Parameter optimization method, device and equipment for CO2 phase state control and storage medium

Abstract

The invention discloses a parameter optimization method, device and equipment for CO2 phase state control and a storage medium, which are applied to CO2 phase state control in a shaft in a CO2 injection process, and the method comprises the following steps: coupling a CO2 physical property parameter calculation module, a pressure calculation module and a temperature calculation module into a calculation process capable of calculating CO2 temperature and CO2 pressure in the shaft after a preset time step length; thirdly, generating sufficient quantity of experimental data through the calculation process; in this way, the injection parameters are optimized according to the importance sequence of the set injection parameters. Due to the fact that the CO2 phase state generated through the method can more accurately describe the change process of fluid components in a shaft, the more accurate CO2 phase state of the shaft can be obtained; therefore, according to the method for calculating the phase state in the shaft of the production well, the actual results of the temperature, the pressure and the phase state in the shaft in the production process can be accurately represented, and then a more reliable data basis is provided for parameter optimization.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of oil and gas reservoir exploitation, and particularly relates to a parameter optimization method, system, device and storage medium for CO2 phase state control. BACKGROUND

[0002] Carbon capture and storage (CCUS) technology is a key technology for greenhouse gas emission reduction. The development of this technology is of great significance to promote the efficient use of fossil energy and achieve the "double carbon" goal. According to relevant prediction data, by 2050, about 30% of carbon emissions cannot be eliminated through emission reduction, and after excluding natural carbon sinks, 1-2 billion tons of carbon dioxide need to be processed through CCUS technology. China has listed CCUS technology as a major green and low-carbon technology that needs to be urgently researched, aiming to promote the research, demonstration and industrial application of large-scale CCUS technology.

[0003] CO2 flooding, as an important part of CCUS technology, has a good application prospect in the development process of oilfields, especially in the middle and late stages. CO2 flooding, CO2-water alternating flooding and CO2 fracturing all require the injection of a large amount of CO2. The accurate calculation of the temperature and pressure along the way and the accurate prediction and control of the phase state during the injection process are of great guiding significance for the development of production systems, the optimization of parameters and the deployment of protection measures.

[0004] In the prior art, the physical property parameters of CO2 are calculated by using the SW equation of state, and a steady-state / non-steady-state calculation model of the pressure-temperature coupling of the CO2 drilling wellbore is established.

[0005] The inventors have found that the parameter optimization method for phase state control in the prior art at least has the following defects:

[0006] The injected CO2 contains a small amount of impurity gas (including H2S, NO2, SO2 and O2, etc.), and the SW equation of state has a large deviation when calculating the physical properties, so it cannot accurately predict the changes of the temperature, pressure and each phase state in the wellbore during production.

[0007] The information disclosed in the background section of this document is only intended to increase the understanding of the overall background of the present application and should not be considered as an acknowledgment or in any form as an admission that this information constitutes prior art known to those of ordinary skill in the art. SUMMARY

[0008] The purpose of the present application is to accurately predict the changes of the temperature, pressure and each phase state in the wellbore of a CO2 injection well during production.

[0009] The present application provides a parameter optimization method for CO2 phase state control, which is applied to the CO2 phase state control in the wellbore of a CO2 injection well, wherein the step of CO2 temperature and pressure prediction comprises:

[0010] Step 1: Given the well depth and calculation time t, define the space step (ΔZ) and time step (Δt);

[0011] Step 2: Initialize the temperature of each layer, including CO2 temperature Oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure Pj of each layer;

[0012] Step 3: Make P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n;

[0013] Step 4: According to CO2 temperature CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ;

[0014] Step 5: According to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ;

[0015] Step 6: Determine whether the conditions are met at the same time: T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j +1,new <0.01; if satisfied, jump to step 7; if not satisfied, let P j+1 =Pj+ 1,new , T t j+1 =T t j+1,new , and return to step 4;

[0016] Step 7: Calculate the heat exchange rate q according to the preset temperature calculation model j+1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature of the oil pipe is calculated respectively Oil pipe outer wall temperature Casing inner wall temperature

[0017] Step 8: Determine whether the condition (j+1)Δt<t is met. If so, j=j+1 and return to step 3. If not, stop the calculation and set the current oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

[0018] Preferably, the present invention further comprises:

[0019] Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, further comprising: jumping to step 9;

[0020] Step 9: According to T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

[0021] In another aspect of the present invention, a parameter optimization device for phase state control is provided, which is applied to CO2 phase state control in a CO2 injection wellbore. The unit for predicting CO2 temperature and pressure includes:

[0022] Setting unit, used to define the space step (ΔZ) and time step (Δt) under given well depth and calculation time t;

