A method of determining the content of carbon dioxide in a geothermal reservoir

Abstract

The present application belongs to the technical field of geothermal energy exploitation, and particularly relates to a method for determining the content of carbon dioxide in a geothermal reservoir. The method comprises the steps of: obtaining the field test results of the temperature-pressure profile of a wellbore in a static state and a blowout state; establishing a two-phase phase transition flow model of a CO2-H2O system in a medium-high temperature geothermal wellbore including a flash evaporation process; giving a CO2 content analysis range and dividing it into segments, taking a parameter point in each segment to obtain temperature-pressure prediction results through the two-phase flow model; comparing the prediction results with the field test results to draw a curve of the error and the parameter variation, and the point with the minimum error is the optimal solution of the CO2 content; the two-phase flow model established in the present application has a wide range of application and small error, and can serve the prediction of the dryness and flash evaporation depth in the wellbore, and provide an important basis for the productivity prediction of geothermal wells and the evaluation of scaling prevention and scaling removal; the present application uses the temperature-pressure measured data of the whole wellbore, the sampling is representative and sufficient, and the implementation process is simple and has good accuracy.

Description

Technical Field

[0001] This invention belongs to the field of medium- and high-temperature geothermal energy extraction technology, and further relates to the fields of medium- and high-temperature geothermal reservoir parameter evaluation and wellbore scale prevention and removal, specifically relating to a method for determining the carbon dioxide content in geothermal reservoirs. Background Technology

[0002] Geothermal resources are a low-carbon, environmentally friendly, stable, and widely distributed clean and renewable energy source. Compared to wind and solar energy, they are minimally affected by external factors such as seasons, climate, and day / night cycles. Their power generation efficiency is as high as 73%, approximately 3.5 times that of wind energy and 5.2 times that of solar energy. Therefore, geothermal resources represent a new energy source with enormous potential. In the current context, the effective development and utilization of geothermal resources can make significant contributions to actively addressing climate change, controlling environmental pollution, reforming the energy structure, and achieving my country's dual-carbon goals. A geothermal reservoir is a stratum or rock mass buried underground with effective porosity and permeability, containing geothermal fluids that can be developed and utilized. Most medium- and high-temperature geothermal reservoirs (reservoir temperatures greater than 100℃) contain CO2, and CO2 is the main component of non-condensable gases in geothermal reservoirs; therefore, the presence of CO2 has a significant impact on geothermal development. The impact of CO2 on geothermal development mainly includes the following aspects: (1) It changes the properties of geothermal fluids, causing significant changes in the flash evaporation conditions, thereby affecting power generation efficiency; (2) It may cause calcium carbonate scaling problems in the production well shaft, clogging the well shaft and affecting production capacity; (3) It corrodes geothermal well shafts, pipelines and power generation equipment, affecting service life; (4) The auxiliary measures taken to solve the above problems lead to an increase in the construction cost of geothermal power plants.

[0003] Before evaluating the impact of CO2 on geothermal development, it is necessary to first determine the CO2 content in the geothermal reservoir fluids. Currently, CO2 content is generally determined using sampling analysis, which is further divided into wellhead sampling and downhole fidelity sampling. Wellhead sampling involves using a steam-water separator or similar device to extract the geothermal fluid after passing through the main valve at the geothermal wellhead. After the geothermal fluid condenses, the volume and composition characteristics of the gas and liquid are analyzed to determine the CO2 content. However, due to the uneven distribution of water vapor in the pipeline, and the various physicochemical processes that may occur in the geothermal fluid within the wellbore, wellhead sampling results cannot accurately reflect the condition of the geothermal fluid in the reservoir. Downhole fidelity sampling involves lowering a sealable container to the bottom of the well for sampling. After sampling, the valve is closed to seal the sample, and then it is pulled up for analysis after condensation. The downhole fidelity sampling method involves lowering and raising the downhole sampler, which is cumbersome and prone to accidents. In addition, both wellhead sampling and downhole high-fidelity sampling methods suffer from insufficient sample representativeness. Summary of the Invention

[0004] The present invention aims to overcome the shortcomings of existing technologies in determining CO2 content in medium- and high-temperature geothermal reservoirs, such as large errors, cumbersome sampling operations, and insufficient sample representativeness, and provides a method for determining the carbon dioxide content in geothermal reservoirs.

[0005] To achieve the above-mentioned objectives, the present invention is implemented through the following technical solution: A method for determining the carbon dioxide content in a geothermal reservoir, comprising the following steps: (S.1) obtaining measured temperature-pressure results of the wellbore profile under static and geothermal fluid venting conditions; (S.2) establishing a two-phase phase change flow model of a medium-high temperature geothermal wellbore carbon dioxide-water system including a flash evaporation process; (S.3) selecting several carbon dioxide content parameter points according to a given carbon dioxide content trial-and-error analysis range, and calculating the predicted temperature-pressure results of the wellbore profile corresponding to each carbon dioxide content parameter point using the two-phase phase change flow model of the medium-high temperature geothermal wellbore carbon dioxide-water system described in step (S.2); (S.4) comparing and analyzing the measured temperature-pressure results of the wellbore profile obtained in step (S.1) with the predicted temperature-pressure results of the wellbore profile corresponding to each carbon dioxide content parameter point obtained in step (S.3), thereby obtaining the average relative error-carbon dioxide content parameter point variation curve, and the point with the smallest error in the obtained average relative error-carbon dioxide content parameter point variation curve is the carbon dioxide content value.

[0006] The fluids in medium- and high-temperature geothermal production wells are mainly composed of H2O and CO2, and phase changes occur during the flow process within the wellbore. This invention obtains measured temperature-pressure results of the wellbore profile under both static and geothermal fluid venting conditions, eliminating the need for wellhead or bottom sampling. The process is simple and convenient. Based on the principles of mass, energy, and momentum conservation, this invention establishes a one-dimensional vertical wellbore phase change flow control equation for the carbon dioxide-water (CO2-H2O) system, thereby further establishing a two-phase phase change flow model for the CO2-H2O system in medium- and high-temperature geothermal wells, including the flash evaporation process. This two-phase phase change flow model for the CO2-H2O system in medium- and high-temperature geothermal wells, including the flash evaporation process, can be applied to systems with temperatures exceeding 100℃ and carbon dioxide partial pressures not exceeding 100 bar, exhibiting a wide range of applications and minimal measurement error. This invention selects several carbon dioxide content parameter points within a given carbon dioxide content analysis range and calculates the temperature-pressure prediction results of the wellbore profile corresponding to each parameter point using a two-phase phase change flow model of the CO2-H2O system in medium- and high-temperature geothermal wells. This overcomes the deficiency of insufficient sample representativeness in existing sampling analysis methods, further improving the accuracy of measurement results. Finally, the measured temperature-pressure results of the wellbore profile are compared and analyzed with the predicted temperature-pressure results of the wellbore profile corresponding to each carbon dioxide content parameter point, resulting in a curve showing the change in average relative error versus carbon dioxide content parameter point. The point with the smallest error in the curve is the carbon dioxide content value. After determining the carbon dioxide content through inversion trial-and-error analysis, the two-phase phase change flow model of the CO2-H2O system in medium- and high-temperature geothermal wells can be used to predict the dryness and flash depth within the wellbore, providing an important basis for geothermal well productivity prediction and scaling and scale prevention evaluation.

[0007] Preferably, the specific steps for obtaining the measured temperature-pressure results of the wellbore profile under static conditions are as follows: calibrate the testing instrument; conduct temperature and pressure tests on the wellbore profile at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead, respectively, to obtain the measured temperature-pressure results of the wellbore profile under static conditions.

