CN104612659B - A kind of determination method of the critical liquid carry over of low gas liquid rate gas well - Google Patents

Abstract

The invention provides a method for determining the critical liquid-carrying capacity of a gas well with a low gas-liquid ratio. Firstly, the gas well parameters are collected, and then the liquid miscible density and liquid miscible viscosity are calculated. According to the type of gas well, the gas-liquid-carrying equation of a horizontal well with a low gas-liquid ratio or a low The gas-liquid ratio vertical well gas-liquid-carrying equation is fitted to obtain the maximum daily liquid production rate, which is the critical liquid-carrying capacity of a low gas-liquid ratio gas well. The invention provides a model of the relationship between daily gas production and daily liquid production of a gas well with a low gas-liquid ratio. The design parameters in the model are the daily necessary test and measurement data of the bottom and wellhead of the gas well. Using this model to characterize the complex gas-liquid-carrying relationship in the wellbore can realize real-time monitoring of the wellbore condition. Based on this model, the critical liquid-carrying capacity and reasonable productivity of the gas well with water breakthrough can be determined, which can provide important information for the prediction of wellbore fluid accumulation and later production measures. in accordance with.

Description

A Method for Determining the Critical Liquid Carrying Capacity of Gas Wells with Low Gas-Liquid Ratio

technical field

The invention relates to a method for determining the critical liquid-carrying capacity of a gas well with a low gas-liquid ratio, and belongs to the technical field of mining.

Background technique

After the formation water enters the bottom of the wellbore, the single-phase flow (gas) in the wellbore changes into a gas-liquid two-phase flow. According to the gas flow rate and gas-liquid ratio changes, there may be four types of bubble flow, slug flow, circular flow, and mist flow in the wellbore. a state of flow. When the wellbore is in the state of mist flow, the liquid droplet model headed by turner can be used to calculate the critical liquid carrying capacity of the gas well. In work, gas wells generally go through a production process in a non-fog flow state after water breakthrough. How to calculate the critical liquid carrying capacity of a gas well in a non-fog flow state is of great significance for prolonging the production time of a gas well and improving the recovery rate of a gas well.

Contents of the invention

In order to solve the deficiencies of the prior art, the present invention provides a method for determining the critical liquid carrying capacity of a low gas-liquid ratio gas well, which can solve the problem of real-time monitoring of liquid accumulation in existing low gas-liquid ratio gas wells, prediction of wellbore liquid accumulation time and Calculate the reasonable productivity of gas wells with low gas-liquid ratio, etc., so as to improve the recovery rate of gas wells and increase their economic benefits.

The technical scheme adopted by the present invention to solve the technical problem is: a method for determining the critical liquid carrying capacity of a gas well with a low gas-liquid ratio is provided, which specifically includes the following steps:

(1) Gather gas well parameters, which include wellhead pressure P ₁ , bottomhole pressure P ₂ , wellhead temperature T ₁ , bottomhole temperature T ₂ , tubing inner diameter d, formation water density ρ _w , crude oil density ρ _o , water Viscosity σ _w of oil, viscosity of oil σ _o , proportion of water in produced fluid α ₁ , proportion of oil in produced fluid α ₂ , and daily gas production q _g , and determine wellhead conditions according to wellhead pressure P ₁ and wellhead temperature T ₁ The gas deviation coefficient Z ₁ under the wellhead condition and the gas density ρ _g1 under the wellhead condition, the gas deviation coefficient Z ₂ and the gas density ρ _g2 under the bottom hole condition are determined according to the bottom hole pressure P ₂ and the bottom hole temperature T ₂ ;

(2) Calculate the liquid miscible density ρ _L according to the following formula:

ρ _L =α ₁ ·ρ _w +α ₂ ·ρ _o

(3) Calculate the liquid miscible viscosity σ according to the following formula:

σ＝α ₁ ·σ _w +α ₂ ·σ _o

(4) Determine the well type of the gas well. If the gas well is a horizontal well, use the gas-liquid-carrying equation of a horizontal well with a low gas-liquid ratio for fitting:

