A new method for analyzing the inflow dynamics at the pump inlet

Abstract

A new method for analyzing the inflow dynamics at the pump inlet provided by the present invention, the analysis method comprising: obtaining the basic data of well logging in different oil layers; establishing a productivity prediction model applicable to a given oil reservoir according to the basic data; drawing an inflow performance curve corresponding to an oil well according to the productivity prediction model; taking a position upward as the setting depth of the pump; performing wellbore multiphase flow calculation on the dynamic points until the points corresponding to the pump inlet, and obtaining multiphase dynamic points with the production rate as the abscissa and the pump inlet pressure as the ordinate; connecting the multiphase dynamic points into a curve by using the point plotting method, and the curve being the inflow performance curve at the pump inlet corresponding to the depth; obtaining the optimal setting depth and the optimal production parameters. It provides a basis for selecting a reasonable setting depth range and determining a reasonable working system for non-flowing oil wells, especially for rod pumped deep pumping technology oil wells.

Description

Technical Field

[0001] The present invention relates to the technical field of oil production in oilfield pumping wells, and particularly to a new method for analyzing the inflow dynamics at the pump inlet. Background Art

[0002] At present, the inflow performance curve has been widely used in the production process of major oilfields. The inflow performance curve is the relationship curve between the bottom-hole flowing pressure and the oil well production, which reflects the liquid supply capacity of the formation. As a production capacity prediction method, it can predict the production capacity of the oil well after the future reduction of the bottom-hole flowing pressure, and has important significance for the oilfield to adjust the working system and select a reasonable production method.

[0003] The traditional inflow performance curve plays an irreplaceable role in oil wells with natural flow production. However, for most artificial lift methods, such as reciprocating pumps, electrical submersible pumps and other lift technologies, there are certain limitations in using the traditional inflow performance curve as the basis for adjusting the working system of oil wells. For example, when performing nodal analysis with the bottom hole as the solution point, the traditional inflow performance curve cannot reflect this important variable of the pump setting depth, and the pump setting depth is an important parameter that needs to be considered for low-permeability deep pumping wells; the traditional inflow performance curve reflects the relationship between the bottom-hole flowing pressure and the production, while for rod-pumped oil wells, the pressure at the pump inlet is often more valuable than the bottom-hole flowing pressure, and the bottom-hole flowing pressure cannot directly analyze parameters such as the filling degree of the pump and the leakage of the pump. Summary of the Invention

[0004] In view of the above problems, the present invention is proposed to provide a new method for analyzing the inflow dynamics at the pump inlet that overcomes or at least partially solves the above problems.

[0005] According to one aspect of the present invention, there is provided a new method for analyzing the inflow dynamics at the pump inlet, the analysis method comprising:

[0006] Obtaining the basic data of well logging for different oil layers;

[0007] Establishing a production capacity prediction model applicable to a given oil reservoir according to the basic data;

[0008] Drawing the inflow performance curve of the corresponding oil well according to the production capacity prediction model;

[0009] Starting from the well depth, taking a position upward as the pump setting depth, starting from 0 MPa on the inflow performance curve, at intervals of 1 MPa, obtaining the bottom-hole flowing pressure value corresponding to a production of 0 m 3 / d, and obtaining dynamic points with the production as the abscissa and the bottom-hole flowing pressure value as the ordinate;

[0010] Perform wellbore multiphase flow calculations on the dynamic points up to the point corresponding to the pump inlet to obtain multiphase dynamic points with production rate as the abscissa and pump inlet pressure as the ordinate.

[0011] Connect the multiphase dynamic points into a curve using the point plotting method, and the curve is the inflow dynamic curve at the corresponding depth of the pump inlet.

[0012] Analyze the inflow dynamic curve at the pump inlet to obtain the optimal pump setting depth and optimal production parameters.

