Deepwater oil field shaft throttling digitization and moisture content calculation method and computer equipment

Abstract

The invention relates to a deepwater oil field shaft throttling digitization and moisture content calculation method and computer equipment. The method has the following three core functions: 1, the digital representation of the throttling phenomenon of an oil well which is seriously throttled is realized, and the optimization of a working system and the improvement of a well completion scheme are guided; 2, on the basis of related historical data, the water content is predicted when the flow meter fails; and 3, by comparing a test yield with a verification yield error, identifying an abnormal problem well (for example, an integrated throttling coefficient is a negative value), and by combining a shutdown test, inverting and correcting a reasonable throttling coefficient interval, calculating a reasonable real water content, and supporting short-term prediction and dynamic analysis of the water content. According to the method, by digitally representing the throttling characteristics of the shaft, monitoring the data quality of the flow meter and predicting the real water content in a short time during the failure or verification period of the flow meter, reliable technical support is provided for deepwater oilfield development process optimization and single well potential evaluation.

Description

Technical Field

[0001] The present invention relates to the technical field of oil and gas field development engineering, and in particular to a deepwater oil field wellbore throttling digitization and water content calculation method and computer equipment. Background Art

[0002] A cluster of deepwater oilfields utilizes subsea wellhead development. With no individual well sampling points onshore, water-cut monitoring typically relies on downhole multiphase flowmeters. When water breaks through an oil well, the fluid's PVT properties change, potentially causing inaccurate water-cut measurements. Significant errors in water-cut measurements for individual wells can severely impact the accuracy of production performance and potential analysis for that individual well (or reservoir), negatively impacting the effectiveness and economics of future adjustment wells, treatment wells, and flow field manipulation. For example, due to flowmeter measurement errors, the daily difference between test oil and verified oil in a cluster of oilfields reached 16%, severely impacting individual well potential analysis and further compromising the effectiveness of adjustment wells and treatment wells, resulting in potential economic losses exceeding 60 million RMB.

[0003] Furthermore, the production tubing in the oilfield cluster utilizes a dual-tank, dual-pump structure, with the dual pumps switched via a TDV automatic reversing valve. This dual-tank, dual-pump structure allows for one pump unit to be used and one to be backed up. The submersible pumps downhole collect fluid and deliver it to the production tubing through a reversing valve, which then delivers it to the Christmas tree at the wellhead. If the TDV automatic reversing valve throttles, it will severely limit the well's production capacity, significantly impacting oilfield development and production indicators. The calculation of the throttling coefficient is dependent on the well's water content. Significant errors in the water content measured by the flowmeter will affect the calculated throttling coefficient, making it impossible to accurately identify throttling. 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 throttling and calculating water content in a deepwater oilfield wellbore.

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

[0006] S1. When the error between the test production and the verified production onshore of the oil field exceeds a preset production error threshold, obtain the reservoir PVT data, the current wellhead temperature and wellhead pressure of each oil well, the current pressure at the outlet of the downhole oil and gas collection equipment of each oil well, and the current water cut measured by the underwater multiphase flowmeter 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; perform the following steps for each oil well:

[0007] S2. If the current integrated throttling coefficient of the current oil well is less than a first preset coefficient threshold, obtaining a difference in verified onshore production of the oil field before and after the current oil well is shut down for a certain period of time while the operating systems of other oil wells remain unchanged, and calculating the current true water cut of the current oil well based on the difference in verified onshore production;

[0008] S3. Calculating a true integrated throttling coefficient of the current oil well based on the current true water cut of the current oil well and a 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 true integrated throttling coefficient of the current oil well after production is resumed, and calculate the predicted water cut of the current oil well during the underwater multiphase flowmeter calibration based on the relationship between the water cut and the integrated throttling coefficient.