Among them, q _L represents the daily liquid production rate in m ³ /d; q _g represents the daily gas production rate in m ³ /d; Z ₁ represents the gas deviation coefficient under the wellhead condition; Z ₂ represents the gas deviation under the bottom hole condition Coefficient; P ₁ represents wellhead pressure, unit is MPa; P ₂ represents bottom hole pressure, unit is MPa; T ₁ represents well head temperature, unit is K; T ₂ represents bottom hole temperature, unit is K; d represents tubing inner diameter, unit is m; ρ _g1 represents the gas density under the wellhead condition, the unit is kg/m ³ ; ρ _g2 represents the gas density under the bottom hole condition, the unit is kg/m ³ ; ρ _L represents the liquid miscible density, the unit is kg/m ³ , The unit is σ, which means the liquid miscible viscosity, and the unit is N/m;

If the gas well is a vertical well, use the gas-liquid-carrying equation of a vertical well with a low gas-liquid ratio to calculate the daily liquid production:

Among them, q _L represents the daily liquid production rate in m ³ /d; q _g represents the daily gas production rate in m ³ /d; Z ₁ represents the gas deviation coefficient under the wellhead condition; Z ₂ represents the gas deviation under the bottom hole condition Coefficient; P ₁ represents wellhead pressure, unit is MPa; P ₂ represents bottom hole pressure, unit is MPa; T ₁ represents well head temperature, unit is K; T ₂ represents bottom hole temperature, unit is K; d represents tubing inner diameter, unit is m; ρ _g1 represents the gas density under the wellhead condition, the unit is kg/m ³ ; ρ _g2 represents the gas density under the bottom hole condition, the unit is kg/m ³ ; ρ _L represents the liquid miscible density, the unit is kg/m ³ , The unit is σ, which means the liquid miscible viscosity, and the unit is N/m;

In the gas-liquid-carrying equation of horizontal wells with low gas-liquid ratio or in the gas-liquid-carrying equation of vertical wells with low gas-liquid ratio, the maximum daily liquid production rate is the critical liquid-carrying capacity.

The beneficial effects of the present invention based on its technical solution are: the present invention provides a method for determining the critical liquid carrying capacity of a gas well with a low gas-liquid ratio, and determines the relationship between gas well parameters and daily liquid production. The daily test data is simple and only needs to be measured once a day to characterize the complex gas-liquid-carrying relationship in the wellbore, which can realize real-time monitoring of the wellbore condition and determine the critical liquid-carrying volume based on this. The calculation is accurate and can be used for It provides an important basis for predicting wellbore fluid accumulation and post-production measures.

Description of drawings

Fig. 1 is a schematic diagram of the relationship between the gas production rate of a gas well and the maximum liquid carrying capacity under stable liquid supply.

Fig. 2 is a comparison chart of the liquid-carrying capacity calculated by the gas-liquid-carrying equation with low gas-liquid ratio and the actual liquid-carrying capacity of gas wells under the same conditions, in which Fig. 2(1), Fig. 2(2) and Fig. 2(3) are respectively A comparison chart of the liquid carryover calculated by the low gas-liquid ratio gas-liquid carryover equation and the actual liquid carryover of the gas well under the same conditions for a vertical well, a certain horizontal well A and a certain horizontal well B.

Fig. 3 is a schematic flow chart of the present invention.

detailed description

The present invention will be further described below in conjunction with drawings and embodiments.

The invention deduces the change law between the gas flow rate (flow velocity) of the gas well and its maximum liquid carrying capacity based on the theory of the change of flow state between gas and liquid. As shown in Fig. 1, when the gas-liquid space in the wellbore is in the mist flow state, the gas production rate of the gas well is nearly proportional to the maximum liquid carrying capacity; From plug flow to transitional flow, the gas production rate of the gas well and the maximum liquid-carrying capacity have a near-parabolic relationship. Since the slippage loss between gas and liquid is the smallest in the slug flow state, the gas-liquid-carrying capacity in the slug flow state at the circle mark is critical. value reaches the maximum.

