A deepwater oilfield wellbore throttling digitization and water cut calculation method and computer equipment

Abstract

The present application relates to a kind of deepwater oilfield wellbore throttling digitization and water cut calculation method and computer equipment.The method has three core functions:1.throttling phenomenon digital representation is realized to the oil well of severe throttling, guide work system optimization and completion program improvement;2.based on relevant historical data, predict water cut when flowmeter fails;3.through the error of comparison test production and verified production, identify abnormal problem well (such as integrated throttling coefficient is negative), combined with shutdown test inversion correction reasonable throttling coefficient interval, calculate reasonable real water cut, support short-term prediction and dynamic analysis of water cut.The present application monitors flowmeter data quality by digital representation of wellbore throttling characteristics, predicts real water cut in short term during flowmeter failure or calibration, and provides reliable technical support for deepwater oilfield development process optimization and single well potential evaluation.

Description

Technical Field

[0001] This invention relates to the field of oil and gas field development engineering technology, and in particular to a digital method and computer equipment for calculating water cut in deep-water oilfield wellbore throttling. Background Technology

[0002] A certain deep-water oilfield cluster employs subsea wellhead development, lacking onshore single-well sampling points. Water cut monitoring typically relies on downhole multiphase flow meters. After water breakthrough, the fluid's PVT properties change, potentially leading to inaccurate water cut measurements. Significant errors in single-well water cut measurements severely impact the accuracy of single-well (reservoir) production dynamics and potential analysis, negatively affecting the effectiveness and economic viability of future adjustment wells, intervention wells, and flow field control. For example, due to flow meter errors, the daily test oil and verification oil discrepancy in a certain oilfield cluster reached 16%, severely impacting single-well potential analysis and further affecting the effectiveness of adjustment and intervention wells, resulting in potential economic losses exceeding 60 million RMB.

[0003] Furthermore, the oil well production tubing in the oilfield cluster employs a dual-tank, dual-pump structure. The two pumps are switched via a TDV (Automated Directional Control Valve), allowing for one-on-one standby operation of the electric submersible pump unit. After collecting fluid, the downhole EDV pump delivers it to the production tubing via the directional control valve, and then to the wellhead's Christmas tree. If the TDV experiences throttling, it will severely limit the release of oil well productivity, significantly impacting oilfield development and production indicators. The throttling coefficient is related to the well's water cut. If the flowmeter's measurement of the well's water cut has a large error, it will affect the calculated throttling coefficient, leading to inaccurate identification of throttling phenomena. Summary of the Invention

[0004] The technical problem to be solved by the present invention is to provide a method and computer equipment for digitalizing wellbore throttling and calculating water cut in deepwater oilfields.

[0005] The technical solution adopted by this invention to solve its technical problem is: a method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields, comprising the following steps:

[0006] S1. When the error between the tested production and the verified production on shore exceeds the preset production error threshold, acquire reservoir PVT data, the current wellhead temperature and pressure of each well, the current pressure at the outlet of the downhole oil and gas acquisition equipment of each well, and the current water cut measured by the subsea multiphase flow meter of each well. Based on the relationship between water cut and the integrated throttling coefficient, calculate the current integrated throttling coefficient of each well. Perform the following steps for each well:

[0007] S2. If the current integrated throttling coefficient of the current oil well is less than the first preset coefficient threshold, then obtain the difference in onshore verified production of the oil field before and after the current oil well is shut down for a certain period of time, with the working system of other oil wells remaining unchanged. Calculate the current true water cut of the current oil well based on the difference in onshore verified production.

[0008] S3. Calculate the actual integrated throttling coefficient of the current oil well based on the current true water cut and the relationship between the water cut and the integrated throttling coefficient.

[0009] S4. Obtain the wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and the actual integrated throttling coefficient after the current oil well resumes production. Based on the relationship between the water cut and the integrated throttling coefficient, calculate the predicted water cut of the current oil well during the underwater multiphase flow meter calibration period.

[0010] Furthermore, after step S1, the following is also included:

[0011] S5. If the current integrated throttling coefficient of the current oil well is between the first preset coefficient threshold and the second preset coefficient threshold, and the absolute value of the difference between the current and the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain the current oil well's historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and water cut measured by the subsea multiphase flow meter. Based on the relationship between the water cut and the integrated throttling coefficient, calculate the historical integrated throttling coefficient of the current oil well.

