Hydrate inhibitor concentration prediction and injection method and system based on multiphase flow

Abstract

The present application relates to the field of deepwater oil and gas development, and particularly relates to a hydrate inhibitor concentration prediction and injection method and system based on multiphase flow. The method comprises the following steps: 1, basic data acquisition and processing; 2, dividing the space-time grid of the whole process of the wellbore-collecting pipeline in the production and transportation system; 3, judging the position of the unit cell; 4, solving the continuity equation and momentum equation of the gas phase-water phase-inhibitor phase in the unit cell and correcting to obtain the flow velocity, volume fraction distribution of different components and the pressure in the unit cell; 5, according to the position of the unit cell, solving the comprehensive heat transfer coefficient respectively above and below the mud line to obtain the temperature in the unit cell; 6, calculating the unit cell step by step along the downstream direction of the fluid flow until the offshore platform is calculated. The present application can accurately calculate the effective concentration of the inhibitor in the pipeline in real time, and adjust the inhibitor injection system in real time according to the inhibitor concentration, so as to realize safe and efficient development of deepwater oil and gas fields.

Description

TECHNICAL FIELD

[0001] The present application relates to the field of deepwater oil and gas development, and particularly relates to a hydrate inhibitor concentration prediction and injection method and system based on multiphase flow. BACKGROUND

[0002] In the process of deepwater oil and gas field exploitation and transportation, the low-temperature and high-pressure environment of the seabed is easy to make oil and gas generate hydrates in the development wellbore and long-distance seabed gathering pipeline. The generation and deposition of hydrates on the pipe wall are one of the main risks that cause flow obstacles, reduce production and transportation efficiency, and even cause production accidents. On site, the method of injecting thermodynamic inhibitors (such as methanol or ethylene glycol) is usually used to change the thermodynamic conditions of hydrates to prevent hydrate generation. The inhibitors are pumped into the underwater wellhead or seabed Christmas tree through the chemical agent injection pipeline, and then transported along the pipeline to the downstream with the formation production fluid (oil, gas, and water), and gradually diffused to the entire potential hydrate risk area. To reduce the number of umbilical cables and pump injection systems, the most economical and common arrangement is a single inhibitor injection point.

[0003] However, due to the long distance (several tens of kilometers or even hundreds of kilometers) of the pipeline, the complex structure, the large temperature difference of the environment, and other characteristics of the deepwater oil and gas production and transportation system, and the single injection point arrangement and the dramatic fluctuation of the formation water production rate, the inhibitors are continuously diluted, mixed, and consumed during transportation. The effective concentration distribution of the inhibitors is highly uneven, and it is difficult to accurately predict by existing means. In actual production, it is usually necessary to rely on over-injection of inhibitors to ensure safety, but this method not only increases the consumption and operation cost of the inhibitors, but also may cause environmental risks.

[0004] Most of the existing inhibitor concentration prediction methods rely on empirical formulas or simplified assumptions, such as considering the inhibitors as uniformly distributed in the long-distance pipeline, or ignoring the influence of gas-liquid two-phase flow characteristics and inhibitor gasification loss process on the inhibitor concentration. This kind of method is difficult to truly reflect the transportation, dilution, and redistribution rules of the inhibitors in the long-distance pipeline under the condition of multiphase flow, resulting in large deviation of the prediction results.

[0005] Therefore, it is urgent to propose a hydrate inhibitor concentration prediction and injection method and system based on multiphase flow to improve the utilization efficiency of the inhibitors and reduce the risk of hydrate flow obstacles. SUMMARY

[0006] The present application aims at the above-mentioned defects existing in the prior art, and provides a hydrate inhibitor concentration prediction and injection method and system based on multiphase flow.

[0007] The hydrate inhibitor concentration prediction and injection method based on multiphase flow provided by the present application has the technical scheme comprising the following steps:

[0008] Step one: basic data acquisition and processing, inputting the required basic data according to the early design data of the development well, and calculating the seawater and formation section environmental temperature profile;

[0009] Step two: dividing the wellbore-collecting pipeline whole-flow space and time grid in the production and transportation system, inputting the initial conditions and boundary conditions of the bottom of the oil and gas production wellbore, taking the point as the calculation starting point, and calculating along the fluid flow;

[0010] Step three: judging the unit body position, if the unit body is located upstream of the inhibitor injection point, the inhibitor loss amount in the unit body is 0; if the unit body is located downstream of the injection point, the inhibitor loss amount is calculated according to the temperature and pressure distribution in the unit body by using the Arrhenius function;

[0011] Step four: solving the continuity equation and momentum equation of the gas phase-water phase-inhibitor phase in the unit body and correcting, so as to obtain the flow velocity, volume fraction distribution of different components and the pressure in the unit body;

[0012] Step five: solving the comprehensive heat transfer coefficient according to the position of the unit body being located above and below the mud line, then solving the energy equation in the unit body and correcting, so as to obtain the temperature in the unit body; the temperature of the inhibitor injection point is obtained by solving the energy equation in the inhibitor injection pipeline, if the calculation unit body is located at the inhibitor injection point, the temperature of the fluid mixed by the inhibitor and the formation produced fluid is solved according to the specific heat of the fluid; otherwise, the influence of the inhibitor injection is not considered;

[0013] Step six: calculating the unit step by step along the fluid flow direction to the downstream until the calculation is completed to the offshore platform, the time step calculation is completed; the inhibitor concentration distribution, temperature and pressure field distribution in the whole production pipeline section are obtained, the relationship between the hydrate phase equilibrium curve and the temperature field is converted, the hydrate generation risk area is identified, and the “inhibitor concentration deficiency” or “inhibitor concentration excess” is calculated, so as to guide the real-time adjustment of the injection strategy by the inhibitor injection optimization system.