[0013] Optionally, the production capacity prediction model established based on the basic data and applicable to a given reservoir

[0014] Specifically includes:

[0015] Production capacity prediction model

[0016]

[0017]

[0018] where k F , k M are the permeabilities of the fracture and matrix respectively; w is the fracture width; h is the reservoir thickness; B is the volume coefficient; μ is the crude oil viscosity; η is the formation pressure conductivity coefficient; X f is the half-length of the fracture; c is the comprehensive compressibility coefficient; φ M is the matrix porosity.

[0019] Optionally, starting from the well depth, take a position upward as the pump setting depth, and calculate from 0 MPa on the inflow dynamic curve at intervals of 1 MPa to obtain the bottom hole flowing pressure value corresponding to a production rate of 0 m 3 / d, and the specific steps for obtaining the dynamic points with production rate as the abscissa and the bottom hole flowing pressure value as the ordinate include:

[0020] The pressure gradient of the wellbore multiphase pipe flow includes: the pressure potential energy required to overcome gravity by lifting the liquid, the kinetic energy increased by the fluid due to acceleration, and the frictional loss of the fluid along the pipeline. The mathematical expression is as follows:

[0021]

[0022] In the formula, ρ m is the density of the multiphase mixture; v m is the flow velocity of the multiphase mixture; f m is the friction resistance coefficient when the multiphase mixture flows; d is the pipe diameter; p is the pressure; h is the depth; g is the acceleration due to gravity; θ is the complement of the well deviation angle;

[0023] Calculate the pressure distribution along the wellbore based on the pressure gradient of the multiphase flow in the wellbore.

[0024] Optionally, the calculation of the pressure distribution along the wellbore according to the pressure gradient of the multiphase flow in the wellbore specifically includes:

[0025] Iteratively calculate the pressure distribution along the wellbore using the depth increment;

[0026] Take the pressure P0 at the position of the well as the starting point, where the position of the well includes any one of the wellhead and the bottom hole; obtain the pressure drop value ΔP as the calculated pressure interval, and obtain the depth increment Δh corresponding to the pressure drop value ΔP, which is used to calculate the temperature T1 at the lower end of the well according to the temperature gradient;

[0027] Calculate the average temperature T and average pressure P of the corresponding wellbore pipe section according to the temperature T1 at the lower end of the well, and determine all the corresponding fluid property parameters, where all the fluid property parameters include the dissolved gas-oil ratio R g 、the oil formation volume factor B o and the viscosity μ o 、the gas density ρ g and the viscosity μ g , the mixture viscosity μ m and the surface tension σ;

[0028] Calculate the pressure gradient of the wellbore pipe section Calculate the depth difference Δh of the corresponding wellbore pipe section corresponding to the pressure drop value ΔP 计 ;

[0029] Obtain the depth difference Δh 计 and the difference from the depth increment Δh, and determine whether the difference exceeds the set range ε. If so, continue the iteration; otherwise, stop the iteration;

[0030] Calculate the depth L corresponding to the lower end of the wellbore pipe section i and the pressure P i ;

[0031]

[0032] P i =P o +iΔP (6)

[0033] where i = 1, 2, 3,... n

[0034] Taking the pressure at L i as the starting point, repeat the above steps to calculate the depth L i+1 and the pressure P i+1 of the next wellbore pipe section until the cumulative depth L n ≥ the well length L.

[0035] Optionally, the pressure gradient of the wellbore multiphase pipe flow specifically includes:

[0036] Pressure drop formula and flow pattern division boundary:

[0037]

[0038] In the formula, ΔP k is the pressure drop of the calculated pipe section; Δh k is the depth difference of the calculated pipe section; P is the average pressure of the calculated pipe section;

[0039] Volume flow rate of gas:

[0040] In the formula, q g is the volume flow rate of gas, m3 / s; γ o is the relative density of oil; q o is the oil production rate, t / d. Note: When R p <R s , take R p =R s .

[0041] Mass flow rate of gas:

[0042] In the formula, W g —Mass flow rate of gas, kg / s; γ g —Relative density of gas;

[0043] Volume flow rate of liquid:

[0044] In the formula, Q l —Volume flow rate of liquid, m3 / s; q l —Liquid production rate, t / d;

[0045] Volume flow rate of liquid:

[0046] In the formula, W l —Mass flow rate of liquid, kg / s;

[0047] Total volume flow rate of mixture: Q t =Q g +Q l (12)

[0048] Total mass flow rate of mixture: W t =W g +W l (13).