[0008] As a further preferred embodiment, the specific steps for obtaining the measured temperature-pressure results of the wellbore profile under static conditions are as follows: The temperature and pressure sensors are calibrated and verified to ensure they are suitable for high-temperature and high-pressure conditions (i.e., suitable for systems where the temperature exceeds 100°C and the partial pressure of carbon dioxide does not exceed 100 bar); the temperature and pressure of the wellbore profile are tested at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead, with a test interval of 0.5~1.5m, and the test errors from the wellhead to the bottom of the well and from the bottom of the wellhead are 0~5%, thus obtaining the measured temperature-pressure results of the wellbore profile under static conditions.

[0009] By setting up the above parameters, the measured results of temperature and pressure of the wellbore profile under static conditions are obtained, which facilitates a full understanding of the temperature and pressure of the original geothermal reservoir fluid. Furthermore, based on the measured results of temperature and pressure of the wellbore profile, the fluid composition and properties can be further analyzed.

[0010] Preferably, the specific steps for obtaining the measured temperature-pressure results of the wellbore profile under the geothermal fluid venting state are as follows: calibrate the testing instrument; control the geothermal fluid to vent at different flow rates and conduct temperature and pressure tests on the wellbore profile at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead, respectively, to obtain the measured temperature-pressure results of the wellbore profile under the geothermal fluid venting state at different flow rates.

[0011] As a further preferred embodiment, the specific steps for obtaining the measured temperature and pressure results of the wellbore profile under the geothermal fluid venting condition are as follows: The temperature and pressure sensors are calibrated and verified to ensure they are suitable for high-temperature and high-pressure conditions (i.e., suitable for systems where the temperature exceeds 100°C and the partial pressure of carbon dioxide does not exceed 100 bar); the temperature and pressure of the wellbore profile are tested at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead under different flow venting conditions, with a test interval of 0.5~1.5m. The test error from the bottom of the well to the wellhead is 0~5%. Flow control is achieved by adjusting the opening size of the wellhead valve (where the adjustment ratio of the wellhead valve opening is within 50%, the geothermal fluid can be controlled under low flow release state; the adjustment ratio of the wellhead valve opening is between 50% and 60%, the geothermal fluid can be controlled under medium flow release state; and the adjustment ratio of the wellhead valve opening is between 60% and 100%, the geothermal fluid can be controlled under high flow release state). The measured temperature-pressure results of the wellbore profile under different flow rates of geothermal fluid are obtained.

[0012] Through the above settings, the measured results of temperature and pressure of the wellbore profile under different flow rates of geothermal fluid were obtained. This facilitates a full understanding of the impact of surrounding rock heat exchange under different flow rates of geothermal fluid, thereby improving the accuracy of CO2 content measurement and further clarifying the impact of surrounding rock heat exchange on geothermal well productivity prediction and scaling and scale prevention evaluation.

[0013] Preferably, the one-dimensional vertical wellbore phase change flow control equations established in step (S.2) for the two-phase phase change flow model of the carbon dioxide-water system in the high-temperature geothermal wellbore include: The boundary conditions at the bottom of the well are: total mass velocity The mass fraction of CO2 isγ The pressure is P d The temperature is T d In equations (1) to (3): ρ l and ρ g These are the densities of the liquid and gas phases, respectively, in kg / m³. 3 ; u l and u g These are the velocities for the liquid phase and the gas phase, respectively, in m / s; This refers to the volume fraction of the gas phase. The total mass velocity is expressed in kg / s. and These are the mass velocities of the liquid phase and the gas phase, respectively, in kg / s; x l CO2 and y g CO2 These represent the mass fractions of CO2 in the liquid and gas phases, respectively. P For total pressure, , and These are the partial pressures of H2O and CO2, respectively, in Pa. z This is the shaft elevation, in meters (m). For mixed density, Unit: kg / m 3 ; g It is the acceleration due to gravity. g =9.8 m 2 / s; A For area, Unit m 2 ; Let be the wellbore friction coefficient, when the Reynolds number is... hour, ,otherwise ; Well wall roughness, in meters (m); d The diameter of the wellbore is in meters (m). u m The average velocity of the mixture, The unit is m / s; μ m The viscosity of the mixture, ,unit ; and These are the viscosities of the liquid phase and the gas phase, respectively. h mThe enthalpy of the mixture, in J / kg. ; x This refers to the mass fraction of the gas phase. and These are the liquid phase and gas phase enthalpy, respectively, in J / kg; ；q This refers to the heat exchange rate per unit length between the wellbore and the surrounding rock. , ; T and T wb These are the temperatures of the wellbore fluid and the wellbore wall, respectively, in °C. (Wellbore wall temperature) T wb Obtained through static temperature testing; For lumped parameters, the unit is , (in , The diameter of the well ( r 1) Cementing radius ( r 2) and surrounding rock ( k T ), cementing cement ( k cem Thermal conductivity and specific heat capacity ( ) c r The combined effects of time (t) and time (t).

[0014] Preferably, the specific steps for selecting carbon dioxide content parameter points in step (S.3) are as follows: Given a carbon dioxide content trial-and-error analysis range [X, Y], it is evenly divided into N segments, thereby obtaining N+1 carbon dioxide content parameter points. γ i And their values ​​are respectively: .

[0015] As a further optimization, given a trial-and-error analysis range of [0, 0.04] for carbon dioxide content, the points for obtaining carbon dioxide content parameters are selected. γ 0=0 γ 1 = 0.5% γ 2 = 1.0% γ 3 = 1.5%.

[0016] By using the above settings, a larger number of carbon dioxide content parameter points can be selected within a given range of trial and error analysis, and these points can be selected at equal intervals. This makes the selected carbon dioxide content parameter points representative and the sample size larger, thereby obtaining more accurate temperature-pressure prediction results for the wellbore profile.

[0017] As a preferred method, the calculation of temperature-pressure prediction results of wellbore profiles corresponding to various carbon dioxide content parameter points using a two-phase phase change flow model of a carbon dioxide-water system in a medium-high temperature geothermal well includes the following steps: S1: Input the bottom boundary conditions and model parameters for the two-phase phase change flow model of the carbon dioxide-water system in a medium-high temperature geothermal well: Input the first variable at the bottom of the well: Pressure at the bottom of the well casing. P d 、 Temperature at the bottom of the well casing T d 、 Total mass velocity Carbon dioxide mass fraction at the bottom of the well casing γ Input parameter: wellbore diameter d、 Wellbore length L、 Wellbore roughness ε、 S1: Calculate the spacing dz; S2: Determine whether the bottom phase is single-phase or two-phase, and update the fluid properties accordingly; S3: Calculate the target temperature T for the next point based on the current temperature of the previous point; S4: Set the target gas fraction for the next point based on the gas fraction of the previous point. x S5: Based on temperature target T and gas phase fraction target x The upward position increment dz corresponding to the temperature target T is calculated using a two-phase phase change flow model of a medium-high temperature geothermal well carbon dioxide-water system, and the energy balance is checked; S6: Determine whether the energy balance check passes. If not, return to step S4; S7: If yes, continue to determine whether the accumulated dz is greater than the wellhead position z. wellhead If not, return to step S3; S8: Output the predicted temperature-pressure results of the wellbore profile corresponding to the carbon dioxide content parameter point.

[0018] Preferably, in step S2, when the state of the bottom-hole phase is determined to be single-phase, the variable to be determined after the fluid properties are updated is the total pressure. P Liquid phase enthalpy h l Liquid phase velocity u l .