[0010] Furthermore, after step S1, the following steps are further included:

[0011] S5. If the current integrated throttling coefficient of the current oil well is between a first preset coefficient threshold and a second preset coefficient threshold, and the absolute value of the difference between the current integrated throttling coefficient and the second preset coefficient threshold exceeds a preset coefficient error threshold, obtaining historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and water cut measured by a subsea multiphase flowmeter for the current oil well, and calculating the historical integrated throttling coefficient of the current oil well based on a relationship between the water cut and the integrated throttling coefficient;

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

[0013] Furthermore, after step S1, the following steps are further 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 integrated throttling coefficient and the second preset coefficient threshold exceeds a preset coefficient error threshold, obtaining all wellhead temperatures and wellhead pressures of the current oil well, the pressure at the outlet of the downhole oil and gas collection equipment, and the water cut measured by the underwater multiphase flowmeter, and calculating all integrated throttling coefficients of the current oil well based on a relationship between the water cut and the integrated throttling coefficient;

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

[0016] Furthermore, in step S8, the duration of the time during which the integrated throttling coefficient is greater than the second preset coefficient threshold and the absolute value of the difference with the second preset coefficient threshold exceeds the preset coefficient error threshold is counted. If the duration exceeds the preset time threshold, it is determined that throttling occurs in the current oil well.

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

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

[0019] Among them, ΔP is the difference between the pressure at the outlet of the downhole oil and gas collection equipment and the wellhead pressure, ΔP 油管 is the oil pipe flow pressure drop loss, ICC is the integrated throttling coefficient, ρ og is the corrected fluid mixture density, WC is the water content, ρ w is the formation water density, g is the acceleration of gravity, and h is the vertical depth from the outlet of the downhole oil and gas collection equipment to the wellhead.

[0020] Furthermore, the calculation method of the oil pipe flow pressure drop loss is:

[0021] The corrected fluid mixed density and the secondary corrected wellhead fluid mixed viscosity are obtained, and the oil pipe flow pressure drop loss is calculated based on the Fanning formula.

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

[0023] Calculate the mixed viscosity of the wellhead fluid under the wellhead pressure condition based on the trend line function;

[0024] The following formula is used to perform a primary correction on the mixed viscosity of the wellhead fluid under pressure conditions:

[0025] η mix =η0×(1-WC)+η water ×WC,

[0026] Among them, η mix is the wellhead fluid mixed viscosity after one correction, η0 is the wellhead fluid mixed viscosity under wellhead pressure conditions, WC is the water cut, η water is the formation water viscosity;

[0027] The secondary correction under temperature conditions is performed using the following formula:

[0028]

[0029] Among them, ηmixcorrect is the mixed viscosity of the wellhead fluid after secondary correction, η mix is the wellhead fluid mixed viscosity after one correction, R is the gas constant, is the activation energy of crude oil, is the water activation energy, T res is the reservoir temperature, T head is the wellhead temperature, and WC is the water content.

[0030] Furthermore, the calculation formula of the corrected fluid mixture density is:

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

[0032] Among them, ρ mix is the corrected fluid mixture density, ρ oil is the density of crude oil, ρ gas is the density of natural gas, GOR is the gas-oil ratio, B ocorrect is the corrected wellhead fluid volume coefficient.

[0033] Furthermore, the calculation method of the corrected wellhead fluid volume coefficient is:

[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 under temperature conditions using the following formula:

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

[0037] Among them, B ocorrect is the corrected wellhead fluid volume coefficient, B o Wellhead fluid volume coefficient under wellhead pressure conditions, T head is the wellhead temperature, T res is 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 when the processor executes the computer program, the steps of the deepwater oilfield wellbore throttling digitization and water content calculation method as described in any one of the above items are implemented.

[0039] The implementation of the deepwater oilfield wellbore throttling digitization and water cut calculation method and computer equipment of the present invention has the following beneficial effects: when the error between the test production of the oilfield and the verified production onshore exceeds the preset production error threshold, the current integrated throttling coefficient of the oil well is calculated, and the throttling condition of the oil well can be digitally represented; by comparing the current integrated throttling coefficient of the oil well with the first preset coefficient threshold, problem wells with flow meter anomalies can be accurately identified, and then the stable real integrated throttling coefficient is used to predict and calculate the water cut during the underwater multiphase flow meter calibration period. In the absence of a flow meter, reliable technical support is provided for the accuracy of single well production dynamics and potential analysis. BRIEF DESCRIPTION OF THE DRAWINGS

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

[0041] Figure 1 It is a flow chart of a method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to one embodiment of the present invention;

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

[0043] Figure 3 This is a comparison diagram before and after guiding a well repair based on the integrated throttling coefficient in one embodiment of the present invention;

[0044] Figure 4 1 is a trend line diagram of wellhead pressure and fluid volume coefficient according to an embodiment of the present invention;

[0045] Figure 5 FIG. 1 is a trend line diagram of wellhead pressure and mixed viscosity according to an embodiment of the present invention. DETAILED DESCRIPTION

[0046] In order to have a clearer understanding of the technical features, purposes and effects of the present invention, specific embodiments of the present invention are now described in detail with reference to the accompanying drawings.