[0049] Optionally, the average density and friction loss gradient specifically include:

[0050] The calculation methods for the average density and the friction loss gradient under different flow patterns are different, specifically including: Under the bubble flow pattern:

[0051] Average density:

[0052]

[0053] H L +H g = 1 (15)

[0054] In the formula, H g — Gas holdup, calculated as the ratio of the gas volume to the pipe volume in the calculated pipe section; H L — Liquid holdup, calculated as the ratio of the liquid volume to the pipe volume in the calculated pipe section; ρ g 、ρ L 、 — Densities of gas, liquid and mixture under , kg / m3;

[0055] The gas holdup is calculated by the slip velocity V s ; The slip velocity is defined as the difference between the gas flow velocity and the liquid flow velocity;

[0056]

[0057] H g can be solved as:

[0058]

[0059] In the formula, v s — Slip velocity, determined by experiment, m / s; v sg 、v sL — Apparent flow velocities of gas and liquid, m / s;

[0060] The friction loss gradient of bubble flow is calculated based on the liquid phase:

[0061]

[0062]

[0063] In the formula, f — Friction resistance coefficient;

[0064] v LH — True liquid flow velocity, m / s;

[0065] Average density of slug flow mixture

[0066]

[0067] where δ is the liquid distribution coefficient; v s — the slip velocity, m / s;

[0068] The slip velocity can be calculated by the formula proposed by Griffith and Wallis:

[0069]

[0070] For the mixture average density and friction gradient in transitional flow, they are first calculated separately for slug flow and mist flow, and then the corresponding values are determined by interpolation method;

[0071]

[0072]

[0073] where ρ SL , τ SL and ρ Mi , τ Mi are the mixture density and friction gradient calculated for slug flow and mist flow respectively;

[0074] The calculation formula for the mist flow mixture density is the same as that for bubble flow:

[0075]

[0076] Since there is no relative movement velocity between gas and liquid in mist flow, that is, the slip velocity is close to zero and there is basically no slip; so

[0077]

[0078] the friction gradient is calculated according to the continuous gas phase, that is

[0079]

[0080] where v sg — the apparent gas velocity, v sg = q g / A p m / s.

[0081] A new type of pump inlet inflow dynamic analysis method provided by the present invention, the analysis method includes: obtaining the basic data of well logging of different oil layers; establishing a production capacity prediction model applicable to a given oil reservoir according to the basic data; drawing an inflow dynamic curve corresponding to the oil well according to the production capacity prediction model; starting from the well depth, taking a position upward as the setting depth of the pump, starting from 0 MPa on the inflow dynamic curve, at intervals of 1 MPa, obtaining the production of 0 m 3The bottom-hole flowing pressure value corresponding to Q / d is obtained, and a dynamic point with the production rate as the abscissa and the bottom-hole flowing pressure value as the ordinate is obtained; the dynamic point is subjected to wellbore multiphase flow calculation up to the point corresponding to the pump inlet, and a multiphase dynamic point with the production rate as the abscissa and the pump inlet pressure as the ordinate is obtained; the multiphase dynamic points are connected into a curve by the point-plotting method, and the curve is the pump inlet inflow dynamic curve corresponding to the depth; the pump inlet inflow dynamic curve is analyzed to obtain the optimal pump setting depth and the optimal production parameters. It provides a basis for selecting a reasonable pump setting depth range and determining a reasonable working system for non-flowing oil wells, especially rod-pumped deep pumping technology oil wells.

[0082] The above description is only an overview of the technical solution of the present invention. In order to be able to understand the technical means of the present invention more clearly, it can be implemented according to the content of the specification. And in order to make the above and other objects, features and advantages of the present invention more obvious and understandable, the following specifically describes the embodiments of the present invention. BRIEF DESCRIPTION OF THE DRAWINGS

[0083] In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings required for the description of the embodiments will be briefly introduced below. Obviously, the drawings in the following description are only some embodiments of the present invention. For those of ordinary skill in the art, other drawings can be obtained based on these drawings without creative efforts.

