Method for predicting shaft sulfur deposition amount of sulfur-containing gas well

Abstract

The invention discloses a method for predicting the shaft sulfur deposition amount of a sulfur-containing gas well, and belongs to the technical field of oil and gas field development. The method comprises the following steps that S1, basic parameters of the sulfur-containing gas well are collected, and the temperature and pressure of any position in a shaft are calculated; s2, establishing a shaft three-dimensional model, dividing well sections, forming a sulfur inlet and a gas inlet at a shaft bottom inlet, and then performing grid division; s3, establishing a numerical simulation control equation; s4, setting initial and boundary conditions, and performing unsteady-state numerical simulation by applying CFD (Computational Fluid Dynamics) software; s5, the amount of solid-phase sulfur generated by each well section is obtained according to the result of the unsteady-state numerical simulation, and the sulfur concentration of the well mouth is obtained through calculation; and S6, detecting the actual value of the sulfur-containing concentration of the wellhead of the sulfur-containing gas well, comparing the actual value with the value obtained in the step S5, and according to a comparison result, repeating the steps S4 to S6 or directly obtaining the sulfur deposition amount of the sulfur-containing gas well. The method can obtain the distribution condition of the sulfur deposition amount in the shaft, and accurately predicts the sulfur deposition amount in the shaft.

Description

Technical Field

[0001] The invention relates to the technical field of oil and gas field development, and in particular to a method for predicting sulfur deposition in a wellbore of a sulfur-containing gas well. Background Art

[0002] At present, the research on sulfur-containing gas wells in China is still in the initial exploration stage. 2 With the further exploitation of gas wells and the change of wellbore temperature and pressure, the liquid and solid sulfur in natural gas will be deposited in the wellbore, which will reduce the flow channel of natural gas in the wellbore and even block the wellbore, thus reducing the production of gas wells. In addition, the acidic gas in sour natural gas will also corrode pipelines and downhole tools, thus affecting the safe production of gas wells.

[0003] The elemental sulfur deposited in the gas wellbore mainly comes from H 2 S, which reacts with oxidizing gases in natural gas or salts in formation water under high temperature and high pressure in the reservoir to generate elemental sulfur. At high temperatures, sulfur exists in natural gas in a gaseous state. On the one hand, as the gas well is mined, the formation temperature and pressure change, and some elemental sulfur will precipitate in the production section of the wellbore; on the other hand, as the sour natural gas is lifted, the temperature and pressure continue to drop, and sulfur deposition will occur at all depths of the wellbore. Therefore, how to simulate the deposition of sulfur in the wellbore as the temperature changes and accurately predict the amount of sulfur deposition in sour gas wells is a technical problem that needs to be solved urgently. Summary of the invention

[0004] In view of the above problems, the present invention aims to provide a method for predicting sulfur deposition in the wellbore of a sour gas well.

[0005] The technical solution of the present invention is as follows: A method for predicting sulfur deposition in a sour gas wellbore comprises the following steps: S1: Collect basic parameters of sour gas wells and calculate the temperature and pressure at any location in the wellbore; S2: establishing a three-dimensional wellbore model of the sour gas well, dividing the well sections, setting a sulfur inlet and a gas inlet at the well bottom entrance, and then performing grid division to obtain a gridded three-dimensional wellbore model; S3: Taking sulfur and air as experimental objects, establish the control equations of numerical simulation; S4: setting initial conditions and boundary conditions, and performing unsteady-state numerical simulation on the gridded wellbore three-dimensional model using CFD software according to the temperature and pressure obtained in step S1 and the control equation established in step S3; S5: according to the result of the non-steady-state numerical simulation in step S4, the amount of solid sulfur generated in each well section of the sour gas well is obtained, and the sulfur concentration at the wellhead is calculated; S6: Detecting the actual sulfur concentration value at the wellhead of the sulfur-containing gas well, and comparing the actual sulfur concentration value with the sulfur concentration at the wellhead obtained in step S5: If the error between the two is not within the error threshold, the boundary condition in step S4 is changed and steps S4-S6 are repeated; If the error between the two is within the error threshold, the amount of solid sulfur obtained in step S4 is the amount of sulfur deposition in the sour gas well.