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

[0048] S1. When the error between the test production of the oil field and the verified production onshore exceeds the preset production error threshold, obtain the reservoir PVT data, the current wellhead temperature and wellhead pressure of each oil well, the current pressure at the outlet of the downhole oil and gas collection equipment of each oil well, and the current water cut measured by the underwater multiphase flowmeter of each oil well. Based on the relationship between water cut and 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 on shore in a certain deepwater oilfield group, the verified production of the oilfield on shore refers to the total oil production measured by metering equipment after the output of all oil wells in the oilfield group is transported to shore (such as an oil and gas field gathering station, refinery, etc.). Subsea multiphase flowmeters can be installed at seabed oil trees or manifolds to perform real-time online measurement of single well production. The test production of the oilfield refers to the total oil production calculated by measuring the liquid production and water content provided by the underwater multiphase flowmeter installed in each oil well. The production error threshold is set based on the overall production situation of the deepwater oilfield group. In this embodiment, the production error threshold is set to 5%. An error exceeding 5% indicates an abnormality.

[0050] The reservoir PVT data in this embodiment includes data such as fluid mixed viscosity, gas constant, crude oil activation energy, water activation energy, reservoir temperature, crude oil density, natural gas density, gas-to-oil ratio, wellhead fluid volume coefficient, and formation water viscosity. Furthermore, since the reservoir types within an oilfield group are essentially the same, this data applies to all wells within the group. The current wellhead temperature and wellhead pressure of an oil well are the fluid temperature and pressure currently measured at the inlet of the oil tree of that oil well. The current pressure at the outlet of the downhole oil and gas acquisition equipment (i.e., electric submersible pump) of the oil well is the fluid pressure currently measured at the outlet of the downhole oil and gas acquisition equipment. Furthermore, the fluid temperature at the outlet of the downhole oil and gas acquisition equipment (i.e., electric submersible pump) can also be obtained to compare whether the reservoir temperature has changed, thereby ensuring the accuracy of the calculation results. By substituting the relevant data for each oil well into the relationship between water cut and integrated throttling coefficient, the current integrated throttling coefficient corresponding to each oil well can be calculated, thereby digitally representing the wellbore throttling status of each oil well. The integrated throttling coefficient is calculated by integrating multiple factors affecting throttling and is used to characterize the degree of throttling within an oil well. The relationship between water cut and the integrated throttling coefficient is constructed using the pressure differential method, integrating factors such as tubing flow pressure drop loss, local tubing pressure drop loss, acceleration pressure drop loss, and fluid pressure drop loss.

[0051] Perform the following steps for each well:

[0052] S2. If the current integrated throttling coefficient of the current oil well is less than the first preset coefficient threshold, the difference in verified onshore production of the oil field before and after the current oil well is shut down for a certain period of time while the working system of other oil wells remains unchanged is obtained, and the current true water cut of the current oil well is calculated based on the difference in verified onshore 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 particular oil well is less than 0, it indicates that its underwater multiphase flowmeter has a significant error, and the well is identified as a problem well. Of course, in other embodiments, the value of the first preset coefficient threshold can be adjusted according to actual needs. While the operating system of other oil wells in the oilfield group remains unchanged, the problem well is shut down for a certain period of time. The difference in oil and liquid production before and after the shutdown is obtained, and then the current true water cut of the problem well is calculated.

[0054] S3. Calculate the real integrated throttling coefficient of the current oil well according to the current real water cut of the current oil well and the relationship between the water cut and the integrated throttling coefficient.

[0055] Specifically, the reservoir PVT data, the current true water cut of the problem well, the current wellhead temperature and wellhead pressure, and the current pressure at the outlet of the downhole oil and gas collection equipment are substituted into the relationship between water cut and 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 true integrated throttling coefficient after the current oil well resumes production. Based on the relationship between water cut and the integrated throttling coefficient, calculate the predicted water cut of the current oil well during the underwater multiphase flowmeter calibration period.

