RU2620137C1 - Gas-condensate well operation method - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: method comprises measurement of thermobaric parameters such as wellhead pressure and wellhead temperature, determination of gas supercompressibility, maintenance of well discharge wellhead choke not less than critical by regulating, providingformation fluid export from the bottomhole. Wherein the critical well discharge is determined by the following formula:

, where Q is well gas discharge necessary for liquid export through a lifting pipe, P_wh is wellhead pressure; D is internal diameter of the lifting pipe; T_wh is wellhead temperature; Z is gas supercompressibility coefficient corresponding to wellhead and critical values of pressure and temperature.

EFFECT: reduced losses of retrograde condensate and prevention of liquid accumulation in wellbore.

1 ex

Description

The invention relates to methods of operating gas and gas condensate wells and can be used to reduce the loss of retrograde condensate and prevent the accumulation of fluid in the wellbore.

A known method of operating a gas condensate well, which includes determining the surface tension coefficient of the gas condensate, which determines the critical droplet size of the gas condensate, above which the droplet is crushed, and calculates the critical gas flow rate that ensures the removal of the critical droplet, while the well is operated at wellhead pressure, temperature and flow rates above critical, ensuring the existence of a dispersed system of condensate droplets in the well that suspended in gas [RU 2120541 C1, IPC ⁶ ЕВВ 43/00, publ. 05/10/1998].

The disadvantages of this method include the fact that the calculation of the critical velocity is suitable for the removal of finely dispersed liquid in the flow core, but does not take into account liquid droplets ejected as a result of turbulent gas pulsations onto the pipe walls. Thus, moisture agglomeration in the liquid film is possible on the pipe walls and, under certain dynamic and thermobaric conditions, it can drain to the bottom of the well.

There is a known method of fluid removal from the bottom of a well with gas, in which gas-dynamic studies (GDI) are carried out at the well in stationary filtration modes, during the GDI gas flow rate is changed to the value at which the fluid is removed, and then the gas flow rate on the pump shoe is calculated compressor pipes (tubing) and determine the minimum flow rate that ensures the removal of fluid from the bottom of the well [RU 2124635 C1, IPC ⁶ Е21В 47/10, Е21В 43/00, publ. 1999].

The disadvantages of the known method include the fact that to calculate the critical gas flow rate, it is necessary to conduct gas-dynamic studies, so that the essence of the method is reduced to direct observation of the process of fluid removal in one mode or another and calculation of the critical flow rate does not make sense, i.e. the inverse problem is solved.

The technical problem is the establishment of the technological mode of operation of the well, in which the conditions for the removal of condensation liquid and retrograde condensate will be satisfied.

When implementing the claimed technical solution, the problem posed is solved by achieving a technical result, which consists in reducing the loss of retrograde condensate and preventing its accumulation, as well as condensation water at the bottom of the well, by establishing the required production rate of the produced product - formation fluid, fluid (two-phase gas condensate mixture).

The specified technical result is achieved by the fact that in the method of operating a gas or gas condensate well by raising the formation fluid to the wellhead while maintaining wellhead flow control by the well’s flow rate is not less critical, ensuring the formation fluid is removed from the bottom including measuring pressure and wellhead parameters, such as wellhead pressure and wellhead temperature , determination of the gas supercompressibility coefficient, a feature is that the critical well rate is determined according to the expression

where Q is the gas flow rate of the well, necessary for the removal of fluid through the riser, thousand m ³ / day; R _mouth - wellhead pressure, 0.098 MPa or kgf / cm ² ; D is the inner diameter of the lifting pipe, m; T _mouth - wellhead temperature, K; Z is the gas compressibility coefficient corresponding to wellhead and critical pressures and temperatures.

The causal relationship between the claimed technical result and the essential features characterizing the essence of the claimed technical solution is as follows.

The determination of the flow rate required for the removal of condensation water, retrograde condensate according to the proposed formula will provide the necessary flow regime for the produced fluid - formation fluid (flow of produced products, two-phase gas-condensate mixture) to prevent the accumulation of finely dispersed liquid at the bottom and walls of the well. In this case, the calculation of the flow rate for the removal of fluid according to the claimed solution is suitable for both vertical and horizontal sections of the lifting pipes (tubing, elevator column). Reduction of losses of retrograde condensate will occur due to the same conditions that are suitable for the removal of liquids (condensation, produced water).

The essence of the proposed method

The flow of ascending gas will bend around a single fluid particle located on the wall of the pipe. Upon reaching a certain gas velocity, a liquid particle will be carried away from the pipe wall, thereby preventing the formation of a liquid film.

Thus, the forces in equilibrium and acting on a fluid particle located in a vertical pipe can be represented as:

where Ftp is the friction force, Ftension is the force of gravity acting on the particle; Fout - lifting force; R is the resistance force.

In this case, the gravity force F is expressed by the ratio [Lee James, Nickens Henry, Wells Michael “Operation of waterlogged gas wells. Technological solutions for the removal of fluid from wells. - M.: LLC “Premium Engineering”, 2008. - 384 p.]:

Where:

g is the constant of gravity, m / s ² ;

g _c - gravity constant, kg m / kgf s ² ;

v _d is the droplet velocity, m / s;

d is the diameter of the drop, m;

ρ _W - the density of the liquid phase, kg / m ³ ;

ρ _g - gas density, under given conditions, kg / m ³ .

The lifting force F is determined by the formula [Lee James, Nickens Henry, Wells Michael, “Operation of Watered Gas Wells. Technological solutions for the removal of fluid from wells. - M.: LLC “Premium Engineering”, 2008. - 384 p.]:

Where

v _G is the gas velocity, m / s;

v _d is the droplet velocity, m / s;

ρ _g - gas density, kg / m ³ ;

A _d is the projection area of the cross section of the drop, m ² ;

C _D - drag coefficient.

