A method for determining the TPC curve of a gas well under the influence of wellbore liquid accumulation

Abstract

The present invention belongs to the field of gas field development, and particularly relates to a method for determining the TPC curve of a gas well under the influence of wellbore liquid accumulation. In the present invention, in order to eliminate the influence of liquid accumulation on flowing pressure calculation, the wellbore is divided into a liquid accumulation section and a non-liquid accumulation section, a wellbore pressure drop model considering the influence of liquid accumulation is established, and a method for determining the TPC curve of a gas well under the influence of wellbore liquid accumulation is proposed. This method has theoretical rationality and practical production application value in the actual application of gas reservoir production increase.

Description

Technical Field

[0001] The present invention belongs to the field of gas field development, and particularly relates to a method for determining the TPC curve of a gas well under the influence of wellbore liquid accumulation. Background Art

[0002] The currently commonly used wellbore multiphase flow pressure drop models do not consider the influence of liquid accumulation when calculating the wellbore pressure drop. However, the liquid accumulation phenomenon in shale gas wells is obvious, which leads to the result of calculating the bottom-hole flowing pressure using the conventional multiphase pipe flow pressure drop model being often less than the actual bottom-hole flowing pressure, affecting the reasonable production allocation and process application in the later stage of gas wells. Therefore, we divide the wellbore into two parts: the liquid accumulation section and the non-liquid accumulation section, establish a wellbore pressure drop model considering the influence of liquid accumulation, and propose a method for determining the TPC curve of a gas well under the influence of wellbore liquid accumulation. This method has theoretical rationality and practical production application value in the actual application of gas reservoir production enhancement. Summary of the Invention

[0003] The purpose of the present invention is to solve the practical application problem of wellbore liquid accumulation pressure drop in the process of gas reservoir development. By establishing the pressure drop models of the liquid accumulation section and the non-liquid accumulation section of the gas wellbore, the wellbore pressure drop under different gas production requirements is calculated and determined. The new method in the present invention can effectively determine the TPC curve after wellbore liquid accumulation in shale gas wells, which is helpful for subsequent gas field development design, formulating a reasonable production plan, and providing technical support for formulating an effective development plan.

[0004] To achieve the above purpose, the present invention provides a method for determining the TPC curve of a gas well under the influence of wellbore liquid accumulation, which includes the following steps:

[0005] First step, determine the formation gas production, formation water production, wellhead pressure, tubing inner diameter, bottom-hole and wellhead temperatures, time step parameter, and the liquid accumulation height of the wellbore liquid accumulation section at the previous moment according to the on-site production data , and the liquid accumulation volume ;

[0006] Second step, according to the formation gas production , and the formation water production , calculate the water production that meets the liquid-carrying requirement at the liquid accumulation height from the wellhead downwards;

[0007] Third step, calculate the liquid accumulation volume , of the liquid accumulation section by comparing the sizes;

[0008] Fourth step, calculate the initial value of the liquid accumulation height according to the formula ;

[0009] Fifth step, according to the liquid accumulation height being Calculate the pressure distributions of the non-liquid-accumulation section and the liquid accumulation respectively;

[0010] Step 6: Calculate the liquid accumulation volume of the liquid accumulation section according to the formula , and verify and whether it meets the accuracy requirements. If not, let , and repeat step (5) until the accuracy requirements are met;

[0011] Step 7: Recalculate the water production rate at which the liquid holdup height meets the liquid-carrying requirement , and verify and whether it meets the accuracy requirements. If not, let be brought into step (3) for continuous calculation until is basically unchanged;

[0012] Step 8: Plot the TPC curve of the gas well considering the influence of liquid accumulation.