[0057] Specifically, the water cut of an oil well changes as production progresses, while the wellbore structure typically remains constant, resulting in a relatively stable integrated throttling coefficient. Therefore, by substituting reservoir PVT data, the problem well's actual integrated throttling coefficient, and the wellhead temperature, wellhead pressure, and pressure at the outlet of the downhole oil and gas collection equipment after production resumes into the equation for the relationship between water cut and the integrated throttling coefficient, the water cut of the problem well can be predicted during underwater multiphase flowmeter calibration. This solution enables short-term prediction of oil well water cut in the absence of a flowmeter, providing reliable technical support for accurate analysis of individual well production performance and potential.

[0058] by Figure 2For example, after implementing MRC technology, Well A5H in a certain oilfield cluster went into production in December 2024. At that time, the downhole multiphase flowmeter measured a water cut of 62.2%, and the well produced 376 cubic meters of oil per day. Subsequently, as the well's operating system improved (the operating systems of other wells remained unchanged), the total oil production verified onshore increased by approximately 640 cubic meters. This error from the incremental production of the oilfield's tested production exceeded the preset production error threshold. Based on the 62.2% water cut, the well's integrated throttling coefficient was calculated to be -2.0, which did not match the production performance of adjacent wells and the MRC post-drilling geological reservoir understanding. Assuming the well's throttling level is very low, the integrated throttling coefficient is set to a positive number close to zero, 0.1, and the calculated water cut of the well should be less than 49%. In summary, the water cut measured by the downhole multiphase flowmeter is significantly abnormal.

[0059] After calibrating the flowmeter, the flowmeter measured the water cut of A5H well to be 36.8% and the daily oil production to be 634 cubic meters, which was slightly different from 36.2%. The two data were highly consistent, proving that the algorithm is reliable and has great practical significance. Figure 2 It can be seen from the figure that the moisture content measured by the flow meter changes significantly before and after calibration: the area before the dotted line shows the production situation before the flow meter calibration. Before calibration, the measured moisture content of the flow meter (the "Water Content (Flow Meter)" curve in the figure, i.e., Curve 1) and the calculated true moisture content at each time point (the "Water Content (Calculated)" curve in the figure, i.e., Curve 2) have a large error. The area after the dotted line shows the production situation after the flow meter calibration. The measured value after the flow meter calibration has a small error from the true moisture content.

[0060] It can be seen that 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 flow meter calibration, providing reliable technical support for the accuracy of single well production performance and potential analysis.

[0061] In one embodiment, step S1 further includes:

[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 with the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain the historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and water content measured by the underwater multiphase flowmeter of the current oil well, and calculate the historical integrated throttling coefficient of the current oil well based on the relationship between the water content and the 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 conditions of each oil well in the oil field. 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 means that the underwater multiphase flowmeter of the oil well also has an error, but the error is relatively minor. Obtain historical data when the current oil well production is stable and the flowmeter is normal, including the historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas acquisition equipment, and the measured water content of the underwater multiphase flowmeter, and calculate the historical integrated throttling coefficient of the current oil well.

[0064] S6. Obtain the current wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and historical integrated throttling coefficient of the current oil well. Based on the relationship between water cut and the integrated throttling coefficient, calculate the predicted water cut of the current oil well during the period when the underwater multiphase flowmeter fails.

[0065] Specifically, the water cut of an oil well changes as the production process progresses, while the wellbore structure generally remains unchanged. The true integrated throttling coefficient is relatively stable, and the historical integrated throttling coefficient calculated from historical data when production was stable and the flowmeter was functioning properly is close to the true integrated throttling coefficient. Therefore, by substituting the reservoir PVT data, the historical integrated throttling coefficient of the problem well, as well as the current wellhead temperature, wellhead pressure, and pressure at the outlet of the downhole oil and gas collection equipment into the equation for the relationship between water cut and the integrated throttling coefficient, it is possible to predict the water cut of the problem well during the period of failure of the underwater multiphase flowmeter (shorter than the flowmeter calibration time). This solution enables short-term prediction of the water cut of an oil well in the absence of a flowmeter, providing reliable technical support for the accuracy of single-well production performance and potential analysis.