[0023] Initialization unit, used to initialize the temperature of each layer, including: CO2 temperature Oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure P of each layer j ;

[0024] Assignment unit, used to make P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n;

[0025] The first pressure calculation unit is used to calculate the pressure according to the CO2 temperature CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ;

[0026] The first temperature calculation unit is used to calculate the temperature according to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ;

[0027] The first judgment unit is used to judge whether the following conditions are met at the same time: t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j +1,new -P j+1 | / P j+1,new <0.01; if satisfied, jump to the second temperature calculation unit; if not satisfied, let P j+1 =P j+1,new , T t j+1 =T t j+1,new , and returns to the first pressure calculation unit;

[0028] The second temperature calculation unit is used to calculate the heat exchange rate q according to the preset temperature calculation model j+1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature of the oil pipe is calculated respectively Oil pipe outer wall temperature Casing inner wall temperature

[0029] The result generation unit is used to determine whether the condition is met: (j+1)Δt<t. If so, j=j+1 and return to the assignment unit; if not, stop the calculation and set the current oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

[0030] Preferably, in the present invention, a curve drawing unit is further included;

[0031] Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new<0.01; if satisfied, the curve drawing unit is based on T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

[0032] In another aspect of the embodiment of the present invention, a storage medium is further provided, on which a computer program is stored. When the computer program is executed by a processor, the various steps of the parameter optimization method for phase state control as described in any one of the above items are implemented.

[0033] On the other hand, an embodiment of the present invention provides a parameter optimization device for phase control. The parameter optimization device for phase control includes a computer program stored on a medium, and the computer program includes program instructions. When the program instructions are executed by a computer, the computer executes the methods described in the above aspects and achieves the same technical effects.

[0034] Compared with the prior art, the present invention has the following beneficial effects:

[0035] The present invention organically couples multiple calculation processes including fluid physical property parameter calculation, pressure calculation and temperature calculation, and can obtain more accurate calculation results (i.e., CO2 temperature and CO2 pressure including CO2 temperature after a preset time step, tubing inner wall temperature, outer wall temperature, casing inner wall temperature and along-line pressure); then, a sufficient amount of experimental data can be generated by the above-mentioned CO2 temperature and CO2 pressure calculation method; in this way, the injection parameters can be optimized by ranking the set injection parameters according to their importance.

[0036] Since the CO2 phase state generated by the present invention can more accurately describe the changing process of fluid components in the wellbore, a more accurate CO2 phase state in the wellbore can be obtained; therefore, the calculation method of the phase state in the wellbore of the production well of the present invention can accurately characterize the actual results of the temperature, pressure and phase state in the wellbore during the production process, thereby providing a more reliable data basis for parameter optimization.

[0037] The above description is only an overview of the technical solution of the present invention. In order to more clearly understand the technical means of the present invention and to implement it according to the contents of the specification, and to make the above and other purposes, technical features and advantages of the present invention easier to understand, one or more preferred embodiments are listed below and described in detail with reference to the accompanying drawings. BRIEF DESCRIPTION OF THE DRAWINGS

[0038] In order to more clearly illustrate the technical solution of the present invention, the following briefly introduces the drawings required for use in the embodiments. Obviously, the drawings described below are only some embodiments of the present invention. For ordinary technicians in this field, other drawings can be obtained based on these drawings without paying any creative work.

[0039] Figure 1 is a step diagram of the parameter optimization method for phase state control described in the present invention;

[0040] Figure 2 Schematic diagram of the structure of the parameter optimization device for phase state control described in the present invention;

[0041] Figure 3 It is a schematic diagram of the structure of the parameter optimization equipment for phase control described in the present invention. DETAILED DESCRIPTION

[0042] The specific embodiments of the present invention are described in detail below with reference to the accompanying drawings, but it should be understood that the protection scope of the present invention is not limited by the specific embodiments.

[0043] Unless expressly stated otherwise, throughout the specification and claims, the term “comprise” or variations such as “include” or “comprising” will be understood to include the stated elements or components but not to exclude other elements or components.

[0044] In this document, the terms "first", "second", etc. are used to distinguish two different elements or parts, and are not used to limit specific positions or relative relationships. In other words, in some embodiments, the terms "first", "second", etc. can also be interchangeable with each other.

