Thick oil horizontal well liquid production profile interpretation method and system

Abstract

The invention provides a thick oil horizontal well liquid production profile interpretation method and system, and the method comprises the steps: 1, dividing a horizontal section into a plurality of unit sections according to the position of an injection allocation device; 2, considering the variable mass flow, and determining the on-way pressure drop of the horizontal shaft; 3, considering oil reservoir-wellbore coupling, and determining a horizontal wellbore temperature field; 4, temperature and pressure data at different injection allocator positions are monitored through a thermomanometer; and step 5, inverting a horizontal well fluid production profile by combining an MCMC algorithm. The thick oil horizontal well liquid production profile interpretation method and system meet the requirement for full well section liquid production cognition of a thick oil thermal recovery horizontal well, guide effective implementation of follow-up blocking and adjusting, steam injection and other process measures of an oil well, and improve the overall recovery efficiency and economic benefits of a thick oil reservoir.

Description

TECHNICAL FIELD

[0001] The present application relates to the technical field of oil and gas field development, and particularly relates to a heavy oil horizontal well liquid production profile interpretation method and system. BACKGROUND

[0002] Accurate interpretation of the horizontal well liquid production profile has important guiding significance for horizontal well production condition judgment, development plan adjustment and field measure implementation. Especially for the determination of the heavy oil thermal recovery horizontal well liquid production profile after multi-point steam injection, which is crucial for the selection of the next round of steam injection volume, steam injection pressure, steam injection temperature, steam dryness and shunt position of the injection distributor. However, due to the fact that the related testing problems have not been fundamentally solved, the heavy oil horizontal well liquid production profile cannot be directly measured at present, and it is usually obtained by indirect interpretation using temperature and pressure data, tracer analysis and production data.

[0003] In the Chinese patent application with the application number CN202110106737.1, a horizontal oil well liquid production profile calculation method is involved. However, this method only delivers the measured marker to the predetermined position of the oil field logging through the release device to measure the liquid production profile flow of different horizontal oil wells. This invention uses the tracer method and does not involve temperature and pressure logging data.

[0004] In the Chinese patent application with the application number CN202211119337.5, a multi-layer commingled production liquid profile splitting method based on XGBoost and CV cross function is involved. However, this invention only involves the machine learning processing method of static and dynamic data of oil and water wells and does not involve the establishment of temperature field model.

[0005] In 2014, Deng Zhongxian et al. published a heavy oil horizontal well steam absorption profile interpretation method based on well temperature data in Special Oil and Gas Reservoirs. According to the completion conditions, a theoretical model is established, the steam wellbore heat and mass transfer calculation theory is used, and the curve fitting method is adopted to achieve the technical purpose of inverting the horizontal section steam absorption profile through well temperature data. Although this method only involves steam absorption profile interpretation and does not consider wellbore pressure distribution and reservoir-wellbore coupling calculation, it has certain reference significance for horizontal well liquid production profile interpretation.

[0006] In 2023, Zhu Haitao et al. published a horizontal well liquid production profile temperature measurement inversion method based on Adam optimization algorithm in Journal of China University of Petroleum (Edition of Natural Science). However, this method only simply segments the horizontal well and does not consider the position of the field injection distributor; the established wellbore temperature distribution function does not consider the reservoir-wellbore coupling; the inversion method considers the Adam optimization algorithm and does not involve the MCMC algorithm.

[0007] In 2023, Wang Tao et al. published a study on the prediction of liquid production profile of horizontal wells in bottom water reservoirs in Petroleum and Chemical Applications. A model for predicting the liquid production profile of horizontal wells in bottom water reservoirs was established, which coupled the reservoir seepage and the annular flow of the wellbore. Although the model takes into account the influence of the segmentation method of horizontal wells, it only considers bottom water reservoirs and does not involve the segmentation method of the position of the injection distributor in heavy oil thermal recovery horizontal wells, as well as the liquid production profile calculation method related to the injection distributor.

[0008] In summary, the current heavy oil horizontal well liquid production profile interpretation method has certain problems, therefore we have invented a new heavy oil horizontal well liquid production profile interpretation method and system. SUMMARY

[0009] The purpose of the present application is to provide a heavy oil horizontal well liquid production profile interpretation method and system that addresses the need for full well segment liquid production awareness in heavy oil thermal recovery horizontal wells, guides the effective implementation of subsequent plugging and adjusting, steam injection and other process measures, and improves the overall recovery rate and economic benefits of heavy oil reservoirs.

[0010] The purpose of the present application can be achieved through the following technical measures: a heavy oil horizontal well liquid production profile interpretation method, which comprises:

[0011] Step 1: According to the position of the injection distributor, the horizontal section is divided into multiple unit segments;

[0012] Step 2: Considering variable mass flow, determine the pressure drop along the horizontal wellbore;

[0013] Step 3: Considering the reservoir-wellbore coupling, determine the temperature field of the horizontal wellbore;

[0014] Step 4: Use temperature and pressure gauges to monitor temperature and pressure data at different injection distributors;

[0015] Step 5: Combine the MCMC algorithm to invert the horizontal well liquid production profile.

[0016] The purpose of the present application can also be achieved through the following technical measures:

[0017] In step 1, the horizontal section is divided into n unit segments from the toe to the heel according to the placement position of the n injection distributors, which is equivalent to one injection distributor controlling the liquid production of one unit segment. This segmentation method ensures that the reservoir properties of each unit segment remain basically unchanged, and the segmentation is reasonable. The permeability, liquid production and fluid properties of the oil layer in each unit segment are assumed to be constant, and the produced liquid of each unit segment flows out from the injection distributor that controls this unit segment. The segmentation length of each unit segment is s1, s2, …, s n (m), and the liquid production is Q1, Q2, …, Q n (m 3 / s).

[0018] In step 2, the production process, considering the influence of different flow patterns, variable mass flow, the establishment of horizontal wellbore pressure field calculation method, to determine the horizontal wellbore pressure drop along the way; horizontal well pressure field calculation method, (dP / ds) i The pressure drop of the i-th section due to the liquid production rate Q i The pressure drop of the i-th section due to the liquid production rate Q i The temperature rise of the i-th section (dT / ds) i , the greater the pressure drop, the higher the temperature rise.

[0019] In step 2, the wellbore pressure drop is composed of gravity pressure drop, friction pressure drop, acceleration pressure drop, injection port pressure drop and mixing pressure drop, wherein the inclination angle θ of the horizontal well is zero, so the gravity pressure drop is not considered. The wellbore pressure drop calculation formula is:

[0020] (dP / ds) i =(dP / ds) f,i +(dP / ds) acc,i +(dP / ds) inj,i +(dP / ds) mix,i (1)

[0021] The friction pressure drop calculation formula is:

[0022]

[0023] Wherein, (dP / ds) i The pressure drop of the i-th section, MPa; (dP / ds) f,i The friction pressure drop of the i-th section, MPa; (dP / ds) acc,i The acceleration pressure drop of the i-th section, MPa; (dP / ds) inj,i The injection port pressure drop of the i-th section, MPa; (dP / ds) mix,i The mixing pressure drop of the i-th section, MPa; ρ is the density of the fluid in the wellbore, kg / m 3 ; r wb The cement sheath radius, m; v i The flow rate of the i-th section, m / s; f i The friction coefficient of the i-th section along the way; The friction coefficient f i is related to the flow pattern, different flow patterns correspond to different horizontal liquid holdup, which in turn affects the Reynolds number N re size, and the friction coefficient f i There is a certain correspondence with the Reynolds number, as shown in equation (3),

[0024]

[0025] The acceleration pressure drop calculation formula is:

[0026]

[0027] P i is the i-th section of the wellbore pressure, MPa; Q i represents the i-th section of the unit section of liquid production, m 3 / s.