Taking the gas production rate and the maximum liquid carrying capacity as the independent variable and the dependent variable respectively, and using the binomial equation as the basic mathematical model, the gas production rate and the corresponding liquid carrying capacity of gas wells with accumulated liquid and low gas-liquid ratio are used to fit the mathematical model to determine Quadratic term, linear term and constant term coefficients in the equation.

During the liquid-carrying process of wellbore gas, the liquid-carrying volume of the gas mainly depends on its initial energy and the energy loss during the liquid-carrying process. Therefore, the coefficients in the mathematical model are bottom-hole pressure, bottom-hole temperature, tubing diameter, wellhead pressure, Comprehensive expression of wellhead temperature, gas density, liquid viscosity and other parameters. Through the analysis of the wellbore phase state and related data of gas wells with low gas-liquid ratio, it can be known that after the gas well enters the non-fog flow state, not all the well intervals flow in the non-fog flow state, but are composed of fog flow and non-fog flow phase states. . According to comprehensive analysis, in the gas-liquid-carrying equation of gas wells with low gas-liquid ratio, the coefficient of the quadratic term represents the influence factor of non-fog flow phase state, and the primary phase coefficient represents the influence factor of mist flow phase state. The gas-liquid-carrying model of horizontal wells with low gas-liquid ratio is:

The gas-liquid-carrying model of a vertical well with low gas-liquid ratio is:

Among them, q _L represents the daily liquid production rate in m ³ /d; q _g represents the daily gas production rate in m ³ /d; Z ₁ represents the gas deviation coefficient under the wellhead condition; Z ₂ represents the gas deviation under the bottom hole condition Coefficient; P ₁ represents wellhead pressure, unit is MPa; P ₂ represents bottom hole pressure, unit is MPa; T ₁ represents well head temperature, unit is K; T ₂ represents bottom hole temperature, unit is K; d represents tubing inner diameter, unit is m; ρ _g1 represents the gas density under the wellhead condition, the unit is kg/m ³ ; ρ _g2 represents the gas density under the bottom hole condition, the unit is kg/m ³ ; ρ _L represents the liquid miscible density, the unit is kg/m ³ , The unit is σ, which means the liquid miscible viscosity, and the unit is N/m.

In the wellbore of a water-producing well in a condensate gas reservoir, oil, gas and water coexist in three phases, and the boundary line between high and low gas-liquid ratio is 1300.

1 well (vertical well):

After the wellbore began to accumulate liquid, the gas-liquid ratio of the gas well produced was 400-1000, showing a three-phase non-mist flow state of oil, gas and water.

2 wells (horizontal wells):

After the wellbore began to accumulate liquid, the gas-liquid ratio of the gas well produced was 800-1000, showing a three-phase non-mist flow state of oil, gas and water.

3 wells (horizontal wells):

After the wellbore begins to accumulate liquid, the gas well produces a gas-liquid ratio of 1000-2000, and the three-phase oil, gas and water in the wellbore gradually transitions from the mist flow state to the slug flow.

4 wells (horizontal wells):

After the wellbore began to accumulate liquid, the gas well produced a gas-liquid ratio of 900-1900, and the three-phase oil, gas and water in the wellbore gradually transitioned from the mist flow state to the slug flow.

The relevant data of gas well parameters collected by each well are shown in the following table:

Table 1. Basic parameters of the wellhead and bottom of each well in a condensate gas reservoir

Based on this, the present invention provides a method for determining the critical liquid carrying capacity of a low gas-liquid ratio gas well, referring to Figure 3, which specifically includes the following steps:

(1) Gather gas well parameters, which include wellhead pressure P ₁ , bottomhole pressure P ₂ , wellhead temperature T ₁ , bottomhole temperature T ₂ , tubing inner diameter d, formation water density ρ _w , crude oil density ρ _o , water Viscosity σ _w of oil, viscosity of oil σ _o , proportion of water in produced fluid α ₁ , proportion of oil in produced fluid α ₂ , and daily gas production q _g , and determine wellhead conditions according to wellhead pressure P ₁ and wellhead temperature T ₁ The gas deviation coefficient Z ₁ under the wellhead condition and the gas density ρ _g1 under the wellhead condition, the gas deviation coefficient Z ₂ and the gas density ρ _g2 under the bottom hole condition are determined according to the bottom hole pressure P ₂ and the bottom hole temperature T ₂ ;