[0012] S6. Obtain the current wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and the historical integrated throttling coefficient of the current oil well. Based on the relationship between the water cut and the integrated throttling coefficient, calculate the predicted water cut of the current oil well during the period of failure of the subsea multiphase flow meter.

[0013] Furthermore, after step S1, the following is also included:

[0014] S7. If the current integrated throttling coefficient of the current oil well is greater than the second preset coefficient threshold and the absolute value of the difference between the current oil well and the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain the wellhead temperature and wellhead pressure of the current oil well, the pressure at the outlet of the downhole oil and gas acquisition equipment, and the measured water cut of the subsea multiphase flow meter. Based on the relationship between water cut and integrated throttling coefficient, calculate the integrated throttling coefficient of the current oil well.

[0015] S8. Determine whether the current oil well exhibits a throttling phenomenon based on all the integrated throttling coefficients.

[0016] Further, in step S8, the duration for which the statistically integrated throttling coefficient is greater than the second preset coefficient threshold and the absolute value of the difference between the coefficient and the second preset coefficient threshold exceeds a preset coefficient error threshold is determined. If the duration exceeds a preset time threshold, it is determined that the current oil well has a throttling phenomenon.

[0017] Furthermore, the relationship between the moisture content and the integrated throttling coefficient is as follows:

[0018] ΔP=ΔP 油管 ×(1+ICC)+(ρ og ×(1-WC)+ρ W *WC)×g×h,

[0019] Where ΔP is the difference between the pressure at the outlet of the downhole oil and gas extraction equipment and the pressure at the wellhead. 油管 For the pressure drop loss during oil pipe flow, ICC is the combined throttling coefficient, ρ og The corrected fluid mixing density is given by WC, where WC is the water content and ρ is the density of the fluid mixture. w ρ is the formation water density, g is the gravitational acceleration, and h is the vertical depth from the outlet of the downhole oil and gas extraction equipment to the wellhead.

[0020] Furthermore, the method for calculating the pressure drop loss during oil pipe flow is as follows:

[0021] The corrected fluid mixing density and the second-corrected wellhead fluid mixing viscosity are obtained, and the tubing flow pressure drop loss is calculated based on the Fanning formula.

[0022] Furthermore, the calculation method for the mixed viscosity of the wellhead fluid after secondary correction is as follows:

[0023] Calculate the mixing viscosity of wellhead fluid under wellhead pressure conditions based on trendline functions;

[0024] The mixing viscosity of the wellhead fluid under pressure conditions is corrected using the following formula:

[0025] η mix =η0×(1-WC)+η water ×WC,

[0026] Where, η mix The wellhead fluid mixture viscosity is the corrected viscosity after one adjustment, η0 is the wellhead fluid mixture viscosity under wellhead pressure conditions, WC is the water cut, and η water Formation water viscosity;

[0027] The following formula is used for secondary correction under temperature conditions:

[0028]

[0029] Where, ηmixcorrect η represents the wellhead fluid mixing viscosity after secondary correction. mix Here, R represents the wellhead fluid mixing viscosity after one correction, and R is the gas constant. As the activation energy of crude oil, For water activation energy, T res For reservoir temperature, T head WC represents the wellhead temperature and WC represents the water cut.

[0030] Furthermore, the formula for calculating the corrected fluid mixing density is as follows:

[0031] ρ mix =(ρ oil +ρ gas ×GOR) / B ocorrect ,

[0032] Where, ρ mix For the corrected fluid mixing density, ρ oil ρ is the density of crude oil. gas Here, GOR represents the density of natural gas, and B represents the gas-oil ratio. ocorrect This is the corrected wellhead fluid volume factor.

[0033] Furthermore, the method for calculating the corrected wellhead fluid volume factor is as follows:

[0034] Calculate the wellhead fluid volume coefficient under wellhead pressure conditions based on the trend line function;

[0035] The wellhead fluid volume coefficient is corrected for temperature conditions using the following formula:

[0036] B ocorrect =B o *(1+(T head -T res )*0.00095,

[0037] Among them, B ocorrect B is the corrected wellhead fluid volume factor. o The wellhead fluid volume coefficient, T, under wellhead pressure conditions. head T represents the wellhead temperature. res This refers to the reservoir temperature.

