A fault diagnosis method for water injection wells under digitization

Abstract

The present application belongs to the field of fault diagnosis, and specifically relates to a fault diagnosis method for a water injection well under digital conditions. The method comprises the following steps: obtaining wellhead injection pressure through a sensor, and predicting wellbore pressure distribution based on the injection pressure; calculating pressure loss of injection medium through a water nozzle and formation water absorption index; predicting stratified injection volume of the water injection well based on the wellbore pressure distribution, the pressure loss and the formation water absorption index; and diagnosing faults of the water injection well based on the prediction result. The present application aims at further improving the diagnosis accuracy of the working condition of the water injection well, realizes more accurate diagnosis of the working condition of the water injection well, provides a more solid technical foundation for safe and efficient operation of the water injection well, and strengthens the application foundation of intelligent construction of oilfields in the aspect of water injection wells.

Description

Technical Field

[0001] This invention belongs to the field of fault diagnosis, specifically a fault diagnosis method for water injection wells under digital conditions. Background Technology

[0002] Water injection is a crucial technology in oilfield production. In recent years, with the advancement of digitalization and the Internet of Things (IoT) in oilfields, a large number of water injection well monitoring systems based on real-time parameter acquisition have been deployed. These systems monitor operating conditions and issue alarms based on the characteristics of water injection well production data, which is of great significance for achieving intelligent management of oil and water wells.

[0003] Currently, the overall maturity of this technology is limited, and further research and improvement are needed. One of the keys to improving this technology is how to further integrate the relevant pipe flow and seepage mechanics theories of water injection wells with digital data acquisition and testing, and artificial intelligence analysis. Summary of the Invention

[0004] This invention addresses the need for further improvement in the accuracy of water injection well condition diagnosis by designing a new solution to achieve more accurate water injection well condition diagnosis, providing a more solid technical foundation for the safe and efficient operation of water injection wells, and strengthening the application foundation of intelligent oilfield construction in water injection wells.

[0005] The technical solution adopted by the present invention to achieve the above objectives is as follows:

[0006] A fault diagnosis method for water injection wells under digital conditions includes the following steps:

[0007] The wellhead injection pressure is obtained through sensors, and the wellbore pressure distribution is predicted based on this.

[0008] Calculate the pressure loss of the injected medium through the nozzle and the formation water absorption index;

[0009] Predict the stratified water injection volume of injection wells based on wellbore pressure distribution, pressure loss, and formation water absorption index.

[0010] Fault diagnosis is performed on water injection wells based on the prediction results.

[0011] The predicted wellbore pressure distribution is specifically as follows:

[0012]

[0013] Where, p i+1 p is the pressure value along the (i+1)th well depth direction. i Let Δp1 be the pressure value along the depth direction of the well, Δh be the pressure change at any segment of the wellbore, and p be the segment length. m Let θ be the density of the mixed medium, θ be the angle between the well section location and the horizontal direction, f be the friction coefficient, and v be the density of the mixed medium.m D represents the flow rate of the mixed medium. e Let g be the equivalent diameter of the flow channel and g be the acceleration due to gravity.

[0014] The pressure loss of the injected medium after passing through the water nozzle is specifically as follows:

[0015]

[0016] Where Δp2 is the pressure loss of the injected medium passing through the water nozzle, Q m For the injected medium flow rate, d n Let be the faucet diameter, and k and A be undetermined coefficients determined by regression analysis of the faucet wear curve.

[0017] The formation water absorption index is specifically as follows:

[0018]

[0019] Among them, I r p is the water absorption index of the injection layer. r p represents the formation pressure in the water injection zone. in The actual water injection pressure is given by p, where p is the pressure of the injected medium before it passes through the nozzle and at the calculated nozzle depth.

[0020] The predicted stratified injection volume of the injection well includes the following steps:

[0021] 1) Determine the friction adjustment coefficient Fm for the entire well;

[0022] 2) Based on the regression results of the test nozzle damage curve, fit the undetermined coefficients k and A of each layer of the injection well;

[0023] 3) Calculate the pressure and flow rate of each layer in the well based on the real-time wellhead water injection pressure and injection volume.

[0024] Step 1) specifically refers to:

[0025] The predicted bottom hole pressure in the wellbore pressure distribution is compared with the test bottom hole pressure. If the predicted pressure is greater than the test pressure, the friction adjustment coefficient Fm is increased, and the bottom hole pressure is re-predicted until the difference between the predicted pressure and the test bottom hole pressure meets the error.