[0013] Compared with the prior art, the present invention has the following beneficial effects: (1) It has a wide range of applications and can be applied to gas reservoirs under different conditions; (2) The calculation method is convenient and effective, and the work efficiency is high; (3) The calculation method is easy to promote. BRIEF DESCRIPTION OF THE DRAWINGS

[0014] In the drawings:

[0015] Figure 1 is the technical roadmap of this method;

[0016] Figure 2 is the calculation flow chart. DETAILED DESCRIPTION OF THE EMBODIMENTS

[0017] The following further describes the present invention in conjunction with the embodiments and the drawings;

[0018] The present invention provides a method for determining the TPC curve of a gas well affected by wellbore liquid accumulation. This method includes the following steps:

[0019] S100: Determine the formation gas production , the formation water production , the wellhead pressure, the wellbore inner diameter, the bottom-hole and wellhead temperatures, the time-step parameter, and the liquid holdup height of the wellbore liquid accumulation section at the previous moment , the liquid accumulation volume ;

[0020] S200: Calculate the water production rate at which the liquid holdup height meets the liquid-carrying requirement from the wellhead downward according to the formation gas production :

[0021]

[0022] In the formula is the liquid production volume that meets the liquid-carrying requirement at the current gas production volume, with the unit of ; is the gas production volume, with the unit of ; z is the gas compressibility factor, dimensionless; T is the temperature, with the unit of K; is the gas density in the wellbore, with the unit of ; is the friction coefficient at the apparent gas velocity, dimensionless; is the surface tension, with the unit of ; is the liquid density in the wellbore, with the unit of ; A is the cross-sectional area of the wellbore, with the unit of ; p is the wellhead pressure, with the unit of MPa;

[0023] S300: According to the comparison 、 size, calculate the liquid accumulation volume in the liquid accumulation section;

[0024] S400: According to the formula calculate the initial value of the liquid accumulation height ;

[0025] S500: According to the liquid accumulation height being calculate the pressure distributions in the non-liquid accumulation section and the liquid accumulation section respectively:

[0026] Liquid accumulation section:

[0027] ,

[0028] In the formula is the pressure gradient, with the unit of MPa / m; is the density of the mixed fluid in the wellbore, with the unit of ; g is the acceleration due to gravity, taking 9.8 ; is the angle between the wellbore and the horizontal plane, with the unit of degrees; is the friction coefficient, dimensionless; is the flow velocity of the mixed fluid, with the unit of ; D is the inner diameter of the wellbore, with the unit of m;

[0029] Non-liquid accumulation section:

[0030]

[0031] In the formula is the total pressure drop, with the unit of MPa; g is the acceleration of gravity, taking 9.8 ; is the unit conversion coefficient, dimensionless, and is 1 in the International System of Units; is the gas density in the wellbore, with the unit of ; h is the depth, with the unit of m; is the friction coefficient, dimensionless; G is the mass flow rate (mass flow per unit area), with the unit of ; D is the inner diameter of the wellbore, with the unit of m; is the density of the mixed fluid in the wellbore, with the unit of ; is the density of the mixed fluid at the wellhead, with the unit of ; is the gas void fraction (gas volume fraction), dimensionless, ranging from 0 to 1;

[0032] S600: Calculate the liquid holdup in the liquid accumulation section according to the formula :

[0033]

[0034] In the formula , are the liquid holdups of the non-liquid accumulation well section and the liquid accumulation well section, measured by on-site experiments, dimensionless; is the liquid accumulation position, with the unit of m; is the liquid holdup in the liquid accumulation section of the previous day, with the unit of m 3 ; is the change in the liquid holdup in the liquid accumulation section, with the unit of m 3 ; H is the wellbore depth, with the unit of m; A is the cross-sectional area of the wellbore, with the unit of ; h is the depth, with the unit of m;

[0035] Verify and whether meet the accuracy requirements. If not, let , and repeat step S500 until the accuracy requirements are met, with an error less than 5%;

[0036] S700: Recalculate the water production rate that meets the liquid carrying requirement at for the liquid accumulation height , verify and whether meet the accuracy requirements, with an error less than 5%. If not, let be brought into step S300 for continued calculation until remains unchanged;

[0037] S800: Draw the TPC curve considering the influence of liquid accumulation with the wellbore pressure drop as the vertical coordinate and the gas production as the horizontal coordinate.

[0038] Compared with the prior art, the present invention has the following beneficial effects: (1) It has a wide range of applications and can be applied to gas wells under different conditions; (2) The calculation method is convenient and effective, with high work efficiency; (3) The calculation method is easy to promote.