[0028] The liquid flow through the injection distributor will have a throttling effect, and the injection distributor hole pressure drop calculation formula is:

[0029]

[0030]

[0031]

[0032] fr i and ax i are the calculation process assumed parameters and do not represent specific physical quantities; c is the injection distributor hole roughness, m; r ci is the screen inner diameter, m; d inj is the injection distributor hole diameter, m; s i represents the i-th unit section length, m; S i represents the i-th injection distributor flow area, m 2 .

[0033] The mixed pressure drop is related to the injection distributor hole pressure drop, and the calculation formula is:

[0034]

[0035] In step 2, the flow pattern of downhole fluid flow is mainly divided into four types: separated flow, transition flow, intermittent flow and dispersed flow. For oil-gas-water three-phase flow, E L represents the liquid volume fraction, E L takes the value of [0, 1], N Fr represents the Froude number; for oil-water two-phase flow, E L takes the value of 1. When E L <0.01 and N Fr <316*E L 0.302 , or E L ≥0.01 and N Fr <0.0009*E L -2.4684 , the downhole flow pattern is determined as separated flow; when E L >0.01 and 0.0009*E L -2.4684 <NFr ≤0.1*E L -1.4516 At that time, the downhole flow pattern was determined to be transitional flow; when 0.01 <E L <0.4 and 0.1*E L -1.4516 <N Fr ≤316*E L 0.302 , or E L ≥0.4 and 0.1*E L -1.4516 <N Fr ≤0.5*E L -6.738 At that time, the downhole flow pattern was determined to be intermittent flow; when E L <0.4 and N Fr ≥316*E L 0.302 , or E L ≥0.4 and N Fr >0.5*E L -6.738 At that time, the downhole flow pattern was determined to be a dispersed flow.

[0036] In step 3, the coupling relationship between the reservoir temperature field and the wellbore temperature field is reflected in the fact that the temperature and pressure distribution along the horizontal well affects the fluid production of the reservoir in each unit section, while the fluid production of the reservoir affects the temperature and pressure distribution along the horizontal well. The two need to be coupled and calculated.

[0037] In step 3, heat exchange occurs between the fluid flow inside the screen tube and the formation, mainly including heat conduction and heat convection. During the heat transfer process between the formation and the wellbore, the heat transfer coefficients U1 between the screen tube and the cement sheath, U2 between the cement sheath and the formation, and U1 between the formation and the wellbore are calculated. 总 They are respectively:

[0038]

[0039]

[0040] U 总,i =U1+U 2,i (11)

[0041] Among them, K cas and K cem λ and r are the thermal conductivity of the sieve tube and cement ring, respectively, in W / (m·℃); ci r co and r wb These are the inner diameter of the screen tube, the outer diameter of the screen tube, and the radius of the cement ring, respectively, in meters (m); T i T represents the fluid flow temperature in the i-th wellbore segment, in °C, where i = 1, 2, ..., n;In,i T f represents the oil reservoir temperature, ℃; in the heat transfer coefficient, U1 is a constant value;

[0042] The produced fluid in the oil reservoir flows into the injection distributor through the seepage channel, and the amount and properties of the produced fluid affect the temperature of the produced fluid flowing into the injection distributor, so the produced fluid inflow temperature T In,i needs to be calculated.

[0043]

[0044] wherein, K f is the thermal conductivity of the formation, W / (m·℃); ρ is the density, kg / m 3 ; c p is the specific heat capacity, J / (kg·℃); μ is the viscosity, mPa·s; k i is the permeability, mD; β is the volumetric expansion coefficient, decimal;

[0045] The produced fluid inflow temperature T In,i is related to the produced fluid amount Q i of the oil reservoir and also affects the fluid flow temperature T i in the screen pipe, and is the link between the reservoir temperature field and the wellbore temperature field, and is also the key node of the reservoir-wellbore temperature field coupling;

[0046] The flow rate in the i-th section of the screen pipe is equal to the sum of the produced fluid amounts flowing through the injection distributors in the first section to the i-th section. According to the mass and energy conservation equations, considering the effects of heat conduction, heat convection and variable mass flow, the fluid temperature in the i-th unit section of the screen pipe is:

[0047] T i =T i-1 +(dT / ds) i ·s i (13)

[0048]

[0049] wherein, (dT / ds) i represents the temperature rise per unit well length of the i-th section due to the inflow of the produced fluid amount Q i ; (dP / ds) i represents the pressure drop per unit well length of the i-th section due to the inflow of the produced fluid amount Q i , which is obtained according to step 2; S i is the discharge area of the i-th injection distributor, m 2 ; θ is the inclination angle, °

[0050] The discharge area S i of the injection distributor is related to the aperture and hole density of the injection distributor, and S iThe calculation formula is:

[0051] S i = πd inj 2 / 4·Holes (15)

[0052] Wherein, d inj is the diameter of the injection device hole, m; Holes is the number of injection device holes, the diameter of the injection device hole and the number of holes affect the effect of balanced steam injection of thermal recovery wells, and the steam injection effect ultimately affects the liquid production of the horizontal section in the production process of the horizontal well.

[0053] In step 4, when the thermal recovery well is in stable production, the temperature and pressure gauge is lowered into the production string, and the temperature and pressure data are monitored from the injection device closest to the toe of the horizontal well. After monitoring the temperature and pressure of this injection device, the temperature and pressure gauge is moved to monitor the temperature and pressure data of other injection devices in turn, that is, n injection devices correspond to n temperature measuring points and pressure measuring points, and finally the measured well temperature data and measured pressure data in the production process of the horizontal well are obtained.

[0054] Step 5 includes:

[0055] Step 51, a target function is established to represent the difference between the inversion value and the measured value, so as to measure the goodness of the inversion result; the calculation formula of the target function is:

[0056]

[0057]

[0058] Wherein, F P and F T are the target function values of pressure and temperature respectively; P 实测 and T 实测 are the real pressure value and temperature value measured by the temperature and pressure gauge; P(Q) and T(Q) respectively represent the pressure value and temperature value calculated by the horizontal wellbore pressure field and temperature field model in the heavy oil horizontal well liquid production profile interpretation method established according to the present application under the given assumption of flow rate Q; C is the covariance matrix.

[0059] Step 52, an initial flow rate Q(0) is reasonably assumed, the assumed flow rate Q(0) is substituted into the horizontal wellbore pressure field and temperature field calculation model established in steps 2 and 3 to obtain the corresponding pressure P a (0) and well temperature T a (0), and the target functions F P (0) and F T (0) are calculated.

[0060] Step 53, the MCMC algorithm is used to make the target functions F P (0) and F T(0) reach minimum, set a random jump △Q ~ N (0, sigma) from the uniform distribution of MCMC, and then generate a new sample by disturbing the current sample, and the flow of the next horizontal section is Q (1) = Q (0) + △Q;

[0061] Step 54, substituting the flow Q (1) into the horizontal wellbore pressure field and temperature field calculation model to obtain the corresponding pressure P a (1) and well temperature T a (1), and combining the temperature and pressure data measured by the temperature and pressure gauge in step 4, the objective function F P (1) and F T (1) is calculated;

[0062] Step 55, set a random number A ~ U (0, 1), and determine whether to accept the flow Q (1) generated by the MCMC distribution model in step 53 according to the acceptance probability:

[0063]

[0064]

[0065] If A < alpha1 and A < alpha2 are satisfied at the same time, Q (1) is accepted, and the calculation of the next horizontal section is performed, otherwise, steps 52 to 54 are repeated until the conditions are met;

[0066] Step 56, the flow Q (i) finally inverted by each horizontal section is the distribution of the horizontal well liquid production profile.