[0006] Preferably, in step S1, the basic parameters include wellbore structure data, wellhead pressure, wellhead temperature, daily liquid production, water content, gas-liquid ratio, tubing diameter and reservoir temperature.

[0007] Preferably, in step S1, when calculating the temperature and pressure at any position in the wellbore, the bottom of the well is taken as the coordinate origin, vertically upward is the positive coordinate of the z-axis, and a microelement with a length of dz is taken in the oil pipe. The temperature at the outlet of each microelement is calculated by the following formula: Where: T fout is the fluid temperature at the outlet of each unit, °C; T eout is the formation temperature at the outlet of each unit, °C; A is the relaxation factor, dimensionless; z is the measured depth from a certain point in the wellbore to the bottom of the well, m; z in is the measured depth from the entrance of the unit to the bottom of the well, m; g is the acceleration of gravity, m / s 2 ; C pm is the constant pressure specific heat capacity of the fluid, J / (kg·℃); C Jm is the Joule-Thomson coefficient, °C / Pa; p is the pressure, Pa; v m is the apparent velocity of the mixture, m / s; g T is the geothermal gradient, K / m; f g is the gas friction coefficient, dimensionless; D is the pipe diameter, m; T fin is the fluid temperature at the unit inlet, °C; T ein is the formation temperature at the entrance of the unit, °C; The wellbore pressure is calculated by the following formula: (2) Where: ρ m is the density of the mixture, kg / m 3 ; θ is the well inclination angle, °; f is the friction coefficient, dimensionless.

[0008] Preferably, the relaxation factor is calculated by the following formula: (3) Where: r to is the outer diameter of the casing, m; U to is the total heat transfer coefficient, W·(m·℃); k e is the formation thermal conductivity, W·(m·℃); Q mis the mass flow rate of the mixture, kg / s; f(t) is the dimensionless time function.

[0009] Preferably, the mixture superficial velocity is calculated by the following formula: (4) Where: v SG is the superficial gas velocity, m / s; v SL is the superficial liquid velocity, m / s; The mixture density is calculated by the following formula: (5) Where: ρ l is the liquid density, kg / m 3 ;H l is the liquid holdup rate, %;ρ g is the gas density, kg / m 3 .

[0010] Preferably, the liquid holdup is calculated by the following formula: (6) (7) (8) Where: N GV 、N LV All are Froude dimensionless numbers and are dimensionless.

[0011] Preferably, the friction coefficient is calculated by the following formula: (9) Where: E is the absolute roughness, dimensionless; N Re is the no-slip Reynolds number, dimensionless.

[0012] Preferably, the no-slip Reynolds number is calculated by the following formula: (10) Where: ρ ns is the density of the mixture without slippage, kg / m 3 ;μ ns Viscosity of the no-slip mixture, Pa·s.

[0013] Preferably, in step S3, the control equations include a continuity equation, a momentum equation and an energy equation; The continuity equation is: (11) Where: ρ is the fluid density, kg / m 3 ; t is time, s; is the gradient symbol; v is the unit cell velocity vector, m / s; The momentum equation is: (12) Where: p is pressure, Pa; μ is dynamic viscosity, Pa·s; T is temperature, K; I is turbulence intensity; g is gravitational acceleration with direction, m / s 2 ; F σ Surface tension source phase; The energy equation is: (13) Where: e i is the internal energy generated by the unit body, J; F is the friction coefficient, dimensionless; P is the pressure on the unit body, Pa; q R is the volume heating rate per unit mass, W / (m 3 ·kg·K); λ is thermal conductivity, W / (m·K).

[0014] Preferably, in step S4, the boundary conditions include: setting the boundary condition of the bottom hole inflow surface as the velocity inlet, setting the gas flow rate of the gas inlet according to the gas production of the sour gas well, setting the flow rate of the liquid sulfur at the sulfur inlet according to the actual value of the wellhead sulfur concentration of the sour gas well; setting the wellhead outflow surface as the pressure outlet; setting the temperature of each section of the wellbore to the average temperature of different positions in step S1.