[0084] Figure 1 It is a flowchart of a new pump inlet inflow dynamic analysis method provided by an embodiment of the present invention;

[0085] Figure 2 Taking an oil well in the Linpan block of Shengli Oilfield as an example, it is the obtained inflow dynamic curve provided by an embodiment of the present invention;

[0086] Figure 3 It is a flowchart for considering gas phase and liquid phase when calculating the pressure gradient provided by the Orkiszewski method of the present invention;

[0087] Figure 4 It is a schematic diagram of the current pump inlet inflow dynamic curve of an oil well provided by an embodiment of the present invention. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0088] The exemplary embodiments of the present disclosure will be described in more detail below with reference to the drawings. Although the exemplary embodiments of the present disclosure are shown in the drawings, it should be understood that the present disclosure can be implemented in various forms and should not be limited by the embodiments set forth herein. On the contrary, these embodiments are provided so that the present disclosure can be more thoroughly understood and the scope of the present disclosure can be fully conveyed to those skilled in the art.

[0089] In the embodiments of the specification, claims and drawings of the present invention, the terms "comprising", "having" and any variations thereof are intended to cover non-exclusive inclusion. For example, a series of steps or units are included.

[0090] The technical solution of the present invention will be further described in detail below with reference to the drawings and embodiments.

[0091] As Figure 1 shown, a new method for analyzing the inflow dynamics at the pump inlet includes:

[0092] Obtain the basic data of well logging for different oil layers;

[0093] Establish a productivity prediction model applicable to a given oil reservoir based on the basic data;

[0094] Draw the inflow performance curve of the corresponding oil well according to the productivity prediction model; through the above model, combined with the actual on-site data, draw the corresponding inflow performance curve. Taking an oil well in the Linpan block of Shengli Oilfield as an example, the obtained inflow performance curve is as shown in the appendix Figure 2 shown.

[0095] Starting from the well depth, take a position upward as the setting depth of the pump. On the inflow performance curve, starting from 0 MPa, at intervals of 1 MPa, obtain the bottom-hole flowing pressure value corresponding to a production rate of 0 m 3 / d, and obtain the dynamic points with the production rate as the abscissa and the bottom-hole flowing pressure value as the ordinate;

[0096] Perform wellbore multiphase flow calculation on the dynamic points until the point corresponding to the pump inlet, and obtain the multiphase dynamic points with the production rate as the abscissa and the pump inlet pressure as the ordinate;

[0097] Use the point plotting method to connect the multiphase dynamic points into a curve, and the curve is the inflow performance curve at the pump inlet corresponding to the depth;

[0098] Analyze the inflow performance curve at the pump inlet to obtain the optimal setting depth and optimal production parameters.

[0099] The establishment of the productivity prediction model applicable to a given oil reservoir based on the basic data specifically includes:

[0100] Productivity prediction model

[0101]

[0102]

[0103] where k F , k MThey are the permeabilities of the fracture and the matrix respectively; w is the fracture width; h is the reservoir thickness; B is the volume factor; μ is the crude oil viscosity; η is the formation pressure conductivity coefficient; X f is the half-length of the fracture; c is the comprehensive compressibility; φ M is the matrix porosity.

[0104] Starting from the well depth, taking a position upward as the setting depth of the pump, calculating from 0 MPa on the inflow performance curve at intervals of 1 MPa, and obtaining the bottom-hole flowing pressure value corresponding to a production rate of 0 m 3 / d, and obtaining the dynamic points with the production rate as the abscissa and the bottom-hole flowing pressure value as the ordinate specifically includes:

[0105] The pressure gradient of multiphase pipe flow in the wellbore includes: the pressure potential energy required to overcome gravity by lifting the liquid, the kinetic energy increased by the acceleration of the fluid, and the frictional loss of the fluid along the pipeline. The mathematical expression is as follows:

[0106]

[0107] In the formula, ρ m is the density of the multiphase mixture; v m is the flow velocity of the multiphase mixture; f m is the friction resistance coefficient when the multiphase mixture flows; d is the pipe diameter; p is the pressure; h is the depth; g is the acceleration due to gravity; θ is the complementary angle of the well deviation angle;

[0108] Calculate the pressure distribution along the path according to the pressure gradient of the multiphase pipe flow in the wellbore.

