RU2792961C1 - Method for operation of gas and gas condensate wells - Google Patents

Abstract

FIELD: oil and gas industry.

SUBSTANCE: operation of gas, gas condensate and oil wells. The method for operation of gas and gas condensate wells, including flooded ones, consists in the fact that a pipe support and a valve are additionally installed on the X-mas tree above the cross. Produce calculation of conditions for the lowering of a flexible long-length production string (FLPS) and operation of the well in the annulus. Calculate the minimum allowable flow rate Q_min in the well for the current tubing (TBG), which ensures continuous removal of fluid in this TBG. Downhole pressure is determined there. Determine the flow rate in the well Q_well. The values of the minimum flow rate Q_min and the estimated flow rate Q_well are compared and then a conclusion is made about the need to descent the FLPS into the well. Moreover, the lowering is made without killing the well. Management is carried out manually. Further operation of the well takes place along the annulus formed between the TBG and FLPS until the termination of the conditions for ensuring the removal of fluid through the casing-tubing annulus (CTA).

EFFECT: ensure the conditions for the removal of liquid, the prevention of procedures associated with well killing.

2 cl, 1 tbl, 3 ex

Description

The invention relates to the oil and gas industry and can be used in the operation of gas, gas condensate and oil wells.

For the operation of gas and gas condensate wells, tubing strings (LC) are lowered into them, consisting of tubing pipes (tubing pipes) designed to transport fluid from the bottom to the wellhead in any complicated conditions (in the presence of corrosive components, water, gas condensate , oil, mechanical impurities, etc.). During the operation of wells through the tubing lowered into the well, as the reservoir pressure decreases and the volume of incoming fluid increases, the conditions for the removal of fluid at the wellhead are no longer provided (gas velocity decreases), as a result, the fluid accumulates at the bottomhole, which leads to a decrease in the working flow rate and in some cases to self-damping of the well.

To prevent self-damping, the well is killed with special fluids, the existing LK is removed and new tubing of a smaller diameter is lowered.

Usually, after killing, the productive characteristics of the well deteriorate, and the porosity and porosity properties decrease. In depleted fields with low formation pressures as a result of killing, in some cases, wells cannot be developed at all. In this regard, there is a need to carry out work without killing wells.

The prior art method of operating a well by replacing the tubing with pipes of smaller diameter (Buzinov S.N. Justification of the optimal diameter of the lift columns // Problems of gas production. - M.: VNIIGAZ, 1979. -p. 117-125). It is described that due to the fact that as a result of refinement of technological regimes, the flow rates of individual single wells are limited to 200 thousand m3/day. and less, which can cause complications in the operation of wells with a large diameter of tubing strings. This necessitates the replacement of lift pipes in these wells with smaller diameters.

The prior art also knows a method of operating a well by replacing tubing with pipes of a smaller diameter (James Lee, Henry V. Nickens, Michael Wells. Exploitation of flooded gas wells. Technological solutions for removing fluid from wells / translation from English. - M .: LLC " Premium Engineering", 2008. - 384 p., ill. (Chapter 5)).

The cross-sectional area of the channel through which gas is produced (it can be tubing, annulus, or both) determines the capacity of a small diameter column, or a siphon column installed to increase the flow rate, or simply determines how much effectively and for a long time the pipe string through which gas is produced will ensure the operation of the well.

The choice of tubing for a particular well is, on the one hand, to have pipes with a tubing diameter large enough, thereby eliminating excessive friction, and on the other hand, small enough, thereby increasing the flow rate and, therefore, eliminating the possibility of fluid accumulation . The purpose of the selection is to choose a design of the tubing that satisfies these requirements along its entire length. It is also desirable that these requirements be satisfied for a long period of time (several years) before it becomes necessary to replace the well design with a new one.

The choice of tubing diameter for pipe replacement is made by the method of nodal analysis (combination of reservoir and tubing characteristics) and the concept of critical velocity (the minimum velocity at which fluid is carried out). When choosing a tubing diameter to reduce fluid buildup, reservoir performance, lift, and critical velocity should be considered. To prevent accumulation of fluid during well operation and to justify the lowering of pipes of smaller diameter, it is necessary to take into account the nature of the change in well flow rate and pressure in the reservoir and at the wellhead over time.