[0019] As a further optimization, when the bottom phase is a single phase, the gas-phase related quantities in the one-dimensional vertical wellbore phase change flow control equations (1) to (3) are all 0, that is... , , The variable to be determined is total pressure. P Liquid phase enthalpy h l and liquid phase velocity u l There are three variables, and all other parameters can be functions of these three variables to be determined.

[0020] Preferably, in step S2, when the state of the bottom phase is determined to be single phase, the flash depth is obtained by calculating from the bottom of the well upwards after the fluid properties are updated.

[0021] As a further preferred option, when determining the bottom-hole phase state as single-phase in step S2, the specific steps for calculating the flash depth from the bottom of the well upwards after updating the fluid properties are as follows: Assigning temperature ,pressure and enthalpy ; Cycle i=1, L / dz; Based on the partial pressure of water: The density of water in the liquid phase is obtained through equation calculation. , internal energy and viscosity The density of water in the gas phase , internal energy and viscosity Based on the liquid phase density: The density of dissolved CO2 can be calculated using the formula. ;according to Formula for calculating the pressure drop caused by gravity P gr Numerical value; based on speed: Reynolds number and wellbore friction coefficient f , Formula calculation yields: Pressure reduction caused by wellbore friction P fr Numerical value; based on the formula: Update pressure P new Numerical value; based on the formula: Update Hot Han h new Numerical value; according to P new , h new , γ Numerical acquisition of system temperature T new and gas phase mass fraction x If the gas phase mass fraction If the position is correct, then the flash depth is reached, and the loop exits; otherwise... , , Continue the calculation in a loop.

[0022] Preferably, in step S2, when the state of the bottom-hole phase is determined to be two-phase, the variable to be determined after the fluid properties are updated is the liquid phase density. ρ l gas phase density ρ gTotal pressure P Liquid phase thermal han h l , gas phase thermal han h g Mass fraction of CO2 in the liquid phase x l CO2 Mass fraction of CO2 in the gas phase y g CO2 Gas phase volume fraction α Gas phase mass fraction x Liquid phase velocity u l Gas phase velocity u g .

[0023] As a further optimization, when the bottom phase is a two-phase state, the unknown variable to be determined is the liquid phase density. ρ l gas phase density ρ g Total pressure P Liquid phase thermal han h l , gas phase thermal han h g Mass fraction of CO2 in the liquid phase x l CO2 Mass fraction of CO2 in the gas phase y g CO2 Gas phase volume fraction α Gas phase mass fraction x Liquid phase velocity u l Gas phase velocity u g Furthermore, state-aided equations are also required.

[0024] As a further preferred embodiment, the state-aided equation includes: in the two-phase case, the partial pressure of water is a function of temperature, i.e.: mass fraction of CO2 in the liquid phase It is a function of the partial pressure and temperature of CO2 in the gas phase, that is: In equations (4) to (5): Henry's constant, obtained through calculation by an external subroutine (such as Tough2 / EOS2); liquid phase density It is the total pressure P ,temperature T and the mass fraction of CO2 in the liquid phase The function of gas phase density; CO2 mass fraction in the gas phase All are temperatures T partial pressure of H2O partial pressure of CO2 The function.

[0025] Enthalpy of liquid mixture for: in: and pressure P and temperature T The internal energy and density of the liquid phase H2O below; For voltage divider and temperature T Enthalpy of CO2 at a given temperature; The heat released when CO2 dissolves in water.

[0026] Enthalpy of gas mixture for: in: and pressure and temperature T The internal energy and density of H2O in the gas phase below.

[0027] gas phase volume fraction In two-phase calculations, this is a crucial parameter, which, by definition, is: For velocity heterogeneous models (i.e.) (It is also necessary to establish the gas phase volume fraction) The relationship with velocity. The most commonly used model is the drift flux model (DFM), originally established by Zuber and Findlay: Wherein: volume average velocity ; This refers to the gas phase drift velocity. As a distributed parameter, it is affected by local gas phase saturation, transverse velocity distribution in the pipeline, flow regime, well inclination, and flow direction. Combining (8) and (9), we can finally obtain: Distribution parameters and gas phase drift velocity have a decisive influence on the gas phase volume fraction, which ultimately has a significant impact on the distribution of pressure and temperature.

[0028] For wellbore diameters less than 0.35 m, this invention selects the drift flow model from Shi et al. (2005): Where: parameters , , , , , , ;parameter It is the gas phase volume fraction. The function, i.e. ; , and These are all empirical parameters; in this invention, we take... , , .

[0029] For wellbore diameters greater than 0.35 m, the drift flow model used in this invention is the Hibiki and Ishii (2003) model: in: The gas-liquid interfacial tension is used. The above model involves many property parameters, such as density, enthalpy, and saturated vapor pressure, which can be obtained by looking up tables (such as the NIST standard database).

[0030] As a further optimization, a calculation method for predicting the temperature and pressure of the wellbore profile corresponding to each carbon dioxide content parameter point is obtained through a two-phase phase change flow model of a carbon dioxide-water system in a medium-high temperature geothermal well. This method includes the following steps: S1: Input the bottom boundary conditions and model parameters for the two-phase phase change flow model of the carbon dioxide-water system in a medium-high temperature geothermal well: Input the first variable at the bottom of the well: pressure at the bottom of the well casing. P d 、 Temperature at the bottom of the well casing T d 、 Total mass velocity Carbon dioxide mass fraction at the bottom of the well casing γ Input parameter: wellbore diameter d、 Wellbore length L、 Wellbore roughness ε、 Calculate the spacing dz; input the static temperature distribution of the wellbore profile. T wb and lumped heat transfer coefficient U .

[0031] S2: According to the formula , (here) Pick Calculate the partial voltage; if If the water pressure is within a single phase, the bottom phase can be determined to be single-phase; otherwise, the bottom phase can be determined to be two-phase. When the bottom phase is single-phase: based on the partial pressure of water: The density of water in the liquid phase is obtained by formula calculation. and internal energy The density of water in the gas phase and internal energy ;

[0032] Based on the partial pressure of CO2: The formula calculates the partial voltage as follows: Temperature is Enthalpy of gaseous CO2 under certain conditions Based on the enthalpy of the fluid at the bottom of the well: The temperature is obtained through formula calculation. Heat of solution of CO2 under certain conditions ;

[0033] Based on the bottom-hole liquid density: The density of dissolved CO2 is obtained by formula calculation. When the bottom of the well is in a single-phase state, the flash depth also needs to be calculated.

[0034] When the bottom of the well is in a two-phase state: according to the partial pressure of water: The density of water in the liquid phase is obtained by formula calculation. and internal energy The density of water in the gas phase and internal energy ;according to The formula is used to calculate the partial pressure of CO2. P CO2 Numerical value; according to Formula for calculating the mass fraction of CO2 in the liquid phase Numerical value; based on the voltage divider Temperature is Enthalpy of gaseous CO2 under certain conditions and density and temperature Heat of solution of CO2 under certain conditions , Formula for calculating the bottom-hole liquid phase enthalpy h l Numerical value; according to Formula for calculating the mass fraction of CO2 in the gas phase Numerical value; according to Formula calculation to obtain bottom hole gas phase thermal enthalpy hg Numerical value; according to Formula for calculating gas phase mass fraction x Numerical value; according to Formula for calculating total enthalpy h l Numerical value; according to Formula for calculating the bottom-hole liquid density ρ l Numerical value; based on gas phase density: Formula for calculating gas phase density ρ g Numerical value; according to Formula for calculating gas phase volume fraction α Numerical value; according to Formula for calculating liquid phase velocity u l Numerical value; according to Formula for calculating gas phase velocity u g Numerical value.

