RU2706283C2 - Method of optimal operation of gas and gas condensate wells with high liquid content - Google Patents

Abstract

FIELD: soil or rock drilling; mining.

SUBSTANCE: invention relates to gas production and can be used in development of gas and gas condensate fields. Method provides for use of design model mathematically describing movement of gas-liquid flow in well, including in conditions of its foaming with surface-active substances (SAS), software implemented in computation module of autonomous industrial controller, allowing in continuous mode to determine completely unknown parameters of well operation, such as amount of condensation (distilled) water, which has passed into liquid phase from natural gas in upper sections of well shaft, flowing downwards along flow column or production tubing (tubing string) and accumulating at well bottom, amount of liquid gas condensate transferred into liquid phase from natural gas in upper sections of well shaft, flowing downward along the tubing string and accumulating on the bottomhole of the well, amount of water coming from the formation (or into formation), amount of liquid gas condensate coming from the formation (or into the formation), gas/carbonated gas separation depth in the wellbore, carbonated liquid/liquid separation depth in the wellbore, thickness of the water-cut part of the perforation interval (filter), which determines the well current productivity by gas and the well productivity by water, as well as use for self-tuning measured by appropriate equipment or in continuous mode to calculate temperature at well bottom, pressure at well bottom, gas flow rate, condensate-gas flow factor at wellhead, water-gas flow factor at wellhead, flow rate of hydrate inhibitor based on user-defined invariable parameters of well, such as formation temperature, formation pressure in area of well, depth of well to bottomhole, depth of bottom of tubing, depth of upper and lower marks of perforation interval or filter in productive formation, inner diameter of tubing string, internal diameter of production string or filter, angles of deviation of trajectory from vertical, type of well perforation, gas effective formation thickness, filtration resistance coefficients in equation of gas influx to well, mineralization of formation water, as well as parameters of the corresponding telemetering equipment in continuous mode and parameters coming to the controller, such as well head temperature, well head pressure, pressure in annular space of well, pressure at well bottom in case of packer operation, temperature downstream of gas flow rate regulator, pressure downstream of gas flow rate regulator, flow rate regulator of flow rate regulator id, and also allowing in continuous mode to predict well operation mode for a given period of time, including dynamics of all listed parameters, including in conditions of supply of liquid surfactant solution by means of corresponding equipment, depending on schedule of control parameters, such as set pressure in gas collection collector and type of used SAS, and depending on schedule of control parameters, such as the installed flow rate of the flow rate regulator, the installed surfactant solution flow rate, the SAS set concentration, as well as in the continuous mode interacting with the optimiser, allowing to perform adjustment of model parameters by dynamics of known well operation parameters and allowing selection of optimal schedule of control parameters for their transfer to controller as settings for control of control equipment.

EFFECT: method makes it possible to efficiently remove liquid from gas or gas condensate wells, providing stable extraction of gas.

10 cl, 4 dwg

Description

The invention relates to gas production and can be used for the operation of gas and gas condensate wells (including inclined and horizontal) with a high liquid content. The accumulation of fluid at the bottom of a gas or gas condensate well leads to a decrease in its flow rate or to a complete shutdown of the well.

Mineralized water of natural origin or process water coming from the formation may act as a fluid accumulating at the bottom of the well borehole; liquid gas condensate from the reservoir; gas condensate, which transferred to the liquid phase during the movement of natural gas in the upper sections of the wellbore, flowing down the tubing string (hereinafter tubing) and accumulating at the bottom of the well; condensation (distilled) water transferred to the liquid phase from natural gas in the upper sections of the wellbore, flowing down the tubing string and accumulating at the bottom of the well; an aqueous or other solution of a hydrate inhibitor supplied to the well through a pipe or annulus and flowing down to the bottom of the well. All of the listed fluids can be delivered to the bottom of the well simultaneously in different quantities.

The accumulation of liquid occurs due to the insufficient flow rate of the gas-liquid mixture in the production string (hereinafter referred to as EC), including in the interval of perforation or filter, as well as in elevator (tubing) pipes located inside the EC. With high gas flow rates and a large gas-liquid ratio, the flow velocity is sufficient to carry the dropping liquid (over 2-5 m / s, depending on a number of parameters).

The problem to which the proposed solution is directed, arises:

(a) with an increase in the proportion of fluid (mainly produced water) in the fluid extracted from the formation. Large volumes of fluid entering the bottom of the well do not have time to be brought to the surface at the same gas flow rates in the wellbore. The resulting hydraulic resistance leads to a decrease in the gas flow rate of the well, to the accumulation of liquid at the bottom with a gradual complete killing of the well by hydrostatic pressure. In addition, due to watering the formation, the gas flow rate and gas flow rate decrease due to a decrease in the gas-saturated thickness of the formation and a decrease in the phase permeability of the formation through gas with an increase in the proportion of liquid in the reservoir rock.