[0038] A computer device, a memory, and a processor are also provided, wherein the memory stores a computer program executable by the processor, and the processor executes the computer program to implement the steps of the deepwater oilfield wellbore throttling digitization and water cut calculation method as described in any of the preceding claims.

[0039] The deep-water oilfield wellbore throttling digitization and water cut calculation method and computer equipment of the present invention have the following beneficial effects: When the error between the oilfield's test production and the onshore verified production exceeds a preset production error threshold, the current integrated throttling coefficient of the oil well is calculated, which can digitally characterize the throttling status of the oil well; by comparing the current integrated throttling coefficient of the oil well with a first preset coefficient threshold, problem wells with flow meter anomalies can be accurately identified, and then the water cut during the underwater multiphase flow meter calibration period can be predicted and calculated using a stable real integrated throttling coefficient, providing reliable technical support for the accuracy of single-well production dynamics and potential analysis in the absence of flow meters. Attached Figure Description

[0040] The present invention will be further described below with reference to the accompanying drawings and embodiments. In the accompanying drawings:

[0041] Figure 1 This is a flowchart illustrating the method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields according to one embodiment of the present invention.

[0042] Figure 2 This is a comparison diagram of the flow meter before and after calibration in one embodiment of the present invention;

[0043] Figure 3 This is a comparison diagram before and after well workover guided by the integrated throttling coefficient in one embodiment of the present invention;

[0044] Figure 4 This is a schematic diagram of the trend line between wellhead pressure and fluid volume coefficient according to an embodiment of the present invention;

[0045] Figure 5 This is a schematic diagram of the trend line between wellhead pressure and mixing viscosity according to an embodiment of the present invention. Detailed Implementation

[0046] To provide a clearer understanding of the technical features, objectives, and effects of the present invention, specific embodiments of the present invention will now be described in detail with reference to the accompanying drawings.

[0047] like Figure 1 As shown, in one embodiment of the digital throttling and water cut calculation method for deepwater oilfield wellbore according to the present invention, the following steps are included:

[0048] S1. When the error between the test production of the oilfield and the production verified on shore exceeds the preset production error threshold, obtain the reservoir PVT data, the current wellhead temperature and pressure of each oil well, the current pressure at the outlet of the downhole oil and gas acquisition equipment of each oil well, and the current water cut measured by the subsea multiphase flow meter of each oil well. Based on the relationship between water cut and the integrated throttling coefficient, calculate the current integrated throttling coefficient of each oil well.

[0049] In this embodiment, since no sampling points are set up for each individual well onshore in a certain deepwater oilfield cluster, the verified production onshore refers to the total oil production obtained by measuring the output of all oil wells in the oilfield cluster after it is transported to shore (such as oil and gas field gathering and transportation stations, refineries, etc.). Subsea multiphase flow meters can be installed at subsea wellheads or manifolds for real-time online measurement of single-well production. The tested production of the oilfield refers to the total oil production calculated by measuring the fluid production and water cut provided by the subsea multiphase flow meters installed in each well. The production error threshold is set according to the overall production situation of the deepwater oilfield cluster. In this embodiment, the production error threshold is set to 5%. An error exceeding 5% indicates an anomaly.

[0050] The reservoir PVT data in this embodiment includes fluid mixing viscosity, gas constant, crude oil activation energy, water activation energy, reservoir temperature, crude oil density, natural gas density, gas-oil ratio, wellhead fluid volume factor, and formation water viscosity. Furthermore, since the reservoir types in the oilfield cluster are basically the same, this data is applicable to all wells within that cluster. The current wellhead temperature and pressure are the fluid temperature and pressure currently measured at the well's tree inlet. The current pressure at the outlet of the downhole gas extraction equipment (i.e., ESP) is the fluid pressure currently measured at the outlet of the downhole gas extraction equipment. Additionally, the fluid temperature at the outlet of the downhole gas extraction equipment (i.e., ESP) can be obtained to compare whether the reservoir temperature has changed, thus ensuring the accuracy of the calculation results. By substituting the relevant data for each well into the relationship between water cut and the unified throttling coefficient, the current unified throttling coefficient for each well can be calculated, thereby digitally representing the wellbore throttling status of each well. The integrated throttling coefficient refers to the throttling coefficient calculated by combining multiple throttling influencing factors, used to characterize the degree of throttling within the oil well. The relationship between water cut and the integrated throttling coefficient is constructed using the pressure difference method, which integrates throttling influencing factors such as tubing flow pressure drop loss, local tubing pressure drop loss, accelerated pressure drop loss, and fluid pressure drop loss.