[0067] The purpose of the application can also be achieved by the following technical measures: a heavy oil horizontal well liquid production profile interpretation system, the heavy oil horizontal well liquid production profile interpretation system comprising:

[0068] A horizontal well section analysis unit divides the horizontal section into multiple unit sections according to the injection distributor position;

[0069] A horizontal well along-the-way pressure distribution processing unit determines the pressure drop along the horizontal wellbore by considering variable mass flow;

[0070] A horizontal well along-the-way temperature distribution processing unit determines the temperature field of the horizontal wellbore by considering reservoir-wellbore coupling;

[0071] A temperature and pressure data monitoring unit monitors the temperature and pressure data at different injection distributors by using a temperature and pressure gauge;

[0072] An MCMC inversion processing unit inverses the horizontal well liquid production profile by combining the MCMC algorithm.

[0073] The purpose of the application can also be achieved by the following technical measures:

[0074] The horizontal well section analysis unit divides the horizontal section into n unit sections from toe to heel according to the placement positions of the n diverters of the horizontal well, which is equivalent to that one unit section is controlled by one diverter to control the liquid production; and transmits the horizontal well section information to the horizontal well along the line pressure distribution processing unit during production.

[0075] The horizontal well along the line pressure distribution processing unit calculates the pressure distribution at different diverter positions of the horizontal well during production by using the wellbore pressure drop equation composed of friction pressure drop, acceleration pressure drop, diverter hole pressure drop and mixed pressure drop, and considers the influence of different flow patterns in the pressure calculation process; and transmits the calculated pressure data at different diverter positions of the horizontal well to the horizontal well along the line temperature distribution processing unit and the MCMC inversion processing unit.

[0076] The horizontal well along the line temperature distribution processing unit considers the effects of reservoir-wellbore coupling and variable mass flow, analyzes the heat conduction and heat convection between the wellbore and the formation, and the interaction relationship between the liquid production and the temperature and pressure, and calculates the temperature distribution at different diverter positions of the horizontal well during production; and transmits the calculated temperature data to the MCMC inversion processing unit.

[0077] The temperature and pressure data monitoring unit monitors and collects the measured temperature and pressure data of the horizontal well at different diverter positions during production; and transmits the collected temperature and pressure data to the MCMC inversion processing unit.

[0078] The heavy oil horizontal well liquid production profile interpretation system further comprises a liquid production profile interpretation output unit, the MCMC inversion processing unit establishes a target function representing the difference between the temperature and pressure inversion values and the measured values, combines the MCMC inversion algorithm to calculate the flow rate of each horizontal section controlled by each diverter; and transmits the calculated liquid production results of each horizontal section to the liquid production profile interpretation output unit.

[0079] The heavy oil horizontal well liquid production profile interpretation system further comprises a next round steam injection optimization analysis unit, the liquid production profile interpretation output unit outputs the corresponding liquid production at each diverter position; and transmits the calculated liquid production to the next round steam injection optimization analysis unit; the next round steam injection optimization analysis unit uses the liquid production of this round output by the liquid production profile interpretation output unit, reconsiders the reservoir properties and steam injection effect according to the result, and adjusts the diverter distribution position and the diverter steam injection volume during the next round steam injection of the heavy oil well.

[0080] The heavy oil horizontal well liquid production profile interpretation method and system in the application is an inversion algorithm based on temperature and pressure data and MCMC (Markov Chain Monte Carlo), which is used to overcome the problem that the existing horizontal well testing technology cannot directly measure the horizontal well liquid production profile, and achieve the technical purpose of inverting the liquid production profile by using temperature and pressure monitoring data. The horizontal section is divided into multiple unit sections according to the position of the horizontal section injection distributor set during steam injection. During the production process of the horizontal well, the liquid production of each unit section is assumed, and a horizontal well liquid production profile theoretical model suitable for screen pipe completion is established. The influence of different flow patterns and variable mass flow is considered in the model, and the temperature and pressure data of different unit sections of the horizontal well during the production process are obtained by combining the reservoir-wellbore coupled temperature field and pressure field calculation method, and the liquid production profile along the injection distributor position of the horizontal well is obtained by using the MCMC inversion algorithm.

[0081] The application discloses a heavy oil horizontal well multi-point steam injection horizontal well production process combined with an MCMC inversion algorithm, and a heavy oil horizontal well liquid production profile interpretation method considering different flow patterns and variable mass flow under reservoir-wellbore coupling. A system for interpreting the liquid production profile of the horizontal section after multi-point steam injection of the heavy oil horizontal well by using the above method is also disclosed. After the liquid production profile of the horizontal section after multi-point steam injection of the horizontal well is obtained by using the interpretation method and system, the oil layer physical properties and steam injection effect can be re-considered, the distribution position of the injection distributor and the steam injection volume during the next round of steam injection of the heavy oil well can be adjusted, the liquid production profile of the next round is obtained by using the interpretation method and system, and the liquid production change of the horizontal well after adjustment of the injection distributor position is analyzed by comparing the liquid production profile of the previous round, so that the distribution position of the injection distributor and the steam injection volume are continuously optimized, balanced steam injection and liquid production of the entire horizontal section are realized, and the overall recovery rate of the heavy oil reservoir is finally improved. BRIEF DESCRIPTION OF DRAWINGS

[0082] Figure 1 It is a flowchart of the heavy oil horizontal well liquid production profile interpretation method using temperature and pressure data according to the application;

[0083] Figure 2 It is a schematic diagram of segmenting the horizontal section according to the injection distributor position according to the application;

[0084] Figure 3 It is a schematic diagram of the heavy oil horizontal well liquid production profile interpretation system according to an embodiment of the application;

[0085] Figure 4 It is a wellbore liquid temperature and pressure distribution diagram of well A in a specific embodiment 2 of the application;

[0086] Figure 5 It is a liquid production profile interpretation result diagram of well A in a specific embodiment 2 of the application;

[0087] Figure 6Figure 3 is a diagram of the liquid production profile interpretation result of well B in a specific embodiment 3 of the present application. DETAILED DESCRIPTION

[0088] It should be noted that the following detailed description is exemplary in nature and is intended to provide further description of the application. Unless otherwise defined, all technical and scientific terms used herein have the same meaning as commonly understood by one of ordinary skill in the art to which this application belongs.

[0089] It is also important to note that the terms used herein are not intended to limit the particular embodiments of the present application which can be practiced with the examples of the present application. As used, unless otherwise defined, the singular forms "a," "an," and "the" are intended to mean "one or more" unless the context clearly indicates otherwise. Further, it should be understood that the terms "comprises" and / or "comprising," when used in this specification, specify the presence of stated features, steps, operations, elements, and / or components, but do not preclude the presence or addition of one or more other features, steps, operations, elements, components, and / or groups thereof.

[0090] As shown in FIG. 1, Figure 1 as shown in FIG. 1, Figure 1 is a flow chart of the heavy oil horizontal well liquid production profile interpretation method of the present application. The heavy oil horizontal well liquid production profile interpretation method comprises:

[0091] Step 1, according to the position of the injection distributor, the horizontal section is divided into multiple unit sections.

[0092] Step 2, during production, considering the influence of different flow patterns and variable mass flow, a horizontal wellbore pressure field calculation method is established to determine the pressure drop along the horizontal wellbore.

[0093] Step 3, during production, considering the reservoir-wellbore coupling, combined with the pressure drop along the horizontal wellbore determined in step 2, the temperature field distribution along the horizontal wellbore is calculated.

[0094] Step 4, temperature and pressure data at different injection distributor positions are monitored and collected using a temperature and pressure gauge.