[0109] Optionally, the calculating the pressure distribution along the path according to the pressure gradient of the multiphase pipe flow in the wellbore specifically includes:

[0110] Using depth increment for iterative calculation of the pressure distribution along the path;

[0111] Taking the pressure P0 at the well location as the starting point, the well location includes any one of the wellhead and the bottom hole; obtaining the pressure drop value ΔP as the calculated pressure interval, and obtaining the depth increment Δh corresponding to the pressure drop value ΔP for calculating the temperature T1 at the lower end of the well according to the temperature gradient;

[0112] Calculating the average temperature T and average pressure P of the corresponding wellbore pipe section according to the temperature T1 at the lower end of the well, and determining all the corresponding fluid property parameters. All the fluid property parameters include the dissolved gas-oil ratio R g , the crude oil volume factor B o and the viscosity μ o , the gas density ρ g and the viscosity μ g , the mixture viscosity μ m and the surface tension σ;

[0113] Calculate the pressure gradient of the wellbore pipe section Calculate the depth difference Δh of the corresponding wellbore pipe section corresponding to the pressure drop value ΔP 计 ;

[0114] Obtain the depth difference Δh 计 Find the difference from the depth increment Δh, and determine whether the difference exceeds the set range ε. If so, continue the iteration; otherwise, stop the iteration;

[0115] Calculate the depth L corresponding to the lower end of the wellbore pipe section i and the pressure P i ;

[0116]

[0117] P i = P o + iΔP (6)

[0118] where i = 1, 2, 3, … n

[0119] Starting from the pressure at L i Repeat the above steps to calculate the depth L of the next wellbore pipe section i+1 and the pressure P i+1 , until the cumulative depth L of each section n ≥ the pipe length L

[0120] When calculating the pressure gradient, the distribution relationship between the gas phase and the liquid phase needs to be considered. Here, the Orkiszewski method is adopted. The flow chart is shown in the appendix Figure 3 :

[0121] The pressure gradient of the multiphase pipe flow in the wellbore specifically includes:

[0122] Pressure drop formula and flow pattern division boundary:

[0123]

[0124] In the formula, ΔP k is the pressure drop of the calculated pipe section; Δh k is the depth difference of the calculated pipe section; P is the average pressure of the calculated pipe section;

[0125] Volume flow rate of gas:

[0126] In the formula, q g is the volume flow rate of gas, m3 / s; γ o is the relative density of oil; q o is the oil production rate, t / d. Note: When R p <Rs When taking R p = R s .

[0127] Mass flow rate of gas:

[0128] In the formula, W g — Mass flow rate of gas, kg / s; γ g — Relative density of gas;

[0129] Volume flow rate of liquid:

[0130] In the formula, Q l — Volume flow rate of liquid, m3 / s; q l — Liquid production, t / d;

[0131] Volume flow rate of liquid:

[0132] In the formula, W l — Mass flow rate of liquid, kg / s;

[0133] Total volume flow rate of mixture: Q t = Q g + Q l (12)

[0134] Total mass flow rate of mixture: W t = W g + W l (13).

[0135] Under different flow patterns, and τ f are calculated differently. The flow pattern needs to be judged first in the calculation. The dividing boundaries of the four flow patterns of this method are shown in Table 1.