[0051] Perform the following steps for each oil well:

[0052] S2. If the current integrated throttling coefficient of the current oil well is less than the first preset coefficient threshold, then obtain the difference in onshore verified production of the oil field before and after the current oil well is shut down for a certain period of time, with the working system of other oil wells remaining unchanged. Calculate the current true water cut of the current oil well based on the difference in onshore verified production.

[0053] Specifically, since the actual integrated throttling coefficient should not be less than 0, the first preset coefficient threshold is set to 0. When the current integrated throttling coefficient of a certain oil well is less than 0, it indicates that its subsea multiphase flow meter has a significant error, and it is determined to be a problem well. Of course, in other embodiments, the value of the first preset coefficient threshold can be adjusted according to actual needs. With the operating procedures of other oil wells in the oilfield unchanged, the problem well is shut down for a certain period of time, and the difference in oil production and fluid production verified onshore before and after shutdown are obtained. Then, the current true water cut of the problem well is calculated.

[0054] S3. Based on the current true water cut of the current oil well and the relationship between water cut and the integrated throttling coefficient, calculate the current true integrated throttling coefficient of the current oil well.

[0055] Specifically, the reservoir PVT data, the current true water cut of the problem well, the current wellhead temperature and pressure, and the current pressure at the outlet of the downhole oil and gas extraction equipment are substituted into the relationship between water cut and the integrated throttling coefficient to calculate the true integrated throttling coefficient of the problem well.

[0056] S4. Obtain the wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and the actual combined throttling coefficient after the current oil well resumes production. Based on the relationship between water cut and combined throttling coefficient, calculate the predicted water cut of the current oil well during the underwater multiphase flow meter calibration period.

[0057] Specifically, the water cut of an oil well changes during the production process, while the wellbore structure typically remains constant, resulting in a relatively stable true integrated throttling coefficient. Therefore, by substituting reservoir PVT data, the true integrated throttling coefficient of the problematic well, and the wellhead temperature, wellhead pressure, and pressure at the outlet of the downhole oil and gas extraction equipment after production resumption into the relationship between water cut and the integrated throttling coefficient, the water cut of the problematic well can be predicted during the calibration of the subsea multiphase flowmeter. This method provides reliable technical support for the accuracy of single-well production dynamics and potential analysis by predicting the water cut of oil wells in the absence of flowmeters in the short term.

[0058] by Figure 2For example, well A5H in a certain oilfield cluster was put into production in December 2024 after implementing MRC technology. At that time, the water cut measured by the downhole multiphase flowmeter was 62.2%, and the well produced 376 cubic meters of oil per day. Subsequently, with the improvement of the well's operating system (while the operating systems of other oil wells remained unchanged), the total oil production verified onshore increased by approximately 640 cubic meters. The error between this and the increase in the oilfield's tested production exceeded the preset production error threshold. Based on the water cut of 62.2%, the integrated throttling coefficient for this well was calculated to be -2.0, which is inconsistent with the production dynamics of adjacent wells and the post-MRC geological reservoir understanding. Assuming that the throttling degree of this oil well is very low, and taking a positive value close to zero (0.1) for the integrated throttling coefficient, the calculation shows that the water cut of the oil well should be less than 49%. In summary, it can be concluded that there is a significant anomaly in the water cut measured by the downhole multiphase flowmeter.

[0059] After calibration of the flow meter, the flow meter measured the water cut of well A5H to be 36.8% and the daily oil production to be 634 cubic meters. The error compared to 36.2% was small, and the two sets of data showed high consistency, proving the reliability of the algorithm and its significant practical value. Figure 2 As can be seen from the figure, the moisture content measured by the flow meter changed significantly before and after calibration: the area before the dashed line represents the production situation before the flow meter calibration. Before calibration, the measured moisture content of the flow meter (the "Moisture Content (Flow Meter)" curve in the figure, i.e., curve 1) had a large error compared with the calculated actual moisture content at each time point (the "Moisture Content (Calculated)" curve in the figure, i.e., curve 2). The area after the dashed line represents the production situation after the flow meter calibration. The measured value of the flow meter after calibration had a very small error compared with the actual moisture content.