(2) Calculate the liquid miscible density ρ _L according to the following formula:

ρ _L =α ₁ ·ρ _w +α ₂ ·ρ _o

(3) Calculate the liquid miscible viscosity σ according to the following formula:

σ＝α ₁ ·σ _w +α ₂ ·σ _o

(4) Determine the well type of the gas well. If the gas well is a horizontal well, use the gas-liquid-carrying equation of a horizontal well with a low gas-liquid ratio for fitting:

Among them, q _L represents the daily liquid production rate in m ³ /d; q _g represents the daily gas production rate in m ³ /d; Z ₁ represents the gas deviation coefficient under the wellhead condition; Z ₂ represents the gas deviation under the bottom hole condition Coefficient; P ₁ represents wellhead pressure, unit is MPa; P ₂ represents bottom hole pressure, unit is MPa; T ₁ represents well head temperature, unit is K; T ₂ represents bottom hole temperature, unit is K; d represents tubing inner diameter, unit is m; ρ _g1 represents the gas density under the wellhead condition, the unit is kg/m ³ ; ρ _g2 represents the gas density under the bottom hole condition, the unit is kg/m ³ ; ρ _L represents the liquid miscible density, the unit is kg/m ³ , The unit is σ, which means the liquid miscible viscosity, and the unit is N/m;

If the gas well is a vertical well, use the gas-liquid-carrying equation of a vertical well with a low gas-liquid ratio to calculate the daily liquid production:

Among them, q _L represents the daily liquid production rate in m ³ /d; q _g represents the daily gas production rate in m ³ /d; Z ₁ represents the gas deviation coefficient under the wellhead condition; Z ₂ represents the gas deviation under the bottom hole condition Coefficient; P ₁ represents wellhead pressure, unit is MPa; P ₂ represents bottom hole pressure, unit is MPa; T ₁ represents well head temperature, unit is K; T ₂ represents bottom hole temperature, unit is K; d represents tubing inner diameter, unit is m; ρ _g1 represents the gas density under the wellhead condition, the unit is kg/m ³ ; ρ _g2 represents the gas density under the bottom hole condition, the unit is kg/m ³ ; ρ _L represents the liquid miscible density, the unit is kg/m ³ , The unit is σ, which means the liquid miscible viscosity, and the unit is N/m;

In the gas-liquid-carrying equation of a horizontal well with a low gas-liquid ratio or a vertical well with a low gas-liquid ratio, the maximum daily liquid production rate is the critical liquid-carrying rate, and the daily liquid production rate is the reasonable production capacity of the well. In Fig. 2, the hollow circles represent the actual saturated liquid-carrying capacity, and the solid triangles represent the saturated liquid-carrying capacity calculated by the gas-liquid-carrying equation of the horizontal well with low gas-liquid ratio or the gas-liquid-carrying equation of the vertical well with low gas-liquid ratio. Fig. 2(1) And Fig. 2(2) and Fig. 2(3) respectively show the liquid-carrying capacity of a vertical well, a certain horizontal well A and a certain horizontal well B calculated according to the gas-liquid-carrying equation with low gas-liquid ratio and the actual liquid-carrying capacity of the gas well under the same conditions. volume comparison chart. If the actual liquid-carrying capacity of the gas well reaches the theoretically calculated value, it means that the gas well has reached a saturated liquid-carrying state, and liquid accumulation may occur in the wellbore at any time. No effusion. When the actual liquid carrying capacity of the gas well reaches the theoretically calculated value, the well should take manual liquid drainage measures in time to prolong the production time of the gas well and increase the recovery factor. At the same time, according to the calculation formula, the maximum liquid carrying capacity under the non-mist flow state can be obtained. This value is the reasonable production capacity adjusted by the gas well. liquid cost.