[0035] When the flash depth is less than the wellhead position, a two-phase phase change flow calculation is performed. The calculation process is as follows: S3: Calculate the target temperature T for the next point based on the current temperature at the previous point; set a slight temperature reduction. Set temperature target ( T last (The temperature calculated in the previous step).

[0036] S4: Set the gas phase fraction target for the next point based on the gas phase fraction at the previous point. x ; Set the gas phase mass fraction to increase by trace amounts Set gas phase fraction target ( x last (This refers to the gas phase fraction calculated in the previous step).

[0037] S5: According to Formula for calculating the partial pressure of water P H2O Numerical value; according to T , γ , x Determine the partial pressure of CO2 P CO2 Numerical value; according to The formula calculates the total pressure. P Numerical value; known density of liquid water , internal energy and viscosity The density of water in the gas phase , internal energy and viscosity ;according to Formula for calculating the mass fraction of CO2 in the liquid phase x l CO2 Numerical value; known partial pressure is Temperature is Enthalpy of gaseous CO2 under certain conditions and density The temperature is Heat of solution of CO2 under certain conditions Viscosity of CO2 in the gas phase ;according to Formula for calculating liquid phase enthalpy h l ;according to Formula for calculating the mass fraction of CO2 in the gas phase x g CO2 Numerical value; according to Formula for calculating gas phase enthalpy h g Numerical value; according to Formula for calculating gas phase viscosity μ g Numerical value; according to Formula for calculating total enthalpy h Numerical value; density of dissolved CO2 known. ;according to Formula for calculating liquid phase density ρ l Numerical value; according to Formula for calculating gas phase density ρ g Numerical value; according to Formula for calculating gas phase volume fraction α Numerical value; according to Formula for calculating the density of the mixture ρ m Numerical value; according to Formula for calculating liquid phase velocity u l Numerical value; according to Formula for calculating gas phase velocity u g Numerical value; according to Formula to calculate the mixing speed u m Numerical value; according to Formula for calculating the mixed viscosity μ m Numerical values; known Reynolds number and wellbore friction coefficient. f ;according to Formula calculation to obtain the pressure reduction gradient caused by gravity P gr Numerical value; according to Formula calculation yields the pressure reduction gradient caused by wellbore friction. P fr Numerical value; according to The formula calculates the depth change dz value; the surrounding rock heat transfer is known. q ;according to Formula for calculating enthalpy h new Numerical value.

[0038] S6: Enthalpy h new The numerical value is compared with the enthalpy from the previous step for balance check. If they are inconsistent, return to step S4.

[0039] S7: Yes, continue to determine whether the accumulated dz is greater than the wellhead position z. wellhead If not, return to step S3.

[0040] S8: Yes, output the predicted temperature-pressure results of the wellbore profile corresponding to the carbon dioxide content parameter point: temperature value, pressure value, and gas mass fraction value of the wellbore profile.

[0041] Preferably, the specific steps for obtaining the average relative error-carbon dioxide content parameter point variation curve in step (S.4) are as follows: using the measured temperature-pressure results of the wellbore profile obtained in step (S.1) and the predicted temperature-pressure results of the wellbore profile obtained in step (S.3), respectively draw the monitoring and prediction comparison curves of fluid temperature and fluid pressure throughout the entire length of the wellbore; calculate the average relative error of temperature and the average relative error of pressure corresponding to each carbon dioxide content parameter point; draw the variation curves of the average relative error of temperature, the average relative error of pressure and the carbon dioxide content parameter points, thereby obtaining the average relative error-carbon dioxide content parameter point variation curve.

[0042] Therefore, the present invention has the following beneficial effects: (1) The two-phase phase change flow model of the carbon dioxide-water system in the medium-high temperature geothermal well, which includes the flash evaporation process, established in the present invention can be applied to systems with temperatures exceeding 100℃ and carbon dioxide partial pressure not exceeding 100 bar, with a wide range of applications and small measurement errors; (2) The present invention utilizes the measured temperature-pressure results of the entire wellbore profile of the medium-high temperature geothermal well, combined with the two-phase phase change flow model of the carbon dioxide-water system in the medium-high temperature geothermal well and the predicted temperature-pressure results of the wellbore profile calculated by the model, from The determination of carbon dioxide content in geothermal reservoirs overcomes the shortcomings of insufficient sampling representativeness in existing sampling analysis methods, and does not require sampling at the wellhead or bottom, making the implementation process simple; (3) Since temperature and pressure measurements are simple and reliable, the method of determining the carbon dioxide content in geothermal reservoirs also has high reliability; (4) After determining the carbon dioxide content through inversion trial and error analysis, the present invention can further use the two-phase flow model of carbon dioxide-water system in medium and high temperature geothermal wells to predict the dryness and flash depth in the wellbore, providing an important basis for the prediction of geothermal well productivity and the evaluation of scaling and scale prevention. Attached Figure Description

[0043] Figure 1 This is a flowchart illustrating a method for rapidly determining the CO2 content in a thermal reservoir based on wellbore profile temperature and pressure tests.

[0044] Figure 2 A comparison of the predicted temperature-pressure results of the wellbore profile calculated by the two-phase phase change flow model of the CO2-H2O system in medium- and high-temperature geothermal wells under different CO2 contents with the measured temperature-pressure results of the wellbore profile.

[0045] Figure 3 This is a curve showing the average relative error of temperature-pressure as a function of CO2 content. Detailed Implementation

[0046] The present invention will be further described below with reference to the accompanying drawings and specific embodiments. Those skilled in the art will be able to implement the present invention based on these descriptions. Furthermore, the embodiments of the present invention described below are generally only some, not all, of the embodiments of the present invention. Therefore, all other embodiments obtained by those skilled in the art based on the embodiments of the present invention without inventive effort should fall within the scope of protection of the present invention.

[0047] As one implementation method, the specific steps for obtaining the measured temperature-pressure results of the wellbore profile under static conditions are as follows: calibrate the testing instrument; conduct temperature and pressure tests on the wellbore profile at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead, respectively, to obtain the measured temperature-pressure results of the wellbore profile under static conditions.

[0048] As a preferred embodiment, the specific steps for obtaining the measured temperature-pressure results of the wellbore profile under static conditions are as follows: The temperature and pressure sensors are calibrated and verified to ensure they are suitable for high-temperature and high-pressure conditions (i.e., suitable for systems where the temperature exceeds 100°C and the partial pressure of carbon dioxide does not exceed 100 bar); the temperature and pressure of the wellbore profile are tested at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead, with a test interval of 0.5~1.5m. The test errors from the wellhead to the bottom of the well and from the bottom of the wellhead are 0~5%, thus obtaining the measured temperature-pressure results of the wellbore profile under static conditions.

[0049] By setting up the above parameters, the measured results of temperature and pressure of the wellbore profile under static conditions are obtained, which facilitates a full understanding of the temperature and pressure of the original geothermal reservoir fluid. Furthermore, based on the measured results of temperature and pressure of the wellbore profile, the fluid composition and properties can be further analyzed.

[0050] As one implementation method, the specific steps for obtaining the measured temperature-pressure results of the wellbore profile under the geothermal fluid venting state are as follows: calibrate the testing instrument; control the geothermal fluid to vent at different flow rates and conduct temperature and pressure tests on the wellbore profile at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead, respectively, to obtain the measured temperature-pressure results of the wellbore profile under the geothermal fluid venting state at different flow rates.