[0026] Step 3) includes the following steps:

[0027] 3.1) Calculate the flow rate, pressure, and temperature from the wellhead to the first injection point;

[0028] 3.2) Calculate the flow rate, pressure, and temperature after the first injection point nozzle;

[0029] 3.3) Based on the formation pressure and the pressure after the nozzle at the first injection point, determine whether the injection flow rate is correct; if correct, proceed to step 3.4); otherwise, correct Fm and return to step 3.1).

[0030] 3.4) Starting from the first injection point, subtract the first layer flow rate from the total flow rate to obtain the new flow rate. Calculate the flow rate, pressure, and temperature from the first injection point to the second injection point using the pressure at the nozzle of the first injection point.

[0031] 3.5) Repeat steps 3.2) to 3.4) until the last sub-point is calculated.

[0032] In step 3.3), determining whether the injection flow rate is correct specifically involves:

[0033] Calculate the actual water absorption Q of the bottom layer m1 :

[0034] Q m1 =(p in -p r )I r

[0035] Among them, I r p is the water absorption index of the injection layer. r p represents the formation pressure in the water injection zone. in This represents the actual water injection pressure.

[0036] Determine the actual water absorption Q m1 If the error between the flow rate and the flow rate after the first injection point nozzle is within the threshold range, then the injection flow rate is correct; otherwise, the injection flow rate is incorrect.

[0037] The fault diagnosis of water injection wells based on the prediction results is specifically as follows:

[0038] Based on the apparent water absorption index I of the entire well qr Wellhead injection pressure p whi Back pressure p bc Total well water injection volume Q m The changes are used to diagnose the fault, specifically:

[0039] a) When the back pressure increases, the wellhead injection pressure decreases, the change in the apparent water absorption index of the whole well is less than the threshold and the water injection volume of the whole well decreases, the tubing above the first packer will leak. When calculating the apparent water absorption index of the whole well, the formation pressure is taken as the average value of each layer and the injection pressure is taken as the wellhead injection pressure.

[0040] b) When the back pressure increases, the injection pressure decreases, the change in the apparent water absorption index of the whole well is less than the threshold, and the change in the water injection volume of the whole well is less than the threshold, the first-stage packer fails.

[0041] c) When the injection pressure decreases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the change in the water injection volume of the whole well is less than the threshold, the packer below the first-stage packer fails.

[0042] d) When the injection pressure decreases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the water injection volume of the whole well increases, the nozzle will either fall off or become larger.

[0043] e) When the injection pressure increases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the water injection volume of the whole well decreases, nozzle blockage occurs.

[0044] f) Formation contamination occurs when the injection pressure increases, the back pressure remains constant, the apparent water absorption index of the whole well decreases, and the total water injection volume of the whole well decreases.

[0045] g) When the injection pressure decreases, the back pressure remains unchanged, the apparent water absorption index of the whole well increases, and the water injection volume of the whole well increases, the formation resistance decreases.

[0046] h) When the injection pressure increases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the injection volume of the whole well decreases, the formation pressure increases.

[0047] i) When the injection pressure decreases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the injection volume of the whole well increases, the formation pressure decreases.

[0048] j) When all indicators change less than the threshold, or the injection pressure decreases while the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the injection volume of the whole well decreases, or the injection pressure increases while the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the injection volume of the whole well increases, the operating condition is normal and there is no fault.

[0049] The present invention has the following beneficial effects and advantages:

[0050] 1. This invention enables the diagnosis of various water injection well faults under digital conditions, thereby improving the efficiency of water injection well problem detection.

[0051] 2. This invention enables the calculation of the layer volume of stratified water injection wells, reduces the workload of water well testing, and improves the management level of stratified water injection work.

[0052] 3. This invention fully explores and utilizes the value of water well-related data. Attached Figure Description

[0053] Figure 1 Flowchart for diagnosing water injection well faults. Detailed Implementation

[0054] The present invention will now be described in further detail with reference to the accompanying drawings and embodiments.

[0055] The main process of this invention is as follows: First, the pressure distribution of the wellbore is calculated; then, the pressure loss of the injected medium through the nozzle is calculated; and finally, the formation water absorption index is calculated. Based on the calculations in the first three parts, the layered water injection volume prediction and common fault diagnosis of the injection well are realized.