[0136] Table 1 Flow pattern boundaries

[0137]

[0138] The average density and friction loss gradient specifically include:

[0139] Under different flow patterns, the calculation methods of the average density and friction loss gradient are different, specifically including: Under the bubble flow pattern:

[0140] Average density:

[0141]

[0142] H L + H g = 1 (15)

[0143] Wherein, H g — gas holdup, calculated as the ratio of the gas volume to the pipe volume in the calculated pipe section; H L — liquid holdup, calculated as the ratio of the liquid volume to the pipe volume in the calculated pipe section; ρ g 、ρ L 、 — the density of the gas, liquid, and mixture under conditions, kg / m3;

[0144] The gas holdup is calculated from the slip velocity V s ; the slip velocity is defined as the difference between the gas flow velocity and the liquid flow velocity;

[0145]

[0146] H g can be solved as:

[0147]

[0148] Wherein, v s — slip velocity, determined experimentally, m / s; v sg 、v sL — superficial velocities of the gas and liquid, m / s;

[0149] The frictional loss gradient of slug flow is calculated based on the liquid phase:

[0150]

[0151]

[0152] Wherein, f is the friction coefficient;

[0153] v LH — true liquid velocity, m / s;

[0154] The average density of the slug flow mixture

[0155]

[0156] Wherein, δ is the liquid distribution coefficient; v s — slip velocity, m / s;

[0157] The slip velocity can be calculated using the formula proposed by Griffith and Wallis:

[0158]

[0159] For transitional flow, the average density and frictional gradient of the mixture are first calculated separately for slug flow and mist flow, and then the corresponding values are determined by interpolation;

[0160]

[0161]

[0162] Where ρ SL 、τ SL and ρ Mi 、τ Mi are the mixture density and friction gradient calculated according to slug flow and mist flow respectively;

[0163] The calculation formula for the mist flow mixture density is the same as that for the bubble flow:

[0164]

[0165] Since there is no relative velocity between gas and liquid in mist flow, that is, the slip velocity is close to zero and there is basically no slip; therefore

[0166]

[0167] the friction gradient is calculated according to the continuous gas phase, that is

[0168]

[0169] Where v sg —superficial gas velocity, v sg = q g / A p m / s.

[0170] Plotting the inflow performance curve at the pump inlet by the point - plotting method

[0171] For the selected points, the suction pressure of the pump at this production rate can be calculated using the Orkiszewski method, thus obtaining a batch of mapped points at the pump inlet for the selected points. Next, by connecting these mapped points with the point - plotting method, the current inflow performance curve at the pump inlet of this oil well can be obtained, as shown in the appendix Figure 4 as follows.

[0172] Application of the inflow performance curve at the pump inlet: Finding the reasonable interval of pump setting depth

[0173] For pumping wells, especially low - permeability oil wells, their inflow performance curves often have different shapes from the conventional ones. Under the influence of reservoir stress sensitivity or gas, the inflow performance curve often shows an "inflection point", that is, as the bottom - hole flowing pressure decreases, the production capacity increases slowly or may even decrease, and the corresponding inflow performance curve at the pump inlet will also show an "inflection point". From the appendix Figure 4It can be seen that the production values at the "inflection points" of the inflow dynamic curves flowing into different pump ports do not vary significantly, only the pump inlet pressures differ quite obviously. However, in any case, the production regime should be adjusted as much as possible to keep the operating point near the "inflection point" to obtain the maximum production. On this premise, combined with the attached Figure 4 It can be found that when the depth of the downhole pump is relatively shallow, the inflection point of the inflow dynamic curve at the pump port is below the horizontal axis. Practically speaking, only when the pump inlet pressure is negative can the "inflection point" production be achieved. Therefore, there is a lower limit for the value of the downhole pump depth, that is, the "inflection point" of the inflow dynamic curve corresponding to this downhole pump depth should be at least above the horizontal axis. As the downhole pump depth increases, the production corresponding to the "inflection point" of the inflow dynamic curve at the pump port does not increase significantly, but the cost of the tubing consumed and the pump efficiency loss (especially the stroke loss) increase significantly. Therefore, it is necessary to optimize in combination with the pump efficiency and tubing cost to select the upper limit of the downhole pump depth value. The optimal downhole pump depth range can be obtained based on the upper and lower limits of the downhole pump depth value.