[0015] The beneficial effects of the present invention are: The present invention obtains the temperature and pressure in the wellbore by calculation, then establishes a wellbore model, simulates the deposition of sulfur in the wellbore as the temperature changes, and finally achieves the effect of accurately predicting the amount of sulfur deposition in the wellbore, providing a theoretical basis for removing sulfur deposition in the gas wellbore. DETAILED DESCRIPTION

[0016] The present invention is further described below in conjunction with embodiments. It should be noted that, in the absence of conflict, the embodiments in this application and the technical features in the embodiments can be combined with each other. It should be noted that, unless otherwise specified, all technical and scientific terms used in this application have the same meanings as those generally understood by those of ordinary skill in the art to which this application belongs. The words "including" or "comprising" and the like used in the disclosure of the present invention mean that the elements or objects appearing before the word cover the elements or objects listed after the word and their equivalents, without excluding other elements or objects.

[0017] The present invention provides a method for predicting sulfur deposition in a sour gas wellbore, comprising the following steps: S1: Collect basic parameters of sour gas wells and calculate the temperature and pressure at any location in the wellbore.

[0018] In a specific embodiment, the basic parameters include wellbore structure data, wellhead pressure, wellhead temperature, daily liquid production, water content, gas-liquid ratio, oil pipe diameter and reservoir temperature.

[0019] In a specific embodiment, when calculating the temperature and pressure at any position in the wellbore, the bottom of the well is taken as the coordinate origin, vertically upward is the positive coordinate of the z-axis, and a microelement with a length of dz is taken in the oil pipe. The temperature at the outlet of each microelement is calculated by the following formula: Where: T fout is the fluid temperature at the outlet of each unit, °C; T eoutis the formation temperature at the outlet of each unit, °C; A is the relaxation factor, dimensionless; z is the measured depth from a certain point in the wellbore to the bottom of the well, m; z in is the measured depth from the entrance of the unit to the bottom of the well, m; g is the acceleration of gravity, m / s 2 ; C pm is the constant pressure specific heat capacity of the fluid, J / (kg·℃); C Jm is the Joule-Thomson coefficient, °C / Pa; p is the pressure, Pa; v m is the apparent velocity of the mixture, m / s; g T is the geothermal gradient, K / m; f g is the gas friction coefficient, dimensionless; D is the pipe diameter, m; T fin is the fluid temperature at the unit inlet, °C; T ein is the formation temperature at the entrance of the unit, °C; The wellbore pressure is calculated by the following formula: (2) Where: ρ m is the density of the mixture, kg / m 3 ; θ is the well inclination angle, °; f is the friction coefficient, dimensionless.

[0020] In a specific embodiment, the relaxation factor is calculated by the following formula: (3) Where: r to is the outer diameter of the casing, m; U to is the total heat transfer coefficient, W·(m·℃); k e is the formation thermal conductivity, W·(m·℃); Q m is the mass flow rate of the mixture; f(t) is the dimensionless time function.

[0021] In a specific embodiment, the mixture superficial velocity is calculated by the following formula: (4) Where: v SG is the superficial gas velocity, m / s; v SL is the superficial liquid velocity, m / s; The mixture density is calculated by the following formula: (5) Where: ρ l is the liquid density, kg / m 3 ;H l is the liquid holdup rate, %;ρ g is the gas density, kg / m 3 .

[0022] In a specific embodiment, the liquid holdup is calculated by the following formula: (6) (7) (8) Where: N GV 、N LVAll are Froude dimensionless numbers and are dimensionless.

[0023] In the above embodiment, the liquid holdup calculation model shown in formula (6) is based on experimental tests and the parameter range of gas production and liquid production of sulfur-containing gas wells. It is established based on the experimental test results and the expression form of the Mukehejee-Brill liquid holdup model. At the same time, a new dimensionless criterion is used to better achieve the flow similarity between the experiment and the high-pressure gas well.

[0024] In a specific embodiment, the friction coefficient is calculated by the following formula: (9) Where: E is the absolute roughness, dimensionless; N Re is the no-slip Reynolds number, dimensionless.