Lowering pipes of smaller diameter into the well allows increasing the flow rate to a predetermined value and ensuring the removal of fluid from the well for a long time. Generally speaking, higher velocity reduces fluid holdup (percentage of tubing volume occupied by fluid) and reduces dynamic bottomhole pressure, which is associated with the effect of gravity on tubing flow. Excessive reduction in diameter leads to excessive friction pressure losses and contributes to an increase in dynamic bottom hole pressure.

When deciding to run a tubing with a smaller diameter, it should be borne in mind that the next replacement may be required in the future. It is necessary to evaluate the duration of use of a small diameter tubing string, using the method of nodal analysis or comparison with existing operating experience of similar structures.

If liquid accumulates in a small diameter tubing string, it is impossible to perform swabbing and use a nitrogen lift to lift the liquid. The same volume of liquid can be negligible for large diameter tubing and significant for small diameter tubing (in terms of pressure created by the liquid column in the string).

The production potential of the well is limited (the well can operate with a large flow rate, but this will lead to large losses along the wellbore and rapid depletion of reservoir energy).

The disadvantage of these analogues is that the operation of the well is carried out along the production string, where when the tubing is changed to pipes of smaller diameter, the conditions for fluid removal are improved, however, to change the tubing, it is necessary to kill the wells, which significantly reduces the reservoir properties for wells with low formation pressures. formation. As the formation pressure decreases and the volume of the incoming fluid increases, the operation to replace the tubing with pipes of a smaller diameter must be performed again.

A typical well scheme when replacing tubing with pipes of smaller diameter is shown in figure 1). Also known from the prior art is a method for operating a gas well (Patent for Invention No. 2513942), in which the gas well is supplied with a main production string and a central production string concentrically placed in it with the formation of an annular space between them. The end face of the central tubing string is placed below the end face of the main tubing string, and gas extraction is carried out simultaneously along the central tubing string and the annulus. At the same time, there is a control complex at the wellhead, with the help of which the received data are analyzed and a command is sent to the automatic gas flow control valve, optimizing the total well flow rate.

The disadvantage of this analogue is that for the stable operation of the well, it is necessary to install a control complex that allows you to control the gas flows through the central production string and the annulus, as well as maintain the gas flow rate in the central production string in the required range to ensure the conditions for the removal of liquid. In addition, it is required to replace the standard X-mas tree with a modified one, which allows the well to be operated through two channels - the CLC and the MCP.

в скважине для текущей насосно-компрессорной трубы (НКТ), обеспечивающий непрерывный вынос жидкости в данной НКТ, определяют там забойное давление, определяют дебит в скважине

, сравнивают значения минимального дебита

и расчетного дебита

и далее делают вывод о необходимости спуска в скважину ГДЛК, причем спуск производится без глушения скважины, управление производится в ручном режиме, и дальнейшая эксплуатация скважины происходит по кольцевому каналу (пространству), образованному между НКТ и ГДЛК, до момента прекращения условий по обеспечению выноса жидкости по межтрубному кольцевому пространству (МКП). По мере снижения пластового давления или изменении других условий, которые привели к нарушению условий выноса жидкости по МКП при спущенной ГДЛК, производят модернизацию фонтанной арматуры путем установки дополнительной крестовины с соответствующей обвязкой и устанавливают управляющий комплекс для обеспечения регулирования потоков по центральной лифтовой колонне (ЦЛК) и МКП. (фиг.2).The proposed method for the operation of gas and gas condensate wells, including watered ones, consists in the fact that a pipe holder and a valve are additionally installed on the X-mas tree above the cross, the conditions for running a flexible long-length tubing string (GDLK) are calculated and the well is operated along an annular channel (space) between tubing and GDLC, namely, they calculate the minimum allowable flow rate

in the well for the current tubing (tubing), which ensures the continuous removal of fluid in this tubing, determine the bottomhole pressure there, determine the flow rate in the well

, compare the values of the minimum flow rate

and estimated debit

and then they conclude that it is necessary to lower the GDLC into the well, and the descent is carried out without killing the well, the control is carried out in manual mode, and the further operation of the well occurs along the annular channel (space) formed between the tubing and the GDLC, until the conditions for ensuring the removal of liquid are terminated along the annulus annular space (MCP). As the formation pressure decreases or other conditions change that led to a violation of the conditions for the removal of fluid through the MCP with the deflated GDLC, the X-mas tree is modernized by installing an additional cross with appropriate piping and a control complex is installed to ensure flow control through the central production string (CLC) and MCP. (figure 2).