[0045] Example 1

[0046] In order to accurately predict the changes in temperature, pressure and phase state in the CO2 injection wellbore during production, such as Figure 1 As shown, in an embodiment of the present invention, a parameter optimization method for CO2 phase control is provided, which is applied to CO2 phase control in a CO2 injection wellbore, wherein the step of predicting CO2 temperature and pressure includes:

[0047] Step 1: Given the well depth and calculation time t, define the space step (ΔZ) and time step (Δt);

[0048] In actual applications, when entering information about the target CO2 injection well, the required information data includes fluid data, well depth structure, production conditions and formation physical properties. Specifically, the fluid data mainly consists of CO2 and impurity gases; the well depth structure mainly includes the inner (outer) diameter of the tubing, the inner (outer) diameter of the casing, the material and thermal conductivity of the tubing, the well depth, and the thermal conductivity of the cement sheath; the production conditions mainly include injection temperature, injection pressure, injection volume, and injection time; and the formation physical properties include surface temperature, geothermal gradient, formation density, and formation heat capacity.

[0049] In the embodiment of the present invention, after the well depth data is determined, the spatial step (ΔZ) and time step (Δt) of the calculation process are set according to the data calculation and processing capabilities of the computer equipment and actual needs.

[0050] Among them, the spatial step refers to the logical division of the target CO2 injection well into multiple layers (well sections) according to the well depth data, and each spatial step is used to calculate one layer.

[0051] Step 2: Initialize the temperature of each layer, including CO2 temperature Oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure Pj of each layer;

[0052] When starting the calculation, it is necessary to initialize the data of each layer in the target CO2 injection well. The specific data include CO2 temperature Oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature In addition, there is the CO2 pressure Pj of each layer;

[0053] Step 3: Let T t j+1 =T t j , P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n;

[0054] Step 4: According to CO2 temperature T t j+1 、CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ;

[0055] In this embodiment, the formula required by the pressure calculation model may specifically include:

[0056]

[0057] Where z is the well depth, m; v is the flow velocity, m / s; g is the acceleration due to gravity, m / s 2 ; θ is the well inclination angle, °; d is the inner diameter of the tubing, m; f is the Darcy friction factor, dimensionless;

[0058] For the CO2 flow system, f is related to the Reynolds number, and the calculation formula includes:

[0059]

[0060]

[0061]

[0062] Step 5: According to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ;

[0063] In this step, the CO2 physical property parameter calculation equation may specifically include:

[0064] The physical properties of CO2 include thermal physical parameters and fluid physical parameters. The thermal physical parameters include CO2 density, specific heat capacity, and coke coefficient; the fluid physical parameters include viscosity and thermal conductivity.

[0065] Calculating the thermophysical parameters includes: using GERG-2008 to calculate the fluid density, specific heat capacity and coke soup coefficient for the slightly impure gas in CO2; the impurity gas may specifically include H2S, NO2, SO2, and O2;

[0066] Input the CO2 raw gas source composition data (mol%), CO2:H2O:O2:H2S:...=A:B:C:D:...; combine the CO2 temperature and oil pipeline pressure data, and use GERG-2008 to calculate the fluid density, specific heat capacity and coke soup coefficient;

[0067] The calculation of fluid property parameters includes: calculating viscosity and thermal conductivity using equations (1) and (2) respectively;

[0068] η(T,ρ)=η0(T)+η1(T)ρ+Δη r (T,ρ)+Δη c (T,ρ) (1)

[0069] In formula (1), η is the dynamic viscosity, unit is mPa·s; T is the absolute temperature, unit is °C; ρ is the density, unit is kg / m 3; η0(T) is the viscosity at the low density limit, in mPa·s; η1(T) is the linear viscosity coefficient within the density, in mPa·s; Δη r (T,ρ) is the temperature- and density-dependent residual viscosity in mPa·s; Δη c (T,ρ) is the enhanced viscosity very close to the gas-liquid critical point, in mPa·s;

[0070] λ(T,ρ)=λ0(T)+Δλ(T,ρ)+Δλ c (T,ρ) (2)

[0071] In formula (2), λ0(T) = λ(0,T) is the thermal conductivity of the rarefied gas limit, in W / (m·℃); Δλ(T,ρ) is the residual thermal conductivity, in W / (m·℃); Δλ c (T,ρ) is the thermal conductivity of the critical enhancement term, with the unit of W / (m·℃).

[0072] The heat transfer equation of CO2 in the wellbore includes the formula:

[0073]

[0074] Where, P fr is the friction loss of CO2 fluid, Pa; α J is the coke coefficient, K / Pa.