(b) with a gradual decrease in gas flow rates (speeds) due to the impossibility of a further decrease in bottomhole pressure following a natural decrease in pressure in the formation. To continue to reduce wellhead and downhole pressure, basically, does not allow compressor equipment. As a result, even with a low liquid content in the gas (for example, only condensation water), it is not removed from the well and gradually accumulates, which leads to a decrease in the gas flow rate and to a shutdown of the well.

Both reasons (a) and (b) can occur, either individually or together.

The following methods are known for removing liquid from a gas well: re-equipment / retrofitting of compressor equipment to obtain lower pressures at the wellheads; periodic "purge" of wells from the fluid to the flare line; replacement of elevator pipes with pipes of smaller diameter; “Purging” of wells through the annulus with high-pressure gas from “donor wells” without gas loss; the use of concentric elevator systems (pipe in a pipe, or “tubing + pipe”) for periodic cleaning of a well from a liquid by working through an internal pipe; the use of downhole arrangements for pumping fluid; the use of “plunger elevator” systems (an elevator column equipped with a “flying” vessel, collecting and transporting liquid at the mouth, is pushed out by gas pressure); the use of foaming solid and liquid substances (including solutions of surfactants, hereinafter referred to as surfactants) with their supply to the face.

A known method of removing fluid from a well / RU 2248443 C1, MPK7 EV 43/00, publ. 2005 /, including the introduction into the well of the composition of foaming and gas-forming substances, their dissolution in formation water, the formation of foam and gas and the replacement of fluid in the well with foam. A water-soluble foaming agent with a foam stabilizer and a reaction initiator, as well as a gas-forming substance, are introduced into the well. In order to increase the efficiency of liquid removal from gas wells, the required amount of surfactant is supplied through the annulus of the well. The amount of the necessary substance for supply is determined by measuring many parameters of the well, the volume of accumulated fluid is determined by the measured parameters and the moment of surfactant supply is identified.

Known methods have disadvantages due to the fact that the equipment used or in the calculation algorithms either do not take into account or do not indicate parameters that affect the efficiency and efficiency of the method. These parameters are: well slope; type of formation fluid to be removed; the type and concentration of the foaming agent supplied to the bottom of the well, and the rate of destruction of the foam; a method of supplying a foaming substance to the bottom or into the wellbore; the rate of fluid flow from the formation and / or reverse filtration of condensation water into the formation; the presence at the bottom of the well of sandy clay deposits that begin to move at the mouth when foaming the flow; well flow control mode for the most efficient removal of fluid from the bottom; the need for a hydrate inhibitor to be fed into the well and its effect on foaming efficiency; options for well equipment at the wellhead associated with their placement on land or on the sea shelf, etc.

The problem to which the claimed technical solution is directed is to develop a method for operating gas and gas condensate wells with a high fluid content, which provides for the effective removal of fluid accumulating in a gas or gas condensate well, and which allows to increase the extraction of gas and gas condensate from the formation.

In the implementation of the invention, the task is solved by achieving a technical result, which consists in reducing or eliminating the irrevocable loss of gas for “purging” wells to the flare line; reducing the amount of foaming agents; increasing the resulting gas production rate of the well or the accumulated gas production over a certain period of time; reducing the time spent on reaching the target well operation mode; reducing the amount of hydrate inhibitor supplied to the slaughter; reduction of the well overhaul period.