[0039] Finally, it should be noted that: the above embodiments are only used to illustrate rather than limit the technical solutions of the present invention. Although the present invention has been described in detail with reference to the above embodiments, those of ordinary skill in the art should understand that: the present invention can still be modified or equivalently replaced, and any modification or partial replacement without departing from the spirit and scope of the present invention shall be covered by the scope of the claims of the present invention.

Claims

1. A method for determining the TPC curve of a gas well affected by wellbore liquid accumulation, characterized in that, The method comprises the following steps: S100: Determine the formation gas production based on on-site production data , the formation water production , the wellhead pressure, the inner diameter of the wellbore, the bottom-hole and wellhead temperatures, the time-step parameter, and the liquid accumulation height of the liquid accumulation section in the wellbore at the previous moment , the liquid accumulation volume ; S200: Calculate the water production volume that meets the liquid-carrying requirement at the liquid accumulation height from the wellhead downwards according to the formation gas production volume and the formation water production volume where the liquid-carrying requirement is met : In the formula is the liquid production volume that meets the liquid-carrying requirement at the current gas production volume, with the unit of ; is the gas production volume, with the unit of ; z is the gas compressibility factor, dimensionless; T is the temperature, with the unit of K; is the gas density in the wellbore, with the unit of ; is the friction factor at the gas superficial velocity, dimensionless; is the surface tension, with the unit of ; is the liquid density in the wellbore, with the unit of ; A is the cross-sectional area of the wellbore, with the unit of ; p is the wellhead pressure, with the unit of MPa; S300: Calculate the liquid accumulation volume in the liquid accumulation section according to the comparison , ; ; S400: Calculate the initial value of the liquid accumulation height according to the formula ;​ S500: Calculate the pressure distributions of the non-liquid accumulation section and the liquid accumulation section respectively according to the liquid accumulation height: ​ Liquid accumulation section: ， where is the pressure gradient, with the unit of MPa / m; is the density of the mixed fluid in the wellbore, with the unit of ; g is the acceleration due to gravity, taking 9.8 ; is the angle between the wellbore and the horizontal plane, with the unit of degree; is the friction coefficient, dimensionless; is the flow velocity of the mixed fluid, with the unit of ; D is the inner diameter of the wellbore, with the unit of m; Non-liquid accumulation section: where is the total pressure drop, with the unit of MPa; g is the acceleration of gravity, taking 9.8 ; is the unit conversion coefficient, dimensionless, being 1 in the International System of Units; is the gas density in the wellbore, with the unit of ; h is the depth, with the unit of m; is the friction coefficient, dimensionless; G is the mass velocity, i.e., the mass flow rate per unit area, with the unit of ; D is the inner diameter of the wellbore, with the unit of m; is the density of the mixed fluid in the wellbore, with the unit of ; is the density of the mixed fluid at the wellhead, with the unit of ; is the gas void fraction, also the gas volume fraction, dimensionless, ranging from 0 to 1; S6 00: Calculate the liquid accumulation volume in the liquid accumulation section according to the formula : where , are the liquid holdup rates of non-liquid accumulation well sections and liquid accumulation well sections, measured by on-site experiments, dimensionless; is the liquid accumulation position, in m; is the liquid accumulation volume of the liquid accumulation section of the previous day, in m 3 ; is the change in the liquid accumulation volume of the liquid accumulation section, in m 3 ; H is the wellbore depth, in m; A is the cross-sectional area of the wellbore, in ; h is the depth, in m; Verification and to check whether the accuracy requirement is met. If not, set a new and repeat step S500 until the accuracy requirement is achieved, with an error less than 5%; S700: Recalculate the water production when the liquid holdup height at meets the liquid-carrying requirement , verify and whether it meets the accuracy requirement, with an error less than 5%. If not, let be brought into step S300 for continued calculation until remains unchanged; S800: Draw a TPC curve considering the influence of liquid accumulation with the wellbore pressure drop as the ordinate and the gas production rate as the abscissa.

Images