[0075] Step 6: Determine whether the conditions are met at the same time: T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / Pj +1,new <0.01; if satisfied, jump to step 7; if not satisfied, let P j+1 =P j+1,new , T t j+1 =T t j+1,new , and return to step 4;

[0076] Step 7: Calculate the heat exchange rate q according to the preset temperature calculation model j+1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature of the oil pipe is calculated respectively Oil pipe outer wall temperature Casing inner wall temperature

[0077] In this step, the formula required by the temperature calculation model can be as follows:

[0078] q=πdU(T t -T ei )dz;

[0079] Where, T t is the temperature of CO2 fluid in the oil pipe, °C; T ei is the formation temperature, ℃; U is the total heat transfer coefficient, W / (m 2 K), can be expressed by the following formula:

[0080]

[0081] Where h t is the CO2 heat transfer coefficient in the oil pipe, W / (m 2 ·K); k s is the thermal conductivity of oil / casing, W / (m·K); d to is the outer diameter of the oil pipe, m; h a is the heat transfer coefficient of the fluid in the casing annulus, W / (m 2 ·K);d ci is the inner diameter of the casing, m; k c is the thermal conductivity of cement sheath, W / (m·K); d wb is the wellbore diameter, m; d co is the outer diameter of the casing, m; f(t) is the dimensionless temperature function of the formation unsteady heat transfer; k e is the thermal conductivity of the formation, W / (m·K).

[0082] Step 8: Determine whether the condition (j+1)Δt<t is met. If so, j=j+1 and return to step 3. If not, stop the calculation and set the current oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

[0083] Furthermore, in order to draw the spatiotemporal change curve of CO2 phase along the process in real time, in the embodiment of the present invention, the following steps may also be included:

[0084] When the following conditions are met: t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new When <0.01, you can also perform the following steps:

[0085] Step 9: According to T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

[0086] In summary, the embodiments of the present invention organically couple multiple calculation processes, including phase equilibrium calculation, fluid physical parameter calculation, pressure calculation, and temperature calculation, to obtain more accurate calculation results (i.e., CO2 temperature, tubing inner wall temperature, outer wall temperature, casing inner wall temperature, and along-the-line pressure after a preset time step); thus, a more accurate CO2 phase state of the wellbore can be obtained; that is, the CO2 phase state generated by the embodiments of the present invention can more accurately describe the changing process of fluid components within the wellbore. Therefore, the calculation method for the phase state within the wellbore of a production well according to the embodiments of the present invention can accurately characterize the actual results of the temperature, pressure, and phase state within the wellbore during the production process, thereby providing a more reliable data basis for parameter optimization.

[0087] Example 2

[0088] Based on the parameter optimization method for phase control in Example 1, the embodiment of the present invention can also use the technical solutions of steps 1 to 9 to obtain test data and then optimize the injection parameters. The specific steps include:

[0089] Step 10: Set different injection parameters to conduct simulation tests, and obtain bottom hole pressure data and bottom hole temperature data for different test groups through steps 1 to 9; the injection parameters are used for CO2 phase control and include: displacement, injection temperature, injection pressure, friction resistance, and geothermal gradient;

[0090] Step 11: quantifying the influence of each injection parameter on the temperature field and pressure field in the wellbore by using a multi-factor multi-level orthogonal table; the multi-factor multi-level orthogonal table uses the bottom hole pressure and bottom hole temperature as observation values;

[0091] Step 12: Optimize the injection parameters according to the order of their influence on the temperature field and pressure field in the wellbore.

[0092] From the above, it can be seen that the embodiment of the present invention organically couples multiple calculation processes of fluid physical property parameter calculation, pressure calculation and temperature calculation, and can obtain more accurate calculation results (that is, CO2 temperature and CO2 pressure including CO2 temperature after a preset time step, oil pipe inner wall temperature, outer wall temperature, casing inner wall temperature and along-line pressure); then, a sufficient amount of experimental data can be generated through the above-mentioned CO2 temperature and CO2 pressure calculation method; in this way, the injection parameters can be optimized by ranking the importance of the set injection parameters.

[0093] Since the CO2 phase state generated by the embodiment of the present invention can more accurately describe the change process of the fluid components in the wellbore, a more accurate CO2 phase state in the wellbore can be obtained; therefore, the calculation method of the phase state in the wellbore of the production well in the embodiment of the present invention can accurately characterize the actual results of the temperature, pressure and phase state in the wellbore during the production process, thereby providing a more reliable data basis for parameter optimization.

[0094] It should be noted that the technical effects of the specific implementation method for parameter optimization of phase state control in the embodiment of the present invention can be referred to Figure 1 The corresponding parameter optimization method for phase control will not be described here.