The specified technical result is achieved by the fact that the method of optimal operation of gas and gas condensate wells with a high fluid content involves the use of a computational model that mathematically describes the movement of a gas-liquid stream in a well, including under conditions of its foaming by surface-active substances (SAW), programmatically implemented in a computational module autonomous industrial controller that allows to continuously determine completely unknown parameters of the well, as the amount of condensation (distilled) water transferred to the liquid phase from natural gas in the upper sections of the wellbore flowing down the tubing string and accumulating at the bottom of the well, the amount of liquid gas condensate transferred to the liquid phase from natural gas in the upper sections of the wellbore, flowing down the tubing string and accumulating at the bottom of the well, the amount of water coming from the formation (or into the formation), the amount of liquid gas condensate coming from the formation (or into the formation), the gas / gas bath fluid in the borehole, the depth of the soda / liquid section in the borehole, the thickness of the watered part of the perforation interval (filter), which determines the current gas productivity of the well and the productivity of the well in water, as well as use the parameters measured by the corresponding equipment for self-tuning, or continuously calculate temperature at the bottom of the well, pressure at the bottom of the well, gas flow rate, condensate-gas flow factor at the wellhead, water-gas flow factor at the wellhead, flow rate of the hydra inhibitor formation based on user-defined constant parameters of the well, such as reservoir temperature, reservoir pressure in the well area, well depth to bottom, tubing bottom depth, depth of the upper and lower marks of the perforation or filter interval in the reservoir, tubing inner diameter, production casing inner diameter or filter, the angles of deviation of the trajectory from the vertical, the type of perforation of the well, the gas working effective thickness of the reservoir, the coefficients of filtration resistance in the flow equation and gas to the well, the mineralization of produced water, as well as continuously measured by the corresponding telemetry equipment and entering the controller parameters, such as temperature at the wellhead, pressure at the wellhead, pressure in the annulus of the well, pressure on the bottom of the well in case of packer operation , the temperature after the gas flow rate regulator, the pressure after the gas flow rate regulator, the identifier of the diameter of the flow area of the gas flow rate regulator, as well as allowing continuous to determine the mode of operation of the well for a given period of time, including the dynamics of all of the above parameters, including when surfactant is supplied with appropriate equipment, depending on the schedule of control parameters, such as the set pressure in the gas collection manifold and the type of surfactant used, and depending on the schedule of regulating parameters, such as the set diameter of the flow area of the gas flow rate regulator, the set flow rate of the surfactant solution, the set concentration of the surfactant, and also in continuous operation -interacting with the optimizer allows to perform the setting of model parameters to the dynamics of the known parameters of the well operation and to allow for the selection of optimal schedules regulating parameters for transmission to the controller as setpoint for controlling the control equipment.

The method of optimal operation of gas and gas condensate wells with a high liquid content can be used on a gas or gas condensate well, which can be equipped with wellhead piping designed for its operation both on land and offshore, can have an inclined or horizontal trajectory at any point.

The source of electricity for the operation of measuring and control equipment can be autonomous.

Automatic surfactant supply into the well may include its forced injection into the annulus, into the tubing space from the wellhead, as well as its supply to the bottom via a capillary tube located both in the tube and in the annulus of the well (between EC and tubing).

The capillary tube may be equipped with a downhole pressure / temperature sensor or a system of distributed pressure / temperature sensors in the interval of the borehole bottom.

The presence of the inhibitor supply line allows, if necessary, the automatic supply of surfactants to the well together with the supply of a hydrate inhibitor by adding a surfactant after the flow regulator of the hydrate inhibitor.

Surfactant can be supplied to the well via a separate line laid from a centralized storage facility for surfactants or from a gas collection and treatment point.

Surfactant can be supplied to the well via an inactive hydrate formation inhibitor supply line, as well as using regulatory equipment to supply a hydrate formation inhibitor.

A container with a surfactant solution, equipment and lines for its supply may include a heating system to protect against freezing.

A container with a surfactant solution can be connected to a system for preparing a surfactant solution of the required concentration.

Equipment for the automatic supply of a surfactant, an inhibitor of hydrate formation and for regulating the gas flow rate can have pneumatic drives that use gas from the well to provide energy to the regulators and pumps due to the gas pressure from the well in order to reduce the energy consumption of the system.

The method provides for additional measurements of the parameters of the well using the following equipment: an echo sounder in the annulus (for a bagless circuit), a sensor for the amount of impurities in the gas stream, a single-phase / multiphase flow meter (or separation unit), a system for distributed measurement of bottomhole pressure and temperature at several points . This equipment and measurements are necessary for more precise adjustment of the calculation model of the computing module of the industrial controller in order to more efficiently operate the well and achieve the specified technical result. The listed equipment may be used periodically and not be permanently connected to the well.

The method involves the use of a computational model that includes the segment structure of the well path: different lengths, diameters and tilt angles (deviation from the vertical) of each well segment. The calculation model may include an interval characteristic of the filtration properties of the productive formation and uneven flow of gas and liquid from the interval of opening the formation by the well.

The method takes into account (or calculates) the rate of fluid flow from the reservoir (into the reservoir) at each time point, the different type of fluid removed from the well, including a mixture of produced water, condensation water, a hydrate inhibitor, gas condensate (of different component composition and density) in any ratios. The ratio of produced water, condensation water, a hydrate inhibitor and gas condensate can also be calculated for each segment and the interval of drilling at each time point.

The calculation model may provide for a different type of foaming agent supplied to the well.

The method provides for calculating the required amount of a hydrate inhibitor for hydrate-free well operation, respectively, the functions of controlling the flow of a hydrate inhibitor can be transferred to the system controller, or the system may include equipment for supplying a hydrate inhibitor;

The calculation model can use well-known calculation methods and experimental functions.