Thus, conditions are created for the removal of fluid from the well through the annulus annulus (ICP). In Fig.1 marked: 1-lift column (tubing); 2 - valve; 3 - device for regulating the flow rate of the well; 4 - cross; 5 - GJ (CLK); 6 - pipe holder; 7 - cross (optional); 8 - control complex (UK).

If it is impossible to operate the well at a given time without a control complex (in manual mode) - significant pressure surges in the gas mixing station (GSS), a significant impact on the operation of neighboring wells in the cluster, etc., the control complex is also installed (in truncated version, because operation on one channel). When the well is put into operation in two columns, the control complex is modernized (equipped with the necessary equipment).

As the formation pressure decreases or other conditions change that led to a violation of the conditions for the removal of fluid through the MCP when the GDLC is lowered, the Christmas tree is upgraded, (figure 3) - an additional crosspiece 7 with piping is installed in order to ensure the possibility of operating the well in two channels - MCP and CLC, and provide for the installation of a control complex 8 to ensure the regulation of flows through the CLC and MCP. Thus, this makes it possible to operate the well more rationally in terms of reservoir energy conservation.

The technical result of the invention is expressed in ensuring the conditions for the removal of fluid, the rational use of reservoir energy, reducing the cost of the required equipment (control complex, a one-time complete modernization of the Christmas tree), as well as preventing procedures associated with killing the well.

To select the optimal CLC diameter, the well operation is calculated after the proposed CLC is lowered under the current thermobaric conditions of the well operation, as well as a predictive calculation for 3-5 years (calculation is made for all pipes from a range of 73, 89, 102, 114 mm). Graphical dependencies (indicator curves) of well operation are built for all pipes. The choice of the optimal diameter of the CLC is made by determining the option with the closest possible well operation to the design one (minimum pressure losses are ensured, the required flow rate is ensured, well restriction conditions are met, etc.).

The calculation of the well operation modes is carried out, for example, according to the method proposed in STO Gazprom 2-2.3-1017-2015 “Operation of gas wells of the fields of the Nadym-Pur-Taz region using concentric lift columns”.

Designations:

- минимальная допустимая скорость газа, необходимая для выноса жидкости, м/с (Точигин А.А., Одишария Г.Э. Прикладная гидродинамика газожидкостных смесей. - М.: Всероссийский научно-исследовательский институт природных газов и газовых технологий. Ивановский государственный энергетический университет, 1998. - 400 с);

- the minimum allowable gas velocity required for the removal of liquid, m / s (Tochigin A.A., Odisharia G.E. Applied hydrodynamics of gas-liquid mixtures. - M .: All-Russian Research Institute of Natural Gases and Gas Technologies. Ivanovo State Energy University , 1998. - 400 s);

- внутренний диаметр ЛК, м;

- internal diameter of LC, m;

- эквивалентный диаметр, м;

- equivalent diameter, m;

- пластовое давление, МПа;

- formation pressure, MPa;

- устьевое давление, МПа;

- wellhead pressure, MPa;

- забойное давление, МПа;

- bottomhole pressure, MPa;

- приведенное давление,

- reduced pressure,

- критическое давление газа, МПа;

- critical gas pressure, MPa;

- давление (среднее по лифтовой колонне), МПа,

- pressure (average over the tubing string), MPa,

- давление в стандартных условиях, 10⁵ Па;

- pressure under standard conditions, 10 ⁵ Pa;

- пластовая температура, К;

- formation temperature, K;

- температура в стандартных условиях, 273,15 К;

- temperature under standard conditions, 273.15 K;

- забойная температура, К;

- bottomhole temperature, K;

- температура газа (средняя по колонне);

- gas temperature (average over the column);

- температура на устье скважины, К;

- wellhead temperature, K;

- приведенная температура, К;

- reduced temperature, K;

