106] III. Current oil production capacity Y 2 or current dimensionless water production Y If one of the three capabilities is greater than the assessment threshold and the other is less than the assessment threshold, it indicates that oil or water phase accumulation has occurred in the wellbore of the oil and gas well being tested, and the well is at risk of production reduction. An assessment result of medium risk of production reduction due to wellbore fluid accumulation is generated to prompt staff to consider adjusting production parameters to enhance the gas phase oil carrying capacity.

[0107] Furthermore, given the current oil production capacity Y 2 is greater than the evaluation threshold and the current dimensionless water production Y If the value is less than the evaluation threshold, it indicates that oil phase accumulation has occurred in the wellbore of the oil and gas well being tested; when the current oil production capacity is... Y 2. Less than the evaluation threshold and the current dimensionless water production Y If 3 is greater than the evaluation threshold, it indicates that water phase accumulation has occurred in the wellbore of the oil and gas well being tested.

[0108] Furthermore, given the current gas production capacity Y 4. If it is not within the normal production range, it means that the oil and gas well under test has a large amount of gas phase release or accumulation during the production cycle. This indicates that the oil and gas well is in an abnormal production state (such as some valves failing). Production needs to be stopped, staff should be notified to test the oil and gas well, and after troubleshooting, production should be resumed and data should be recorded again.

[0109] This application's embodiments determine the three-phase productivity index within the tubing of the tested oil and gas well using readily obtainable field production parameters such as reservoir pressure, reservoir temperature, bottom hole flowing pressure, tubing diameter, gas phase flow rate, oil phase flow rate, and water phase flow rate. This solves the problem of existing traditional critical fluid-carrying flow rate models and liquid accumulation models failing under scenarios such as high gas-liquid ratios and three-phase flow of oil, gas, and water, overcoming the limitations of traditional evaluation methods under high gas-liquid ratio conditions. The oil, gas, and water three-phase productivity index determined by this application's embodiments is used to evaluate the production capacity of the tested oil and gas well, and to determine whether gas flow enhancement fluid-carrying measures are needed to control the formation of liquid accumulation in the oil and gas well, ultimately preventing production reductions caused by liquid accumulation and extending the well's lifespan.

[0110] While this application provides the method operation steps as described in the embodiments or flowcharts, more or fewer operation steps may be included based on conventional or non-inventive labor. The order of steps listed in this embodiment is merely one possible execution order among many and does not represent the only execution order. In actual device or client product execution, the methods shown in this embodiment or the accompanying drawings can be executed sequentially or in parallel (e.g., in a parallel processor or multi-threaded processing environment).

[0111] like Figure 3 As shown in the illustration, this application also provides an apparatus for evaluating the multiphase production capacity of oil and gas wells. The apparatus includes: The dimensionless data processing module 10 is used to acquire the raw data of the oil and gas well to be tested, and to preprocess the raw data to obtain dimensionless data.

[0112] The wellhead production gas-liquid ratio determination module 20 is used to collect the gas phase flow rate, oil phase flow rate and water phase flow rate after separation by the wellhead splitter in real time through natural gas wellhead instruments, and determine the wellhead production gas-liquid ratio based on the gas phase flow rate, oil phase flow rate and water phase flow rate.

[0113] Productivity index coefficient determination module 30 is used to obtain the tubing parameters of the oil and gas well to be tested and combine them with the wellhead production gas-liquid ratio to determine the productivity index coefficient.

[0114] The current productivity index calculation module 40 is used to obtain the bottom liquid phase water cut, and combine it with dimensionless data, wellhead production gas-liquid ratio and productivity index coefficient to call the productivity index calculation formula to calculate the current productivity index of the oil and gas well to be tested.

[0115] The production capacity assessment module 50 is used to assess the production capacity of the oil and gas well under test based on the current productivity indicators and obtain the production capacity assessment results.

[0116] Some modules in the apparatus described in this application can be described in the general context of computer-executable instructions that are executed by a computer, such as program modules. Generally, program modules include routines, programs, objects, components, data structures, classes, etc., that perform a specific task or implement a specific abstract data type. This application can also be practiced in distributed computing environments where tasks are performed by remote processing devices connected via a communication network. In distributed computing environments, program modules can reside in local and remote computer storage media, including storage devices.