[0056] As attached Figure 1 As shown, this invention mainly consists of five functional blocks: wellbore pressure distribution calculation, pressure loss calculation of the injected medium through the nozzle, formation water absorption index calculation, stratified water injection volume prediction, and fault diagnosis. The main principles and ideas of this invention are as follows:

[0057] (1) Calculation of wellbore pressure distribution

[0058] Given the wellhead injection pressure, calculate the pressure of each segment downwards from the wellhead. The pressure at any segment is then calculated as follows:

[0059]

[0060] p i+1 The pressure value along the (i+1)th well depth direction, in MPa.

[0061] p i The pressure value along the i-th well depth direction, in MPa.

[0062] Δp, pressure change at any segment of the wellbore.

[0063] Δh, calculate the segment length

[0064] ρm, density of the mixed medium, kg / m3

[0065] ρ m =ρ w *wc+ρ p (1-wc)(1-1)

[0066] ρ w density of water

[0067] ρ p Density of additives in injected water

[0068] θ is the angle between the location of the well section and the horizontal direction.

[0069] f, coefficient of friction

[0070] v m Mixed medium flow rate, m / s

[0071]

[0072] Q m = Medium injection rate at the wellhead, m3 / d

[0073] De, equivalent diameter of the flow channel, in meters.

[0074] When using tubing injection, De is taken as the inner diameter of the tubing.

[0075] When using annular injection

[0076] D e =D o -D i (1-3)

[0077] D o The inner diameter of the casing is m.

[0078] D i The inner diameter of the oil pipe is in meters (m).

[0079] g, the acceleration due to gravity, is taken as 9.81 kgm / s².

[0080] Calculation of friction coefficient f

[0081] The coefficient of friction is related to the Reynolds number R and the relative roughness ε.

[0082] When R is less than 2300, the injected flow is laminar, and the friction coefficient is...

[0083] f = F m *64 / R(1-4)

[0084] When R is greater than 2300, the injected flow is turbulent, and the friction coefficient is...

[0085] f = F m *[2log(R / ε)+1.74] -2 (1-5)

[0086] ε-channel absolute roughness, mm

[0087] F in the above two equations m This is the friction adjustment coefficient, with a default value of 1. The actual value can be obtained by regression from the pressure measurement data of the water injection well. This coefficient is defined mainly to take into account the influence of factors that are difficult to quantify statically, such as the water injection tubing string, casing couplings, and oil adhesion.

[0088] The formula for calculating the Reynolds number R is as follows:

[0089] R = ρ m v m D e / μ m (1-6)

[0090] Where μ m Injected mixture viscosity

[0091] μ m =μ w *wc+μp (1-wc)(1-7)

[0092]

[0093] μ w =EXP(1.003-1.479×10) -2 T+1.982×10 -5 T -2 (1-9)

[0094] μ p =f(T), if the injection medium is oily wastewater, μ p Then it is determined by the following experimental relationship.

[0095] lglg(μ p +A)=B+Clg(T+273.15)(1-10)

[0096] A, B, and C are undetermined coefficients, which can be determined by providing at least three sets of crude oil viscosity test data.

[0097] If the injection medium is a polymer, μ p It is recommended to determine the following experimental relationship.

[0098] μ p =aT 5 +bT 4 +cT 3 +dT 2 +eT+f(1-11)

[0099] Where a, b, c, d, e, and f are undetermined coefficients, which can be determined by providing at least six sets of viscosity-temperature test data.

[0100] Where T is the average temperature at the calculated location, in K;

[0101] Water injection well bore temperature distribution

[0102] G = G p +G w =(Q p ρ p +ρ w Q w ) / 24(1-12)

[0103]

[0104] GC=G w C w +G p C p (1-14)

[0105]

[0106] Where T represents the temperature at any depth h, in °C;

[0107] T 1s - Formation temperature at the horizontal location of the wellbore calculation point, in °C;

[0108] α-Geothermal gradient, default value is 0.03℃ / m

[0109] h - depth, m; h = h0 ± Δh

[0110] G w G p -Mass flow rate of injected water and water additives, kg / h;

[0111] C w C p -Specific heat of injected water and water-added additives, kJ / kg·℃

[0112] Qw, Qp - Injection volume of water and water-injection additives, m3 / d;

[0113] ρ w / ρ p - Density of water and additives, kg / m3

[0114] (2) Calculation of pressure loss of the injected medium through the water nozzle

[0115]

[0116] Δp, pressure loss of the injected medium through the nozzle, MPa;

[0117] Q m Injection medium flow rate, m3 / d;

[0118] d n Water tap diameter, mm

[0119] k and A are undetermined coefficients, determined by regression analysis of the test faucet damage curve provided by the faucet manufacturer.