[0051] As a preferred embodiment, the specific steps for obtaining the measured temperature and pressure results of the wellbore profile under the geothermal fluid venting state are as follows: The temperature and pressure sensors are calibrated and verified to ensure they are suitable for high-temperature and high-pressure conditions (i.e., suitable for systems where the temperature exceeds 100°C and the partial pressure of carbon dioxide does not exceed 100 bar); the temperature and pressure of the wellbore profile are measured at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead under different flow venting states of the geothermal fluid, with a test interval of 0.5~1.5m, from the wellhead to the bottom of the well. The test error from the bottom of the well to the wellhead is 0-5%. Flow control is achieved by adjusting the opening size of the wellhead valve (where the adjustment ratio of the wellhead valve opening is within 50%, the geothermal fluid can be controlled under low flow release; the adjustment ratio of the wellhead valve opening is between 50% and 60%, the geothermal fluid can be controlled under medium flow release; and the adjustment ratio of the wellhead valve opening is between 60% and 100%, the geothermal fluid can be controlled under high flow release). The measured temperature-pressure results of the wellbore profile under different flow rates of geothermal fluid are obtained.

[0052] Through the above settings, the measured results of temperature and pressure of the wellbore profile under different flow rates of geothermal fluid were obtained. This facilitates a full understanding of the impact of surrounding rock heat exchange under different flow rates of geothermal fluid, thereby improving the accuracy of CO2 content measurement and further reducing the impact of surrounding rock heat exchange on geothermal well productivity prediction and scaling and scale prevention evaluation.

[0053] As one implementation method, the one-dimensional vertical wellbore phase change flow control equations established in step (S.2) for the two-phase phase change flow model of the carbon dioxide-water system in a high-temperature geothermal well include: The boundary conditions at the bottom of the well are: total mass velocity The mass fraction of CO2 is γ The pressure is P d The temperature is T d In equations (1) to (3): ρ l and ρ g These are the densities of the liquid and gas phases, respectively, in kg / m³. 3 ; u l and u g These are the velocities for the liquid phase and the gas phase, respectively, in m / s; This refers to the volume fraction of the gas phase. The total mass velocity is expressed in kg / s. and These are the mass velocities of the liquid phase and the gas phase, respectively, in kg / s; x l CO2 and y g CO2 These represent the mass fractions of CO2 in the liquid and gas phases, respectively. P For total pressure, , and These are the partial pressures of H2O and CO2, respectively, in Pa. z This is the shaft elevation, in meters (m). For mixed density, Unit: kg / m 3 ; g It is the acceleration due to gravity. g =9.8 m 2 / s; A For area, Unit m 2 ; Let be the wellbore friction coefficient, when the Reynolds number is... hour, ,otherwise ; Well wall roughness, in meters (m); d The diameter of the wellbore is in meters (m). u m The average velocity of the mixture, The unit is m / s; μ m The viscosity of the mixture, ,unit ; and These are the viscosities of the liquid phase and the gas phase, respectively. h m The enthalpy of the mixture, in J / kg. ; x This refers to the mass fraction of the gas phase. and These are the liquid phase and gas phase enthalpy, respectively, in J / kg; ；q This refers to the heat exchange rate per unit length between the wellbore and the surrounding rock. , ; T and T wb These are the temperatures of the wellbore fluid and the wellbore wall, respectively, in °C. (Wellbore wall temperature) T wb Obtained through static temperature testing; For lumped parameters, the unit is , (in , The diameter of the well ( r 1) Cementing radius ( r 2) and surrounding rock ( k T ), cementing cement ( k cem Thermal conductivity and specific heat capacity ( ) c r The combined effects of time (t) and time (t).

[0054] As one implementation method, the specific steps for selecting carbon dioxide content parameter points in step (S.3) are as follows: Given a carbon dioxide content trial-and-error analysis range [X, Y], it is evenly divided into N segments, thereby obtaining N+1 carbon dioxide content parameter points. γ i And their values ​​are respectively: .

[0055] As a preferred embodiment, given a carbon dioxide content trial-and-error analysis range of [0, 0.04], the carbon dioxide content parameter points are selected. γ 0=0 γ 1 = 0.5% γ 2 = 1.0% γ 3 = 1.5%.

[0056] By using the above settings, a larger number of carbon dioxide content parameter points can be selected within a given range of trial and error analysis, and these points can be selected at equal intervals. This makes the selected carbon dioxide content parameter points representative and the sample size larger, thereby obtaining more accurate temperature-pressure prediction results for the wellbore profile.

[0057] As one implementation method, the calculation method for predicting the temperature and pressure of the wellbore profile corresponding to each carbon dioxide content parameter point through a two-phase phase change flow model of a carbon dioxide-water system in a medium-high temperature geothermal well includes the following steps: S1: Input the bottom boundary conditions and model parameters for the two-phase phase change flow model of the carbon dioxide-water system in a medium-high temperature geothermal well: Input the first variable at the bottom of the well: Pressure at the bottom of the well casing. P d 、 Temperature at the bottom of the well casing T d 、 Total mass velocity Carbon dioxide mass fraction at the bottom of the well casing γ Input parameter: wellbore diameter d、 Wellbore length L、 Wellbore roughness ε、 S1: Calculate the spacing dz; S2: Determine whether the bottom phase is single-phase or two-phase, and update the fluid properties accordingly; S3: Calculate the target temperature T for the next point based on the current temperature of the previous point; S4: Set the target gas fraction for the next point based on the gas fraction of the previous point. x S5: Based on temperature target T and gas phase fraction target x The upward position increment dz corresponding to the temperature target T is calculated using a two-phase phase change flow model of a medium-high temperature geothermal well carbon dioxide-water system, and the energy balance is checked; S6: Determine whether the energy balance check passes. If not, return to step S4; S7: If yes, continue to determine whether the accumulated dz is greater than the wellhead position z. wellhead If not, return to step S3; S8: Output the predicted temperature-pressure results of the wellbore profile corresponding to the carbon dioxide content parameter point.

[0058] In one implementation, when the bottom phase is determined to be single-phase in step S2, the variable to be determined after the fluid properties are updated is the total pressure. P Liquid phase enthalpy hl Liquid phase velocity u l .

[0059] In a preferred embodiment, when the bottom phase is a single phase, the gas-phase related quantities in the one-dimensional vertical wellbore phase change flow control equations (1) to (3) are all 0, that is... , , The variable to be determined is total pressure. P Liquid phase enthalpy h l and liquid phase velocity u l There are three variables, and all other parameters can be functions of these three variables to be determined.

[0060] As one implementation method, when the state of the bottom phase is determined to be single phase in step S2, the flash depth is obtained by calculating from the bottom of the well upwards after the fluid properties are updated.

[0061] In a preferred embodiment, when the state of the bottom phase in step S2 is determined to be single-phase, the specific steps for calculating the flash depth from the bottom of the well upwards after updating the fluid properties are as follows: Assigning temperature ,pressure and enthalpy ; Cycle i=1, L / dz; Based on the partial pressure of water: The density of water in the liquid phase is obtained through equation calculation. , internal energy and viscosity The density of water in the gas phase , internal energy and viscosity Based on the liquid phase density: The density of dissolved CO2 can be calculated using the formula. ;according to Formula for calculating the pressure drop caused by gravity P gr Numerical value; based on speed: Reynolds number and wellbore friction coefficient f , Formula calculation yields: Pressure reduction caused by wellbore friction P fr Numerical value; based on the formula: Update pressure P new Numerical value; based on the formula: Update Hot Han h new Numerical value; according to P new , h new, γ Numerical acquisition of system temperature T new and gas phase mass fraction x If the gas phase mass fraction If the position is correct, then the flash depth is reached, and the loop exits; otherwise... , , Continue the calculation in a loop.