[0117] The apparatus or module described in the above embodiments can be implemented by a computer chip or physical entity, or by a product with a certain function. For ease of description, the above apparatus is described by dividing it into various modules according to their functions. When implementing the embodiments of this application, the functions of each module can be implemented in one or more software and / or hardware. Of course, a module that implements a certain function can also be implemented by combining multiple sub-modules or sub-units.

[0118] The methods, apparatus, or modules described in this application can be implemented in a computer-readable program code manner. The controller can be implemented in any suitable manner, such as a microprocessor or processor and a computer-readable medium storing computer-readable program code (e.g., software or firmware) executable by the (micro)processor, logic gates, switches, application-specific integrated circuits (ASICs), programmable logic controllers, and embedded microcontrollers. Examples of controllers include, but are not limited to, the following microcontrollers: ARC 625D, Atmel AT91SAM, Microchip PIC18F26K20, and Silicon Labs C8051F320. A memory controller can also be implemented as part of the control logic of a memory. Those skilled in the art will also recognize that, in addition to implementing the controller in purely computer-readable program code manner, the same functionality can be achieved by logically programming the method steps to make the controller take the form of logic gates, switches, application-specific integrated circuits, programmable logic controllers, and embedded microcontrollers. Therefore, such a controller can be considered a hardware component, and the means included within it for implementing various functions can also be considered as structures within the hardware component. Alternatively, the device used to implement various functions can be viewed as either a software module that implements the method or a structure within a hardware component.

[0119] This application also provides an apparatus, the apparatus comprising: a processor; a memory for storing processor-executable instructions; wherein, when the processor executes the executable instructions, it implements the method described in this application.

[0120] This application also provides a non-volatile computer-readable storage medium storing a computer program or instructions thereon, which, when executed, enables the method described in this application embodiment to be implemented.

[0121] Furthermore, in the various embodiments of the present invention, each functional module can be integrated into a processing module, or each module can exist independently, or two or more modules can be integrated into a single module.

[0122] The aforementioned storage media include, but are not limited to, Random Access Memory (RAM), Read-Only Memory (ROM), Cache, Hard Disk Drive (HDD), or Memory Card. The memory can be used to store computer program instructions.

[0123] As can be seen from the above description of the embodiments, those skilled in the art can clearly understand that this application can be implemented by means of software plus necessary hardware. Based on this understanding, the technical solution of this application, in essence, or the part that contributes to the prior art, can be embodied in the form of a software product, or it can be embodied in the process of data migration. The computer software product can be stored in a storage medium, such as ROM / RAM, magnetic disk, optical disk, etc., and includes several instructions to cause a computer device (which may be a personal computer, mobile terminal, server, or network device, etc.) to execute the methods described in various embodiments or some parts of the embodiments of this application.

[0124] The various embodiments described in this specification are presented in a progressive manner. Similar or identical parts between embodiments can be referred to interchangeably. Each embodiment focuses on its differences from other embodiments. All or part of this application can be used in numerous general-purpose or special-purpose computer system environments or configurations. Examples include: personal computers, server computers, handheld or portable devices, tablet devices, mobile communication terminals, multiprocessor systems, microprocessor-based systems, programmable electronic devices, network PCs, minicomputers, mainframe computers, and distributed computing environments including any of the above systems or devices, etc.

[0125] The above embodiments are only used to illustrate the technical solutions of this application, and are not intended to limit this application. Although this application has been described in detail with reference to the foregoing embodiments, those skilled in the art should understand that modifications can still be made to the technical solutions described in the foregoing embodiments, or equivalent substitutions can be made to some or all of the technical features therein. Such modifications or substitutions do not cause the essence of the corresponding technical solutions to deviate from the scope of the technical solutions of this application.