[0120] (3) Calculation of formation water absorption index

[0121]

[0122] I r The water absorption index of the injection layer, m3 / d / MPa;

[0123] p r Formation pressure in the water injection zone, MPa;

[0124] p iActual water injection pressure, the pressure of the injected medium after passing through the water nozzle, in MPa.

[0125] p is the pressure of the injected medium before it passes the water nozzle and at the calculated water nozzle depth, i.e., the pressure value calculated to the water nozzle position using the method in section (1).

[0126] (4) Prediction of stratified water injection volume

[0127] The first step is to determine the friction adjustment coefficient Fm for the entire well.

[0128] Calculate the bottom hole pressure using formula (1) and its auxiliary formulas, and compare it with the tested bottom hole pressure. If the calculated pressure is greater than the tested pressure, increase Fm and recalculate until the calculated wellbore pressure and the tested bottom hole pressure meet the given error.

[0129] The second step involves using the regression formula (2) to adjust the data from the stratified injection well nozzles, where k and A are used to fit the k and A values ​​for each layer. Simultaneously, formula (3) is used to fit the water absorption index I of each layer. r .

[0130] The third step is to calculate the overall well pressure distribution and the flow rate at each layer.

[0131] The pressure and flow rate of each layer downhole are calculated based on the real-time wellhead injection pressure and injection volume of a well. The flow rate, pressure, and temperature are calculated segment by segment from the wellhead downwards until the last injection layer.

[0132] 1) Calculate the flow rate, pressure, and temperature from the wellhead to the first injection point using formula (1) and its associated formulas;

[0133] 2) Calculate the flow rate, pressure, and temperature after the first injection point nozzle using formula (2);

[0134] 3) Use the formation pressure at the first injection point and the pressure after the nozzle at the first injection point, combined with formula (3), to determine whether the injection flow rate is correct; if correct, proceed to the next step of calculation; otherwise, return to the previous step, correct Fm and recalculate.

[0135] The process for determining whether the injection flow rate is correct is as follows:

[0136] Calculate the actual water absorption of the formation

[0137] Q m1 =(p i -p r )I r

[0138] Determine Q m1 Check if the error between the calculated flow rate and the previous step is within the allowable range, preferably within ±5%. If it is, it is correct; otherwise, it is incorrect.

[0139] 4) Starting from the first injection point, subtract the first layer of water volume from the total flow rate to obtain the new water volume, and continue to calculate downwards using the pressure in front of the nozzle at the first injection point.

[0140] 5) Calculate the flow rate, pressure, and temperature from the first injection point to the second injection layer using formula (1) and its auxiliary formulas, and calculate up to the last injection layer using the methods in steps 2), 3), and 4).

[0141] (5) Well Fault Diagnosis

[0142] Key parameters for judgment, apparent water absorption index I of the whole well qr Wellhead injection pressure p whi Back pressure p bc Total well water injection volume Q m ,

[0143] The full well apparent water absorption index is defined as follows:

[0144]

[0145] Back pressure p bc When injecting oil into the tubing, the back pressure is taken from the casing pressure; when injecting oil into the annulus, the back pressure is taken from the oil pressure.

[0146] p qr Predicted whole-well formation pressure

[0147] p qr For the value of , two methods are recommended:

[0148] 1. Take the average pressure of each layer.

[0149] II. Under the condition of ensuring normal production (I) qr (Stable), multiple sets of wellhead water injection volume and water injection pressure values ​​were obtained by testing, and regression was performed according to formula (4).

[0150] Downhole injection pressure p at the first-stage packer qi

[0151] The pressure at the first water injection layer calculated using formula (1) is the downhole injection pressure p at the first-stage packer. qi

[0152] 1) Leakage in the tubing above the primary packer

[0153] Back pressure increases, injection pressure decreases, apparent water absorption index remains basically unchanged, and water injection volume decreases.