[0025] In a specific embodiment, the no-slip Reynolds number is calculated by the following formula: (10) Where: ρ ns is the density of the mixture without slippage, kg / m 3 ;μ ns Viscosity of the no-slip mixture, Pa·s.

[0026] S2: Establishing a three-dimensional wellbore model of the sour gas well, dividing the well sections, setting a sulfur inlet and a gas inlet at the well bottom entrance, and then performing grid division to obtain a gridded three-dimensional wellbore model.

[0027] In a specific embodiment, when dividing the well section, the wellhead is divided into sections of 10 m, and the rest of the well is divided into sections of 100 m.

[0028] S3: Taking sulfur and air as experimental objects, establish the control equations for numerical simulation.

[0029] In a specific embodiment, the control equations include a continuity equation, a momentum equation, and an energy equation; The continuity equation is: (11) Where: ρ is the fluid density, kg / m 3 ; t is time, s; is the gradient symbol; v is the unit cell velocity vector, m / s; The momentum equation is: (12) Where: p is pressure, Pa; μ is dynamic viscosity, Pa·s; T is temperature, K; I is turbulence intensity; g is gravitational acceleration with direction, m / s 2 ; F σ Surface tension source phase; The energy equation is: (13) Where: e iis the internal energy generated by the unit body, J; F is the friction coefficient, dimensionless; P is the pressure on the unit body, Pa; q R is the volume heating rate per unit mass, W / (m 3 ·kg·K); λ is thermal conductivity, W / (m·K).

[0030] S4: setting initial conditions and boundary conditions, and performing unsteady-state numerical simulation on the gridded wellbore three-dimensional model using CFD software according to the temperature and pressure obtained in step S1 and the control equation established in step S3.

[0031] It should be noted that the non-steady-state numerical simulation is a prior art, and the simulation results of sulfur deposition in sour gas wells are obtained by setting boundary conditions of the calculation domain, establishing discrete equations, determining initial conditions and boundary conditions, giving solution control parameters, initializing the calculation domain, and solving. The specific numerical simulation process is not repeated here. Optionally, the CFD software uses FLUENT software.

[0032] In a specific embodiment, the boundary conditions include: setting the boundary condition of the bottom hole inflow surface as a velocity inlet, setting the gas flow rate at the gas inlet according to the gas production of the sour gas well, and setting the flow rate of the liquid sulfur at the sulfur inlet according to the actual value of the wellhead sulfur concentration of the sour gas well; setting the wellhead outflow surface as a pressure outlet; and setting the temperature of each section of the wellbore to the average temperature of different positions in step S1.

[0033] S5: According to the result of the non-steady-state numerical simulation in step S4, the amount of solid sulfur generated in each well section of the sour gas well is obtained, and the sulfur concentration at the wellhead is calculated.

[0034] In a specific embodiment, the concentration of the sulfur phase in a well section 10 m long at the wellhead is calculated, and the value is the sulfur concentration at the wellhead.

[0035] S6: Detecting the actual sulfur concentration value at the wellhead of the sulfur-containing gas well, and comparing the actual sulfur concentration value with the sulfur concentration at the wellhead obtained in step S5: If the error between the two is not within the error threshold, the boundary condition in step S4 is changed and steps S4-S6 are repeated; If the error between the two is within the error threshold, the amount of solid sulfur obtained in step S4 is the amount of sulfur deposition in the sour gas well.

[0036] In a specific embodiment, the error threshold is 20%. It should be noted that the error threshold is a manually set value, and the smaller the value, the more accurate the result.

[0037] In a specific embodiment, taking a sulfur-containing gas well as an example, the sulfur deposition amount in the wellbore of the sulfur-containing gas well is predicted by using the method for predicting sulfur deposition amount in the wellbore of the sulfur-containing gas well according to the present invention, which specifically includes the following steps: (1) Collect basic parameters of the sour gas well and calculate the temperature and pressure at any location in the wellbore by combining equations (1)-(2); (2) establishing a three-dimensional wellbore model of the sour gas well, dividing the well sections, setting a sulfur inlet and a gas inlet at the well bottom entrance, and then performing grid division to obtain a gridded three-dimensional wellbore model; (3) Taking sulfur and air as experimental objects, the control equations of numerical simulation shown in equations (11)-(13) are established; (4) setting initial conditions and boundary conditions, and performing unsteady-state numerical simulation on the gridded three-dimensional wellbore model according to the temperature and pressure obtained in step (1) and the control equation established in step (3); In this embodiment, the boundary condition of the bottom hole inflow surface is set as the velocity inlet, the gas flow rate of the gas inlet is set according to the gas production of the sour gas well, and the flow rate of the liquid sulfur at the sulfur inlet is set according to the actual value of the wellhead sulfur concentration of the sour gas well; the wellhead outflow surface is set as the pressure outlet; and the temperature of each section of the wellbore is set as the average temperature of different positions in step (1).