[0062] In one implementation, when the state of the bottom phase is determined to be two-phase in step S2, the variable to be determined after the fluid properties are updated is the liquid phase density. ρ l gas phase density ρ g Total pressure P Liquid phase thermal han h l , gas phase thermal han h g Mass fraction of CO2 in the liquid phase x l CO2 Mass fraction of CO2 in the gas phase y g CO2 Gas phase volume fraction α Gas phase mass fraction x Liquid phase velocity u l Gas phase velocity u g .

[0063] In a preferred embodiment, when the bottom phase is in a two-phase state, the unknown variable to be determined is the liquid phase density. ρ l gas phase density ρ g Total pressure P Liquid phase thermal han h l , gas phase thermal han h g Mass fraction of CO2 in the liquid phase x l CO2 Mass fraction of CO2 in the gas phase y g CO2 Gas phase volume fraction α Gas phase mass fraction x Liquid phase velocity u l Gas phase velocity u g Furthermore, state-aided equations are also required.

[0064] As a further preferred embodiment, the state-aided equation includes: in the two-phase case, the partial pressure of water is a function of temperature, i.e.: mass fraction of CO2 in the liquid phase It is a function of the partial pressure and temperature of CO2 in the gas phase, that is: In equations (4) to (5): Henry's constant, obtained through calculation by an external subroutine (such as Tough2 / EOS2); liquid phase density It is the total pressure P ,temperature T and the mass fraction of CO2 in the liquid phase The function of gas phase density; CO2 mass fraction in the gas phase All are temperatures T partial pressure of H2O partial pressure of CO2 The function.

[0065] Enthalpy of liquid mixture for: in: and pressure P and temperature T The internal energy and density of the liquid phase H2O below; For voltage divider and temperature T Enthalpy of CO2 at a given temperature; The heat released when CO2 dissolves in water.

[0066] Enthalpy of gas mixture for: in: and pressure and temperature T The internal energy and density of H2O in the gas phase below.

[0067] gas phase volume fraction In two-phase calculations, this is a crucial parameter, which, by definition, is: For velocity heterogeneous models (i.e.) (It is also necessary to establish the gas phase volume fraction) The relationship with velocity. The most commonly used model is the drift flux model (DFM), originally established by Zuber and Findlay: Wherein: volume average velocity ; This refers to the gas phase drift velocity. As a distributed parameter, it is affected by local gas phase saturation, transverse velocity distribution in the pipeline, flow regime, well inclination, and flow direction. Combining (8) and (9), we can finally obtain: Distribution parameters and gas phase drift velocity have a decisive influence on the gas phase volume fraction, which ultimately has a significant impact on the distribution of pressure and temperature.

[0068] For wellbore diameters less than 0.35 m, this invention selects the drift flow model from Shi et al. (2005): Where: parameters , , , , , , ;parameter It is the gas phase volume fraction. The function, i.e. ; , and These are all empirical parameters; in this invention, we take... , , .

[0069] For wellbore diameters greater than 0.35 m, the drift flow model used in this invention is the Hibiki and Ishii (2003) model: in: The gas-liquid interfacial tension is used. The above model involves many property parameters, such as density, enthalpy, and saturated vapor pressure, which can be obtained by looking up tables (such as the NIST standard database).

[0070] As a further preferred embodiment, the calculation method for obtaining the temperature-pressure prediction results of the wellbore profile corresponding to each carbon dioxide content parameter point through a two-phase phase change flow model of a carbon dioxide-water system in a medium-high temperature geothermal well includes the following steps: S1: Input the bottom boundary conditions and model parameters for the two-phase phase change flow model of the carbon dioxide-water system in a medium-high temperature geothermal well: Input the first variable at the bottom of the well: Pressure at the bottom of the well casing. P d 、 Temperature at the bottom of the well casing T d 、 Total mass velocity Carbon dioxide mass fraction at the bottom of the well casing γ Input parameter: wellbore diameter d、 Wellbore length L、 Wellbore roughness ε、 Calculate the spacing dz; input the static temperature distribution of the wellbore profile. T wb and lumped heat transfer coefficient U .

[0071] S2: According to the formula , (here) Pick Calculate the partial voltage; if If the water pressure is within a single phase, the bottom phase can be determined to be single-phase; otherwise, the bottom phase can be determined to be two-phase. When the bottom phase is single-phase: based on the partial pressure of water: The density of water in the liquid phase is obtained by formula calculation. and internal energy The density of water in the gas phase and internal energy ;

[0072] Based on the partial pressure of CO2: The formula calculates the partial voltage as follows: Temperature is Enthalpy of gaseous CO2 under certain conditions Based on the enthalpy of the fluid at the bottom of the well: The temperature is obtained through formula calculation. Heat of solution of CO2 under certain conditions ;

[0073] Based on the bottom-hole liquid density: The density of dissolved CO2 is obtained by formula calculation. When the bottom of the well is in a single-phase state, the flash depth also needs to be calculated.

[0074] When the bottom of the well is in a two-phase state: according to the partial pressure of water: The density of water in the liquid phase is obtained by formula calculation. and internal energy The density of water in the gas phase and internal energy ;according to The formula is used to calculate the partial pressure of CO2. P CO2 Numerical value; according to Formula for calculating the mass fraction of CO2 in the liquid phase Numerical value; based on the voltage divider Temperature is Enthalpy of gaseous CO2 under certain conditions and density and temperature Heat of solution of CO2 under certain conditions , Formula for calculating the bottom-hole liquid phase enthalpy h l Numerical value; according to Formula for calculating the mass fraction of CO2 in the gas phase Numerical value; according to Formula calculation to obtain bottom hole gas phase thermal enthalpy h g Numerical value; according to Formula for calculating gas phase mass fraction x Numerical value; according to Formula for calculating total enthalpy h l Numerical value; according to Formula for calculating the bottom-hole liquid density ρ l Numerical value; based on gas phase density: Formula for calculating gas phase density ρ g Numerical value; according to Formula for calculating gas phase volume fraction α Numerical value; according to Formula for calculating liquid phase velocity u l Numerical value; according to Formula for calculating gas phase velocity u g Numerical value.

[0075] When the flash depth is less than the wellhead position, a two-phase phase change flow calculation is performed. The calculation process is as follows: S3: Calculate the target temperature T for the next point based on the current temperature at the previous point; set a slight temperature reduction. Set temperature target ( T last (The temperature calculated in the previous step).

[0076] S4: Set the gas phase fraction target for the next point based on the gas phase fraction at the previous point. x ; Set the gas phase mass fraction to increase by trace amounts Set gas phase fraction target ( x last (This refers to the gas phase fraction calculated in the previous step).