[0060] As can be seen, the method of the present invention can monitor the measurement quality of flow meters, detect abnormal flow meters, and predict the water cut of oil wells in the short term during the flow meter calibration period, providing reliable technical support for the accuracy of single-well production dynamics and potential analysis.

[0061] In one embodiment, step S1 is followed by:

[0062] S5. If the current integrated throttling coefficient of the current oil well is between the first preset coefficient threshold and the second preset coefficient threshold, and the absolute value of the difference between the current and the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain the current oil well's historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and water cut measured by the subsea multiphase flow meter. Based on the relationship between water cut and integrated throttling coefficient, calculate the current oil well's historical integrated throttling coefficient.

[0063] Specifically, the second preset coefficient threshold is greater than the first preset coefficient threshold, and the second preset coefficient threshold can be set according to the actual production status of each oil well in the oilfield. In this embodiment, the first preset coefficient threshold is set to 0, and the second preset coefficient threshold is set to 3. If the current integrated throttling coefficient of the oil well is between 0 and 3, and the difference from 3 exceeds the preset coefficient error threshold, it indicates that the subsea multiphase flow meter of the oil well also has an error, but the error is minor. Historical data when the current oil well production is stable and the flow meter is normal are obtained, including historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and water cut measured by the subsea multiphase flow meter, and the historical integrated throttling coefficient of the current oil well is calculated.

[0064] S6. Obtain the current wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and historical integrated throttling coefficient of the current oil well. Based on the relationship between water cut and integrated throttling coefficient, calculate the predicted water cut of the current oil well during the period of failure of the subsea multiphase flow meter.

[0065] Specifically, the water cut of an oil well changes during the production process, while the wellbore structure typically remains constant. The true integrated throttling coefficient is relatively stable, and the historical integrated throttling coefficient calculated from historical data during periods of stable production and normal flowmeter operation closely approximates the true integrated throttling coefficient. Therefore, by substituting reservoir PVT data, the historical integrated throttling coefficient of the problematic well, and the current wellhead temperature, wellhead pressure, and pressure at the outlet of the downhole oil and gas extraction equipment into the relationship between water cut and the integrated throttling coefficient, the water cut of the problematic well can be predicted during periods of subsea multiphase flowmeter failure (shorter than the flowmeter calibration time). This method provides reliable technical support for the accuracy of single-well production dynamics and potential analysis by predicting the water cut of oil wells in the absence of flowmeters in the short term.

[0066] In one embodiment, step S1 is followed by:

[0067] S7. If the current integrated throttling coefficient of the current oil well is greater than the second preset coefficient threshold, and the absolute value of the difference between the current oil well and the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain the wellhead temperature and wellhead pressure of the current oil well, the pressure at the outlet of the downhole oil and gas acquisition equipment, and the measured water cut of the subsea multiphase flow meter. Based on the relationship between water cut and integrated throttling coefficient, calculate the integrated throttling coefficient of the current oil well.

[0068] S8. Determine whether there is a throttling phenomenon in the current oil well based on all the integrated throttling coefficients.

[0069] If the current integrated throttling coefficient of the oil well is greater than the second preset coefficient threshold, and the difference between the two exceeds the preset coefficient error threshold, it indicates that the wellbore throttling condition may be abnormal. Therefore, relevant data from all time points since the oil well was put into production are obtained, and the integrated throttling coefficient at each time point is calculated. By digitally representing all throttling conditions in the wellbore, it is possible to determine whether a throttling phenomenon exists, which is beneficial for optimizing the oil well operating system and improving the completion plan in the later stages. In other embodiments, depending on actual needs, it is also possible to choose to observe only the throttling condition of the most recent period.

[0070] Specifically, in step S8, the duration for which the statistically integrated throttling coefficient is greater than the second preset coefficient threshold and the absolute value of the difference between the coefficient and the second preset coefficient threshold exceeds the preset coefficient error threshold is determined. If the duration exceeds the preset time threshold, it is determined that the current oil well has a throttling phenomenon.