[0154] expression

[0155]

[0156] The parameters before and after the subscript represent the parameter values ​​collected before and after a diagnosis time, and the same applies to the following formulas.

[0157] 2) Primary packer failure

[0158] Back pressure increases, injection pressure decreases, apparent water absorption index remains basically unchanged, and total water injection volume remains basically unchanged.

[0159]

[0160] 3) Failure of packers below the primary packer level.

[0161] The injection pressure decreased, the back pressure remained unchanged, the apparent water absorption index of the whole well remained basically unchanged, and the total water injection volume of the whole well remained basically unchanged.

[0162]

[0163] 4) The water tap is too large or has fallen off.

[0164] Injection pressure decreases, back pressure remains unchanged, apparent water absorption index of the whole well remains basically unchanged, and water injection volume of the whole well increases.

[0165]

[0166] 5) Clogged faucet

[0167] Injection pressure increases, back pressure remains unchanged, apparent water absorption index of the whole well remains basically unchanged, and water injection volume of the whole well decreases.

[0168]

[0169] 6) Formation contamination

[0170] Injection pressure increases, back pressure remains unchanged, apparent water absorption index decreases, and total water injection volume decreases.

[0171]

[0172] 7) Formation resistance decreases

[0173] The injection pressure decreased, the back pressure remained unchanged, the apparent water absorption index of the whole well increased, and the total water injection volume of the whole well increased.

[0174]

[0175] 8) Increased formation pressure

[0176] Water injection pressure increases, back pressure remains unchanged, apparent water absorption index of the whole well remains basically unchanged, and water injection volume of the whole well decreases.

[0177]

[0178] 9) Formation pressure decreases

[0179] Water injection pressure decreases, back pressure remains unchanged, apparent water absorption index of the whole well remains basically unchanged, and water injection volume of the whole well increases.

[0180]

[0181] 10) Normal operating conditions

[0182] Indicators stable

[0183]

[0184] or

[0185] Water injection pressure decreases, back pressure remains unchanged, apparent water absorption index of the whole well remains basically unchanged, and water injection volume of the whole well decreases.

[0186]

[0187] or

[0188] Water injection pressure increases, back pressure remains unchanged, apparent water absorption index of the whole well remains basically unchanged, and water injection volume of the whole well increases.

[0189]

[0190] The limits in the following formulas are general recommended values. When applied to a specific unit, they can be optimized by taking into account expert opinions or artificial intelligence calculation results.

Claims

1. A fault diagnosis method for water injection wells under digital conditions, characterized in that, Includes the following steps: The wellhead injection pressure is obtained through sensors, and the wellbore pressure distribution is predicted based on this. Calculate the pressure loss of the injected medium through the nozzle and the formation water absorption index; Predict the stratified water injection volume of injection wells based on wellbore pressure distribution, pressure loss, and formation water absorption index. Fault diagnosis of water injection wells based on prediction results; The fault diagnosis of water injection wells based on the prediction results is as follows: Based on the apparent water absorption index of the entire well Wellhead injection pressure Back pressure Total well water injection volume The changes are used to diagnose the fault, specifically: a) When the back pressure increases, the wellhead injection pressure decreases, the change in the apparent water absorption index of the whole well is less than the threshold, and the water injection volume of the whole well decreases, tubing leakage above the first-stage packer occurs. When calculating the apparent water absorption index of the whole well, the formation pressure is taken as the average value of each layer, and the injection pressure is taken as the wellhead injection pressure. b) When the back pressure increases, the injection pressure decreases, the change in the apparent water absorption index of the whole well is less than the threshold, and the change in the water injection volume of the whole well is less than the threshold, the first-stage packer fails. c) When the injection pressure decreases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the change in the water injection volume of the whole well is less than the threshold, the packer below the first-stage packer fails. d) When the injection pressure decreases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the water injection volume of the whole well increases, the nozzle may become enlarged or fall off. e) When the injection pressure increases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the water injection volume of the whole well decreases, nozzle blockage occurs. f) Formation contamination occurs when the injection pressure increases, the back pressure remains constant, the apparent water absorption index of the whole well decreases, and the total water injection volume of the whole well decreases. g) When the injection pressure decreases, the back pressure remains unchanged, the apparent water absorption index of the whole well increases, and the water injection volume of the whole well increases, the formation resistance decreases. h) When the injection pressure increases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the injection volume of the whole well decreases, the formation pressure increases. i) When the injection pressure decreases, the back pressure remains unchanged, the change in the apparent water absorption index of the whole well is less than the threshold, and the injection volume of the whole well increases, the formation pressure decreases. j) When all indicators change less than the threshold, or the injection pressure decreases while the back pressure remains constant, the change in the apparent water absorption index of the entire well is less than the threshold, and the total water injection volume of the entire well decreases, or the injection pressure increases while the back pressure remains constant, the change in the apparent water absorption index of the entire well is less than the threshold, and the total water injection volume of the entire well increases, the operating condition is normal and there are no faults. Apparent water absorption index of the whole well Specifically: ； in, For the entire well formation pressure, Inject downhole pressure at the primary packer; The back pressure Specifically: When injecting oil into the tubing, the back pressure is taken as the casing pressure; when injecting oil into the annulus, the back pressure is taken as the oil pressure.