[0014] Preferably, in step one, the basic data comes from the development well design and production allocation system, including wellbore trajectory, well structure, formation information, fluid composition, environmental information, subsea pipeline structure and distribution, inhibitor composition and production data; among them, the environmental temperature profile is divided into seawater section and formation section. The seawater section is calculated using different empirical formulas according to the water depth distribution and different seasons, and the formation temperature is calculated based on the geothermal gradient.

[0015] Preferably, in step two, the grid space step size is d. z The time step is d t The model solution starts at the bottom of the well and is calculated along the flow trajectory towards the wellhead and then towards the sea level. Therefore, the boundary condition is the fluid state at the bottom of the well. The bottom pressure is calculated using the production capacity equation. Natural gas is produced at a constant rate, and the water-to-gas ratio is a fixed value, resulting in the apparent flow velocities of the gas and water phases. The boundary conditions used in the model calculation are expressed by equation (1):

[0016] (1);

[0017] The solution for the inhibitor pipeline temperature and pressure starts at sea level and is performed along the injection pipeline towards the injection point. Therefore, the boundary point temperature is the sea level temperature and the boundary point pressure is the injection pump pressure, as shown in equation (2).

[0018] (2);

[0019] In the formula, n This refers to a time point, which is dimensionless. p and p wf These represent the pressure distribution inside the pipeline and the bottom-of-well pressure, respectively, in Pa; A The effective cross-sectional area of ​​the pipe is m. 2 ; q g_wf and q l_wf For gas and liquid production under bottom hole conditions, m 3 ·s -1 ; v sg and v sl Apparent flow velocities for gas and liquid, respectively, in m / s. -1 ; E g and E l These are the volume fractions of gas and liquid, respectively, and are dimensionless. v g The actual gas flow rate is given in m·s. -1 ; p in and p pumpPa, is the pressure distribution in the inhibitor injection pipeline and the injection pump pressure; T sea Tf is the temperature of the formation produced water, °C. T in Tsp is the sea level temperature and the temperature in the inhibitor injection pipeline, °C.

[0020] The initial conditions are calculated for the initial opening well drainage stage, the production tubing and the transportation pipeline are half filled with the test fluid, the initial temperature of the wellbore and the pipeline is close to the ambient temperature, the initial pressure is calculated by the hydrostatic pressure, thus the calculated initial conditions of the wellbore and the transportation pipeline are characterized by equation (3), and the initial conditions of the inhibitor injection pipeline are characterized by equation (4):

[0021] (3),

[0022] (4),

[0023] In the equations, j is the dimensionless for solving the space node; T and T en Tf is the temperature of the formation produced water, °C. dz is the space step, m; p and p in and are the mixed fluid density and the inhibitor solution density, wherein p in are calculated by equation (5), kg·m -3 ; α is the well inclination angle, °;

[0024] (5),

[0025] In the equations, p in0 is the density of the solute in the inhibitor solution, kg·m -3 ; p l is the formation produced water density, kg·m -3 ; x in0 is the initial injection concentration of the inhibitor, kg·kg -1 .

[0026] In step three, in order to facilitate the coupling calculation of the inhibitor gasification loss in the multiphase flow model, the relational expression method is used for calculation, the function relationship of the alcohol inhibitor gasification loss, the steam pressure, the temperature and the inhibitor concentration in the aqueous solution is obtained by using the Arrhenius function model and the Vandermonde matrix fitting, see equations (6) and (7):

[0027] (6),

[0028] (7),

[0029] where, L M defined as the ratio of the amount of inhibitor volatilized into the gas phase to the amount of inhibitor in the water phase, is expressed by equation (8), kg-10 -3 m 3 :

[0030] (8).

[0031] Preferably, in step four, the mass conservation equations of gas-liquid two-phase and momentum conservation equations of gas-liquid mixture phase are established based on the drift-flux model, see equation (9):

[0032] (9),

[0033] where, p g is the gas density, kg-m -3 ; v g and v l are the gas and liquid velocities, m-s -1 ; x in is the inhibitor concentration, kg-m -3 ; q g and q l are the gas and water production rates, kg-s -1 m -1 ; q in is the inhibitor injection rate, kg-s -1 m -1 ; r loss is the inhibitor loss rate, kg-s -1 m -1 ; F r is the flow friction, Pa.

[0034] Preferably, the flow friction is an important parameter to describe the size of the resistance that the fluid receives in the flow, which is calculated using the full flow regime friction factor calculation model, see equations (10)-(12):

[0035] (10),

[0036] (11),

[0037] (12),

[0038] where a 1, a 2, b 1, b 2, c , d , t are obtained by fitting the experimental data of García at different gas volume fractions; Re is the gas apparent Reynolds number, dimensionless; the mass and momentum conservation equations are nonlinear, and it is difficult to obtain the analytical solution of the flow parameters. Meanwhile, this method involves long wellbore and transportation pipeline. Therefore, the finite difference method with high efficiency is used to solve equation (9) numerically.