The selection of the optimal operating mode of the well for fluid removal can be carried out taking into account the imposed restrictions on the intensity of removal of mechanical impurities from the well when a certain gas flow rate at the wellhead is reached according to monitoring the amount of mechanical impurities in the gas stream.

The industrial controller can be connected to remote information transmission systems.

The method can be used in gas production control systems, while the calculation model and the controller can receive the necessary target settings from the upper level systems.

The software, including the calculation model, can function remotely (including on the basis of a separate computing infrastructure), receiving information from the system (controller) and controlling the system (controller) via communication channels.

Third party software can be used as an optimizer in the calculation model.

The method provides that the adjustment of the calculation model, optimization calculations and well control are performed in parallel, including using parallel computing technologies.

Between the claimed technical result and the essential features of the invention there is the following causal relationship. The surfactant solution supplied to the well allows the foam to accumulate in the well and to remove it with a gas stream at high pressure in the gas collector, or to continuously operate the well in the presence of fluid, which can increase the extraction of gas and gas condensate from the formation, minimize or eliminate irretrievable gas losses for flushing wells to the flare line, to maximize the overhaul period of the well. The software and calculation model of the computational module allows determining unknown parameters of the well’s operation and predicting the well’s operating mode under surfactant supply conditions, which makes it possible to establish a relationship between the amount of surfactant supplied and gas production rate. The optimizer included in the calculation model allows minimizing the amount of foaming agents supplied, maximizing the resulting gas production rate of the well, or accumulated gas production over a certain period of time, minimizing the time taken to reach the target well operation mode, and minimizing the amount of hydrate inhibitor supplied to the bottom.

The method of optimal operation of gas and gas condensate wells with a high fluid content is illustrated by the drawings, where in FIG. 1 schematically shows the minimum necessary equipment for applying the method. The case is shown when surfactant is supplied to the annulus of the well, which is possible in the case of tankless operation of the well, when the space between the EC and tubing (annulus) communicates with the inner space of the tubing at the bottomhole level and there is access to the annulus from the wellhead.

In FIG. 2 schematically shows the maximum set of equipment for applying the method, as well as for the case when a solution of a hydrate inhibitor is supplied to the well to prevent the formation of hydrates.

In FIG. 3 schematically shows the well parameters used in the calculation model.

In FIG. Figure 4 shows a diagram of the joint functioning of the calculation model (forecasting module) and the optimization module for generating control actions on the gas flow rate regulator and the surfactant supply regulator.

In FIG. 1 shows the fountain fittings 1 of the well, equipped with a pressure sensor in the annulus 2, a pressure and temperature sensor 3 at the wellhead, pressure and temperature (or differential pressure) sensors 4 after the remote gas flow rate regulator 5. An electric power source 6 feeds the industrial controller 7 and the rest measuring and regulating devices. The controller 7 collects information from the sensors, its programmable computing module generates control actions on the gas flow rate controller 5 and on the pump 9, which is used to supply the surfactant liquid solution from the reservoir 8 to the annulus of the well through line 11, receiving information on the surfactant flow rate from the flow meter 10 The controller 7 may be connected to remote information transmission systems (not shown in FIG. 1) and controlled remotely.

In FIG. 2 shows the maximum set of equipment for applying the method, which further includes: an echo sounder 16, a sensor for the amount of solids in the gas stream 17, a single-phase / multiphase flow meter (or separation unit) 18, a downhole pressure and temperature sensor (not shown in FIG. 2). This equipment and measurements are necessary for more precise adjustment of the calculation model of the computing module of the industrial controller in order to more efficiently operate the well and achieve the specified technical result. The listed equipment may be used periodically and not be permanently connected to the well. The controller 7 can control the hydrate inhibitor supply regulator 14, receiving information on the hydrate inhibitor flow rate from the flow meter 15. Surfactant can be fed into the well via a separate line laid from a centralized storage facility for surfactant or from a gas collection and treatment point, as well as through an idle supply line a hydrate inhibitor (not shown in FIG. 2), as well as using regulatory equipment to supply a hydrate inhibitor. Tanks 8 with a surfactant solution, equipment and lines for its supply can provide a heating system to protect against freezing (not shown in Fig. 2). Capacity 8 with a surfactant solution can be connected to a system for preparing a surfactant solution of the required concentration (not shown in Fig. 2). The maximum set of equipment may also include an additional line 12 for supplying surfactants to the pipe space or directly to the bottom of the well by means of a capillary tube (not shown in Fig. 2), including one equipped with distributed pressure sensors in case of packer operation. The maximum set of equipment may also include a pneumatic line 13 to give energy to the regulators 5, 14 and pump 9 due to the gas pressure from the well in order to reduce the energy consumption of the system. As regulatory, measuring, locking devices, standard tools used in oil and gas production are used.