The friction force is determined by the mathematical formula

Where

g is the constant of gravity, m / s ² ;

d is the diameter of the drop, m;

ρ _W - the density of the liquid phase, kg / m ³ ;

The resistance force R is determined by the formula [Lee James, Nickens Henry, Wells Michael “Operation of waterlogged gas wells. Technological solutions for the removal of fluid from wells. - M.: LLC “Premium Engineering”, 2008. - 384 p.]:

Where

ρ _g - gas density, kg / m ³ ;

d is the diameter of the drop, m;

C _D - drag coefficient.

Then the equation for the critical gas velocity has the following form:

From (7), one can express the equation for calculating the critical velocity for liquid particles located on the pipe wall:

Where

v _G is the gas velocity, m / s;

σ is the surface tension, n / m;

ρ _W - the density of the liquid phase, reduced to a given pressure and temperature, kg / m ³ ;

ρ _g - gas density, under given conditions, kg / m ³ ;

C _D - drag coefficient.

The considered option for calculating the critical velocity allows us to describe the process of fluid removal only for a vertical flow. Based on this, the conditions for the removal of fluid in a horizontal flow are determined.

The forces acting on a particle located on the wall of a horizontal pipe can be written in the form of the following system of equations:

where N is the reaction force of the support.

Having written equation (10) in expanded form, we obtain:

From the system of equations (10), one can obtain an expression for calculating the critical flow rate in a horizontal pipe section:

Comparing the formulas for the horizontal and vertical pipe sections, we obtain that, under equal conditions, the critical flow rate in the horizontal pipe section is 1.5 times less than the critical velocity for the vertical pipe section.

Thus, to determine the limiting conditions necessary for the removal of fluid along the wellbore and from the bottom of the well, it is necessary to use the formula for a vertical pipe. In this case, high critical speeds will be obtained, which, therefore, will be optimal for all sections of tubing.

To obtain the critical well production rate, it was found that for a highly turbulent gas flow (operation mode of all gas condensate wells), C _D - drag coefficient becomes a constant value equal to 0.44.

Based on the actual data on the operation of wells in Western Siberian fields, using the formula (8), taking into account the drag coefficient C _D = 0.44, critical velocities were calculated and a power-law dependence of the critical velocity v _G on wellhead pressure was obtained:

Where

v _G is the gas velocity, m / s;

R _mouth - pressure at the wellhead, 0.098 MPa or kgf / cm ² .

According to the obtained dependence, it is possible to obtain the necessary value of the critical velocity at a wellhead wellhead pressure. From the obtained dependence, one can find the critical flow rate reduced to standard conditions, according to expression (1), which is the most convenient value for practical use.

The method is as follows.

During well operation, according to the results of the GKI (gas condensate well study), the actual thermobaric performance indicators and fluid properties are determined:

wellhead pressure P, MPa or kgf / cm ² ;

wellhead temperature T _mouth , K;

critical gas parameters: pressure P _cr , T _cr .

In the absence of GKI, the critical parameters of the gas are taken by analogy, or according to the accepted model of reservoir fluid.

According to the data obtained, the coefficient of supercompressibility is calculated according to the expression of V.V. Latonova - G.R. Gurevich:

Where

P _cr - the critical pressure of the reservoir fluid, MPa;

T _cr - the critical temperature of the reservoir fluid, K;

P is the pressure at the wellhead, MPa;

T is the temperature at the wellhead, K.

Then calculate the flow rate (critical flow rate) of the reservoir fluid (two-phase gas-condensate mixture), in which the fluid particles will be in suspension (an indicator of the moment of equilibrium of the system)

A necessary condition for the extraction of the retrograde condensate and condensation liquid deposited in the wellbore will be the excess of the actual flow rate of the reservoir fluid over the flow rate at which the moment of system equilibrium is reached (critical flow rate).

If in the actual mode of operation of the well, the production rate is lower than necessary, then the operating mode of the well is selected by increasing the production rate to a calculated value that ensures the gas flow rate, above the minimum necessary, for example, by adjusting the wellhead nozzle.

Thus, the inventive method of operation can optimize the operation of the well.

Example

Well X of the Urengoyskoye oil and gas condensate field equipped with a liner is characterized by the following initial (current) data as of the date of calculation:

1. Wellhead pressure - 418 kgf / cm ² ;

2. Wellhead temperature - 318 K;

3. Critical gas parameters: pressure - 46.9 kgf / cm ² , temperature - 212 K;

4. The inner diameter of the tubing is 0.076 m.

According to the calculation formulas determine:

- gas supercompressibility coefficient:

;

;

Calculation of critical flow rate in a riser:

The actual gas flow rate at the mouth was 210 thousand m ³ / day, which is more than the calculated critical flow rate (minimum acceptable) of 149.7 thousand m ³ / day.

Thus, the conditions for the extraction of the retrograde condensate and condensation liquid deposited in the wellbore are met at this well. When the flow rate is less than the calculated value (the minimum allowable), the wellhead fitting establishes the technological mode of operation, which ensures the removal of liquid (condensation water, retrograde condensate) through the tubing.

Claims (7)

A method of operating a gas or gas condensate well, including measuring thermobaric parameters, such as wellhead pressure and wellhead temperature, determining the gas compressibility coefficient, and maintaining the wellhead flow rate by controlling the wellhead nozzle not less than critical, which ensures formation fluid removal from the bottom, characterized in that the critical well flow rate is determined according to the formula:

, where: Q is the gas flow rate of the well, necessary for the removal of fluid through the riser; R _mouth - wellhead pressure; D is the inner diameter of the lifting pipe; T _mouth - wellhead temperature; Z is the gas compressibility coefficient corresponding to wellhead and critical values of pressure and temperature.