2. The method for fault diagnosis of water injection wells under digital conditions according to claim 1, characterized in that, The predicted wellbore pressure distribution is specifically as follows: ； in, For the first along the well depth direction Pressure value, For the first along the well depth direction Pressure value, For pressure changes at any segment of the wellbore, The segment length is... For the density of the mixed medium, The angle between the location of the well section and the horizontal direction. The coefficient of friction, For the flow rate of the mixed medium, The equivalent diameter of the flow channel. This is the acceleration due to gravity.

3. The method for fault diagnosis of water injection wells under digital conditions according to claim 1, characterized in that, The pressure loss of the injected medium after passing through the water nozzle is specifically as follows: ； in, The pressure loss of the injected medium passing through the water nozzle. To inject medium flow rate, For the water nozzle diameter, A and A are both undetermined coefficients, determined by regression analysis of the test nozzle damage curve.

4. The method for fault diagnosis of water injection wells under digital conditions according to claim 1, characterized in that, The formation water absorption index is specifically as follows: ； in, The water absorption index of the injection layer. For the formation pressure of the water injection zone, To reflect the actual water injection pressure, The pressure of the injected medium before it passes through the nozzle and at the calculated nozzle depth. To inject medium flow rate, This refers to the pressure loss of the injected medium as it passes through the water nozzle.

5. The method for fault diagnosis of water injection wells under digital conditions according to claim 1, characterized in that, The predicted stratified injection volume of the injection well includes the following steps: 1) Determine the friction adjustment coefficient Fm for the entire well; 2) Based on the regression results of the test nozzle damage curve, fit the undetermined coefficients of each layer of the injection well. A; 3) Calculate the pressure and flow rate of each layer in the well based on the real-time wellhead injection pressure and injection volume.

6. The method for fault diagnosis of water injection wells under digital conditions according to claim 5, characterized in that, Step 1) specifically refers to: The predicted bottom hole pressure in the wellbore pressure distribution is compared with the test bottom hole pressure. If the predicted pressure is greater than the test pressure, the friction adjustment coefficient Fm is increased, and the bottom hole pressure is re-predicted until the difference between the predicted pressure and the test bottom hole pressure meets the error.

7. The method for fault diagnosis of water injection wells under digital conditions according to claim 5, characterized in that, Step 3) includes the following steps: 3.1) Calculate the flow rate, pressure, and temperature from the wellhead to the first injection point; 3.2) Calculate the flow rate, pressure, and temperature after the first injection point nozzle; 3.3) Based on the formation pressure and the pressure after the nozzle at the first injection point, determine whether the injection flow rate is correct; if correct, proceed to step 3.4); otherwise, correct Fm and return to step 3.1). 3.4) Starting from the first injection point, subtract the first layer flow rate from the total flow rate to obtain the new flow rate. Calculate the flow rate, pressure, and temperature from the first injection point to the second injection point using the pressure at the nozzle of the first injection point. 3.5) Repeat steps 3.2) to 3.4) until the last sub-point is calculated.

8. The method for fault diagnosis of water injection wells under digital conditions according to claim 7, characterized in that, In step 3.3), determining whether the injection flow rate is correct specifically involves: Calculate the actual water absorption of the formation : ； in, The water absorption index of the injection layer. For the formation pressure of the water injection zone, This represents the actual water injection pressure. Determine the actual water absorption If the error between the flow rate and the flow rate after the first injection point nozzle is within the threshold range, then the injection flow rate is correct; otherwise, the injection flow rate is incorrect.

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