In FIG. Figure 3 schematically shows the process of operating a gas well under conditions of accumulation of liquid at the bottom and some well parameters used in the calculation model (surfactant supply and foaming flow are not shown).

The constant (user-defined) parameters are: T _pl - reservoir temperature; P _PL - reservoir pressure in the area of the well; N _SLE - well depth to the bottom; N _tubing - the depth of the bottom of the tubing; H ¹ _perf and H ² _perf - the depth of the upper and lower marks of the interval of perforation or filter in the reservoir; d _tubing - the inner diameter of the tubing (not shown in Fig. 3); d _ek - the inner diameter of the production string or filter (not shown in Fig. 3); α _angle - deviation of the trajectory from the vertical (not shown in Fig. 3); TIPperf — type of well perforation (or type of filter) (not shown in FIG. 3); h _g is the effective gas thickness working with gas, which determines the current gas productivity of the well (not shown in Fig. 3); a ⁰ _well and b ⁰ _well — filtration resistance coefficients in the equation of gas inflow to the well, obtained from the results of gas-dynamic studies of the well with maximum cleaning of the well from the fluid (not shown in Fig. 3); M _vpl - mineralization of produced water (not shown in Fig. 3).

The parameters that are necessarily measured in time are: T _buffer — temperature at the wellhead; P _buffer - pressure at the wellhead; P _shut - pressure in the annulus of the well; P _zab - pressure at the bottom of the well (in the case of packer operation); T _SHL - temperature after the gas flow rate regulator (in the gas collection loop); R _sl - pressure after the gas flow rate regulator (in the gas collection loop); d _regul - the diameter of the flow area of the gas flow controller.

Additionally measured in time parameters are: T _zab - temperature at the bottom of the well; P _zab - pressure at the bottom of the well, including a set of pressure values at various points in depth; Н _echo - the depth of the gas / liquid (or gas / carbonated liquid) section determined by the echo sounder in the wellbore; q _g is the gas flow rate measured by a single-phase / multiphase flow meter; KGF _(zhf ) - _{condensate-gas} flow factor (condensate in the liquid phase) measured by a multiphase flow meter or a mobile separator; VGF ( _zhf ) - measured by a multiphase flow meter or a mobile separator, the gas-water flow factor (water in the liquid phase); q _ingb is the measured flow rate of the hydrate inhibitor. All listed (additionally measured) parameters can be calculated. They are necessary for more accurate and quick setup of the calculation model. In addition, they all have a high measurement error or the technical complexity of the measurement (except q _ingb ).

The parameters that are fully calculated over time are: q _cc - the amount of condensation (distilled) water transferred to the liquid phase from natural gas in the upper sections of the wellbore flowing down the tubing string and accumulating at the bottom of the well; q _q.cap - the amount of liquid gas condensate transferred to the liquid phase from natural gas in the upper sections of the wellbore flowing down the tubing string and accumulating at the bottom of the well; q _vpl - the amount of water coming from the reservoir (or into the reservoir); q _k.pl - the amount of liquid gas condensate coming from the formation (or into the formation); N _g - the depth of the gas / carbonated liquid in the wellbore; N _W - the depth of the carbonated liquid / liquid in the wellbore; h _in - the thickness of the flooded part of the perforation interval (filter), which determines the current well productivity in gas and well productivity in water.

Additionally measured and fully calculated parameters, in the general case, are unknown parameters of the well operation. Moreover, their values at each time moment t are necessary to determine the optimal well mode (including surfactant supply mode) to remove accumulated fluid by a gas stream and achieve the specified technical result, starting from time t

In FIG. Figure 4 shows a diagram of the joint functioning of the calculation model (forecasting module) and the optimization module for generating control actions on the gas flow rate regulator and the surfactant supply regulator. The internal algorithms for the operation of these modules are independent of each other, the interaction of the modules occurs at the data exchange level, while the optimizer can change the input data for the forecasting module and manage its launches, including in parallel computing mode. The functions of the optimizer can be performed by a third-party universal application. To achieve the specified technical result, forecasting and optimization modules can be shared in three modes.