[0071] Since the current abnormality of the integrated throttling coefficient may be caused by accidental factors, this embodiment calculates the duration for which the absolute value of the difference between the integrated throttling coefficient and the second preset coefficient threshold exceeds a preset coefficient error threshold. When the duration exceeds the preset time threshold, it is determined that the current oil well is experiencing a throttling phenomenon; otherwise, it can be considered an anomaly caused by accidental factors. The throttling phenomenon manifests as a sudden drop in oil well production and a sudden increase in the pressure at the electric submersible pump inlet, limiting the release of oil well production capacity.

[0072] refer to Figure 3 The flow data of well A3H in a certain oilfield cluster was analyzed daily and minutely to calculate the daily integrated throttling coefficient. A second preset threshold value of 10 was used. After throttling was detected, the TDV valve in the production tubing was replaced with an ADV valve, which has a lower throttling coefficient, during well workover operations. It can be seen that since well A3H was put into production (equipped with TDV valves), the integrated throttling coefficient of the wellbore has been between 30 and 180. After the subsequent well workover and replacement with ADV valves, the integrated throttling coefficient of the wellbore is generally less than 10, indicating less significant throttling. This significantly improves the production efficiency of the electric pump, promotes further release of oil well production capacity, and yields substantial economic benefits.

[0073] In one specific embodiment, the relationship between water content and the combined throttling coefficient is as follows:

[0074] ΔP=ΔP 油管 ×(1+ICC)+(ρ og ×(1-WC)+ρ W *WC)×g×h (1)

[0075] Wherein, ΔP is the difference between the pressure at the outlet of the downhole oil and gas extraction equipment (electric submersible pump) and the pressure at the wellhead. 油管 For the pressure drop loss during oil pipe flow, ICC is the combined throttling coefficient, ρ ogThe corrected fluid mixing density is given by WC, where WC is the water content and ρ is the density of the fluid mixture. w Where is the formation water density, g is the gravitational acceleration, and h is the vertical depth from the outlet of the downhole oil and gas extraction equipment to the wellhead. Formula (1) is applicable to situations where the fluid pressure at the wellhead is much higher than the saturation pressure. Its construction principle is: ESP outlet pressure - wellhead pressure = tubing flow pressure drop loss + tubing local pressure drop loss + acceleration pressure drop loss + fluid pressure drop loss.

[0076] In this embodiment, the method for calculating the pressure drop loss during oil pipe flow is as follows:

[0077] Obtain the corrected fluid mixing density and the second-corrected wellhead fluid mixing viscosity, and calculate the tubing flow pressure drop loss based on the Fanning formula. For the Fanning formula, please refer to existing technologies.

[0078] Specifically, the formula for calculating the corrected fluid mixing density is as follows:

[0079] ρ mix =(ρ oil +ρ gas ×GOR) / B ocorrect (2)

[0080] Where, ρ mix For the corrected fluid mixing density, ρ oil ρ is the density of crude oil. gas Here, GOR represents the density of natural gas, and B represents the gas-oil ratio. ocorrect This is the corrected wellhead fluid volume factor.

[0081] The method for calculating the corrected wellhead fluid volume factor in formula (2) is as follows:

[0082] A1. Calculate the wellhead fluid volume coefficient under wellhead pressure conditions based on a trendline function. This embodiment uses the least squares method for the trendline function, but other algorithms can also be used. For example... Figure 4 As shown, the horizontal axis represents wellhead pressure, and the vertical axis represents the wellhead fluid volume coefficient. Data such as wellhead pressure and corresponding wellhead fluid volume for a certain oilfield cluster are obtained. The relationship between wellhead pressure and wellhead fluid mixing viscosity for this oilfield cluster, calculated using a trend line function, is as follows:

[0083] B o = -0.0018*P head +1.1168 (3)

[0084] Among them, P head This refers to the wellhead pressure.

[0085] A2. Correct the wellhead fluid volume coefficient under temperature conditions using the following formula:

[0086] Bocorrect =B o *(1+(T head -T res )*0.00095 (4)

[0087] Among them, B ocorrect B is the corrected wellhead fluid volume factor. o The wellhead fluid volume coefficient, T, under wellhead pressure conditions. head T represents the wellhead temperature. res This refers to the reservoir temperature.