[0095] Example 3

[0096] Corresponding to the method embodiment, another aspect of the embodiment of the present invention further provides a parameter optimization device for phase state control. Figure 3 The schematic diagram of the structure of the parameter optimization device for phase state control provided by the embodiment of the present invention is shown. Figure 1 The device corresponding to the parameter optimization method for phase control described in the corresponding embodiment, that is, the device is realized by means of a virtual device. Figure 1 The parameter optimization method for phase state control in the corresponding embodiment and the various virtual modules constituting the parameter optimization device for phase state control can be executed by electronic devices, such as network devices, terminal devices, or servers. Specifically, the unit for predicting CO2 temperature and pressure in the parameter optimization device for phase state control in the embodiment of the present invention includes:

[0097] Setting unit 01 is used to define the spatial step (ΔZ) and time step (Δt) under given well depth and calculation time t;

[0098] Initialization unit 02 is used to initialize the temperature of each layer, including: CO2 temperature T t 0 , Oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure Pj of each layer;

[0099] Assignment unit 03, used to make P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n;

[0100] The first pressure calculation unit 04 is used to calculate the pressure according to the CO2 temperature T t j+1、CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ;

[0101] The first temperature calculation unit 05 is used to calculate the temperature according to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ;

[0102] The first judgment unit 06 is used to judge whether the following conditions are met at the same time: t j+1,new -T t j+1 | / T t j+1,new <0.01|P j +1,new -P j+1 | / P j+1,new <0.01; if satisfied, jump to the second temperature calculation unit; if not satisfied, let P j+1 =P j+1,new , T t j+1 =T t j+1,new , and returns to the first pressure calculation unit;

[0103] The second temperature calculation unit 07 is used to calculate the heat exchange rate q according to the preset temperature calculation model j +1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature of the oil pipe is calculated respectively Oil pipe outer wall temperature Casing inner wall temperature

[0104] The result generating unit 08 is used to judge whether the condition (j+1)Δt<t is satisfied. If so, j=j+1 and returns to the assignment unit; if not, stop the calculation and set the current oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

[0105] Preferably, in the embodiment of the present invention, a curve drawing unit may be further included;

[0106] When the conditions are met at the same time: |T t j+1,new -T t j+1 | / Tt j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new When <0.01, the curve drawing unit is based on T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

[0107] It should be noted that the specific implementation method and technical effects of the parameter optimization device for phase state control in the embodiment of the present invention can be referred to Figure 1 The corresponding parameter optimization method for phase control will not be described here.

[0108] Example 4

[0109] Corresponding to the method embodiments, embodiments of the present invention also provide a parameter optimization device for phase control, such as a terminal or server. The server can be a standalone physical server, a server cluster or distributed system composed of multiple physical servers, or a cloud server that provides basic cloud computing services such as cloud services, cloud databases, cloud computing, cloud functions, cloud storage, network services, cloud communications, middleware services, domain name services, security services, CDN, and big data and artificial intelligence platforms. The terminal can be, but is not limited to, a smartphone, tablet computer, laptop computer, or desktop computer.

[0110] An example diagram of a hardware structure block diagram of a parameter optimization device for phase state control provided by an embodiment of the present invention is shown in FIG. Figure 3 As shown, this may include:

[0111] Processor 1, communication interface 2, memory 3 and communication bus 4;

[0112] The processor 1, the communication interface 2, and the memory 3 communicate with each other via the communication bus 4;

[0113] Optionally, the communication interface 2 may be an interface of a communication module, such as an interface of a GSM module;

[0114] The processor 1 may be a central processing unit (CPU), or an application-specific integrated circuit (ASIC), or one or more integrated circuits configured to implement the embodiments of the present application.

[0115] The memory 3 may include a high-speed RAM memory, and may also include a non-volatile memory (non-volatile memory), such as at least one disk memory.

[0116] The processor 1 is specifically configured to execute the computer program stored in the memory 3 to perform the following steps:

[0117] The steps for CO2 temperature and pressure prediction include:

[0118] Step 1: Given the well depth and calculation time t, define the space step (ΔZ) and time step (Δt);

[0119] Step 2: Initialize the temperature of each layer, including CO2 temperature Oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure Pj of each layer;

[0120] Step 3: Let T t j+1 =T t j , P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n;

[0121] Step 4: According to the CO2 temperature T t j+1 、CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ;

[0122] Step 5: According to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ;

[0123] Step 6: Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, jump to step 7; if not satisfied, let P j+1 =P j+1,new , Tt j+1 =T t j+1,new , and return to step 4;

[0124] Step 7: Calculate the heat exchange rate q according to the preset temperature calculation model j+1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature of the oil pipe is calculated respectively Oil pipe outer wall temperature Casing inner wall temperature

[0125] Step 8: Determine whether the condition (j+1)Δt<t is met. If so, j=j+1 and return to step 3. If not, stop the calculation and set the current oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

[0126] Preferably, the present invention further comprises:

[0127] Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, further comprising: jumping to step 9;

[0128] Step 9: According to T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