[0174] Given the downhole pump depth, determine the reasonable production regime

[0175] After optimizing the downhole pump depth, the optimal production regime under this downhole pump depth can be selected through the inflow dynamic curve at the pump port. Here, it is necessary to combine programming methods to enable the input of production parameters such as the stroke and the number of strokes per minute, and control the downhole pump depth to remain unchanged. By continuously adjusting the parameters to make the operating point as close as possible to the "inflection point", the maximum production can be obtained. The parameters input at this time are the reasonable production regime parameters.

[0176] Beneficial effects:

[0177] 1. The innovative concept of "inflow dynamic curve at the pump port" is proposed, making up for the deficiency that the traditional inflow dynamic curve cannot reflect the depth of the downhole pump in a pumping unit.

[0178] 2. By plotting the inflow dynamic curves at the pump ports with different downhole pump depths, a reasonable downhole pump depth range can be analyzed and obtained.

[0179] 3. After selecting the optimal downhole pump depth and adjusting the parameters, the optimal production parameters can be obtained.

[0180] In the above specific embodiments, the purpose, technical solutions, and beneficial effects of the present invention are further described in detail. It should be understood that the above are only specific embodiments of the present invention and are not used to limit the protection scope of the present invention. Any modifications, equivalent replacements, improvements, etc. made within the spirit and principles of the present invention should be included in the protection scope of the present invention.

Claims

1. A new method for analyzing the inflow dynamics at the pump inlet, characterized in that, The analysis method includes: Obtaining the basic data of well logging for different oil layers; Establishing a productivity prediction model applicable to a given oil reservoir based on the basic data; Drawing an inflow performance curve for the corresponding oil well according to the productivity prediction model; Starting from the well depth, take a position upward as the setting depth of the pump. Starting from 0 MPa on the inflow performance curve, calculate at intervals of 1 MPa to obtain the bottom-hole flowing pressure value corresponding to a production rate of 0 m 3 / d, and obtain dynamic points with the production rate as the abscissa and the bottom-hole flowing pressure value as the ordinate, including: The pressure gradient of the wellbore multiphase pipe flow includes: the pressure potential energy required to overcome gravity by lifting the liquid, the kinetic energy increased by the acceleration of the fluid, and the frictional loss of the fluid along the pipeline. The mathematical expression is as follows: where ρ m is the density of the multiphase mixture; v m is the flow velocity of the multiphase mixture; f m is the friction resistance coefficient during the flow of the multiphase mixture; d is the pipe diameter; p is the pressure; h is the depth; g is the acceleration due to gravity; θ is the complementary angle of the well deviation angle; Calculating the pressure distribution along the path according to the pressure gradient of the wellbore multiphase pipe flow; Performing wellbore multiphase flow calculation on the dynamic points until the point corresponding to the pump inlet, and obtaining multiphase dynamic points with the production rate as the abscissa and the pump inlet pressure as the ordinate; Connecting the multiphase dynamic points into a curve by the point plotting method, and the curve is the pump inlet inflow performance curve at the corresponding depth; Analyzing the pump inlet inflow performance curve to obtain the optimal pump setting depth and optimal production parameters.

2. The novel pump inlet flow dynamic analysis method according to claim 1, characterized in that, The specific steps of establishing a productivity prediction model applicable to a given oil reservoir based on the basic data include: where k F , k M are the permeabilities of the fracture and matrix respectively; w is the fracture width; h is the reservoir thickness; B is the volume coefficient; μ is the crude oil viscosity; η is the formation pressure conductivity coefficient; X f is the half-length of the fracture; c is the comprehensive compressibility coefficient; φ M is the matrix porosity.