[0039] Preferably, in step five, the heat transfer between the flow channel and the external environment is divided into two heat transfer processes, i.e., wellbore-production casing-cement sheath-formation and pipeline-insulation layer-seawater, and the total heat transfer coefficient of the composite medium is introduced U to to represent the unsteady conduction of heat; the total heat transfer coefficient is calculated by taking the heat transfer process of production tubing-annulus fluid-production casing-cement sheath-formation as an example, as shown in equation (17):

[0040] (17),

[0041] The total heat transfer coefficient is substituted into equations (18) and (19) to obtain the relaxation distance between the fluid and the environment at different positions;

[0042] (18),

[0043] (19),

[0044] wherein, U to is the total heat transfer coefficient of the fluid in the pipe and the environment, which is related to the structure of the wellbore and pipeline, the thermal resistance characteristics of the annulus fluid, the material of the oil casing, the cement sheath, and the insulation layer, and W·m -2 ·K -1 ; r out and r out-1 are the outer diameters of the production tubing and the production casing, respectively, m; r in and r in-1 are the inner diameters of the production tubing and the production casing, respectively, m; r w is the well diameter, m; ht , k t , k a , k cas , k cem respectively are the heat transfer coefficient of the fluid in the pipe, the thermal conductivity of the oil pipe, the thermal conductivity of the annular fluid, the thermal conductivity of the casing, the thermal conductivity of the cement sheath, W·m -1 ·K -1 ; T D is the transient heat transfer function, dimensionless; k e is the thermal conductivity of the formation, W·m -1 ·K -1 ; K’ is the relaxation distance of the fluid and the environment, m -1 .

[0045] The hydrate inhibitor concentration prediction and injection system based on multiphase flow mentioned in the application has the technical scheme that: it comprises an oil and gas gathering and transportation pipeline, an inhibitor injection nipple, a downhole safety valve, a downhole packer, a downhole monitoring system, a production casing and a production pipe are arranged under the formation, the downhole packer is arranged in the production casing under the well, the downhole safety valve and the inhibitor injection nipple are arranged at the underwater wellhead, the inhibitor injection nipple is connected with the oil and gas gathering and transportation pipeline outside, wherein, the system further comprises an inhibitor storage tank, an inhibitor injection pump, an inhibitor injection valve, an inhibitor flowmeter, an underwater wellhead flowmeter, an underwater wellhead temperature sensor, an underwater wellhead pressure sensor, an inhibitor injection pipeline, the underwater wellhead flowmeter, the underwater wellhead temperature sensor and the underwater wellhead pressure sensor are arranged on the oil and gas gathering and transportation pipeline, the inhibitor injection pipeline is arranged on one side of the inhibitor injection nipple, the other end of the inhibitor injection pipeline is connected with the inhibitor flowmeter and the inhibitor injection valve, and the inhibitor storage tank is connected with the inhibitor injection valve through the pipeline and the inhibitor injection pump.

[0046] Preferably, the inhibitor flowmeter, the inhibitor injection valve, the inhibitor injection pump, the downhole monitoring system, the underwater wellhead flowmeter, the underwater wellhead temperature sensor and the underwater wellhead pressure sensor are respectively connected with a data acquisition system through signal lines, the data acquisition system is connected with a data calculation and analysis system through signal lines, one port of the data calculation and analysis system is connected with an inhibitor injection control system through signal lines, and the other port is connected with a hydrate risk alarm system.

[0047] Compared with the prior art, the application has the beneficial effects as follows:

[0048] 1. The present invention has high prediction accuracy and strong applicability: The present invention comprehensively considers the gas-liquid two-phase flow characteristics in pipelines and the physical processes such as inhibitor transport, dilution and vaporization in deep-water oil and gas development. It breaks through the limitations of traditional methods that rely on empirical formulas or uniform distribution assumptions, making the prediction results closer to the actual working conditions and having stronger engineering applicability and reliability.

[0049] 2. The invention is highly operable: The invention designs an inhibitor-optimized injection system that can be adjusted in real time according to the inhibitor concentration distribution and hydrate risk zone. Compared with the traditional empirical method of over-injection of inhibitors, the inhibitor injection efficiency is high and the operation is simple.

[0050] 3. This invention achieves cost reduction and efficiency improvement: While ensuring flow safety, by quantitatively predicting the distribution of inhibitor concentration along the pipeline, the injection volume can be reasonably optimized, the inhibitor utilization efficiency can be improved, and the need for excessive injection can be reduced, thereby reducing operating costs and enhancing the value of engineering applications. Attached Figure Description

[0051] Figure 1 This is a schematic diagram of the prediction and optimization injection process of the present invention;

[0052] Figure 2 This is a schematic diagram of the prediction and injection system structure of the present invention;

[0053] Figure 3 The graph shows the distribution of the effective concentration of the inhibitor over time and tube length after the start of the injection.

[0054] Figure 4 The inhibitor injection rate was 9.9965 mg / L. 3 ·d -1 Distribution curve of hydrate risk zone within the entire pipeline section;

[0055] Figure 5 The distribution curve of hydrate risk zone in the entire pipeline after adjusting the inhibitor injection rate;

[0056] In the diagram above: 1. Inhibitor storage tank; 2. Inhibitor injection pump; 3. Inhibitor injection valve; 4. Inhibitor flow meter; 5. Data acquisition system; 6. Data calculation and analysis system; 7. Inhibitor injection control system; 8. Hydrate risk alarm system; 9. Subsea wellhead flow meter; 10. Subsea wellhead temperature sensor; 11. Subsea wellhead pressure sensor; 12. Inhibitor injection pipeline; 13. Signal line; 14. Oil and gas gathering pipeline; 15. Inhibitor injection sub-nozzle; 16. Downhole safety valve; 17. Formation; 18. Production tubing; 19. Production casing; 20. Annular fluid; 21. Downhole packer; 22. Downhole monitoring system; 23. Cement sheath. Detailed Implementation

[0057] The preferred embodiments of the present application will be described below with reference to the accompanying drawings. It should be understood that the preferred embodiments described herein are merely intended to illustrate and explain the present application, and are not intended to limit the present application.