[0077] S5: According to Formula for calculating the partial pressure of water P H2O Numerical value; according to T , γ , x Determine the partial pressure of CO2 P CO2 Numerical value; according to The formula calculates the total pressure. P Numerical value; known density of liquid water , internal energy and viscosity The density of water in the gas phase , internal energy and viscosity ;according to Formula for calculating the mass fraction of CO2 in the liquid phase x l CO2 Numerical value; known partial pressure is Temperature is Enthalpy of gaseous CO2 under certain conditions and density The temperature is Heat of solution of CO2 under certain conditions Viscosity of CO2 in the gas phase ;according to Formula for calculating liquid phase enthalpy h l ;according to Formula for calculating the mass fraction of CO2 in the gas phase x g CO2 Numerical value; according to Formula for calculating gas phase enthalpy h g Numerical value; according to Formula for calculating gas phase viscosity μ g Numerical value; according to Formula for calculating total enthalpy h Numerical value; density of dissolved CO2 known. ;according to Formula for calculating liquid phase density ρl Numerical value; according to Formula for calculating gas phase density ρ g Numerical value; according to Formula for calculating gas phase volume fraction α Numerical value; according to Formula for calculating the density of the mixture ρ m Numerical value; according to Formula for calculating liquid phase velocity u l Numerical value; according to Formula for calculating gas phase velocity u g Numerical value; according to Formula to calculate the mixing speed u m Numerical value; according to Formula for calculating the mixed viscosity μ m Numerical values; known Reynolds number and wellbore friction coefficient. f ;according to Formula calculation to obtain the pressure reduction gradient caused by gravity P gr Numerical value; according to Formula calculation yields the pressure reduction gradient caused by wellbore friction. P fr Numerical value; according to The formula calculates the depth change dz value; the surrounding rock heat transfer is known. q ;according to Formula for calculating enthalpy h new Numerical value.

[0078] S6: Enthalpy h new The numerical value is compared with the enthalpy from the previous step for balance check. If they are inconsistent, return to step S4.

[0079] S7: Yes, continue to determine whether the accumulated dz is greater than the wellhead position z. wellhead If not, return to step S3.

[0080] S8: Yes, output the predicted temperature-pressure results of the wellbore profile corresponding to the carbon dioxide content parameter point: temperature value, pressure value, and gas mass fraction value of the wellbore profile.

[0081] As one implementation method, the specific steps for obtaining the average relative error-carbon dioxide content parameter point variation curve in step (S.4) are as follows: using the measured temperature-pressure results of the wellbore profile obtained in step (S.1) and the predicted temperature-pressure results of the wellbore profile obtained in step (S.3), respectively plot the monitoring and prediction comparison curves of fluid temperature and fluid pressure throughout the entire length of the wellbore; calculate the average relative error of temperature and the average relative error of pressure corresponding to each carbon dioxide content parameter point; plot the variation curves of the average relative error of temperature, the average relative error of pressure and the carbon dioxide content parameter points, thereby obtaining the average relative error-carbon dioxide content parameter point variation curve.

[0082] Example 1

[0083] The flowchart of the method for rapidly determining the CO2 content in a geothermal reservoir based on wellbore profile temperature and pressure testing in this embodiment is as follows: Figure 1 As shown. According to Figure 1 The process shown constructs a two-phase phase change flow model for a medium-high temperature geothermal wellbore CO2-H2O system, including the flash evaporation process. Based on this two-phase phase change flow model for a medium-high temperature geothermal wellbore CO2-H2O system, the calculation input parameters for a certain high-temperature geothermal field are shown in Table 1.

[0084] Table 1: Calculation Input Parameters for Two-Phase Flow Model in High-Temperature Geothermal Field Wellbores

[0085] parameter Value Well casing length (m) 435 Wellbore diameter (m) 0.22 Pressure at the bottom of the casing (MPa) 4.34 Temperature at the bottom of the casing (°C) 188.1 Mass rate (kg / s) 86.94 <![CDATA[CO2 mass fraction at the bottom position of the casing γ > Inversion Coefficient of friction of casing (m) <![CDATA[4.5×10 -5 ]]> The measured temperature-pressure results of the wellbore profile (i.e., the temperature-pressure data in the production capacity test) were provided by relevant experimental personnel. These personnel obtained the measured temperature-pressure results of the wellbore profile under both static and geothermal fluid release conditions. The specific steps for obtaining the measured temperature-pressure results of the wellbore profile under static conditions are as follows: The temperature and pressure sensors were calibrated and verified to ensure they were suitable for high-temperature and high-pressure conditions (i.e., suitable for systems where the temperature exceeds 100℃ and the partial pressure of carbon dioxide does not exceed 100 bar); temperature and pressure tests were conducted on the wellbore profile at equal intervals from the wellhead to the bottom and from the bottom to the wellhead, with a test interval of 0.5~1.5m. The test errors from the wellhead to the bottom and from the bottom to the wellhead were 0~5%, yielding the measured temperature-pressure results of the wellbore profile under static conditions. The specific steps for obtaining the measured temperature and pressure results of the wellbore profile under geothermal fluid venting conditions are as follows: The temperature and pressure sensors are calibrated and verified to ensure they are suitable for high-temperature and high-pressure conditions (i.e., suitable for systems where the temperature exceeds 100℃ and the carbon dioxide partial pressure does not exceed 100 bar); Temperature and pressure tests are conducted on the wellbore profile at equal intervals from wellhead to bottom and from bottom to wellhead under different flow rates (i.e., low, medium, and high flow rates) of the geothermal fluid venting conditions, with the test intervals being 0.5~1.5m. The test error from the bottom of the well to the wellhead is 0-5%. Flow control is achieved by adjusting the opening size of the wellhead valve (where, when the valve opening ratio is within 50%, the geothermal fluid can be controlled under low flow rate release; when the valve opening ratio is between 50% and 60%, the geothermal fluid can be controlled under medium flow rate release; and when the valve opening ratio is between 60% and 100%, the geothermal fluid can be controlled under high flow rate release). The measured temperature-pressure results of the wellbore profile under different flow rate geothermal fluid release conditions are obtained. Given a CO2 content trial-and-error analysis range of 0.000-0.040 (i.e., CO2 mass fraction of 0.0%-0.4%), the carbon dioxide content parameter points are selected. γ 0=0 γ 1 = 0.5% γ 2 = 1.0% γ 3=1.5%. The predicted temperature-pressure results at various carbon dioxide content parameter points were obtained based on the two-phase phase change flow model of the CO2-H2O system in medium-high temperature geothermal wells, and compared with the measured temperature-pressure results of the well profile. The results are as follows: Figure 2 As shown, monitoring and prediction curves of fluid temperature along the entire length of the wellbore are plotted (e.g., Figure 2 (as shown in Figure B) and the monitoring and prediction curves of fluid pressure throughout the entire wellbore (as shown in Figure B). Figure 2(As shown in Figure (A)). A monitoring and prediction comparison curve of fluid dryness along the entire length of the wellbore can also be plotted (e.g., Figure 2 (As shown in Figure (C)). Based on the formula for calculating the average relative error, the average relative error of temperature and the average relative error of pressure corresponding to each carbon dioxide content parameter point are calculated separately. Then, the variation curves of the average relative error of temperature and the average relative error of pressure relative to the carbon dioxide content parameter point are plotted, thus obtaining the variation curve of average relative error versus carbon dioxide content parameter point. The obtained variation curve of average relative error versus carbon dioxide content parameter point is shown below. Figure 3 As shown.

[0086] The formula for calculating the average relative error is as follows: In the formula: j is the number of samples.

[0087] Depend on Figure 2 , Figure 3 Data analysis shows that when the CO2 mass fraction is 0.011, the temperature-pressure prediction results obtained by the two-phase phase change flow model of the CO2-H2O system in the medium-high temperature geothermal well are very close to the measured temperature-pressure results of the well profile, indicating a good image fit. The average relative error of temperature and the average relative error of pressure in the well profile are the smallest, thus the CO2 content can be determined to be 1.1% (i.e., the CO2 mass fraction value corresponding to the lowest point in the curve of the average relative error versus the carbon dioxide content parameter).

[0088] The above description is merely a detailed explanation of preferred embodiments and principles of the present invention. For those skilled in the art, there may be changes in specific implementation methods based on the ideas provided by the present invention, and these changes should also be considered within the scope of protection of the present invention.