Claims (1)

1. the determination method of the critical liquid carry over of a kind of low gas liquid rate gas well, it is characterised in that specifically include following steps：

(1) gas well parameter is gathered, and the gas well parameter includes well head pressure P₁, bottom pressure P₂, wellhead temperature T₁, bottom hole temperature (BHT) T₂, pipe aperture d, stratum water density ρ_w, oil density ρ_o, water viscosity σ_w, oil viscosity σ_o, water accounting example α in production fluid₁、 Oily accounting example α in production fluid₂, and daily output tolerance q_g, and according to well head pressure P₁, wellhead temperature T₁Under the conditions of determining well head Gaseous Z-factor Z₁With gas density ρ under the conditions of well head_g1, according to bottom pressure P₂, bottom hole temperature (BHT) T₂Determine under downhole condition Gaseous Z-factor Z₂With gas density ρ under downhole condition_g2；

(2) liquid mixture density ρ is calculated according to below equation_L：

ρ_L=α₁·ρ_w+α₂·ρ_o

(3) liquid mixed phase viscosity σ is calculated according to below equation：

σ=α₁·σ_w+α₂·σ_o

(4) judge the well type of gas well, if gas well is horizontal well, liquid Equation for Calculating daily output liquid is taken using the horizontal gas well gas of low gas liquid rate Amount：

$q_L=-\frac{Z_1\left(P_2-P_1\right)\·d^2\·\mathrm{\π}}{40\·Z_2\·P_1\·P_2\·T_2}\·{q_g}^2+\frac{1}{T_2}\·q_g-\frac{3.3\·{\mathrm{\ρ}}_{g1}\·{\mathrm{\ρ}}_{g2}}{\left({\mathrm{\ρ}}_L-{\mathrm{\ρ}}_{g2}\right)\·\mathrm{\σ}\·T_1}$

Wherein, q_LDaily fluid production rate is represented, unit is m³/d；q_gDaily output tolerance is represented, unit is m³/d；Z₁Under the conditions of representing well head Gaseous Z-factor；Z₂Represent the Gaseous Z-factor under downhole condition；P₁Well head pressure is represented, unit is MPa；P₂Represent well Bottom pressure, unit are MPa；T₁Wellhead temperature is represented, unit is K；T₂Bottom hole temperature (BHT) is represented, unit is K；D represents pipe aperture, Unit is m；ρ_g1Gas density under the conditions of well head is represented, unit is kg/m³；ρ_g2Represent that gas density under downhole condition, unit are kg/m³；ρ_LLiquid mixture density is represented, unit is kg/m³, σ represents liquid mixed phase viscosity, and unit is N/m；

If gas well is straight well, liquid Equation for Calculating daily fluid production rate is taken using low gas liquid rate straight well gas：

$q_L=-\frac{Z_1\left(P_2-P_1\right)\·d^2\·\mathrm{\π}}{8\·Z_2\·P_1\·P_2\·T_2}\·{q_g}^2+\frac{2.5}{T_2}\·q_g-\frac{9.3\·{\mathrm{\ρ}}_{g1}\·{\mathrm{\ρ}}_{g2}}{\left({\mathrm{\ρ}}_L-{\mathrm{\ρ}}_{g2}\right)\·\mathrm{\σ}\·T_1}$

Wherein, q_LDaily fluid production rate is represented, unit is m³/d；q_gDaily output tolerance is represented, unit is m³/d；Z₁Under the conditions of representing well head Gaseous Z-factor；Z₂Represent the Gaseous Z-factor under downhole condition；P₁Well head pressure is represented, unit is MPa；P₂Represent well Bottom pressure, unit are MPa；T₁Wellhead temperature is represented, unit is K；T₂Bottom hole temperature (BHT) is represented, unit is K；D represents pipe aperture, Unit is m；ρ_g1Gas density under the conditions of well head is represented, unit is kg/m³；ρ_g2Represent that gas density under downhole condition, unit are kg/m³；ρ_LLiquid mixture density is represented, unit is kg/m³, σ represents liquid mixed phase viscosity, and unit is N/m；

The horizontal gas well gas of low gas liquid rate takes liquid equation or low gas liquid rate straight well gas is taken the maximum that daily fluid production rate reaches in liquid equation and is Critical liquid carry over.