[0058] Embodiment 1, refer to Figure 2 The present application refers to a hydrate inhibitor concentration prediction and injection system based on multiphase flow, which comprises an oil and gas gathering pipeline 14, an inhibitor injection nipple 15, a downhole safety valve 16, a downhole packer 21, a downhole monitoring system 22, a production casing 19 and a production tubing 18 installed below a formation 17, the downhole packer 21 installed in the production casing 19, the downhole safety valve 16 and the inhibitor injection nipple 15 installed at a subsea wellhead, and the inhibitor injection nipple 15 connected with the oil and gas gathering pipeline 14 outside. The system further comprises an inhibitor storage tank 1, an inhibitor injection pump 2, an inhibitor injection valve 3, an inhibitor flowmeter 4, a subsea wellhead flowmeter 9, a subsea wellhead temperature sensor 10, a subsea wellhead pressure sensor 11, and an inhibitor injection pipeline 12. The subsea wellhead flowmeter 9, the subsea wellhead temperature sensor 10, and the subsea wellhead pressure sensor 11 are installed on the oil and gas gathering pipeline 14. The inhibitor injection pipeline 12 is connected with the inhibitor injection valve 3 at one end and connected with the inhibitor flowmeter 4 and the inhibitor injection valve 3 at the other end. The inhibitor storage tank 1 is connected with the inhibitor injection valve 3 through a pipeline and the inhibitor injection pump 2.

[0059] The inhibitor flowmeter 4, the inhibitor injection valve 3, the inhibitor injection pump 2, the downhole monitoring system 22, the subsea wellhead flowmeter 9, the subsea wellhead temperature sensor 10, and the subsea wellhead pressure sensor 11 are connected with a data acquisition system 5 through signal lines 13. The data acquisition system 5 is connected with a data calculation and analysis system 6 through signal lines 13. One port of the data calculation and analysis system 6 is connected with an inhibitor injection control system 7 through signal lines 13, and the other port is connected with a hydrate risk alarm system 8.

[0060] In the process of deepwater oil and gas production, the production fluid flows into the production tubing 18 through the reservoir perforation, moves upward to the underwater wellhead and is transported to the platform by the subsea gathering pipeline 14, the downhole monitoring system 22 can collect the data of the bottom hole temperature, pressure and flow rate in the production process as the initial and boundary conditions for the calculation of the application, the data collected by the underwater wellhead temperature sensor 10 and the underwater wellhead flowmeter 9 can provide real-time correction data for the multiphase flow model established by the application. The hydrate inhibitor on the offshore platform is stored in the inhibitor storage tank 1, and is injected into the wellbore through the inhibitor injection pump 2, the inhibitor injection valve 3, the inhibitor flowmeter 4, the inhibitor injection pipeline 12 and the inhibitor injection nipple 15, and is carried downstream with the fluid to fill the entire hydrate risk zone. Once it is found through calculation that the hydrate risk appears due to insufficient inhibitor concentration, the hydrate risk warning system 8 and the inhibitor injection control system 7 will be triggered, and the operator must adjust the inhibitor injection rate according to the "inhibitor concentration shortage" control of the inhibitor injection pump 2 and the inhibitor injection valve 3 to make the entire production pipe section out of the hydrate formation risk zone; once it is found through calculation that there is no hydrate risk zone due to the richness of the inhibitor, the inhibitor injection rate is adjusted according to the "excessive inhibitor concentration" control of the inhibitor injection pump 2 and the inhibitor injection valve 3 under the condition of ensuring the safety margin, and the utilization efficiency of the inhibitor is improved.

[0061] Reference Figure 1 The application refers to a hydrate inhibitor concentration prediction and injection method based on multiphase flow, which comprises the following steps:

[0062] Step one: basic data acquisition and processing, input the required basic data according to the pre-design data of the development well, and calculate the seawater and formation temperature profile;

[0063] Step two: divide the space and time grid of the whole flow process of the wellbore-gathering pipeline in the production and transportation system, input the initial conditions and boundary conditions of the bottom of the oil and gas production wellbore, take this point as the starting point of calculation, and calculate along the fluid flow;

[0064] Step three: judge the position of the unit cell, if it is located upstream of the inhibitor injection point, the inhibitor loss in the unit cell is 0; if it is located downstream of the injection point, calculate the inhibitor loss according to the temperature and pressure distribution in the unit cell by using the Arrhenius function;

[0065] Step four: solve the continuity equation and momentum equation of the gas phase-water phase-inhibitor phase in the unit cell and correct them to obtain the flow rate, volume fraction distribution of different components and the pressure in the unit cell;

[0066] Step five: the overall heat transfer coefficient is solved according to the position of the unit body on the mud line, and then the energy equation in the unit body is solved and corrected to obtain the temperature in the unit body; the temperature at the inhibitor injection point is obtained by solving the energy equation in the inhibitor injection pipeline, and if the calculation unit is located at the inhibitor injection point, the temperature of the mixed fluid after the inhibitor and the formation produced fluid are solved according to the specific heat of the fluid; otherwise, the influence of the inhibitor injection is not considered;

[0067] Step six: the calculation is carried out step by step along the downstream of the fluid flow direction, until the offshore platform is calculated, and the time step calculation is completed; the inhibitor concentration distribution, temperature and pressure field distribution in the whole production pipeline are obtained, which are converted into the relationship between the hydrate phase equilibrium curve and the temperature field, the hydrate formation risk area is identified, and the "inhibitor concentration shortage" or "inhibitor concentration excess" is calculated, thereby guiding the real-time adjustment of the injection strategy of the inhibitor injection optimization system.