[0129] Preferably, in the embodiment of the present invention, the steps may also be included:

[0130] Step 10: Set different injection parameters to conduct simulation tests, and obtain bottom hole pressure data and bottom hole temperature data for different test groups through steps 1 to 9; the injection parameters are used for CO2 phase control and include: displacement, injection temperature, injection pressure, friction resistance, and geothermal gradient;

[0131] Step 11: quantifying the influence of each injection parameter on the temperature field and pressure field in the wellbore by using a multi-factor multi-level orthogonal table; the multi-factor multi-level orthogonal table uses the bottom hole pressure and bottom hole temperature as observation values;

[0132] Step 12: Optimize the injection parameters according to the order of their influence on the temperature field and pressure field in the wellbore.

[0133] The above-mentioned product can execute the method provided by the embodiment of the present invention, and has the functional modules and beneficial effects corresponding to the execution method. For technical details not fully described in this embodiment, please refer to the parameter optimization method for phase control provided by the embodiment of the present invention.

[0134] Example 5

[0135] In an embodiment of the present invention, a storage medium is further provided. The storage medium may store a program suitable for execution by a processor, wherein the program is used to:

[0136] The steps for CO2 temperature and pressure prediction include:

[0137] Step 1: Given the well depth and calculation time t, define the space step (ΔZ) and time step (Δt);

[0138] Step 2: Initialize the temperature of each layer, including: CO2 temperature T t 0 , Oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure Pj of each layer;

[0139] Step 3: Let T t j+1 =T t j , P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n;

[0140] Step 4: According to CO2 temperature CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ;

[0141] Step 5: According to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ;

[0142] Step 6: Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / Tt j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, jump to step 7; if not satisfied, let P j+1 =P j+1,new , T t j+1 =T t j+1,new , and return to step 4;

[0143] Step 7: Calculate the heat exchange rate q according to the preset temperature calculation model j+1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature of the oil pipe is calculated respectively Oil pipe outer wall temperature Casing inner wall temperature

[0144] Step 8: Determine whether the condition (j+1)Δt<t is met. If so, j=j+1 and return to step 3. If not, stop the calculation and set the current oil pipe inner wall temperature Oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

[0145] Preferably, the present invention further comprises:

[0146] Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, further comprising: jumping to step 9;

[0147] Step 9: According to T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

[0148] Preferably, in the embodiment of the present invention, the steps may also be included:

[0149] Step 10: Set different injection parameters to conduct simulation tests, and obtain bottom hole pressure data and bottom hole temperature data for different test groups through steps 1 to 9; the injection parameters are used for CO2 phase control and include: displacement, injection temperature, injection pressure, friction resistance, and geothermal gradient;

[0150] Step 11: quantifying the influence of each injection parameter on the temperature field and pressure field in the wellbore by using a multi-factor multi-level orthogonal table; the multi-factor multi-level orthogonal table uses the bottom hole pressure and bottom hole temperature as observation values;

[0151] Step 12: Optimize the injection parameters according to the order of their influence on the temperature field and pressure field in the wellbore.

[0152] Optionally, the detailed functions and extended functions of the program may refer to the above description.

[0153] The above-mentioned product can execute the method provided by the embodiment of the present invention, and has the functional modules and beneficial effects corresponding to the execution method. For technical details not fully described in this embodiment, please refer to the methods provided by other embodiments of the present invention.

[0154] Those skilled in the art will appreciate that the units and algorithm steps of each example described in conjunction with the embodiments disclosed herein can be implemented in electronic hardware, or a combination of computer software and electronic hardware. Whether these functions are performed in hardware or software depends on the specific application and design constraints of the technical solution. Professional and technical personnel can use different methods to implement the described functions for each specific application, but such implementation should not be considered beyond the scope of this application.

[0155] In the several embodiments provided herein, it should be understood that the disclosed systems, devices, and methods may be implemented in other ways. Furthermore, the couplings or direct couplings or communication connections shown or discussed may be indirect couplings or communication connections through interfaces, devices, or units, and may be electrical, mechanical, or other forms.

[0156] The units described as separate components may or may not be physically separate, and the components shown as units may or may not be physical units, that is, they may be located in one place or distributed across multiple network units. Some or all of these units may be selected to achieve the purpose of this embodiment according to actual needs.

[0157] In addition, each functional unit in each embodiment of the present application may be integrated into one processing unit, or each unit may exist physically separately, or two or more units may be integrated into one unit.

[0158] It should be understood that in the embodiments of the present application, the various embodiments and features can be combined with each other to solve the aforementioned technical problems.