The first mode (I) is implemented after the system is first turned on in the parameter monitoring mode, during periods of fluid accumulation in the wellbore without surfactant supply, and can also be reproduced in virtual mode using historical information about the well operation parameters. Mode I is not used to control the well. The mode takes into account the time period t ₀ ... t ₁ and is necessary to determine the unknown parameters of the well at the time t ₁ (the moment of receipt of the latest data). For each moment of time t _i depending on the values of the user-defined constant parameters (T _pl , R _pl , N _SLE , N _nkg , H ¹ _perf , H ² _perf , d _nct , d _ek , α _angle , TYPE _perf , and ⁰ _SLE , b ⁰ _DH, M _v.pl), carefully measured parameters (T _{puff, puff} P, P _Difficult T _SL, R _SL, d _regulator) and a set of experimental parameters and functions №1 prediction unit calculates further parameters to be measured (T _Zab , R _zab , q _g , KGF _(zhf) , VGF _(zhf) , q _ingb ) and fully calculated parameters (q _v.kap , q _k.kap , q _v.pl , q _q.pl , N _g , N _w ) to compare them with the observed values iyami. Additionally, the measured parameter H _{echo is} not calculated, but is used for comparison with the calculated value of N _g . The calculated values of N _g and N _f can be compared with the readings of a system of distributed downhole pressure sensors.

For the calculation, both well-known and unique experimental functions protected by copyright can be used.

The pressure at the outlet of the ith segment of the well can be determined by the function P _i = f (P ₀ ; q _gpl ; q _q.cap ; q _v.cap ; PVT [P _cp , T _cp ] _{g, k, in} ; d _{tubing (eq)} ; λ _{tubing (eq)} ; α _angle ), where P ₀ is the flow pressure at the inlet to the segment; q _gf , q _q.kap , q _v.kap - the costs of the fluids entering the segment (in this case, reservoir gas, liquid non-equilibrium gas condensate and a mixture of condensation and produced water). The costs of liquids entering the segment (q _q.kap , q _q.kap ) can have a negative sign, which means the movement of phases in the opposite direction to the gas and determines the accumulation of liquid at the bottom; PVT [P _cp , T _cp ] _{g, k, c} — dependences of the component composition and the ratio of the liquid and gaseous phases of the fluids entering the segment, as well as the compressibility, viscosity and phase density of the average pressure and temperature in the segment; λ _{tubing (eq)} - coefficient of hydraulic resistance of pipes.

The temperature at the outlet of the ith segment of the well can be determined by the function T _i = f (T ₀ ; q _{g, k, c} ; PVT [P _cp , T _cp ] _{g, k, c} ; d _{tubing (ek)} ; Cp [P _cf , T _cf ]; Di [PVT]; λp; Cn), where T ₀ is the flow temperature at the inlet to the segment; Cp [P _cf , T _cp ] is the heat capacity of the stream; Di [PVT] - differential Joule-Thomson coefficient; λп - thermal conductivity of the space surrounding the pipe; Cn is the heat capacity of the space surrounding the pipe.

Flow rate of gas passing through the meter (controller) may be determined by the function q _g = f (d _regulator; R _buf; T _buf; P _SHL; T _SHL; VGF [P _SL, T _{SHL] LF;} FCT [P _SL, T _{SHL] LF).}

The gas production rate from the reservoir can be determined by the function q _mp = f (a ⁰ _well ; b ⁰ _well ; h _g ; h _c ; RPP; k _ol ; PVT [P, T] _g ; R _pl ; R _zab ), where RPP - functions of the relative phase permeability of the formation in the gas-liquid system (gas-water, gas-condensate) depending on the coefficients of water-, gas- and condensate saturation; k _CR - absolute permeability coefficient of the reservoir.

Flow rate of water can be determined from the function _v.pl q = f (h _a, the RPT; k _{pr, pl} P; P _Zab).

Flow rate of liquid condensate can be determined by the function _k.pl q = f (h _g PCE; k _pr; PVT [P, T] _{z, k;} F _mp; P _Zab).

The amount of hydrate inhibitor supplied to the well can be determined by the function q _ingb = f (P; T; q _g.pl ; q _q.cap ; q _v.cap ; M _v.pl ; PVT [R _cf. , T _cp ] _{g, k , c} ).

All of the above functions include coefficients and experimental constants having uncertainty and ranges of possible variation. The optimization module, operating in the adaptation mode of parameters from the set of functions No. 1, uses well-known optimization algorithms and manages multiple starts of the forecasting module, while changing the coefficients and experimental constants of functions No. 1 in the ranges specified by the user, minimizing the discrepancy between the calculated and measured (measured) parameters in each given point in time U of a time period t ₀ ... t ₁ . As a result of repeated launches of the forecasting module for a time period t ₀ ... t _{1, the} most reliable coefficients and experimental constants of the set of functions No. 1 are revealed and the most reliable fully calculated parameters (q _v.cap , q _c.cap , q _v.pl , q _{to .pl} , N _g , N _g ) at each time t _i , including at time t ₁ .