[0068] In step one, the basic data is derived from the development well design and the production allocation system, including well trajectory, well structure, formation information, fluid composition, environmental information, sea pipe structure and distribution, inhibitor composition and production data; wherein the environmental temperature profile is divided into seawater section and formation section, the seawater section is calculated according to the water depth distribution and different seasons by using different empirical formula, and the formation temperature is calculated based on the geothermal gradient.

[0069] In step two, the grid space step is d z , and the time step is d t ; the starting point of the model solution is the bottom of the well, and the calculation is carried out along the flow trajectory to the wellhead and then to the sea level, so the boundary condition is the fluid state at the bottom of the well, the bottom hole pressure is calculated by using the productivity equation, the natural gas is produced at a constant rate, and the water-gas ratio is a fixed value, so the apparent flow rate of gas and water two-phase is obtained; the boundary condition used in the model calculation is represented by formula (1):

[0070] (1)

[0071] The starting point of the inhibitor pipeline temperature and pressure solution is the sea level, and the calculation is carried out along the injection pipeline to the injection point, so the boundary point temperature is the sea level temperature, and the boundary point pressure is the injection pump pressure, as shown in formula (2):

[0072] (2)

[0073] In the formula, n is the time node, dimensionless; p and p wf are the pressure distribution in the pipeline and the bottom hole pressure, respectively, Pa; A is the effective cross-sectional area of the pipeline, m 2 ; q g_wfand q l_wf m is the gas and liquid production rate at the well bottom conditions, m 3 ·s -1 ; v sg and v sl Vgand V1are the superficial velocities of gas and liquid, respectively, m·s -1 ; E g φgand φ1are the volume fractions of gas and liquid, respectively, dimensionless; E l φgand φ1are the volume fractions of gas and liquid, respectively, dimensionless; v g vgis the real velocity of gas, m·s -1 ; p in P1is the pressure in the inhibitor injection pipeline, Pa; p pump P1is the pressure in the inhibitor injection pipeline, Pa; T sea T1is the temperature in the inhibitor injection pipeline, °C. T in T1is the temperature in the inhibitor injection pipeline, °C.

[0074] The initial conditions for the calculation are the initial drainage stage, the production tubing 18 and the transport pipeline are half full of test fluid, the initial temperature of the wellbore and the pipeline is close to the ambient temperature, and the initial pressure is calculated using the hydrostatic column pressure, so the initial conditions for the calculation of the wellbore and the transport pipeline are characterized by equation (3), and the initial conditions for the calculation of the inhibitor injection pipeline are characterized by equation (4):

[0075] (3),

[0076] (4),

[0077] wherein, j is the spatial node, dimensionless; T and T en T1and T2are the temperatures of the mixed fluid in the flow channel and the environment, respectively, °C; dz Δx is the spatial step, m; p and p in ρ1and ρ2are the densities of the mixed fluid and the inhibitor solution, respectively, wherein p in is calculated using equation (5), kg·m -3 ; α is the inclination angle, °;

[0078] (5),

[0079] wherein,p in0 ρs is the density of the inhibitor solution, kg·m -3 ; p l ρw is the density of the formation produced water, kg·m -3 ; x in0 ρ0 is the initial injection concentration of the inhibitor, kg·kg -1 .

[0080] In step three, in order to facilitate the coupling calculation of the inhibitor gasification loss in the multiphase flow model, the relationship method is used for calculation, and the function relationship between the alcohol inhibitor gasification loss and the vapor pressure, temperature and inhibitor concentration in the aqueous solution is obtained by using the Arrhenius function model and the Vandermonde matrix fitting, see formula (6), (7):

[0081] (6),

[0082] (7),

[0083] In the formula, L M ρg is the gas density, kg·m -3 ·m 3 ; the values of the remaining correlation coefficients A 、 B 、 C 、 D can be referred to Table 1:

[0084] (8).

[0085] Table 1 Empirical parameters related to formula (7)

[0086]

[0087] In step four, the mass conservation equation of gas-liquid two-phase and the momentum conservation equation of gas-liquid mixed phase are established based on the drift flow model, see formula (9), it needs to be specially pointed out that although the inhibitor is not considered as a separate phase, the mass conservation relationship of the inhibitor needs to be used to determine the inhibitor concentration, therefore the inhibitor also needs to give the continuity equation;

[0088] (9),

[0089] In the formula, p g ρg is the gas density, kg·m -3 ; v g and vl The velocities of the gas and liquid are respectively, in m·s. -1 ; x in The concentration of the inhibitor is kg·m -3 ; q g and q l Gas production rate and water production rate, respectively, kg·s -1 ·m -1 ; q in The rate of inhibitor injection is expressed in kg·s. -1 ·m -1 ; r loss The rate of inhibitor loss is expressed in kg·s. -1 ·m -1 ; F r The flow friction is Pa.