- критическая температура газа, К;

- critical gas temperature, K;

- эмпирический коэффициент;

- empirical coefficient;

- ускорение свободного падения, 9,8 м/с²;

- free fall acceleration, 9.8 m/s ² ;

- экспонента (число Эйлера ≈ 2,718);

- exponent (Euler number ≈ 2.718);

- коэффициент поверхностного натяжения жидкости, Н/м;

- coefficient of surface tension of the liquid, N/m;

- плотность жидкости, кг/м³;

- liquid density, kg/m ³ ;

- угол наклона ЛК к горизонту, град;

- LK tilt angle to the horizon, deg;

- плотность газа на забое, кг/м³.

- gas density at the bottomhole, kg/m ³ .

- плотность газа в стандартных условиях, кг/м³;

- gas density under standard conditions, kg/m ³ ;

- безразмерный параметр;

- dimensionless parameter;

- коэффициент сопротивления ствола скважины;

- wellbore drag coefficient;

- относительная плотность газа по воздуху;

- relative density of gas in air;

- длина ЛК, м;

- LK length, m;

- коэффициент сверхсжимаемости газа (средний по колонне);

- coefficient of gas supercompressibility (average for the column);

- коэффициент гидравлического сопротивления колонны;

- coefficient of hydraulic resistance of the column;

- коэффициент гидравлического сопротивления МКП;

- coefficient of hydraulic resistance of the MCP;

- линейный коэффициент фильтрационного сопротивления пласта,

- linear coefficient of filtration resistance of the formation,

- квадратичный коэффициент фильтрационного сопротивления пласта,

- quadratic coefficient of formation filtration resistance,

- дебит газа по МКП, тыс.м³/сут.

- gas flow rate according to the MCP, thousand m ³ / day.

The initial data for the calculation are given in Table 1.

1. Calculation of the minimum allowable flow rate for the current tubing.

для забойных (пластовых) условий по формуле1.1. Determine the reduced temperature

for downhole (reservoir) conditions according to the formula

для забойных (пластовых) условий по формуле1.2. Determine the reduced pressure

for downhole (reservoir) conditions according to the formula

1.3. The coefficient of supercompressibility for bottomhole (reservoir) conditions is determined by the formula

1.4. Calculate the density of the gas under working conditions at the bottom according to the formula

1.5. The minimum allowable gas velocity for liquid removal is determined by the formula:

для непрерывного выноса жидкости по текущей НКТ по формуле:1.6. Determine the value of the minimum allowable gas flow rate,

for continuous removal of fluid along the current tubing according to the formula:

1.7. The value of the minimum allowable gas flow rate Q _min is multiplied by a factor of 1.1

2. Determination of bottomhole pressure in the well for the current tubing.

The bottomhole pressure in the well is determined (solved by the method of successive approximations) for the current tubing (the last step of the solution is shown).

2.1. Calculate the average value of the temperature along the wellbore according to the formula

2.2. The reduced temperature value is calculated by the formula

2.3. Calculate the average value of pressure along the wellbore according to the formula

2.4. Calculate the reduced pressure value by the formula

2.5. Calculate the average value of the gas supercompressibility coefficient along the trunk according to the formula

2.6. The parameter S is calculated by the formula

2.7. Calculate the drag coefficient of the wellbore 9 according to the formula:

2.8. Bottomhole pressure is calculated for the current tubing according to the formula

2.9. The well flow rate is determined by the formula

скважина не может обеспечить вынос жидкости с забоя, необходимо произвести спуск ГДЛК и эксплуатировать скважину по МКП для обеспечения выноса жидкости.Given that

the well cannot provide liquid carryover from the bottomhole, it is necessary to run the GDLC and operate the well according to the MCP to ensure the liquid carryover.

3. Determination of the value of the minimum allowable gas flow rate according to the MCP

As an example, the calculation will be made for GDLK with an outer diameter of 73 mm and an inner diameter of 50 mm.