[0095] Step 5, using the monitored temperature and pressure data in step 4 and the temperature field calculation method established in step 3, combined with the MCMC inversion algorithm, the horizontal wellbore liquid production profile is determined.

[0096] As shown in FIG. 1, Figure 3 The present application also discloses a heavy oil horizontal well multi-point steam injection horizontal section liquid production profile interpretation system using the above interpretation method, comprising: a horizontal well section analysis unit, a production time horizontal well along the pressure distribution processing unit, a production time horizontal well along the temperature distribution processing unit, a temperature and pressure data monitoring unit, an MCMC inversion processing unit, a liquid production profile interpretation output unit, and a next round of steam injection optimization analysis unit.

[0097] The horizontal well section analysis unit divides the horizontal section into n unit sections from the toe to the heel according to the placement positions of the n injectors, and the liquid production of each unit section is controlled by one injector. The horizontal well section information is transmitted to the horizontal well pressure distribution processing unit during production.

[0098] The horizontal well pressure distribution processing unit during production calculates the pressure distribution at different injector positions of the horizontal well during production by using the wellbore pressure drop equation composed of friction pressure drop, acceleration pressure drop, injector hole pressure drop and mixed pressure drop, and the influence of different flow patterns is considered in the pressure calculation process. The calculated pressure data at different injector positions of the horizontal well are transmitted to the horizontal well temperature distribution processing unit during production and the MCMC inversion processing unit.

[0099] The horizontal well temperature distribution processing unit during production considers the effects of reservoir-wellbore coupling and variable mass flow, analyzes the heat conduction and heat convection between the wellbore and the formation, and the interaction relationship between the liquid production and the temperature and pressure, and calculates the temperature distribution at different injector positions of the horizontal well during production. The calculated temperature data are transmitted to the MCMC inversion processing unit.

[0100] The temperature and pressure data monitoring unit monitors and collects the measured temperature and pressure data at different injector positions of the horizontal well during production. The collected temperature and pressure data are transmitted to the MCMC inversion processing unit.

[0101] The MCMC inversion processing unit establishes an objective function representing the difference between the temperature and pressure inversion values and the measured values, combines the MCMC inversion algorithm, and calculates the flow rate of each horizontal section controlled by each injector. The calculated liquid production results of each horizontal section are transmitted to the liquid production profile interpretation output unit.

[0102] The liquid production profile interpretation output unit is used to output the corresponding liquid production at each injector position. The calculated liquid production is transmitted to the next round of steam injection optimization analysis unit.

[0103] The next round of steam injection optimization analysis unit uses the liquid production of this round output by the liquid production profile interpretation output unit, reconsiders the reservoir properties and steam injection effect according to the result, and adjusts the injector distribution position and the steam injection rate of the next round of steam injection of the heavy oil well.

[0104] The next round of injector distribution position information is transmitted to the horizontal well section analysis unit, and the next round of liquid production profile is obtained by the interpretation system proposed in the application. The liquid production profile of the next round is compared with that of the previous round to analyze the change of the liquid production of the horizontal well after adjusting the injector position, and the distribution position and the steam injection rate of the injector are continuously optimized to realize balanced steam injection and liquid production of the entire horizontal section, and finally improve the overall recovery of the heavy oil reservoir.

[0105] The technical advantage of the present application is that:

[0106] 1. After multi-point steam injection in a heavy oil horizontal well, a method for interpreting the liquid production profile of the horizontal well is provided, which considers different flow patterns and variable mass flow, and the coupling of the reservoir and the wellbore. The interpretation method takes into account the actual production situation on site, greatly improving the interpretation accuracy.

[0107] 2. The MCMC algorithm is used to invert the liquid production, which improves the calculation speed and accuracy compared to the traditional curve fitting method.

[0108] 3. The present application can fully utilize the oilfield field data resources to calculate the liquid production profile of the horizontal well at low cost and high precision. The proposed liquid production profile interpretation method and system can analyze the liquid production and water content of each production layer, providing a basis for the effective implementation of subsequent plugging and adjustment, steam injection and other process measures.

[0109] The following are several specific embodiments of the application

[0110] Example 1

[0111] In a specific embodiment 1 of the application, the heavy oil horizontal well liquid production profile interpretation method includes the following steps:

[0112] In step 1, the horizontal section is divided into multiple unit sections according to the position of the injection distributor. During the steam injection process of the thermal recovery horizontal well, steam is injected through the injection distributor. The placement position of the injection distributor in the horizontal section is related to the reservoir properties of the oil layer, considering the distribution characteristics of the oil layer permeability, the distribution difference of the porosity, etc., so that the injection distributor achieves the purpose of balanced steam injection in all oil layer sections. Therefore, the placement position of the injection distributor is fully considered in terms of oil layer properties and steam injection effect. During the production process of the horizontal well, the produced liquid also flows into the wellbore from the injection distributor. According to the placement position of the n injection distributors, the horizontal section is divided into n unit sections from the toe to the heel. It is equivalent to one injection distributor controlling the liquid production of one unit section. This segmentation method ensures that the reservoir properties of each unit section remain basically unchanged, and the segmentation is reasonable. The specific segmentation diagram is shown in Figure 2 .

[0113] It is assumed that the permeability, liquid production, and fluid properties of each unit section remain unchanged. The produced liquid of each unit section flows out of the injection distributor that controls this unit section. The segmentation length of each unit section is s1, s2, …, s n (m), and the liquid production is Q1, Q2, …, Q n (m 3 / s).

[0114] In step 2, considering the effects of different flow patterns and variable mass flow during production, a method for calculating the pressure field of a horizontal wellbore is established to determine the pressure drop along the wellbore. The aforementioned method for calculating the pressure field of a horizontal well is described as follows: (dP / ds) i This indicates that the i-th segment has a production volume Q i The pressure drop per unit well length caused by inflow, the pressure drop in the i-th segment (dP / ds). i The temperature rise (dT / ds) affecting this section i The greater the pressure drop, the higher the temperature rise. This invention fully considers the effect of variable mass flow during horizontal well production and, in conjunction with the influence of different flow patterns, determines the wellbore pressure drop equation. According to a preferred embodiment of this invention, the wellbore pressure drop calculation method includes:

[0115] 2-1 Wellbore pressure drop consists of five parts: gravity pressure drop, frictional pressure drop, acceleration pressure drop, injector orifice pressure drop, and mixing pressure drop. Since the inclination angle θ of a horizontal well is zero, gravity pressure drop is not considered. Therefore, the formula for calculating wellbore pressure drop is:

[0116] (dP / ds) i =(dP / ds) f,i +(dP / ds) acc,i +(dP / ds) inj,i +(dP / ds) mix,i (1)

[0117] 2-2 The formula for calculating frictional voltage drop is:

[0118]

[0119] Wherein, (dP / ds) i Represents the pressure drop in the wellbore of the i-th segment, in MPa; (dP / ds) f,i This represents the frictional pressure drop of the i-th segment, in MPa (dP / ds). acc,i Represents the acceleration pressure drop of the i-th segment, in MPa; (dP / ds) inj,i This represents the pressure drop at the orifice of the dispenser in the i-th segment, in MPa (dP / ds). mix,i The pressure drop across the i-th segment is represented by ρ, in MPa; ρ is the fluid density inside the wellbore, in kg / m³. 3 ;r wb v is the radius of the cement ring, in meters. i f is the fluid velocity in the i-th segment, in m / s; i It is the friction coefficient along the i-th segment; friction coefficient f i It is related to the flow pattern; different flow patterns correspond to different liquid holdup rates in horizontal wells, which in turn affects the Reynolds number N of the fluid. re Size, and coefficient of friction f i There is a certain correspondence between it and the Reynolds number, as shown in equation (3).