[0088] Specifically, the calculation method for the mixed viscosity of the wellhead fluid after secondary correction is as follows:

[0089] B1. Calculate the wellhead fluid mixing viscosity under wellhead pressure conditions based on the trendline function. This embodiment uses the least squares method for the trendline function, but other algorithms can also be used. For example... Figure 5 As shown, the horizontal axis represents wellhead pressure, and the vertical axis represents the wellhead fluid mixing viscosity. The relationship between wellhead pressure and the corresponding wellhead fluid mixing viscosity for a certain oilfield group was obtained using a trend line function.

[0090] η0=0.0024×P head +0.7104 (5)

[0091] B2. Use the following formula to perform a first-order correction of the wellhead fluid mixing viscosity under pressure conditions:

[0092] η mix =η0×(1-WC)+η water ×WC (6)

[0093] Where, η mix The wellhead fluid mixture viscosity is the corrected viscosity after one adjustment, η0 is the wellhead fluid mixture viscosity under wellhead pressure conditions, WC is the water cut, and η water This refers to the viscosity of the formation water.

[0094] B3. Referring to the Arrhenius formula, perform a secondary correction under temperature conditions using the following formula:

[0095]

[0096] Where, η mixcorrect η represents the wellhead fluid mixing viscosity after secondary correction. mix Here, R represents the wellhead fluid mixing viscosity after one correction, and R is the gas constant. As the activation energy of crude oil, For water activation energy, T res For reservoir temperature, Thead WC represents the wellhead temperature and WC represents the water cut.

[0097] The above calculation formula can be constructed in an Excel spreadsheet, and the operation steps are simple. In some embodiments, it can also be constructed through programming.

[0098] In one embodiment of a computer device provided by the present invention, the device includes a memory and a processor. The memory stores a computer program executable by the processor. When the processor executes the computer program, it implements the steps of the deepwater oilfield wellbore throttling digitization and water cut calculation method disclosed in any of the above embodiments. Specifically, according to embodiments of the present invention, the processes described above with reference to the flowcharts can be implemented as computer software programs. For example, embodiments of the present invention include a computer program product comprising a computer program carried on a computer-readable medium, the computer program containing program code for performing the methods shown in the flowcharts. In such embodiments, the computer program can be downloaded and installed by a computer device and, when executed, performs the functions defined in the methods of the embodiments of the present invention. The computer device in the present invention can be a laptop, desktop computer, workstation, industrial control computer, server, etc.

[0099] It is understood that the above embodiments only illustrate preferred embodiments of the present invention, and their descriptions are relatively specific and detailed, but they should not be construed as limiting the scope of the present invention. It should be noted that those skilled in the art can freely combine the above technical features without departing from the concept of the present invention, and can also make several modifications and improvements, all of which fall within the protection scope of the present invention. Therefore, all equivalent transformations and modifications made with respect to the scope of the claims of the present invention should fall within the scope of the claims of the present invention.

Claims

1. A method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields, characterized in that, Includes the following steps: S1. When the error between the tested production and the verified production on shore exceeds the preset production error threshold, acquire reservoir PVT data, the current wellhead temperature and pressure of each well, the current pressure at the outlet of the downhole oil and gas acquisition equipment of each well, and the current water cut measured by the subsea multiphase flow meter of each well. Based on the relationship between water cut and the integrated throttling coefficient, calculate the current integrated throttling coefficient of each well. Perform the following steps for each well: S2. If the current integrated throttling coefficient of the current oil well is less than the first preset coefficient threshold, then obtain the difference in onshore verified production of the oil field before and after the current oil well is shut down for a certain period of time, with the working system of other oil wells remaining unchanged. Calculate the current true water cut of the current oil well based on the difference in onshore verified production. S3. Calculate the actual integrated throttling coefficient of the current oil well based on the current true water cut and the relationship between the water cut and the integrated throttling coefficient. S4. Obtain the wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and the actual integrated throttling coefficient after the current oil well resumes production. Based on the relationship between the water cut and the integrated throttling coefficient, calculate the predicted water cut of the current oil well during the underwater multiphase flow meter calibration period. The relationship between the moisture content and the combined throttling coefficient is as follows: , This is the difference between the pressure at the outlet of the downhole oil and gas extraction equipment and the pressure at the wellhead. This is the pressure drop loss during oil pipeline flow. To integrate the throttling coefficient, The corrected fluid mixing density, Moisture content, The density of the formation water, It is the acceleration due to gravity. The vertical depth from the outlet of the downhole oil and gas extraction equipment to the wellhead; The method for calculating the tubing flow pressure drop loss is as follows: obtain the corrected fluid mixing density and the wellhead fluid mixing viscosity after secondary correction, and calculate the tubing flow pressure drop loss based on the Fanning formula.