[0090] Preferably, flow friction is an important parameter describing the resistance experienced by a fluid during flow. It is calculated using a full-flow-mode friction coefficient calculation model, as shown in equations (10)-(12):

[0091] (10)

[0092] (11),

[0093] (12)

[0094] In the formula a 1, a 2, b 1, b 2, c , d , t All data were obtained by fitting García experimental data at different gas volume fractions, as shown in Table 2. Re is the apparent Reynolds number for the gas, which is dimensionless;

[0095] Table 2. Coefficients under different porosities a 1. a 2. b 1. b 2. c , d and t

[0096]

[0097] Further, the mass conservation and momentum conservation equations are nonlinear, and it is difficult to obtain the analytical solution of the flow parameters. Meanwhile, the method involves long wellbore and transportation pipeline, and the calculation engineering quantity is large. Therefore, the finite difference method with high efficiency is used to solve equation (9) numerically. The gas, liquid, and inhibitor continuity equations can be discretized into equations (13)-(15), and the mixed phase momentum equation can be discretized into equation (16).

[0098] (13),

[0099] (14),

[0100] (15),

[0101] (16)。

[0102] Preferably, in step five, the heat transfer between the flow channel and the external environment is divided into two heat transfer processes according to the position, i.e., wellbore-production casing 19-cement sheath 23-formation 17 and pipeline-insulation layer-seawater, and the total heat transfer coefficient of the composite medium is introduced to represent the unsteady conduction of heat U to ; the total heat transfer coefficient is calculated by taking the heat transfer process of production tubing 18-annulus fluid 20-production casing 19-cement sheath 23-formation 17 as an example, as shown in equation (17):

[0103] (17),

[0104] The total heat transfer coefficient is substituted into equations (18) and (19) to obtain the relaxation distance between the fluid and the environment at different positions.

[0105] (18),

[0106] (19),

[0107] In the equations, U to is the total heat transfer coefficient of the fluid in the pipe and the environment, which is related to the structure of the wellbore and the pipeline, the thermal resistance characteristics of the annulus fluid, the material of the tubing and casing, the material of the cement sheath and the insulation layer, and W·m -2 ·K -1 ; r out and r out-1 are the outer diameters of production tubing 18 and production casing 19, respectively, m; r in and r in-1 are the inner diameters of production tubing 18 and production casing 19, respectively, m;r w is the wellbore radius, m; h t , k t , k a , k cas , k cem is the convection heat transfer coefficient of the fluid in the pipe, W·m -1 ·K -1 ; T D is the transient heat transfer function, dimensionless; k e is the formation thermal conductivity, W·m -1 ·K -1 ; K’ is the relaxation distance of the fluid to the environment, m -1 .

[0108] Further, the relaxation distance is substituted into equation (20) to obtain the temperature of the mixed fluid in the unit body;

[0109] (20)

[0110] wherein, C pg and C pl are the specific heat capacities of the gas and liquid at constant pressure, J·kg -1 ·K -1 ; μ J-T is the Joule-Thomson coefficient of the natural gas, which can be solved according to the BWRS equation, K·Pa -1 ; h e is the formation inflow enthalpy, J·kg -1 ; Q F is the frictional heat between the fluid and the pipe wall, J·s -1 ·m -1 ; Q in is the heat change caused by the inhibitor injection, J·s -1 ·m -1 .

[0111] Similarly, the temperature field equation of the inhibitor in the inhibitor injection pipeline can also be obtained by substituting into equation (21);

[0112] (21)

[0113] wherein, C pin Cp is the specific heat capacity at constant pressure of the injected inhibitor solution, J·kg -1 ·K -1 ; v in V is the fluid velocity in the inhibitor injection pipeline, m·s -1 ; K in ’ L is the inhibitor and ambient relaxation distance, m -1 ; A in A is the cross-sectional area of the inhibitor injection pipeline, m 2 ; Q Fin Q is the frictional heat between the inhibitor and the injection pipeline wall, J·s -1 ·m -1 ;

[0114] (22),

[0115] wherein, C pin0 Cp is the specific heat capacity at constant pressure of the injected inhibitor solution, J·kg -1 ·K -1 .

[0116] Further, in step six, the method for calculating the hydrate phase equilibrium curve according to the inhibitor concentration and the temperature-pressure field distribution is prior art and very mature, and thus will not be described here. If there is a hydrate risk zone at a position, a safety margin of 5℃ is taken to obtain the highest phase equilibrium temperature for the position to be out of the risk zone, the required inhibitor concentration is back-calculated, and the "inhibitor concentration deficit" is calculated; if there is no hydrate risk zone at a position and the safety margin is exceeded, it indicates that the inhibitor concentration at the position is excessive, the required inhibitor concentration is back-calculated, and the "inhibitor concentration excess" is calculated.

[0117] The internal experiment is as follows: the method of the application is applied to obtain the inhibitor concentration distribution and the hydrate generation region distribution under the action of the inhibitor in the production process of a case well of a deepwater gas field. The water depth of the case well is 1000 m, the well depth is 7480 m, the length of the subsea gathering pipeline is 3000 m, the gas flow is 380,000 m3 / d, and the reservoir pressure is 28.5 MPa. The gathering pipeline and the wellbore trajectory are as follows: 0-1000 m is the seawater section; 1000-3000 m is the subsea gathering pipeline section; and 3000-7480 m is the production well. The methanol inhibitor is injected from the offshore platform through an inhibitor injection pump 2, the injection pump pressure is 20 MPa, an inhibitor injection nipple 15 is located 400 m below the mud line, the platform injection inhibitor concentration is 100 wt%, and the injection rate is 9.9965 m 3 ·d -1.