The second mode (II) takes into account the data received during the periods of operation of the well with surfactant feed, and can also be played in the virtual mode using historical information about the parameters of the well operation to supply the surfactant and of known (previously defined) parameter values (q _v.kap, q _q.cap , q _v.pl , q _q.pl , N _g , N _g ) at time t ₁ . Mode II is also not used to control the well. The mode takes into account the time period t ₁ ... t ₂ (where t ₂ is the moment of receiving the latest data) to determine unknown parameters of the well operation (q _v.kap , q _k.kap , q _v.pl , q _k.pl , N _g , N _g ) under the conditions of surfactant supply for each moment of time t ₁ ... t ₂ , as well as for calculating some of the necessarily measured parameters (T _buffer , P _buffer , P _shutter , T _sl ) and additionally measured parameters (T _sc , P _zab , q _g , KGF _(zhf) , VGF _(zhf) , q _ingb ) at each point in time t ₁ ... t ₂ to compare them with the observed values. At the same time, the input parameters for the calculation are known at each instant of time: _Ршл , d _regul , as well as: TYPE _surfactant - the type of surfactant used, which has individual foaming characteristics, foam stability, and other parameters that determine the efficiency of well cleaning from liquid; q _{surfactant (rr)} - the flow rate of the surfactant solution; K _surfactant - the concentration of surfactant in a surfactant solution.

The optimization module works in the adaptation mode of parameters and coefficients from a set of functions No. 2, similar to No. 1 and including parameters of the supplied surfactant solution: Pi = f (P ₀ ; q _gpl ; q _q.cap ; q _v.cap ; PVT [P _cp , T _cp ] _{g, k, c} ; d _{nct (eq)} ; λ _{nct (ek)} , α _angle ; TIPperf; TYPE of _surfactant ; q _{surfactant (} solution ₎ ; K _surfactant ) and T _i = f (T ₀ ; q _{g, k, c} ; PVT [P _cp , T _cp ] _{g, k, c} ; d _{tubing (ek)} ; Cp [P _cf , T _cf ]; Di [PVT]; λp; Cn; TIPperf; TYPE _SAW ; q _{surfactant (solution)} ; K _surfactant ).

The third mode (III) is the main one and can be used without preliminary operation of the system in modes I and / or II, if the values of the input parameters (q _in.cap , q _in.cap , q _in.pl , _q.pl , N _g , H _w) are known, and the parameters and constants of the feature sets №1 and №2 are reliably determined. Mode III is implemented for a time period t ₂ ... t ₃ (where t ₂ is the current time moment, t ₃ is the predicted time moment specified by the user) and is necessary to search for the optimal schedule (mode) for well control (regulation of gas flow rate) and surfactant supply mode ( including the optimal surfactant concentration) for the most efficient well operation and achievement of the specified technical result in the forecast period t ₂ ... t ₃ .

In mode III, the input data for the forecasting module are: user-specified above constant parameters; the values of the calculated parameters (q _q.cap , q _q.cap , q _q.pl , q _q.pl , N _g , N _g ) at time t ₂ ; control parameters set for the entire period of time t ₂ ... t ₃ R _SHL and TYPE _SAW ; the schedule of regulating parameters of d _regulators changed by the optimizer, q _{surfactant (rr)} , K _surfactant for a period of time t ₂ ... t ₃ . All other parameters are calculated (q _g , T _puff , P _puff , P _jam , T _sl , T _zab , P _zab , KGF _(zhf) , VGF _(zhf) , q _ingb ).

The optimizer’s task is to find the optimal schedule of regulatory parameters d _regula , q _{surfactant (rr)} , K _surfactant , q _ingb for a period of time t ₂ ... t ₃ that meets user-specified optimization criteria that can be combined into a single objective function. In FIG. Figure 4 shows the following optimization criteria: minimizing the time taken to achieve the target well operation mode; maximization of the resulting gas production rate of the well, or accumulated gas production for a given period of time; minimizing the amount of foaming agents; minimizing the amount of hydrate inhibitor supplied.

Mode III is used to control the well. The obtained schedule of regulatory parameters d _regula , q _{surfactant (rr)} , K _surfactant , q _ingb for a period of time t ₂ ... t _{3 is} used for their transmission to the controller as settings for controlling the regulating equipment.

The calculation cycle of mode III should be carried out continuously and clarify the schedule of the well that controls the well as it is implemented and new data on the parameters of the well are obtained. In general, model refinement in mode II, optimization calculations and well control in mode III should be carried out in parallel, including using parallel computing technologies.