3. A novel dynamic analysis method for inflow at the pump inlet according to claim 1, characterized in that, The specific steps of calculating the pressure distribution along the path according to the pressure gradient of the wellbore multiphase pipe flow include: performing iterative calculation of the pressure distribution along the path using depth increments; Taking the pressure P0 at the position of the well as the starting point, where the position of the well includes any one of the wellhead and the bottom hole; obtaining the pressure drop value ΔP as the calculated pressure interval, and obtaining the depth increment Δh corresponding to the pressure drop value ΔP, which is used to calculate the temperature T1 at the lower end of the well according to the temperature gradient; Calculate the average temperature of the corresponding wellbore pipe section based on the temperature T1 at the lower end of the well and the average pressure and determine all the corresponding fluid property parameters, where the all fluid property parameters include the dissolved gas-oil ratio R g , the crude oil volume factor B o and the viscosity μ o , the gas density ρ g and the viscosity μ g , the mixture viscosity μ m and the surface tension σ; Calculate the pressure gradient of the wellbore section Calculate the depth difference Δh of the corresponding wellbore section corresponding to the pressure drop value ΔP 计 ; Obtain the depth difference Δh 计 Calculate the difference from the depth increment Δh, and determine whether the difference exceeds the set range ε. If so, continue the iteration; otherwise, stop the iteration. Calculate the depth L corresponding to the lower end of the wellbore pipe section i and the pressure P i ; P i = P o + iΔP (6) where i = 1, 2, 3,... n Starting from the pressure at L i as the starting point, repeat the above steps to calculate the depth L i+1 and pressure P i+1 of the next section of the wellbore pipe section until the cumulative depth L n ≥ the pipe length L 4. A novel dynamic analysis method for the inflow at the pump port according to claim 1, characterized in that, The pressure gradient of the wellbore multiphase pipe flow specifically includes: The pressure drop formula and the flow pattern division boundary: where ΔP k is the pressure drop of the calculated pipe section; Δh k is the depth difference of the calculated pipe section; P is the average pressure of the calculated pipe section; Volume flow rate of gas: Where q g is the volumetric flow rate of the gas, m3 / s; γ o is the relative density of the oil; q o is the oil production, t / d; Note: when R p <R s , take R p =R s； Mass flow rate of gas: Where, W g — mass flow rate of gas, kg / s; γ g — relative density of gas; Volume flow rate of the liquid: Where Q l — volume flow rate of the liquid, m3 / s; q l — liquid production, t / d Volume flow rate of the liquid: Where, W l — mass flow rate of the liquid, kg / s; Total volume flow rate of the mixture: Q t = Q g + Q l (12) Total mass flow rate of the mixture: W t = W g + W l (13).

5. A novel dynamic analysis method for the inflow at the pump port according to claim 4, characterized in that, The average density and the friction loss gradient specifically include: The calculation methods of the average density and the friction loss gradient under different flow patterns are different. Specifically, under the bubbly flow pattern: Average density: H L +H g = 1 (15) Where, H g — Gas holdup, which is the ratio of the gas volume in the calculation pipe section to the pipe section volume; H L — Liquid holdup, which is the ratio of the liquid volume in the calculation pipe section to the pipe section volume; ρ g 、ρ L 、 — The density of gas, liquid and mixture under condition, kg / m3; The gas-phase storage ratio is calculated from the slippage velocity V s ; the slippage velocity is defined as the difference between the gas-phase flow rate and the liquid-phase flow rate; H can be solved g : where, v s — slippage velocity, determined by experiment, m / s; v sg , v sL — superficial velocities of gas phase and liquid phase, m / s; The bubbly flow friction loss gradient is calculated according to the liquid phase: In the formula, f is the friction resistance coefficient; v LH —True flow velocity of liquid phase, m / s; The average density of the slug flow mixture where δ is the liquid distribution coefficient; v s — the slip velocity, m / s; The slip velocity can be calculated by the formula proposed by Griffith and Wallis: The average density and the friction gradient of the transitional flow mixture are first calculated separately according to the slug flow and the mist flow, and then the corresponding values are determined by the interpolation method; where ρ SL , τ SL and ρ Mi , τ Mi are the mixture density and friction gradient calculated according to slug flow and mist flow respectively; The calculation formula of the mist flow mixture density is the same as that of the bubbly flow; Since there is no relative movement velocity between the gas and the liquid in the mist flow, that is, the slip velocity is close to zero, and there is basically no slip; therefore The friction gradient is calculated according to the continuous gas phase, that is wherein, v sg — superficial gas velocity, v sg = q g / A p m / s

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