Claims

1. A method for determining the carbon dioxide content in a geothermal reservoir, characterized in that, Includes the following steps: (S.1) The measured temperature-pressure results of the wellbore profile were obtained under static and geothermal fluid venting conditions, respectively; (S.2) Establish a two-phase phase change flow model for the carbon dioxide-water system in medium- and high-temperature geothermal wells, including the flash evaporation process; (S.3) Based on the given carbon dioxide content trial-and-error analysis range, select several carbon dioxide content parameter points and calculate the temperature-pressure prediction results of the wellbore profile corresponding to each carbon dioxide content parameter point using the two-phase phase change flow model of the carbon dioxide-water system in the medium-high temperature geothermal wellbore described in step (S.2); wherein, the calculation method includes the following steps: S1: Input the bottom-hole boundary conditions and model parameters for the two-phase phase change flow model of the carbon dioxide-water system in a medium-high temperature geothermal well: Input the first variable at the bottom of the well: the pressure P at the bottom of the well casing. d Temperature T at the bottom of the well casing d Total mass velocity γ, the mass fraction of carbon dioxide at the bottom of the well casing; Input parameters: wellbore diameter d, wellbore length L, wellbore roughness ε, calculation spacing dz; S2: Determine whether the bottom phase is single-phase or two-phase, and update the fluid properties accordingly; S3: Calculate the target temperature T for the next point based on the current temperature setting at the previous point; S4: Set the gas phase fraction target x for the next point based on the gas phase fraction of the previous point; S5: Based on the temperature target T and the gas phase fraction target x, the two-phase phase change flow model of the carbon dioxide-water system in the medium and high temperature geothermal well is used to calculate the upward position increment dz corresponding to the temperature target T, and check whether the energy is balanced. S6: Determine whether the energy balance check has passed. If not, return to step S4. S7: Yes, continue to determine whether the accumulated dz is greater than the wellhead position z. wellhead If not, return to step S3; S8: Output the predicted temperature-pressure results of the wellbore profile corresponding to the carbon dioxide content parameter point; (S.4) Compare and analyze the measured temperature-pressure results of the wellbore profile obtained in step (S.1) with the predicted temperature-pressure results of the wellbore profile corresponding to each carbon dioxide content parameter point obtained in step (S.3) and calculate them to obtain the average relative error-carbon dioxide content parameter point change curve. The point with the smallest error in the obtained average relative error-carbon dioxide content parameter point change curve is the carbon dioxide content value.

2. The method for determining the carbon dioxide content in a geothermal reservoir according to claim 1, characterized in that, The specific steps for obtaining the measured temperature-pressure results of the wellbore profile under static conditions are as follows: Calibrate the testing instruments; Temperature and pressure tests were conducted on the wellbore profile at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead to the wellhead, respectively, to obtain the measured temperature-pressure results of the wellbore profile under static conditions.

3. The method for determining the carbon dioxide content in a geothermal reservoir according to claim 1, characterized in that, The specific steps for obtaining the measured temperature-pressure results of the wellbore profile under the described geothermal fluid venting condition are as follows: Calibrate the testing instruments; Temperature and pressure measurements of the wellbore profile were conducted at equal intervals from the wellhead to the bottom of the well and from the bottom of the wellhead under different flow rates of geothermal fluid. The measured temperature-pressure results of the wellbore profile under different flow rates of geothermal fluid were obtained.

4. The method for determining the carbon dioxide content in a geothermal reservoir according to claim 1, characterized in that, The one-dimensional vertical wellbore phase change flow control equations established in step (S.2) for the two-phase phase change flow model of the carbon dioxide-water system in the high-temperature geothermal well include: The boundary condition at the bottom of the well is: the total mass flow rate. The mass fraction of CO2 is γ, and the pressure is P. d The temperature is T d ; In equations (1) to (3): ρ l and ρ g These are the densities of the liquid and gas phases, respectively, in kg / m³. 3 ; u l and u g These are the velocities for the liquid phase and the gas phase, respectively, in m / s; This refers to the volume fraction of the gas phase. The total mass velocity is expressed in kg / s. and These are the mass velocities of the liquid phase and the gas phase, respectively, in kg / s; x l k and y g k These represent the mass fractions of H2O or CO2 in the liquid and gas phases, respectively. P is the total pressure. , and These are the partial pressures of H2O and CO2, respectively, in Pa. z represents the wellbore elevation, in meters (m). For mixed density, Unit: kg / m 3 ; g is the acceleration due to gravity. =9.8 m 2 / s; A is the area. Unit m 2 ; Let be the wellbore friction coefficient, when the Reynolds number is... hour, ,otherwise ; Well wall roughness, in meters (m); d is the diameter of the wellbore, in meters (m). u m The average velocity of the mixture, The unit is m / s; μ m The viscosity of the mixture, ,unit ; and These are the viscosities of the liquid phase and the gas phase, respectively. h m The enthalpy of the mixture, in J / kg. x represents the gas phase mass fraction; and These are the liquid phase and gas phase enthalpy, respectively, in J / kg; q represents the heat exchange rate per unit length between the wellbore and the surrounding rock, expressed in units of... , T and T wb These are the temperatures of the well fluid and the wellbore, respectively, in °C. The temperature of the wellbore is T. wb Obtained through static temperature testing; For lumped parameters, the unit is , ;in , The well diameter r1, cementing radius r2, and surrounding rock k T Cementing K cem Thermal conductivity and specific heat capacity c r The combined effect of time t.

5. The method for determining the carbon dioxide content in a geothermal reservoir according to claim 1, characterized in that, The specific steps for selecting the carbon dioxide content parameter point in step (S.3) are as follows: Given a carbon dioxide content trial-and-error analysis range of [X, Y], which is uniformly divided into N segments, N+1 carbon dioxide content parameter points γ are obtained. i And their values ​​are respectively: .

6. The method for determining the carbon dioxide content in a geothermal reservoir according to claim 1, characterized in that, In step S2, when the state of the bottom phase is determined to be single-phase, the variables to be determined after the fluid properties are updated are the total pressure P and the liquid phase enthalpy h. l Liquid phase velocity u l .

7. A method for determining the carbon dioxide content in a geothermal reservoir according to claim 1 or 6, characterized in that, In step S2, when the state of the bottom phase is determined to be single phase, the flash depth is calculated from the bottom of the well upwards after the fluid properties are updated.

8. The method for determining the carbon dioxide content in a geothermal reservoir according to claim 1, characterized in that, In step S2, when the state of the bottom-hole phase is determined to be two-phase, the variable to be determined after updating the fluid properties is the liquid phase density ρ. l Gas phase density ρ g Total pressure P, liquid phase heat enthalpy h l , gas phase thermal han h g Mass fraction of CO2 in the liquid phase x l CO2 Mass fraction of CO2 in the gas phase, y g CO2 Gas phase volume fraction α, gas phase mass fraction x, liquid phase velocity u l Gas phase velocity u g .

9. The method for determining the carbon dioxide content in a geothermal reservoir according to claim 1, characterized in that, The specific steps for obtaining the change curve of the average relative error-carbon dioxide content parameter points in step (S.4) are as follows: Using the measured temperature-pressure results of the wellbore profile obtained in step (S.1) and the predicted temperature-pressure results of the wellbore profile obtained in step (S.3), respectively plot the monitoring and prediction comparison curves of fluid temperature and fluid pressure throughout the entire length of the wellbore. Calculate the average relative error of temperature and the average relative error of pressure for each carbon dioxide content parameter point; Plot the curves of the variation of the average relative error of temperature, the average relative error of pressure, and the carbon dioxide content parameter points to obtain the curve of the variation of the average relative error versus the carbon dioxide content parameter points.

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