[0038] (5) according to the result of the non-steady-state numerical simulation in step (4), the amount of solid sulfur generated in each well section of the sour gas well is obtained, and the concentration of the sulfur phase in the well section 10 m long at the wellhead is calculated, and this is used as the sulfur concentration at the wellhead; In this step, in addition to obtaining the amount of solid sulfur generated in each well section of the sour gas well by analyzing the results of the non-steady-state numerical simulation, the wellbore fluid temperature cloud map, pressure cloud map, velocity cloud map, and the curve of the solid-liquid two-phase cloud map of sulfur changing with time can also be obtained simultaneously; (6) Detecting the actual sulfur concentration at the wellhead of the sour gas well, and comparing the actual sulfur concentration with the sulfur concentration at the wellhead obtained in step (5): If the error between the two is greater than 20%, reset the flow rate of the bottom hole liquid sulfur inlet and repeat steps (4)-(6); If the error between the two is less than or equal to 20%, the amount of solid sulfur obtained in step (4) is the sulfur deposition amount of the sour gas well.

[0039] The above description is only a preferred embodiment of the present invention and does not constitute any form of limitation to the present invention. Although the present invention has been disclosed as a preferred embodiment as above, it is not intended to limit the present invention. Any technician familiar with the profession can make some changes or modifications to equivalent embodiments of equivalent changes using the technical contents disclosed above without departing from the scope of the technical solution of the present invention. However, any simple modification, equivalent change and modification made to the above embodiments based on the technical essence of the present invention without departing from the content of the technical solution of the present invention still falls within the scope of the technical solution of the present invention.

Claims

1. A method for predicting sulfur deposition in a sour gas wellbore. It is characterized in that The following steps are involved: S1: Collect basic parameters of sour gas wells and calculate the temperature and pressure at any location in the wellbore; S2: establishing a three-dimensional wellbore model of the sour gas well, dividing the well sections, setting a sulfur inlet and a gas inlet at the well bottom entrance, and then performing grid division to obtain a gridded three-dimensional wellbore model; S3: Taking sulfur and air as experimental objects, establish the control equations of numerical simulation; S4: setting initial conditions and boundary conditions, and performing unsteady-state numerical simulation on the gridded wellbore three-dimensional model using CFD software according to the temperature and pressure obtained in step S1 and the control equation established in step S3; S5: according to the result of the non-steady-state numerical simulation in step S4, the amount of solid sulfur generated in each well section of the sour gas well is obtained, and the sulfur concentration at the wellhead is calculated; S6: Detecting the actual sulfur concentration value at the wellhead of the sulfur-containing gas well, and comparing the actual sulfur concentration value with the sulfur concentration at the wellhead obtained in step S5: If the error between the two is not within the error threshold, the boundary condition in step S4 is changed and steps S4-S6 are repeated; If the error between the two is within the error threshold, the amount of solid sulfur obtained in step S4 is the amount of sulfur deposition in the sour gas well.

2. The method for predicting sulfur deposition in a sour gas well according to claim 1, It is characterized in that In step S1, the basic parameters include wellbore structure data, wellhead pressure, wellhead temperature, daily liquid production, water content, gas-liquid ratio, tubing diameter and reservoir temperature.