[0120]

[0121] The flow pattern of downhole fluid flow is mainly divided into four types: separated flow, transitional flow, intermittent flow and dispersed flow. For oil-gas-water three-phase flow, E L represents the liquid volume fraction, E L takes the value of [0, 1], N Fr represents the Froude number; for oil-water two-phase flow, E L takes the value of 1. When E L <0.01 and N Fr <316*E L 0.302 , or E L ≥0.01 and N Fr <0.0009*E L -2.4684 , the downhole flow pattern is determined as separated flow; when E L >0.01 and 0.0009*E L -2.4684 <N Fr ≤0.1*E L -1.4516 , the downhole flow pattern is determined as transitional flow; when 0.01<E L <0.4 and 0.1*E L -1.4516 <N Fr ≤316*E L 0.302 , or E L ≥0.4 and 0.1*E L -1.4516 <N Fr ≤0.5*E L -6.738 , the downhole flow pattern is determined as intermittent flow; when E L <0.4 and N Fr ≥316*E L 0.302 , or E L ≥0.4 and N Fr >0.5*E L -6.738 , the downhole flow pattern is determined as dispersed flow.

[0122] The acceleration pressure drop calculation formula of 2-3 is:

[0123]

[0124] Where, P i is the pressure of the i-th section of wellbore, MPa; Q i represents the liquid production of the i-th section unit, m 3 / s.

[0125] 2-4 The liquid produced by the unit will be throttled when flowing through the injection distributor, and the pressure drop calculation formula of the injection distributor hole is:

[0126]

[0127]

[0128]

[0129] Where, fr i And ax i are the calculation process assumed parameters, and do not represent specific physical quantities; c is the roughness of the injection distributor hole, m; r ci is the inner diameter of the screen pipe, m; d inj is the diameter of the injection distributor hole, m; s i represents the length of the i-th unit section, m; S i represents the discharge area of the i-th injection distributor, m 2 .

[0130] 2-5 The mixed pressure drop is related to the pressure drop of the injection distributor hole, and the calculation formula is:

[0131]

[0132] In step 3, in the production process, considering the reservoir-wellbore coupling, the temperature field distribution of the horizontal wellbore is calculated in combination with the horizontal wellbore pressure drop determined in step 2.

[0133] The horizontal wellbore temperature field calculation method considering the reservoir-wellbore coupling, in the production process of the horizontal well, the fluid in the reservoir enters the injection distributor through the seepage channel and then flows into the production string, and the effect of variable mass flow is considered. The fluid in the wellbore gradually increases from the toe to the heel of the horizontal well. The coupling relationship between the reservoir temperature field and the wellbore temperature field reflects the influence of the horizontal well along the temperature and pressure distribution on the liquid production of each unit section in the reservoir, and the liquid production of the reservoir will affect the temperature and pressure distribution along the horizontal well, and the two need to be coupled. According to the present application, the reservoir-wellbore coupling temperature field calculation method, comprising:

[0134] 3-1 The fluid flowing in the screen pipe exchanges heat with the formation, mainly including heat conduction and heat convection. In the heat transfer process between the formation and the wellbore, the heat transfer coefficient U1 between the screen pipe and the cement sheath, the heat transfer coefficient U2 between the cement sheath and the formation, and the total heat transfer coefficient U 总 are respectively:

[0135]

[0136]

[0137] U 总,i =U1+U 2,i (11)

[0138] where K cas and K cem are the thermal conductivities of the screen pipe and the cement sheath, respectively, W / (m·℃);r ci , r co and r wb are the inner diameter of the screen pipe, the outer diameter of the screen pipe and the radius of the cement sheath, respectively, m;T i represents the temperature of the wellbore fluid flow in the ith section, ℃, i=1, 2, …, n;T In,i represents the temperature of the produced fluid inflow in the ith section, ℃;T f represents the temperature of the oil reservoir, ℃. In the heat transfer coefficient, U1 is a constant value.

[0139] 3-2 The produced fluid flows into the injection distributor through the seepage channel in the oil reservoir, and the amount and properties of the produced fluid affect the temperature of the produced fluid flowing into the injection distributor, so the temperature of the produced fluid inflow T In,i needs to be calculated.

[0140]

[0141] where K f is the thermal conductivity of the formation, W / (m·℃);ρ is the density, kg / m 3 ;c p is the specific heat capacity, J / (kg·℃);μ is the viscosity, mPa·s;k i is the permeability, mD;β is the volumetric expansion coefficient, decimal.

[0142] The temperature of the produced fluid inflow T In,i is related to the amount of produced fluid Q i in the oil reservoir and also affects the temperature of the fluid flow in the screen pipe T i , which is the link between the reservoir temperature field and the wellbore temperature field and is also the key node of the reservoir-wellbore temperature field coupling.

[0143] 3-3 The flow rate in the ith section of the screen pipe is equal to the sum of the produced fluid flow rates through the injection distributor in the first section to the ith section. According to the mass and energy conservation equations, considering the effects of heat conduction, heat convection and variable mass flow, the temperature of the fluid in the ith unit section of the screen pipe is:

[0144] T i =T i-1 +(dT / ds) i ·s i (13)

[0145]

[0146] Where, (dT / ds) i This indicates that the i-th segment has a production volume Q i Temperature rise per unit well length due to inflow; (dP / ds) i This indicates that the i-th segment has a production volume Q i The pressure drop per unit well length due to inflow is obtained from step 2; S i Let m be the discharge area of ​​the i-th dispenser. 2 θ is the well inclination angle, in °.

[0147] 3-4 Discharge device drainage area S i S is related to the orifice diameter and orifice density of the dispenser. i The calculation formula is:

[0148] S i =πd inj 2 / 4·Holes (15)

[0149] Where, d inj Holes is the orifice diameter of the injector, in meters; Holes is the number of holes in the injector. The orifice diameter and number of holes in the injector affect the effect of balanced steam injection in thermal recovery wells, and the steam injection effect ultimately affects the fluid production of the horizontal section during the production process of horizontal wells.

[0150] In step 4, temperature and pressure data at different dispenser locations are monitored and collected using a thermobarometer.

[0151] The method involves using a thermobarometer to monitor temperature and pressure data at different injector locations. Once the thermal recovery well is in stable production, the thermobarometer is lowered into the production tubing. Temperature and pressure data are monitored starting from the injector closest to the toe of the horizontal well. After monitoring the temperature and pressure of this injector, the thermobarometer is moved to monitor the temperature and pressure data of other injectors in sequence. That is, n injectors correspond to n temperature and pressure measurement points, ultimately obtaining the measured well temperature and pressure data during the horizontal well production process.

[0152] In step 5, the production profile of the horizontal wellbore is determined by using the temperature and pressure data monitored in step 4 and the temperature field calculation method established in step 3, combined with the MCMC inversion algorithm.

[0153] The method for inverting the production profile using the MCMC algorithm, where MCMC stands for Markov Chain Monte Carlo, is a random sampling method with wide applications in data processing and machine learning. According to a preferred embodiment of the present invention, the method for calculating the production profile of a horizontal well using the MCMC algorithm includes:

[0154] 5-1 Establish an objective function to represent the difference between the inverted values ​​and the measured values, thereby measuring the goodness of the inversion results. The formula for calculating the objective function is:

[0155]

[0156]

[0157] where F P and F T are the objective function values of pressure and temperature respectively; P 实测 and T 实测 are the real pressure and temperature values measured by the temperature and pressure gauges respectively; P(Q) and T(Q) represent the pressure and temperature values calculated by the horizontal wellbore pressure field and temperature field models in the heavy oil horizontal well fluid production profile interpretation method established according to the present application under the given assumed flow rate Q; and C is the covariance matrix.