[0159] If the functions are implemented in the form of software functional units and sold or used as independent products, they can be stored in a computer-readable storage medium. Based on this understanding, the technical solution of the present application, or the part that contributes to the prior art or the part of the technical solution, can be embodied in the form of a software product. The computer software product is stored in a storage medium and includes several instructions for enabling a computer device (which can be a personal computer, a server, or a network device, etc.) to execute all or part of the steps of the method described in each embodiment of the present application. The aforementioned storage medium includes various media that can store program codes, such as a USB flash drive, a mobile hard disk, a read-only memory (ROM), a random access memory (RAM), a magnetic disk or an optical disk.

[0160] The above description of the disclosed embodiments is intended to enable one skilled in the art to implement or use the present application. Various modifications to these embodiments will be readily apparent to one skilled in the art, and the general principles defined herein may be implemented in other embodiments without departing from the spirit or scope of the present application. Therefore, the present application is not limited to the embodiments shown herein, but is intended to conform to the widest scope consistent with the principles and novel features disclosed herein.

Claims

1. A parameter optimization method for CO2 phase control, applied to CO2 phase control in a wellbore during CO2 injection, characterized in that: The steps of CO2 temperature and CO2 pressure prediction include: Step 1: Given the well depth and calculation time t, define the space step (ΔZ) and time step (Δt); Step 2: Initialize the temperature of each layer, including: CO2 temperature T t 0 , oil pipe inner wall temperature T ti 0 , oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure Pj of each layer; Step 3: Let T t j+1 =T t j , P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n; Step 4: According to the CO2 temperature T t j+1 、CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ; Step 5: According to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ; Step 6: Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, jump to step 7; if not satisfied, let P j+1 =P j+1,new , T t j+1 =T t j+1,new , and return to step 4; Step 7: Calculate the heat exchange rate q according to the preset temperature calculation model j+1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature T of the oil pipe is calculated respectively. ti j+1,new , oil pipe outer wall temperature Casing inner wall temperature Step 8: Determine whether the condition (j+1)Δt<t is met. If so, j=j+1 and return to step 3. If not, stop the calculation and set the current oil pipe inner wall temperature T ti j+1,new , oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

2. The parameter optimization method for CO2 phase control according to claim 1, characterized in that: Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, further comprising: jumping to step 9; Step 9: According to T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

3. The parameter optimization method for CO2 phase control according to claim 2, characterized in that: Also includes: Step 10: Set different injection parameters to conduct simulation tests, and obtain bottom hole pressure data and bottom hole temperature data of different test groups through steps 1 to 9; The injection parameters are used for CO2 phase control, including displacement, injection temperature, injection pressure, friction and geothermal gradient; Step 11: quantifying the influence of each injection parameter on the temperature field and pressure field in the wellbore by using a multi-factor multi-level orthogonal table; the multi-factor multi-level orthogonal table uses the bottom hole pressure and bottom hole temperature as observation values; Step 12: Optimize the injection parameters according to the order of their influence on the temperature field and pressure field in the wellbore.

4. The parameter optimization method for CO2 phase control according to claim 3, characterized in that: The pressure calculation model includes the formula: Where z is the well depth, m; v is the flow velocity, m / s; g is the acceleration due to gravity, m / s 2 ; θ is the well inclination angle, °; d is the inner diameter of the tubing, m; f is the Darcy friction factor, dimensionless; For the CO2 flow system, f is related to the Reynolds number, and the calculation formula includes:

5. The parameter optimization method for CO2 phase control according to claim 4, characterized in that: The CO2 physical property parameter calculation equation includes: The physical properties of CO2 include thermal physical parameters and fluid physical parameters. The thermal physical parameters include CO2 density, specific heat capacity, and coke coefficient; the fluid physical parameters include viscosity and thermal conductivity. Calculating the thermophysical parameters includes: calculating the fluid density, specific heat capacity and coke soup coefficient using GERG-2008 based on the type and content of impurity gases in the injected CO2, combined with CO2 temperature and oil pipeline pressure data; the impurity gases include H2S, NO2, SO2, and O2; The calculation of fluid property parameters includes: calculating viscosity and thermal conductivity using equations (1) and (2) respectively; η(T,ρ)=η0(T)+η1(T)ρ+Δη r (T,p)+Dη c (T,p) (1) In formula (1), η is the dynamic viscosity, unit is mPa·s; T is the absolute temperature, unit is °C; ρ is the density, unit is kg / m 3 ; η0(T) is the viscosity at the low density limit, in mPa·s; η1(T) is the linear viscosity coefficient within the density, in mPa·s; Δη r (T,ρ) is the temperature- and density-dependent residual viscosity in mPa·s; Δη c (T,ρ) is the enhanced viscosity near the gas-liquid critical point, in mPa·s; λ(T,ρ)=λ0(T)+Δλ(T,ρ)+Δλ c (T,p) (2) In formula (2), λ0(T) = λ(0,T) is the thermal conductivity of the rarefied gas limit, in W / (m·℃); Δλ(T,ρ) is the residual thermal conductivity, in W / (m·℃); Δλ c (T,ρ) is the thermal conductivity of the critical enhancement term, with the unit of W / (m·℃).