[0066] In one embodiment, step S1 further includes:

[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 with the second preset coefficient threshold exceeds the preset coefficient error threshold, then obtain all the wellhead temperatures and wellhead pressures of the current oil well, the pressure at the outlet of the downhole oil and gas collection equipment, and the measured water content of the underwater multiphase flowmeter, and calculate all the integrated throttling coefficients of the current oil well based on the relationship between the water content and the integrated throttling coefficient.

[0068] S8. Determine whether there is throttling 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 a second preset coefficient threshold, and the difference from the second preset coefficient threshold exceeds a preset coefficient error threshold, it indicates that the wellbore throttling condition of the oil well may be abnormal. Therefore, relevant data for the oil well at all time points since it was put into production is 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 throttling is occurring, which is beneficial for optimizing the oil well operating system and improving the completion plan later. In other embodiments, it is also possible to choose to only observe the throttling conditions for a recent period of time, depending on actual needs.

[0070] Specifically, in step S8, the duration of the statistically integrated throttling coefficient being greater than the second preset coefficient threshold and the absolute value of the difference with the second preset coefficient threshold exceeding the preset coefficient error threshold is determined. If the duration exceeds the preset time threshold, it is determined that throttling occurs in the current oil well.

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

[0072] refer to Figure 3 The daily and minute-by-minute wellbore flow data for Well A3H in a specific oilfield cluster was compiled, and the daily integrated throttling coefficient was calculated. The second preset coefficient threshold was set at 10. After throttling was detected in the well, the TDV valve in the production string was replaced with an ADV valve with a lower throttling coefficient during a workover. It can be seen that since the commissioning of Well A3H (with the TDV valve), the integrated throttling coefficient of the wellbore has ranged from 30 to 180. After the subsequent workover and replacement with the ADV valve, the integrated throttling coefficient has generally been less than 10, with no significant throttling. This significantly improved the production efficiency of the electric pump, further releasing the well's production capacity, and achieved significant economic benefits.

[0073] In one embodiment, the relationship between the water content and the integrated throttling coefficient is:

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

[0075] Among them, ΔP is the difference between the outlet pressure of the downhole oil and gas acquisition equipment (electric submersible pump) and the wellhead pressure, ΔP 油管 is the oil pipe flow pressure drop loss, ICC is the integrated throttling coefficient, ρ ogis the corrected fluid mixture density, WC is the water content, ρ w is the formation water density, g is the acceleration of gravity, and h is the vertical depth from the outlet of the downhole oil and gas collection equipment to the wellhead. Formula (1) applies 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 calculation method of the oil pipe flow pressure drop loss is:

[0077] Obtain the corrected fluid mixture density and the secondary corrected wellhead fluid mixture viscosity, and calculate the tubing flow pressure drop loss based on the Fanning formula. For the Fanning formula, refer to the prior art.

[0078] Specifically, the calculation formula for the corrected fluid mixture density is:

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

[0080] Among them, ρ mix is the corrected fluid mixture density, ρ oil is the density of crude oil, ρ gas is the density of natural gas, GOR is the gas-oil ratio, B ocorrect is the corrected wellhead fluid volume coefficient.

[0081] The calculation method of the corrected wellhead fluid volume coefficient in formula (2) is:

[0082] A1. Calculate the volume coefficient of the wellhead fluid under the wellhead pressure condition based on the trend line function. The trend line function of this embodiment adopts the least squares method, of course, other algorithms can also be used. Figure 4 As shown in the figure, the horizontal axis represents the wellhead pressure, and the vertical axis represents the wellhead fluid volume coefficient. The wellhead pressure and corresponding wellhead fluid volume of a certain oilfield group are obtained. The relationship between the wellhead pressure and the wellhead fluid mixed viscosity of a certain oilfield group calculated using the trend line function is:

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

[0084] Among them, P head is the wellhead pressure.

[0085] A2. Use the following formula to correct the wellhead fluid volume coefficient under temperature conditions:

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

[0087] Among them, B ocorrect is the corrected wellhead fluid volume coefficient, B o Wellhead fluid volume coefficient under wellhead pressure conditions, T head is the wellhead temperature, T res is the reservoir temperature.