[0158] 5-2 An initial flow rate Q(0) is reasonably assumed, and the assumed flow rate Q(0) is substituted into the horizontal wellbore pressure field and temperature field calculation models established in steps 2 and 3 to obtain the corresponding pressure P a (0) and well temperature T a (0), and to calculate the objective functions F P (0) and F T (0).

[0159] 5-3 The objective functions F P (0) and F T (0) are minimized by using the MCMC algorithm, a random jump △Q ~ N(0, σ) is set from the uniform distribution of MCMC, and then a new sample is generated by disturbing the current sample, and the flow rate of the next horizontal section is Q(1) = Q(0) + △Q.

[0160] 5-4 The flow rate Q(1) is substituted into the horizontal wellbore pressure field and temperature field calculation models to obtain the corresponding pressure P a (1) and well temperature T a (1), and the objective functions F P (1) and F T (1) are calculated in combination with the temperature and pressure data measured by the temperature and pressure gauges in step 4.

[0161] 5-5 A random number A ~ U(0, 1) is set, and whether to accept the flow rate Q(1) generated by the MCMC distribution model in 5-3 is determined according to the acceptance probability:

[0162]

[0163]

[0164] If A < α1 and A < α2 are both satisfied, Q(1) is accepted, and the calculation of the next horizontal section is performed, otherwise, steps 5-2 to 5-4 are repeated until the conditions are satisfied.

[0165] 5-6The flow rate Q(i) of each horizontal section is the distribution of the liquid production profile of the horizontal well.

[0166] Example 2

[0167] Well A is a thermal recovery horizontal well in a heavy oil reservoir, the oil layer viscosity is 43064 mPa·s, the horizontal section length ranges from 1183 m to 1393 m, and the oil layer section is located in ES3 4+5 The layer position, porosity is 32.5%, permeability is 1207 mD, the reservoir temperature is 56℃, the geothermal gradient is 0.043℃ / m, the pressure coefficient is 0.94-0.95, and it belongs to a high temperature and normal pressure system. According to the reservoir properties of different oil layer sections, 11 injection distributors are installed in the whole horizontal section, the arrangement positions of the injection distributors in the horizontal section are shown in Table 1, the injection distributors are punched according to 360° spiral, the hole diameter is 10 mm, the hole density is 15 holes / m, and the length is 1 m. In the steam injection stage, Well A injects 2500 t of steam, and after five days of soak, the heat preservation production is carried out by using heat preservation tubing, the size of the heat preservation tubing is 100.54*114.3 mm, and after stable production, the temperature and pressure data of different injection distributor positions monitored by the sensor of the well are shown in Table 2. In the production process, the actual wellhead flow rate of Well A is 22 t / d. Figure 4

[0168] Table 1 Injection distributor position table

[0169]

[0170] The method proposed in the present application is used to interpret the liquid production profile of the horizontal well of Well A, and the specific interpretation process is shown as follows.

[0171] Step 101, according to the positions of the injection distributors, the horizontal well is divided into 11 unit sections, and each injection distributor controls the liquid production rate of each horizontal section.

[0172] Step 102, according to the segmentation information of the horizontal well in step 101, the pressure data of different injection distributor positions in the production is calculated by using the wellbore pressure drop equation composed of four parts of friction pressure drop, acceleration pressure drop, injection distributor hole pressure drop and mixed pressure drop.

[0173] Step 103, by using the pressure data calculated in step 102, the effects of reservoir-wellbore coupling and variable mass flow are considered, the heat conduction and heat convection between the wellbore and the formation are analyzed, and the interaction relationship between the liquid production rate and the temperature and pressure is analyzed, so as to calculate the temperature data of different injection distributor positions in the production of the horizontal well.

[0174] ​Step 104, using the temperature and pressure data at each injection distributor position calculated in steps 102 and 103 and the measured temperature and pressure data monitored by the sensor, the MCMC inversion algorithm is used to calculate the corresponding liquid production at each injection distributor position of the heavy oil horizontal well, i.e. the horizontal well liquid production profile, and the result is shown in Fig. 4. Figure 5

[0175] Step 105, the liquid production of different production intervals of well A obtained by interpretation in step 104 is added and compared with the measured liquid production at the wellhead, the liquid production addition is 24.61 t / d, the measured liquid production at the wellhead is 22 t / d, and the interpretation coincidence rate is 88.1%, which verifies the feasibility and effectiveness of the heavy oil horizontal well liquid production profile interpretation method proposed in the present application.

[0176] Example 3

[0177] Well B is a thermal recovery horizontal well in a certain super heavy oil reservoir, the oil layer viscosity is 124000 mPa·s, the horizontal section length ranges from 1385 m to 1620 m, the oil layer section is mainly located in the third member of Shahejie Formation, the average porosity is 32.5%, the average permeability is 734 mD, and the surface crude oil density is 1015.1 kg / m 3 , which belongs to a high-porosity and high-permeability reservoir. The reservoir burial depth is about 800 m, the initial formation temperature is 56℃, the initial formation pressure is 11.5 MPa, the geothermal gradient is 0.033℃ / m, and the pressure coefficient is 1. According to the reservoir properties of different oil layer sections, a total of 10 injection distributors are installed in the entire horizontal section, the arrangement positions of the injection distributors in the horizontal section are shown in Table 2, the injection distributors are punched according to 360° spiral, the hole diameter is 10 mm, the hole density is 10 holes / m, and the length is 1 m. In the steam injection stage, well B injects 3000 t of steam, and after six days of soak, ordinary tubing is used for production, and the tubing size is 76x88.9 mm. During the production process, the measured wellhead flow rate of well B is 67 t / d.

[0178] Table 2 Injection distributor position table

[0179]

[0180] The method proposed in the present application is used to interpret the horizontal well liquid production profile of well B, and the specific interpretation process is shown as follows.

[0181] Step 201, according to the injection distributor position, the horizontal well is divided into 10 unit sections, and each injection distributor controls the liquid production of each horizontal section.

[0182] Step 202, according to the segmentation information of the horizontal well in step 201, the pressure data at different injection distributor positions of the horizontal well during production is calculated by using the wellbore pressure drop equation composed of four parts of friction pressure drop, acceleration pressure drop, injection distributor hole pressure drop and mixed pressure drop.

[0183] ​Step 203, using the pressure data calculated in step 202, considering the effects of reservoir-wellbore coupling and variable mass flow, analyzing the heat conduction and convection between the wellbore and the formation, and the interaction between the fluid production rate and the temperature and pressure, calculating the temperature data at different injection distributor positions in the horizontal well during production.

[0184] Step 204, using the temperature and pressure data at each injection distributor position calculated in steps 202 and 203 and the measured temperature and pressure data monitored by the sensor, combining the MCMC inversion algorithm, calculating the corresponding fluid production rate at each injection distributor position in the heavy oil horizontal well, i.e. the fluid production profile in the horizontal well, the results are shown in Figure 6

[0185] Step 205, comparing the fluid production rate calculated in step 204 for different production intervals in Well B with the measured fluid production rate at the wellhead, the fluid production rate addition is 77.75 t / d, the measured fluid production rate at the wellhead is 67 t / d, and the interpretation accuracy is 84.0%, which verifies the feasibility and effectiveness of the heavy oil horizontal well fluid production profile interpretation method proposed in the present application.

[0186] Step 206, as can be seen from the fluid production profile interpretation result graph, the fluid production rate in the 1472-1492m and 1555-1580m intervals is relatively high, while the fluid production rate in the 1385-1405m interval is very low, almost none. Based on the fluid production results of this round, reconsidering the reservoir properties and steam injection effect, adjusting the distribution position and steam injection rate of the injection distributor for the next round of steam injection in the heavy oil downhole, and then achieving balanced steam injection and fluid production in the entire horizontal section, and ultimately improving the overall recovery of the heavy oil reservoir.