3. The method for predicting sulfur deposition in a sour gas well according to claim 1, It is characterized in that In step S1, when calculating the temperature and pressure at any position in the wellbore, the bottom of the well is taken as the coordinate origin, vertically upward is the positive coordinate of the z-axis, and a microelement with a length of dz is taken in the oil pipe. The temperature at the outlet of each microelement is calculated by the following formula: Where: T fout is the fluid temperature at the outlet of each unit, °C; T eout is the formation temperature at the outlet of each unit, °C; A is the relaxation factor, dimensionless; z is the measured depth from a certain point in the wellbore to the bottom of the well, m; z in is the measured depth from the entrance of the unit to the bottom of the well, m; g is the acceleration of gravity, m / s 2 ; C pm is the constant pressure specific heat capacity of the fluid, J / (kg·℃); C Jm is the Joule-Thomson coefficient, °C / Pa; p is the pressure, Pa; v m is the apparent velocity of the mixture, m / s; g T is the geothermal gradient, K / m; f g is the gas friction coefficient, dimensionless; D is the pipe diameter, m; T fin is the fluid temperature at the unit inlet, °C; T ein is the formation temperature at the entrance of the unit, °C; The wellbore pressure is calculated by the following formula: Where: m is the density of the mixture, kg / m 3 ; θ is the well inclination angle, °; f is the friction coefficient, dimensionless.

4. The method for predicting sulfur deposition in a sour gas well according to claim 3, It is characterized in that The relaxation factor is calculated by the following formula: (3) Where: r to is the outer diameter of the casing, m; U to is the total heat transfer coefficient, W·(m·℃); k e is the formation thermal conductivity, W·(m·℃); Q m is the mass flow rate of the mixture, kg / s; f(t) is the dimensionless time function.

5. The method for predicting sulfur deposition in a sour gas well according to claim 3, It is characterized in that The mixture superficial velocity is calculated by the following formula: (4) Where: v SG is the superficial gas velocity, m / s; v SL is the superficial liquid velocity, m / s; The mixture density is calculated by the following formula: (5) Where: ρ l is the liquid density, kg / m 3 ;H l is the liquid holdup rate, %;ρ g is the gas density, kg / m 3 .

6. The method for predicting sulfur deposition in a sour gas well according to claim 5, It is characterized in that The liquid holdup is calculated by the following formula: (6) (7) (8) Where: N GV 、N LV All are Froude dimensionless numbers and are dimensionless.

7. The method for predicting sulfur deposition in a sour gas well according to claim 3, It is characterized in that The friction coefficient is calculated by the following formula: (9) Where: E is the absolute roughness, dimensionless; N Re is the no-slip Reynolds number, dimensionless.

8. The method for predicting sulfur deposition in a sour gas well according to claim 7, It is characterized in that The no-slip Reynolds number is calculated by the following formula: (10) Where: ρ ns is the density of the mixture without slippage, kg / m 3 ;μ ns Viscosity of the no-slip mixture, Pa·s.

9. The method for predicting sulfur deposition in a sour gas well according to claim 1, It is characterized in that In step S3, the control equations include a continuity equation, a momentum equation and an energy equation; The continuity equation is: (11) Where: ρ is the fluid density, kg / m 3 ; t is time, s; is the gradient symbol; v is the unit cell velocity vector, m / s; The momentum equation is: (12) Where: p is pressure, Pa; μ is dynamic viscosity, Pa·s; T is temperature, K; I is turbulence intensity; g is gravitational acceleration with direction, m / s 2 ; F σ Surface tension source phase; The energy equation is: (13) Where: e i is the internal energy generated by the unit body, J; F is the friction coefficient, dimensionless; P is the pressure on the unit body, Pa; q R is the volume heating rate per unit mass, W / (m 3 ·kg·K); λ is thermal conductivity, W / (m·K).

10. The method for predicting sulfur deposition in a sour gas well according to claim 1, It is characterized in that In step S4, the boundary conditions include: setting the boundary condition of the bottom hole inflow surface as the velocity inlet, setting the gas flow rate of the gas inlet according to the gas production of the sour gas well, and setting the flow rate of the liquid sulfur at the sulfur inlet according to the actual value of the wellhead sulfur concentration of the sour gas well; setting the wellhead outflow surface as the pressure outlet; and setting the temperature of each section of the wellbore to the average temperature of different positions in step S1.

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