Claims

1. A method for evaluating the multiphase production capacity of oil and gas wells, characterized in that, include: S10: Obtain the raw data of the oil and gas well to be tested, and preprocess the raw data to obtain dimensionless data; S20: The gas phase flow rate, oil phase flow rate and water phase flow rate after separation by the wellhead splitter are collected in real time through the natural gas wellhead instrument, and the wellhead production gas-liquid ratio is determined based on the gas phase flow rate, the oil phase flow rate and the water phase flow rate; S30: Obtain the tubing parameters of the oil and gas well to be tested and, in conjunction with the wellhead gas-liquid production ratio, determine the productivity index coefficient; S40: Obtain the bottom liquid phase water cut, and combine it with the dimensionless data, the wellhead production gas-liquid ratio and the productivity index coefficient, and call the productivity index calculation formula to calculate the current productivity index of the oil and gas well to be tested; S50: Evaluate the production capacity of the oil and gas well to be tested based on the current productivity indicators, and obtain the production capacity evaluation results.

2. The method for evaluating the multiphase production capacity of oil and gas wells according to claim 1, characterized in that, The process of acquiring raw data from the oil and gas well to be tested and preprocessing the raw data to obtain dimensionless data includes: If the original data includes the original reservoir temperature, the original reservoir pressure, and the original bottom hole flowing pressure, then the original reservoir temperature is processed to obtain a dimensionless reservoir temperature. Based on the original reservoir pressure and the original bottom hole flowing pressure, the current gas flow rate entering the wellbore steady state from the current formation is calculated using the production capacity equation, and the current gas flow rate entering the wellbore steady state from the current formation is processed into a dimensionless value to obtain the current dimensionless gas flow rate. The dimensionless reservoir temperature and the current dimensionless gas flow rate are used as dimensionless data.

3. The method for evaluating the multiphase production capacity of oil and gas wells according to claim 1, characterized in that, The process of acquiring raw data from the oil and gas well to be tested and preprocessing the raw data to obtain dimensionless data includes: If the original data only includes the original reservoir temperature, the average gas flow rate is added to the original data as the initial formation gas flow rate into the wellbore steady state to update the original data; An optimization step is performed based on the updated original data. The optimization step includes: Based on the updated raw data, perform steps S10 to S40 to obtain the current productivity index; Obtain the target historical productivity index, and calculate the difference between the current productivity index and the target historical productivity index as the index difference; When the difference between the indicators is greater than or equal to the preset deviation, the target historical productivity indicator is updated based on the current productivity indicator, the gas production capacity in the target historical productivity indicator is obtained as the target gas production capacity, and the gas phase flow rate of the current formation entering the wellbore steady state is determined by combining the average value of the gas phase flow rate. The current formation gas flow rate entering the wellbore steady state is used as the new initial formation gas flow rate entering the wellbore steady state and added to the original data to update the original data. The optimization steps are repeated until the index difference is less than the preset deviation. Then, the corresponding original data is obtained and the original data is preprocessed to obtain dimensionless data.

4. The method for evaluating the multiphase production capacity of oil and gas wells according to claim 1, characterized in that, The determination of the wellhead production gas-liquid ratio based on the gas phase flow rate, the oil phase flow rate, and the water phase flow rate includes: Calculate the average values ​​of the gas phase flow rate, the oil phase flow rate, and the water phase flow rate; The average flow rate of the oil phase and the average flow rate of the water phase are added together to obtain the average liquid production rate. The wellhead gas-liquid ratio is determined by the ratio of the average gas flow rate to the average liquid production rate.

5. The method for evaluating the multiphase production capacity of oil and gas wells according to claim 4, characterized in that, Before obtaining the bottom-hole liquid phase water cut, the method for assessing the multiphase production capacity of oil and gas wells further includes: The wellhead oil-water ratio is determined based on the ratio of the average oil phase flow rate to the average water phase flow rate. Based on the tubing inner diameter, tubing outer diameter, and wellhead gas-liquid ratio of the oil and gas well to be tested, the bottom oil-water ratio calculation coefficient table is traversed to determine the bottom oil-water ratio calculation coefficient. Based on the wellhead oil-water ratio, the wellhead gas-liquid ratio, the dimensionless data, and the bottom-hole oil-water ratio calculation coefficient, the bottom-hole oil-water ratio is determined by the bottom-hole oil-water ratio calculation formula. The bottom oil-water ratio is calculated using the formula for calculating bottom liquid phase water cut, and the bottom liquid phase water cut is obtained. The specific formula for calculating the bottom-hole oil-water ratio is as follows: In the formula, OWR 2 indicates the oil-water ratio at the bottom of the well. OWR 1 indicates the oil-water ratio at the wellhead. D , E , F , G and H This represents the calculation coefficient for the oil-water ratio at the bottom of the well. X 2 indicates the gas-liquid ratio produced at the wellhead; X 1 and X 4 represents dimensionless data, where, X 1 represents the dimensionless reservoir temperature. X 4 represents dimensionless gas phase flow rate; The specific formula for calculating the bottom-hole liquid phase water cut is as follows: In the formula, X 3 indicates the bottom-hole liquid water cut. OWR 2 indicates the oil-water ratio at the bottom of the well.