3.1. Determine the value of the equivalent diameter by the formula

3.2. The minimum allowable gas flow rate according to the MCP is determined by the formula

4. Calculation of the value of pressure at the bottom of the well when gas moves only along the MCP

4.1. Calculate the average temperature value according to the MCP according to the formula

4.2. The reduced temperature value is calculated by the formula

4.3. Calculate the average value of pressure according to the MCP according to the formula

4.4. Calculate the reduced pressure value by the formula

4.5. Calculate the MCP average value of the gas supercompressibility coefficient by the formula

4.6. The parameter S is calculated by the formula

4.7. Calculate the coefficient of resistance of the MCP by the formula

4.8. The bottomhole pressure for the MCP is calculated using the formula

4.9. Calculate the new value of the well flow rate by the formula

больше значения минимально допустимого дебита газа по МКП, то эксплуатация скважины производится только по МКП до тех пор, пока обеспечивается данное условие. После этого производится модернизация фонтанной арматуры с установкой управляющего комплекса и дальнейшая работа скважины осуществляется по КЛК. Производится расчет режимов работы скважины по КЛК:4.10. Since the value of the well flow rate

is greater than the value of the minimum allowable gas flow rate according to the MCP, then the well is operated only according to the MCP until this condition is met. After that, the X-mas tree is modernized with the installation of a control complex, and further well operation is carried out according to the KLK. Calculation of well operation modes according to QLK is carried out:

4.11. The minimum allowable gas flow rate for the CLC is determined by the formula

4.12. The value of the minimum allowable gas flow rate for the CLC, we multiply by a factor of 1.1

5. Calculation of the well operation mode during operation along the central production string and annular annulus

5.1. Calculation of the bottomhole pressure value for the central tubing string

5.1.1. Calculate the average temperature value according to the CLC according to the formula:

5.1.2. The reduced temperature value is calculated by the formula:

5.1.3. Calculate the average value of pressure according to the CLC according to the formula:

5.1.4. Calculate the reduced pressure value by the formula:

5.1.5. Calculate the average value of the coefficient of supercompressibility of the gas according to the formula:

5.1.6. The parameter S is calculated by the formula:

5.1.7. Calculate the coefficient of resistance of the CLC according to the formula:

5.1.8. Calculate the bottomhole pressure for the CLC according to the formula

5.1.9. Calculate the new value of the well flow rate by the formula

5.2. We determine the value of pressure at the wellhead in the MCP

5.2.1. We determine the value of the gas flow rate according to the MCP according to the formula

5.2.2. Calculate the average temperature value according to the MCP according to the formula:

5.2.3. The reduced temperature value is calculated by the formula:

5.2.4. Calculate the average value of pressure according to the MCP according to the formula:

5.2.5. Calculate the reduced pressure value by the formula:

5.2.6. Calculate the MCP average value of the gas supercompressibility coefficient by the formula:

5.2.7. The parameter S is calculated by the formula:

5.2.8. Calculate the coefficient of resistance of the MCP by the formula:

5.2.9. Calculate the pressure at the wellhead in the MCP according to the formula

5.2.10. The pressure at the wellhead in the MCP is compared with the pressure in the plume (pressure at the wellhead in the CLC).

1.398 > 1.35 - this confirms the need to install a control complex to regulate flows through the MCP and CLC.

Claims (2)

1. The method of operating gas and gas condensate wells, including those flooded, which consists in the fact that a pipe holder and a valve are additionally installed on the X-mas tree above the cross, the conditions for running a flexible long-length tubing string (GDLK) are calculated and the well is operated through the annulus, and namely: calculate the minimum allowable flow rate Q _min in the well for the current tubing (tubing), which ensures continuous removal of fluid in this tubing, determine the bottomhole pressure there, determine the flow rate in the well Q _well , compare the values of the minimum flow rate Q _min and the calculated flow rate Q _well and then conclude that it is necessary to run the GDLC into the well, and the descent is carried out without killing the well, the control is carried out in manual mode, and further operation of the well occurs along the annular space formed between the tubing and the GDLC until the termination of conditions for ensuring the removal of fluid along the annular annulus space (MCP). 2. The method according to p. 1, characterized in that as the reservoir pressure decreases and the well flow rate changes, which led to a violation of the conditions for the removal of fluid through the MCP with the GDLC lowered, the X-mas tree is modernized by installing an additional cross with appropriate piping and a control complex is installed to ensure the regulation of flows through the central lifting column (CLC) and MCP.

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