[0118] Figure 3 The distribution curve of the inhibitor concentration along the pipeline after the start of methanol injection. The concentration of 100wt% methanol mixed with produced water in the flow channel decreases to 38.29wt%, and gradually decreases along the flow direction affected by the gasification loss. With the increase of injection time, the methanol concentration tends to be stable distribution. Based on the dynamic distribution of inhibitor concentration with time and position, the hydrate phase equilibrium curve under the influence of different concentrations of methanol is obtained, and combined with the temperature field in the pipe, the hydrate formation region is obtained, see Figure 4 ; the thermodynamic inhibitor changes the phase equilibrium condition of the hydrate, which makes the phase equilibrium curve move and reduces the hydrate formation region. As the methanol flows in the pipe to be full, the hydrate formation region gradually decreases, but Figure 4 It can be seen that even if the methanol is full in the whole pipe section, there is still a risk zone of hydrate formation, which cannot eliminate the risk of hydrate, and the hydrate risk alarm system starts, which needs to adjust the inhibitor injection strategy in time.

[0119] The present application controls the inhibitor injection pump 2 and the inhibitor injection valve 3 through the inhibitor injection control system 7, adjusts the inhibitor injection rate from 9.9965m 3 ·d -1 to 19.9998m 3 ·d -1 , and injects into the wellbore through the inhibitor injection pipeline 12 and the inhibitor injection short section 15, as shown in Figure 5 , the whole pipe section is not located in the hydrate formation region from the start of injection to 240min, and meets the demand of safety margin, so as to improve the utilization efficiency of methanol inhibitor while ensuring to avoid the risk of hydrate.

[0120] The above is only part of the preferred embodiments of the present application, and any skilled person in the art can modify the above described technical solutions or modify them into equivalent technical solutions. Therefore, the corresponding simple modification or equivalent transformation according to the technical solutions of the present application is within the scope of protection claimed by the present application.

Claims

1. A method for predicting and injecting hydrate inhibitor concentration based on multiphase flow, characterized by The method comprises the following steps: Step 1: basic data acquisition and processing, inputting the basic data required by the calculation according to the design data of the development well in the early stage, and calculating the seawater and formation environmental temperature profile; Step 2: dividing the space-time grid of the whole flow process of the wellbore-collecting pipeline in the production and transportation system, inputting the initial conditions and boundary conditions of the bottom of the oil and gas production wellbore, taking the point as the starting point of the calculation, and calculating along the fluid flow; Step 3: judging the position of the unit body, if it is located upstream of the inhibitor injection point, the inhibitor loss in the unit body is 0; if it is located downstream of the injection point, the inhibitor loss is calculated according to the temperature and pressure distribution in the unit body by using the Arrhenius function; Step 4: solving the continuity equation and momentum equation of the gas phase-water phase-inhibitor phase in the unit body and correcting, obtaining the flow velocity and volume fraction distribution of different components and the pressure in the unit body; Step 5: solving the comprehensive heat transfer coefficient according to the position of the unit body being located above and below the mud line, then solving the energy equation in the unit body and correcting, obtaining the temperature in the unit body; the temperature of the inhibitor injection point is obtained by solving the energy equation in the inhibitor injection pipeline, if the calculation unit is located at the inhibitor injection point, the temperature of the mixed fluid of the inhibitor and the formation produced fluid is solved according to the specific heat of the fluid; otherwise, the influence of the inhibitor injection is not considered; Step 6: calculating the unit step by step along the fluid flow direction to the downstream until the calculation is completed to the offshore platform, the time step is completed; the inhibitor concentration distribution, temperature and pressure field distribution in the whole production pipeline are obtained, the relationship between the hydrate phase equilibrium curve and the temperature field is converted, the hydrate formation risk area is identified, and the "inhibitor concentration deficiency" or "inhibitor concentration excess" is calculated, thereby guiding the real-time adjustment of the injection strategy of the inhibitor injection optimization system.

2. The method of claim 1, wherein: In step 1, the basic data is derived from the development well design and the production allocation system, including the well trajectory, the well structure, the formation information, the fluid components, the environmental information, the structure and distribution of the marine pipeline, the inhibitor components and the production data; wherein, the environmental temperature profile is divided into seawater section and formation section, the seawater section is calculated according to the water depth distribution and different seasons by using different empirical formulas, and the formation temperature is calculated based on the geothermal gradient.