2. The method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields according to claim 1, characterized in that, Step S1 is followed by: S5. If the current integrated throttling coefficient of the current oil well is between the first preset coefficient threshold and the second preset coefficient threshold, and the absolute value of the difference between the current and the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain the current oil well's historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and water cut measured by the subsea multiphase flow meter. Based on the relationship between the water cut and the integrated throttling coefficient, calculate the historical integrated throttling coefficient of the current oil well. S6. Obtain the current wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and the historical integrated throttling coefficient of the current oil well. Based on the relationship between the water cut and the integrated throttling coefficient, calculate the predicted water cut of the current oil well during the period of failure of the subsea multiphase flow meter.

3. The method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields according to claim 2, characterized in that, Step S1 is followed by: S7. If the current integrated throttling coefficient of the current oil well is greater than the second preset coefficient threshold and the absolute value of the difference between the current oil well and the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain the wellhead temperature and wellhead pressure of the current oil well, the pressure at the outlet of the downhole oil and gas acquisition equipment, and the measured water cut of the subsea multiphase flow meter. Based on the relationship between water cut and integrated throttling coefficient, calculate the integrated throttling coefficient of the current oil well. S8. Determine whether the current oil well exhibits a throttling phenomenon based on all the integrated throttling coefficients.

4. The method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields according to claim 3, characterized in that, In step S8, the duration for which the statistically integrated throttling coefficient is greater than the second preset coefficient threshold and the absolute value of the difference between the coefficient and the second preset coefficient threshold exceeds a preset coefficient error threshold is determined. If the duration exceeds a preset time threshold, it is determined that the current oil well has a throttling phenomenon.

5. The method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields according to any one of claims 1-3, characterized in that, The calculation method for the mixed viscosity of the wellhead fluid after secondary correction is as follows: Calculate the mixing viscosity of wellhead fluid under wellhead pressure conditions based on trendline functions; The mixing viscosity of the wellhead fluid under pressure conditions is corrected using the following formula: ， in, The wellhead fluid mixing viscosity after one correction. The mixing viscosity of the wellhead fluid under wellhead pressure conditions. Moisture content, Formation water viscosity; The following formula is used for secondary correction under temperature conditions: ， in, The mixed viscosity of the wellhead fluid after secondary correction. The corrected wellhead fluid mixing viscosity. The gas constant is As the activation energy of crude oil, For water activation energy, For reservoir temperature, The wellhead temperature, This refers to the moisture content.

6. The method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields according to any one of claims 1-3, characterized in that, The formula for calculating the corrected fluid mixing density is as follows: , in, The corrected fluid mixing density, For crude oil density, For the density of natural gas, The gas-oil ratio, This is the corrected wellhead fluid volume factor.

7. The method for digitalizing wellbore throttling and calculating water cut in deepwater oilfields according to claim 6, characterized in that, The method for calculating the corrected wellhead fluid volume factor is as follows: Calculate the wellhead fluid volume coefficient under wellhead pressure conditions based on the trend line function; The wellhead fluid volume coefficient is corrected for temperature conditions using the following formula: ， in, This is the corrected wellhead fluid volume factor. Wellhead fluid volume coefficient under wellhead pressure conditions The wellhead temperature, This refers to the reservoir temperature.

8. A computer device, characterized in that, include: The system includes a memory and a processor, wherein the memory stores a computer program executable by the processor, and the processor executes the computer program to implement the steps of the deepwater oilfield wellbore throttling digitization and water cut calculation method as described in any one of claims 1 to 7.

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