[0187] Finally, it should be noted that the above description is only a preferred embodiment of the present application and is not intended to limit the present application. Although the present application has been described in detail with reference to the foregoing embodiments, those skilled in the art can still modify the technical solutions described in the foregoing embodiments or make equivalent replacements to some technical features. Any modification, equivalent replacement, improvement, etc. made within the spirit and principles of the present application shall be included in the protection scope of the present application.

[0188] In addition to the technical features described in the specification, they are known to those skilled in the art.​

Claims

1. A method for interpreting liquid production profile in a horizontal well for heavy oil, characterized in that, The heavy oil horizontal well liquid production profile interpretation method comprises the following steps: Step 1, according to the position of the injection distributor, the horizontal section is divided into multiple unit sections; Step 2, considering the variable mass flow, the pressure drop along the horizontal wellbore is determined; Step 3, considering the reservoir-wellbore coupling, the temperature field of the horizontal wellbore is determined; Step 4, the temperature and pressure data at different injection distributors are monitored by using a temperature and pressure gauge; Step 5, the horizontal well liquid production profile is inversed by combining the MCMC algorithm.

2. The heavy oil horizontal well liquid production profile interpretation method and system according to claim 1, characterized in that, In step 1, according to the placement position of n injectors, the horizontal section is divided into n unit sections from the toe to the heel, which means that one injector controls the liquid production of one unit section. This segmentation method ensures that the reservoir properties of each unit section remain basically unchanged, and the segmentation is reasonable. The permeability, liquid production, and fluid properties of the hypothetical oil layer in each unit section are assumed to be constant, and the output liquid of each unit section flows from the injector that controls this unit section. Therefore, the segmentation lengths of each unit section are s1, s2, …, s n (m), and the liquid production is Q1, Q2, …, Q n (m 3 / s), respectively.

3. The method and system for heavy oil horizontal well liquid production profile interpretation according to claim 1, characterized in that, In step 2, during the production process, the influence of different flow patterns and variable mass flow is considered, a horizontal wellbore pressure field calculation method is established, and the pressure drop along the horizontal wellbore is determined; the horizontal well pressure field calculation method, (dP / ds) i represents the pressure drop per unit length of the i-th section due to the inflow of the liquid production rate Q i The pressure drop per unit length of the i-th section caused by the inflow is represented by (dP / ds) i The temperature rise of the section is represented by (dT / ds) i The greater the pressure drop, the higher the temperature rise.

4. The method and system for heavy oil horizontal well liquid production profile interpretation according to claim 3, characterized in that, In step 2, the wellbore pressure drop is composed of five parts, namely gravity pressure drop, friction pressure drop, acceleration pressure drop, injection distributor hole pressure drop and mixing pressure drop, wherein the inclination angle θ of the horizontal well is zero, so the gravity pressure drop is not considered, and the wellbore pressure drop calculation formula is: (dP / ds) i = (dP / ds) f,i + (dP / ds) acc,i + (dP / ds) inj,i + (dP / ds) mix,i (1) The friction pressure drop calculation formula is: wherein (dP / ds) i represents the wellbore pressure drop of the ith section, MPa; (dP / ds) f,i represents the frictional pressure drop of the ith section, MPa; (dP / ds) acc,i represents the acceleration pressure drop of the ith section, MPa; (dP / ds) inj,i represents the perforation pressure drop of the ith section, MPa; (dP / ds) mix,i represents the mixing pressure drop of the ith section, MPa; p is the fluid density in the wellbore, kg / m 3 ; r wb is the cement sheath radius, m; v i is the fluid flow rate of the ith section, m / s; f i is the Darcy friction factor of the ith section; the friction factor f i is related to the flow pattern, different flow patterns correspond to different horizontal well liquid holdup, which in turn affects the Reynolds number N re of the fluid, while the friction factor f i has a certain corresponding relationship with the Reynolds number, as shown in equation (3), The acceleration pressure drop calculation formula is: where P i is the wellbore pressure of the ith section, MPa; Q i represents the unit section liquid production of the ith section, m 3 / s; When the liquid production flows through the injection distributor, throttling occurs, and the injection distributor hole pressure drop calculation formula is: wherein fr i and ax i are calculation process assumed parameters and do not represent specific physical quantities; c is the roughness of the injector hole, m; r ci is the inside diameter of the screen pipe, m; d inj is the diameter of the injector hole, m; s i represents the length of the i-th unit section, m; S i represents the discharge area of the i-th injector, m 2 ; The mixing pressure drop is related to the injection distributor hole pressure drop, and the calculation formula is:

5. The method and system for heavy oil horizontal well liquid production profile interpretation according to claim 4, characterized in that, In step 2, the flow patterns of downhole fluids are mainly divided into four types: separated flow, transitional flow, intermittent flow, and dispersed flow; for three-phase flow of oil, gas, and water, E L E represents the liquid volume fraction. L The value is [0, 1], N Fr Denotes the Floyd number; for oil-water two-phase flow, E L The value is 1; when E L <0.01 and N Fr <316*E L 0.302 , or E L ≥0.01 and N Fr <0.0009*E L -2.4684 At that time, the downhole flow pattern was determined to be a separated flow; when E L >0.01, and 0.0009*E L -2.4684 <N Fr ≤0.1*E L -1.4516 At that time, the downhole flow pattern was determined to be transitional flow; when 0.01 <E L <0.4 and 0.1*E L -1.4516 <N Fr ≤316*E L 0.302 , or E L ≥0.4 and 0.1*E L -1.4516 <N Fr ≤0.5*E L -6.738 At that time, the downhole flow pattern was determined to be intermittent flow; when E L <0.4 and N Fr ≥316*E L 0.302 , or E L ≥0.4 and N Fr >0.5*E L -6.738 At that time, the downhole flow pattern was determined to be a dispersed flow.

6. The method and system for heavy oil horizontal well liquid production profile interpretation according to claim 1, characterized in that, In step 3, the coupling relationship between the reservoir temperature field and the wellbore temperature field is reflected in the influence of the temperature and pressure distribution along the horizontal well on the liquid production of the reservoir in each unit section, and the liquid production of the reservoir also affects the temperature and pressure distribution along the horizontal well, which needs to be coupled and calculated.