6. The method for evaluating the multiphase production capacity of oil and gas wells according to claim 3, characterized in that, The formula for calculating the productivity index is as follows: In the formula, J, K, L, M, N This represents a productivity index coefficient. Y i Indicators of productivity X 1 represents the dimensionless reservoir temperature. X 2 indicates the gas-liquid ratio produced at the wellhead. X 3 indicates the bottom-hole liquid water cut. X 4 represents the dimensionless gas phase flow rate.

7. The method for evaluating the multiphase production capacity of oil and gas wells according to claim 1, characterized in that, The current productivity indicators include current gas production capacity, current oil production capacity, and current water production capacity; The process of assessing the production capacity of the oil and gas well under test based on the current productivity indicators and obtaining the production capacity assessment results includes: Determine whether the current gas production capacity of the oil and gas well under test is within the normal production range during the production cycle. If the current gas production capacity is within the normal production range, compare the current oil production capacity and the current gas production capacity with the evaluation threshold respectively. When both the current oil production capacity and the current gas production capacity are less than the evaluation threshold, it indicates that the oil phase and water phase are accumulating simultaneously in the wellbore of the oil and gas well being tested, resulting in a production capacity evaluation result of high risk of reduced production due to wellbore fluid accumulation. When both the current oil production capacity and the current gas production capacity are greater than the evaluation threshold, it indicates that there is no liquid phase accumulation in the wellbore of the oil and gas well under test, resulting in a low-risk production capacity evaluation result of liquid accumulation leading to reduced production. If one of the current oil production capacity and the current gas production capacity is greater than the evaluation threshold and the other is less than the evaluation threshold, it indicates that oil phase accumulation or water phase accumulation has occurred in the wellbore of the oil and gas well being tested, generating a production capacity assessment result for the risk of wellbore fluid accumulation and production reduction.

8. A device for evaluating the multiphase production capacity of oil and gas wells, characterized in that, include: The dimensionless data processing module is used to acquire the raw data of the oil and gas well to be tested, and to preprocess the raw data to obtain dimensionless data. The wellhead production gas-liquid ratio determination module is used to collect the gas phase flow rate, oil phase flow rate and water phase flow rate after separation by the wellhead splitter in real time through natural gas wellhead instruments, and determine the wellhead production gas-liquid ratio based on the gas phase flow rate, the oil phase flow rate and the water phase flow rate; The productivity index coefficient determination module is used to obtain the tubing parameters of the oil and gas well to be tested and, in combination with the wellhead gas-liquid production ratio, determine the productivity index coefficient. The current productivity index calculation module is used to obtain the bottom liquid phase water cut, and combine the dimensionless data, the wellhead production gas-liquid ratio and the productivity index coefficient to call the productivity index calculation formula to calculate the current productivity index of the oil and gas well to be tested. The production capacity assessment module is used to assess the production capacity of the oil and gas well under test based on the current productivity indicators and obtain the production capacity assessment results.

9. An apparatus for performing a method for assessing the multiphase production capacity of oil and gas wells, characterized in that, include: processor; Memory used to store processor-executable instructions; When the processor executes the executable instructions, it implements the method as described in any one of claims 1 to 7.

10. A non-volatile computer-readable storage medium, characterized in that, Includes storage of computer programs or instructions that, when executed, cause the method as described in any one of claims 1 to 7 to be implemented.

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