6. The parameter optimization method for CO2 phase control according to claim 5, characterized in that: The heat transfer equation of CO2 in the wellbore includes the formula: Where, P fr is the friction loss of CO2 fluid, Pa; α J is the coke coefficient, K / Pa.

7. The parameter optimization method for CO2 phase control according to claim 6, characterized in that: The temperature calculation model includes the formula: q=πdU(T t -T ei )dz Where, T t is the temperature of CO2 fluid in the oil pipe, °C; T ei is the formation temperature, °C; U is the total heat transfer coefficient, W / (m 2 K), can be expressed by the following formula: Where h t is the CO2 heat transfer coefficient in the oil pipe, W / (m 2 ·K); k s is the thermal conductivity of oil / casing, W / (m·K); d to is the outer diameter of the oil pipe, m; h a is the heat transfer coefficient of the fluid in the casing annulus, W / (m 2 ·K);d ci is the inner diameter of the casing, m; k c is the thermal conductivity of cement sheath, W / (m·K); d wb is the wellbore diameter, m; d co is the outer diameter of the casing, m; f(t) is the dimensionless temperature function of the unsteady heat transfer of the formation; k e is the thermal conductivity of the formation, W / (m·K).

8. A parameter optimization device for CO2 phase control, applied to CO2 phase control in a CO2 injection wellbore, characterized in that: The units used to predict CO2 temperature and pressure include: Setting unit, used to define the space step (ΔZ) and time step (Δt) under given well depth and calculation time t; Initialization unit, used to initialize the temperature of each layer, including: CO2 temperature T t 0 , oil pipe inner wall temperature T ti 0 , oil pipe outer wall temperature Casing inner wall temperature Initialize the CO2 pressure P of each layer j ; Assignment unit, used to make T t j+1 =T t j , P j+1 =P j ; Wherein, the time step number j = 0, 1, 2, 3... n; The first pressure calculation unit is used to calculate the pressure according to the CO2 temperature T t j+1 、CO2 pressure P j+1 and pressure calculation model to calculate the new along-line pressure P j+1,new ; The first temperature calculation unit is used to calculate the temperature according to P j+1,new 、CO2 temperature T t j+1 , CO2 physical parameter calculation equation and CO2 heat transfer equation in the wellbore to calculate the new CO2 temperature T t j+1,new ; The first judgment unit is used to judge whether the following conditions are met at the same time: t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j +1,new -P j+1 | / P j+1,new <0.01; if satisfied, jump to the second temperature calculation unit; if not satisfied, let P j+1 =P j+1,new , T t j+1 =T t j+1,new , and returns to the first pressure calculation unit; The second temperature calculation unit is used to calculate the heat exchange rate q according to the preset temperature calculation model j+1,new , and according to the conservation of heat transfer in different layers in the radial direction, the new inner wall temperature T of the oil pipe is calculated respectively. ti j+1,new , oil pipe outer wall temperature Casing inner wall temperature The result generation unit is used to determine whether the condition is met: (j+1)Δt<t. If so, j=j+1 and return to the assignment unit; if not, stop the calculation and set the current oil pipe inner wall temperature T ti j+1,new , oil pipe outer wall temperature Casing inner wall temperature as a prediction result.

9. The parameter optimization device for CO2 phase control according to claim 8, characterized in that: Also includes a curve drawing unit; Determine whether the conditions are met at the same time: |T t j+1,new -T t j+1 | / T t j+1,new <0.01 and |P j+1,new -P j+1 | / P j+1,new <0.01; if satisfied, the curve drawing unit is based on T t j+1,new and P j+1,new Query the CO2 phase state diagram to obtain the CO2 phase state after (j+1) time steps, and draw the spatiotemporal change curve of the CO2 phase state along the process.

10. A parameter optimization device for CO2 phase control, characterized in that: include: memory for storing computer programs; A processor is configured to call and execute the computer program to implement the steps of the parameter optimization method for CO2 phase control according to any one of claims 1 to 7.

11. A storage medium, characterized in that: The method comprises a software program, wherein the software program is suitable for executing the steps of the parameter optimization method for CO2 phase control according to any one of claims 1 to 7 by a processor.

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