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

[0089] B1. Calculate the viscosity of the wellhead fluid mixture under the wellhead pressure condition based on the trend line function. The trend line function of this embodiment adopts the least squares method, of course, other algorithms can also be used. Figure 5 As shown, the horizontal axis represents the wellhead pressure, and the vertical axis represents the wellhead fluid mixed viscosity. The wellhead pressure and the corresponding wellhead fluid mixed viscosity data of a certain oil field group are obtained. The relationship between the wellhead pressure and the wellhead fluid mixed viscosity of a certain oil field group calculated using the trend line function is:

[0090] η0=0.0024×P head +0.7104 (5)

[0091] B2. Use the following formula to make a primary correction to the wellhead fluid mixed viscosity under pressure conditions:

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

[0093] Among them, η mix is the wellhead fluid mixed viscosity after one correction, η0 is the wellhead fluid mixed viscosity under wellhead pressure conditions, WC is the water cut, η water is the formation water viscosity.

[0094] B3. Refer to the Arrhenius formula and use the following formula to perform secondary correction under temperature conditions:

[0095]

[0096] Among them, η mixcorrect is the mixed viscosity of the wellhead fluid after secondary correction, η mix is the wellhead fluid mixed viscosity after one correction, R is the gas constant, is the activation energy of crude oil, is the water activation energy, T res is the reservoir temperature, Thead is the wellhead temperature, and WC is the water content.

[0097] The above calculation formula can be constructed in an EXCEL table with simple operation steps. In some embodiments, it can also be constructed by programming.

[0098] In one embodiment of a computer device provided by the present invention, the device includes: a memory and a processor, wherein a computer program executable by the processor is stored in the memory, and when the processor executes the computer program, the steps of the method for digitizing deepwater oilfield wellbore throttling and calculating water content as disclosed in any of the above embodiments are implemented. Specifically, according to an embodiment of the present invention, the process described above with reference to the flowchart can be implemented as a computer software program. For example, an embodiment of the present invention includes a computer program product, which includes a computer program carried on a computer-readable medium, and the computer program contains program code for executing the method shown in the flowchart. In such an embodiment, the computer program can be downloaded and installed by a computer device and, when executed, performs the above-mentioned functions defined in the method of the embodiment of the present invention. The computer device in the present invention can be a notebook, a desktop computer, a workstation, an industrial computer, a server, etc.

[0099] It is understandable that the above embodiments only express the preferred implementation modes of the present invention, and the description thereof is relatively specific and detailed, but it cannot be understood as limiting the patent scope of the present invention. It should be pointed out that for ordinary technicians in this field, without departing from the concept of the present invention, the above technical features can be freely combined, and several deformations and improvements can be made, all of which fall within the scope of protection of the present invention. Therefore, all equivalent changes and modifications made to the scope of the claims of the present invention should fall within the scope of coverage of the claims of the present invention.

Claims

1. A method for digitizing throttling and calculating water content in a deepwater oilfield wellbore, characterized in that: The following steps are involved: S1. When the error between the test production and the verified production onshore of the oil field exceeds a preset production error threshold, obtain the reservoir PVT data, the current wellhead temperature and wellhead pressure of each oil well, the current pressure at the outlet of the downhole oil and gas collection equipment of each oil well, and the current water cut measured by the underwater multiphase flowmeter 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; perform the following steps for each oil well: S2. If the current integrated throttling coefficient of the current oil well is less than a first preset coefficient threshold, obtaining a difference in verified onshore production of the oil field before and after the current oil well is shut down for a certain period of time while the operating systems of other oil wells remain unchanged, and calculating the current true water cut of the current oil well based on the difference in verified onshore production; S3. Calculating a true integrated throttling coefficient of the current oil well based on the current true water cut of the current oil well and a 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 true integrated throttling coefficient of the current oil well after production is resumed, and calculate the predicted water cut of the current oil well during the underwater multiphase flowmeter calibration based on the relationship between the water cut and the integrated throttling coefficient.

2. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to claim 1, characterized in that: After step S1, the following steps are also included: S5. If the current integrated throttling coefficient of the current oil well is between a first preset coefficient threshold and a second preset coefficient threshold, and the absolute value of the difference between the current integrated throttling coefficient and the second preset coefficient threshold exceeds a preset coefficient error threshold, obtaining historical wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and water cut measured by a subsea multiphase flowmeter for the current oil well, and calculating the historical integrated throttling coefficient of the current oil well based on a relationship between the water cut and the integrated throttling coefficient; S6. Obtain the current wellhead temperature, wellhead pressure, pressure at the outlet of the downhole oil and gas collection equipment, and the historical integrated throttling coefficient of the current oil well, and calculate the predicted water cut of the current oil well during the period of failure of the underwater multiphase flowmeter based on the relationship between the water cut and the integrated throttling coefficient.

3. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to claim 2, characterized in that: After step S1, the following steps are also included: 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 integrated throttling coefficient and the second preset coefficient threshold exceeds a preset coefficient error threshold, obtaining all wellhead temperatures and wellhead pressures of the current oil well, the pressure at the outlet of the downhole oil and gas collection equipment, and the water cut measured by the underwater multiphase flowmeter, and calculating all integrated throttling coefficients of the current oil well based on a relationship between the water cut and the integrated throttling coefficient; S8. Determine whether the current oil well has a throttling phenomenon based on all integrated throttling coefficients.

4. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to claim 3, characterized in that: In step S8, the duration of the time during which the integrated throttling coefficient is greater than the second preset coefficient threshold and the absolute value of the difference with the second preset coefficient threshold exceeds the preset coefficient error threshold is calculated. If the duration exceeds the preset time threshold, it is determined that throttling occurs in the current oil well.

5. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to any one of claims 1 to 3, characterized in that: The relationship between the moisture content and the integrated throttling coefficient is: ΔP=ΔP 油管 ×(1+ICC)+(ρ og ×(1-WC)+ρ W *WC)×g×h, Among them, ΔP is the difference between the pressure at the outlet of the downhole oil and gas collection equipment and the wellhead pressure, ΔP 油管 is the oil pipe flow pressure drop loss, ICC is the integrated throttling coefficient, ρ og is the corrected fluid mixture density, WC is the water content, ρ w is the formation water density, g is the acceleration of gravity, and h is the vertical depth from the outlet of the downhole oil and gas collection equipment to the wellhead.

6. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to claim 5, characterized in that: The calculation method of the oil pipe flow pressure drop loss is: The corrected fluid mixed density and the secondary corrected wellhead fluid mixed viscosity are obtained, and the oil pipe flow pressure drop loss is calculated based on the Fanning formula.

7. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to claim 6, characterized in that: The calculation method of the wellhead fluid mixed viscosity after secondary correction is: Calculate the mixed viscosity of the wellhead fluid under the wellhead pressure condition based on the trend line function; The following formula is used to perform a primary correction on the wellhead fluid mixed viscosity under pressure conditions: or mix =η0×(1-WC)+η water ×WC, Among them, η mix is the wellhead fluid mixed viscosity after one correction, η0 is the wellhead fluid mixed viscosity under wellhead pressure conditions, WC is the water cut, η water is the formation water viscosity; The following formula is used to perform secondary correction under temperature conditions: Among them, η mixcorrect is the mixed viscosity of the wellhead fluid after secondary correction, η mix is the wellhead fluid mixed viscosity after one correction, R is the gas constant, is the activation energy of crude oil, is the water activation energy, T res is the reservoir temperature, T head is the wellhead temperature, and WC is the water content.

8. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to claim 6, characterized in that: The calculation formula for the corrected fluid mixture density is: r mix =(ρ oil +r gas ×GOR) / B ocorrect , Among them, ρ mix is the corrected fluid mixture density, ρ oil is the crude oil density, ρ gas is the natural gas density, GOR is the gas-oil ratio, B ocorrect is the corrected wellhead fluid volume coefficient.

9. The method for digitizing throttling and calculating water content in a deepwater oilfield wellbore according to claim 8, characterized in that: The calculation method of the corrected wellhead fluid volume coefficient is: Calculate the wellhead fluid volume coefficient under wellhead pressure conditions based on the trend line function; The wellhead fluid volume coefficient is corrected under temperature conditions using the following formula: B ocorrect =B o *(1+(T head -T res )*0.00095, Among them, B ocorrect is the corrected wellhead fluid volume coefficient, B o Wellhead fluid volume coefficient under wellhead pressure conditions, T head is the wellhead temperature, T res is the reservoir temperature.

10. A computer device, characterized in that: include: A memory and a processor, wherein the memory stores a computer program executable by the processor, and when the processor executes the computer program, the steps of the deepwater oilfield wellbore throttling digitization and water content calculation method as described in any one of claims 1 to 9 are implemented.

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