Claims (10)

1. A method for the optimal operation of gas and gas condensate wells with a high fluid content, which involves the use of a computational model that mathematically describes the movement of a gas-liquid stream in a well, including under the conditions of its foaming by surface-active substances (SAW), software implemented in the computing module of an autonomous industrial controller and allowing to continuously determine completely unknown parameters of the well, such as the amount of condensation (distillation n) of water transferred to the liquid phase from natural gas in the upper sections of the wellbore, flowing down the column of elevator or tubing and accumulating on the bottom of the well, the amount of liquid gas condensate transferred to the liquid phase from natural gas in the upper sections the wellbore flowing down the tubing string and accumulating at the bottom of the well, the amount of water coming from the formation (or into the formation), the amount of liquid gas condensate coming from the formation (or into the formation), the gas / soda depth fluid in the borehole, the depth of the soda / fluid section in the borehole, the thickness of the watered part of the perforation interval (filter), which determines the current gas productivity of the well and the productivity of the well in water, as well as allowing for self-adjustment measured by appropriate equipment or in continuous operation to calculate temperature at the bottom of the well, pressure at the bottom of the well, gas flow rate, gas condensate flow factor at the wellhead, gas-water flow factor at the wellhead, inhibitor consumption hydrate formation based on user-defined unchanged well parameters, such as reservoir temperature, reservoir pressure in the well area, well depth to bottom, tubing bottom depth, upper and lower marks of the perforation or filter interval in the reservoir, tubing inner diameter, production casing inner diameter or filter, the angles of deviation of the trajectory from the vertical, the type of perforation of the well, the gas working effective thickness of the reservoir, the coefficients of filtration resistance in the equation gas flow to the well, mineralization of produced water, as well as parameters measured continuously by the corresponding telemetry equipment and entering the controller parameters, such as temperature at the wellhead, pressure at the wellhead, pressure in the annulus of the well, pressure at the bottom of the well in case of packer operation , the temperature after the gas flow rate regulator, the pressure after the gas flow rate regulator, the identifier of the diameter of the flow area of the gas flow rate regulator, as well as allowing continuous operation to predict the mode of operation of the well for a given period of time, including the dynamics of all of the above parameters, including the conditions under which a liquid surfactant solution is supplied using appropriate equipment, depending on the schedule of control parameters, such as the set pressure in the gas collector and the type of surfactant used, and depending on the schedule of regulatory parameters, such as the installed diameter of the flow area of the gas flow controller, the established flow rate AB, the established concentration of surfactants, as well as continuously interacting with the optimizer, which allows you to configure the model parameters according to the dynamics of well-known parameters of the well operation and allows you to select the optimal schedule of regulatory parameters for their transfer to the controller as settings for controlling the control equipment. 2. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that it provides for additional measurements of the parameters of the well using an echo sounder in the annulus (for a bezpacker-free circuit), a sensor for the amount of solids in the gas stream, a single-phase / multiphase flow meter or separation installations, systems for distributed measurement of bottomhole pressure and temperature at several points for more precise adjustment of the computational model of the computational module of industrial the controller. 3. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that the calculation model provides for a segmented structure of the well path: different lengths, diameters and angles of inclination (deviation from the vertical) of each well segment. 4. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that the calculation model provides for an interval characteristic of the filtration properties of the productive formation and an uneven flow of gas and liquid from the interval of opening the formation by the well. 5. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that it takes into account (or calculates) the rate of fluid flow from the reservoir (into the reservoir) at each point in time, various types of fluid removed from the well, including a mixture of produced water condensation water, a hydrate inhibitor, gas condensate (various component composition and density) in any ratio, while the ratio of produced water, condensation water, a hydrate inhibitor and gas condensate e can be calculated for each segment and interval of opening of the well at each point in time. 6. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that it provides for the calculation of the required amount of hydrate inhibitor for the hydrate-free operation of the well, respectively, the function of controlling the flow of the hydrate inhibitor into the well can be transferred to the controller. 7. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that the selection of the optimal mode of operation of the well for fluid removal can be carried out taking into account the imposed restrictions on the intensity of removal of mechanical impurities from the well when a certain gas flow rate at the wellhead is reached according to monitoring data amount of mechanical impurities in the gas stream. 8. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that it can be used in gas production control systems, while the calculation model and controller can receive the necessary target settings from upper-level systems via remote information transmission channels. 9. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that the software including the calculation model can function remotely (including based on a separate computing infrastructure), receiving information from the controller and controlling the controller via communication channels. 10. The method of optimal operation of gas and gas condensate wells according to claim 1, characterized in that the adjustment of the calculation model, optimization calculations and well control are performed in parallel, including using parallel computing technologies.

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