3. The hydrate inhibitor concentration prediction and injection method based on multiphase flow according to claim 2, characterized in that: In In step two, the grid space step is d z , and the time step is d t . The starting point of the model solution is the well bottom, and the calculation is performed along the flow trajectory to the wellhead and then to the sea level, so the boundary condition is the fluid state at the well bottom, the well bottom pressure is calculated by using the productivity equation, the natural gas is produced at a constant rate, and the water-gas ratio is a fixed value, so the apparent flow rate of the gas-water two-phase flow is obtained; the boundary condition used in the model calculation is represented by formula (1): （1）； The starting point of the inhibitor pipeline temperature and pressure solution is the sea level, and the calculation is performed along the injection pipeline to the injection point, so the boundary point temperature is the sea level temperature, and the boundary point pressure is the injection pump pressure, as shown in formula (2): （2）； wherein n t is a time node, dimensionless; p and p wf These represent the pressure distribution inside the pipeline and the bottom-of-well pressure, respectively, in Pa; A The effective cross-sectional area of ​​the pipe is m. 2 ; q g_wf and q l_wf For gas and liquid production under bottom hole conditions, m 3 ·s -1 ; v sg and v sl Apparent flow velocities for gas and liquid, respectively, in m / s. -1 ; E g and E l These are the volume fractions of gas and liquid, respectively, and are dimensionless. v g The actual gas flow rate is given in m·s. -1 ; p in and p pump The pressure distribution within the inhibitor injection pipeline and the injection pump pressure, in Pa; T sea and T in The temperature at sea level and the temperature inside the inhibitor injection pipeline are given in °C.

4. The hydrate inhibitor concentration prediction and injection method based on multiphase flow according to claim 3, characterized in that: The initial conditions for the calculation are the initial opening well drainage stage, the semi-full test fluid in the production tubing and the transport pipeline, the initial temperature of the wellbore and the pipeline is close to the ambient temperature, and the initial pressure is calculated by the hydrostatic pressure. Therefore, the initial conditions of the wellbore and the transport pipeline are characterized by formula (3), and the initial conditions of the inhibitor injection pipeline are characterized by formula (4): （3）， （4）， wherein, j is the dimensionless solution of the space node; T and T en are the temperature of the mixed fluid in the flow channel and the ambient temperature, respectively, °C; dz is the space step, m; ρ and ρ in are the density of the mixed fluid and the density of the inhibitor solution, respectively, wherein ρ in is calculated using equation (5), kg·m -3 ; α is the inclination angle, °; （5）， wherein ρ in0 is the density of the inhibitor solution, kg m -3 ; ρ l is the density of the produced water from the formation, kg m -3 ; x in0 is the initial concentration of the inhibitor injected, kg kg -1 .

5. The hydrate inhibitor concentration prediction and injection method based on multiphase flow according to claim 4, characterized in that: In step three, in order to facilitate the coupling calculation of the inhibitor gasification loss amount in the multiphase flow model, the relationship formula method is used for calculation, and the Arrhenius function model and the Vandermonde matrix are used to fit the functional relationship between the alcohol inhibitor gasification loss amount, the vapor pressure, the temperature and the inhibitor concentration in the aqueous solution, as shown in formula (6) and (7): （6）， （7）， In the formula, L M defined as the ratio of the amount of inhibitor volatilized into the gas to the amount of inhibitor in the water phase, is expressed by Equation (8), kg-10 -3 ·m 3 ; （8）。 6. The hydrate inhibitor concentration prediction and injection method based on multiphase flow according to claim 5, characterized in that: In step four, the mass conservation equation of the gas-liquid two-phase and the momentum conservation equation of the gas-liquid mixed phase are established based on the drift flow model, as shown in formula (9): （9）， where ρ g is the gas density, kg·m -3 ; v g and v l are the gas and liquid velocities, respectively; x in is the inhibitor concentration, kg·m -3 ; q g and q l are the gas and water production rates, respectively, kg·s -1 ·m -1 ; q in is the inhibitor injection rate, kg·s -1 ·m -1 ; r loss is the inhibitor loss rate, kg·s -1 ·m -1 ; F r is the flow friction, Pa.

7. The hydrate inhibitor concentration prediction and injection method based on multiphase flow according to claim 6, characterized in that: The flow friction is an important parameter for describing the resistance of fluid in flow, which is calculated by using the full flow type domain friction coefficient calculation model, as shown in formula (10)-(12): （10）， （11）， （12）， wherein a 1, a 2, b 1, b 2, c , d , t are obtained from the fitting of the experimental data of García at different gas volume fractions; Re is the gas apparent Reynolds number, dimensionless; the mass and momentum conservation equations are strongly nonlinear, and it is difficult to obtain the analytical solution of the flow parameters. Meanwhile, this method involves long distance wellbore and transportation pipeline, and the finite difference method with high efficiency is used to solve equation (9).

8. The hydrate inhibitor concentration prediction and injection method based on multiphase flow according to claim 7, characterized in that: In In step five, the heat transfer between the flow channel and the external environment is divided into two processes according to the location, namely, wellbore-production casing (19)-cement sheath (23)-formation (17) and pipe-insulation layer-seawater, and the total heat transfer coefficient of the composite medium is introduced U to The unsteady conduction of heat is characterized; the total heat transfer coefficient is calculated by taking the heat transfer process of production tubing (18)-annulus fluid (20)-production casing (19)-cement sheath (23)-formation (17) as an example, as shown in equation (17): （17）， The total heat transfer coefficient is substituted into formula (18) and (19) to obtain the relaxation distance between the fluid and the environment at different positions; （18）， （19）， In the formula, U to Ktot is the total heat transfer coefficient of the fluid in the pipe and the environment, which is related to the wellbore and pipe structure, annular fluid thermal resistance characteristics, oil casing material, cement sheath and insulation material, W·m -2 ·K -1 ; r out Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; r out-1 Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; r in Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; r in-1 Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; r w Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; h t Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; k t Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; k a Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; k cas Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; k cem Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; -1 ·K -1 Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; T D Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; k e Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; -1 ·K -1 Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m; K’ Dop and Dcs are the outer diameters of the production tubing and the production casing, respectively, m -1 .

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