7. The method and system for heavy oil horizontal well liquid production profile interpretation according to claim 6, characterized in that, In step 3, the fluid flow in the screen pipe exchanges heat with the formation, mainly including heat conduction and heat convection. In the heat transfer process between the formation and the wellbore, the heat transfer coefficient U1 between the screen pipe and the cement sheath, the heat transfer coefficient U2 between the cement sheath and the formation, and the total heat transfer coefficient U between the formation and the wellbore are 总 respectively: U 总,i = U1+ U 2,i (11) wherein K cas and K cem are the thermal conductivities of the screen pipe and the cement sheath, respectively, W / (m oC); r ci , r co , and r wb are the inner diameter of the screen pipe, the outer diameter of the screen pipe, and the radius of the cement sheath, respectively, m; T i represents the temperature of the fluid flow in the i-th section of the wellbore, oC, i = 1, 2, …, n; T In,i represents the temperature of the inflow of the produced fluid in the i-th section of the oil reservoir, oC; T f represents the temperature of the oil reservoir, oC; in the heat transfer coefficient, U1 is a constant value; The produced liquid in the oil layer flows into the injection distributor through the seepage channel, and the amount and the property of the produced liquid affect the temperature of the produced liquid flowing into the injection distributor, and the temperature T of the produced liquid flowing into the injection distributor needs to be calculated In,i : wherein K f is the thermal conductivity of the formation, W / (m °C); p is the density, kg / m 3 ; c p is the specific heat capacity, J / (kg °C); m is the viscosity, mPa s; k i is the permeability, mD; and b is the volumetric expansion coefficient, decimal. Temperature of produced fluid inflow T In,i Both related to the oil layer produced fluid volume Q i And the fluid flow temperature T i In the screen pipe, it is the link between the reservoir temperature field and the wellbore temperature field, and the key node of the reservoir-wellbore temperature field coupling; The flow rate in the i-th section screen pipe is equal to the sum of the liquid production flowing through the injection distributors from the first section to the i-th section, and according to the mass and energy conservation equation, considering the effects of heat conduction, heat convection and variable mass flow, the temperature of the fluid in the i-th unit section screen pipe is: T i = T i-1 + (dT / ds) i · s i (13) where (dT / ds) i represents the temperature increase per unit of well length due to the inflow of the i-th segment; (dP / ds) i represents the pressure decrease per unit of well length due to the inflow of the i-th segment; (dP / ds) i represents the temperature increase per unit of well length due to the inflow of the i-th segment; (dP / ds) i represents the pressure decrease per unit of well length due to the inflow of the i-th segment; (dP / ds) i is the drainage area of the i-th injector, m2 2 ; θ is the inclination angle, ° The flow area S of the injector i The flow area S of the injector i The formula for calculating S is S i = πd inj 2 / 4·Holes (15) where d inj is the diameter of the injector hole, m; Holes is the number of injector holes. The diameter and number of injector holes affect the effect of balanced steam injection in thermal recovery wells, and the steam injection effect ultimately affects the liquid production in the horizontal section during horizontal well production.

8. The method and system for heavy oil horizontal well liquid production profile interpretation according to claim 1, characterized in that, In step 4, when the thermal recovery well is in stable production, the temperature and pressure gauge is lowered into the production string, and the temperature and pressure data are monitored from the injection distributor closest to the toe of the horizontal well, after monitoring the temperature and pressure of the injection distributor, the temperature and pressure data of other injection distributors are monitored in turn, that is, n injection distributors correspond to n temperature measuring points and pressure measuring points, and finally the measured well temperature data and measured pressure data during the production of the horizontal well are obtained.

9. The method and system for interpreting fluid production profile of heavy oil horizontal well according to claim 1, characterized in that, Step 5 includes: Step 51, a target function is established to represent the difference between the inversion value and the measured value, so as to measure the goodness of the inversion result; the calculation formula of the target function is: wherein F P and F T are the objective function values of pressure and temperature respectively; P 实测 and T 实测 are the real pressure and temperature values measured by the pressure and temperature gauges respectively; P(Q) and T(Q) represent the pressure and temperature values calculated by the horizontal wellbore pressure field and temperature field models in the heavy oil horizontal well fluid production profile interpretation method established according to the present application under the given flow rate Q; and C is the covariance matrix. Step 52, reasonably assuming an initial flow rate Q(0), substituting the assumed flow rate Q(0) into the horizontal wellbore pressure field and temperature field calculation model established in steps 2 and 3 to solve the corresponding pressure P a (0) and well temperature T a (0), and calculate the objective function F P (0) and F T (0); Step 53, using MCMC algorithm to make the target function F P (0) and F T (0) reach the minimum, set a random jump △Q ~ N(0, σ) from the uniform distribution of MCMC, and then generate a new sample by disturbing the current sample, at this time the flow of the next level section is Q(1) = Q(0) + △Q; Step 54, substitute the flow rate Q(1) into the horizontal wellbore pressure field and temperature field calculation model to solve the corresponding pressure P a (1) and well temperature T a (1), combined with the temperature and pressure data measured by the temperature and pressure gauge in step 4, to calculate the objective function F P (1) and F T (1); Step 55, a random number A~U(0,1) is set, and whether to accept the flow rate Q(1) generated by the MCMC distribution model in step 53 is determined according to the acceptance probability: If A<α1 and A<α2 are satisfied at the same time, Q(1) is accepted, and the calculation of the next horizontal section is performed, otherwise, steps 52 to 54 are repeated until the conditions are met; Step 56, the flow rate Q(i) inversed finally by each horizontal section is the distribution of the horizontal well liquid production profile.

10. A heavy oil horizontal well fluid production profile interpretation system characterized by, The heavy oil horizontal well liquid production profile interpretation system comprises: A horizontal well section analysis unit, which divides the horizontal section into multiple unit sections according to the position of the injection distributor; A horizontal well along-hole pressure distribution processing unit, which determines the pressure drop along the horizontal wellbore considering the variable mass flow during production; A horizontal well along-hole temperature distribution processing unit, which determines the temperature field of the horizontal wellbore considering the reservoir-wellbore coupling; A temperature and pressure data monitoring unit, which monitors the temperature and pressure data at different injection distributors by using a temperature and pressure gauge; An MCMC inversion processing unit, which inverses the horizontal well liquid production profile by combining the MCMC algorithm.

11. The heavy oil horizontal well liquid production profile interpretation system of claim 10, wherein, The horizontal well section analysis unit divides the horizontal section into n unit sections from toe to heel according to the placement positions of the n diverters, which means that one unit section is controlled by one diverter; and transmits the horizontal well section information to the production-time horizontal well along-hole pressure distribution processing unit.

12. The heavy oil horizontal well liquid production profile interpretation system of claim 10, wherein, The production-time horizontal well along-hole pressure distribution processing unit calculates the pressure distribution at different diverter positions in the production-time horizontal well by using the wellbore pressure drop equation composed of friction pressure drop, acceleration pressure drop, diverter hole pressure drop and mixed pressure drop, and considers the influence of different flow patterns in the pressure calculation process; and transmits the calculated pressure data at different diverter positions in the horizontal well to the production-time horizontal well along-hole temperature distribution processing unit and the MCMC inversion processing unit.

13. The heavy oil horizontal well liquid production profile interpretation system of claim 10, wherein, The production-time horizontal well along-hole temperature distribution processing unit considers the effects of reservoir-wellbore coupling and variable mass flow, analyzes the heat conduction and heat convection between the wellbore and the formation, and the interaction relationship between the fluid production rate and the temperature and pressure, and calculates the temperature distribution at different diverter positions in the production-time horizontal well; and transmits the calculated temperature data to the MCMC inversion processing unit.

14. The heavy oil horizontal well liquid production profile interpretation system of claim 10, wherein, The temperature and pressure data monitoring unit monitors and collects the measured temperature and pressure data at different diverter positions in the production-time horizontal well during the production process; and transmits the collected temperature and pressure data to the MCMC inversion processing unit.

15. The heavy oil horizontal well liquid production profile interpretation system of claim 10, wherein, The heavy oil horizontal well fluid production profile interpretation system further comprises a fluid production profile interpretation output unit, the MCMC inversion processing unit establishes a target function representing the difference between the temperature and pressure inversion values and the measured values, combines the MCMC inversion algorithm, and calculates the flow rate inverted by each diverter-controlled horizontal section; and transmits the calculated fluid production results of each horizontal section to the fluid production profile interpretation output unit.

16. The heavy oil horizontal well liquid production profile interpretation system of claim 15, wherein, The heavy oil horizontal well fluid production profile interpretation system further comprises a next round steam injection optimization analysis unit, the fluid production profile interpretation output unit outputs the corresponding fluid production rate at each diverter position; and transmits the calculated fluid production rate to the next round steam injection optimization analysis unit; the next round steam injection optimization analysis unit uses the fluid production rate output by the fluid production profile interpretation output unit in this round, reconsiders the reservoir properties and steam injection effect according to the result, and adjusts the diverter distribution position and the diverter steam injection rate in the next round of steam injection of the heavy oil well.

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