CN114526023B - Composite liquid discharging device and method for injection and forced discharge - Google Patents
Composite liquid discharging device and method for injection and forced discharge Download PDFInfo
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- CN114526023B CN114526023B CN202011229147.XA CN202011229147A CN114526023B CN 114526023 B CN114526023 B CN 114526023B CN 202011229147 A CN202011229147 A CN 202011229147A CN 114526023 B CN114526023 B CN 114526023B
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- 238000002347 injection Methods 0.000 title claims abstract description 112
- 239000007924 injection Substances 0.000 title claims abstract description 112
- 239000007788 liquid Substances 0.000 title claims abstract description 98
- 238000000034 method Methods 0.000 title claims abstract description 28
- 239000002131 composite material Substances 0.000 title claims description 11
- 238000007599 discharging Methods 0.000 title abstract description 6
- 239000003795 chemical substances by application Substances 0.000 claims abstract description 6
- 239000000463 material Substances 0.000 claims abstract description 3
- 238000012544 monitoring process Methods 0.000 claims description 27
- 239000012530 fluid Substances 0.000 claims description 19
- 238000004519 manufacturing process Methods 0.000 claims description 16
- 238000003860 storage Methods 0.000 claims description 14
- 238000009825 accumulation Methods 0.000 claims description 13
- 238000012806 monitoring device Methods 0.000 claims description 9
- 238000002485 combustion reaction Methods 0.000 claims description 8
- 239000004088 foaming agent Substances 0.000 claims description 7
- 238000009826 distribution Methods 0.000 claims description 6
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 6
- 238000006073 displacement reaction Methods 0.000 claims description 3
- 238000011156 evaluation Methods 0.000 claims description 3
- 230000001052 transient effect Effects 0.000 claims description 2
- 239000000446 fuel Substances 0.000 claims 1
- 150000001875 compounds Chemical class 0.000 abstract description 5
- 239000007789 gas Substances 0.000 description 41
- 239000003921 oil Substances 0.000 description 41
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 description 8
- 230000005540 biological transmission Effects 0.000 description 5
- 239000003345 natural gas Substances 0.000 description 4
- 239000006260 foam Substances 0.000 description 3
- 239000003153 chemical reaction reagent Substances 0.000 description 2
- 238000004891 communication Methods 0.000 description 2
- 230000006835 compression Effects 0.000 description 2
- 238000007906 compression Methods 0.000 description 2
- 238000003912 environmental pollution Methods 0.000 description 2
- 230000010354 integration Effects 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 238000012360 testing method Methods 0.000 description 2
- 230000005514 two-phase flow Effects 0.000 description 2
- 206010063385 Intellectualisation Diseases 0.000 description 1
- 238000013459 approach Methods 0.000 description 1
- 238000013329 compounding Methods 0.000 description 1
- 230000003750 conditioning effect Effects 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 230000001934 delay Effects 0.000 description 1
- 230000000694 effects Effects 0.000 description 1
- 230000007613 environmental effect Effects 0.000 description 1
- 238000005429 filling process Methods 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 239000003209 petroleum derivative Substances 0.000 description 1
- 238000005086 pumping Methods 0.000 description 1
- 238000010926 purge Methods 0.000 description 1
- 238000011897 real-time detection Methods 0.000 description 1
- 229910052710 silicon Inorganic materials 0.000 description 1
- 239000010703 silicon Substances 0.000 description 1
- 229910001220 stainless steel Inorganic materials 0.000 description 1
- 239000010935 stainless steel Substances 0.000 description 1
- 230000003068 static effect Effects 0.000 description 1
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
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- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
- E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B41/00—Equipment or details not covered by groups E21B15/00 - E21B40/00
-
- E—FIXED CONSTRUCTIONS
- E21—EARTH OR ROCK DRILLING; MINING
- E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
- E21B47/00—Survey of boreholes or wells
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- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Mechanical Engineering (AREA)
- Geophysics (AREA)
- Feeding, Discharge, Calcimining, Fusing, And Gas-Generation Devices (AREA)
Abstract
The invention provides a compound liquid discharge device and method for injection and forced discharge. The compound liquid discharging equipment for injecting agent and forced discharging comprises a control system; an injection line selectively communicable with the oil jacket annulus, the injection line controllable by the control system to determine a time of injection and an amount of injection; a gas line selectively communicable with the oil pipe, the gas line being controlled by the control system to be opened or closed; the pressure relief pipeline can be selectively communicated with the oil pipe, the pressure relief pipeline can be opened or closed under the control of the control system, and a combustor is arranged on the pressure relief pipeline so that combustible materials can be put into the atmosphere after being combusted.
Description
Technical Field
The invention relates to the technical field of petroleum and natural gas exploitation, in particular to a compound liquid discharge device and method for injection and forced drainage, and especially relates to a compound liquid discharge device and method for injection and forced drainage, which are suitable for a low-pressure well.
Background
The foam liquid drainage gas production process is a leading process for removing the liquid accumulation of the gas well and maintaining the stable production of the gas well, and is most widely applied to various liquid drainage gas production processes.
In recent years, the foam liquid discharge, gas production and filling process of low-pressure (generally not more than 5 MPa) gas wells is developing to automation and intellectualization, as disclosed in Chinese patent CN202560193U, CN203347764U, CN203097856U and the like.
The injection method is developed to automation, and the production efficiency is improved to a certain extent. However, the existing injection method still has a plurality of problems. For example, for a low-pressure gas well with the wellhead oil pressure basically being equal to the gas transmission pressure, the stratum energy is insufficient, and the well is closed, re-pressed and manually forced discharged after the foaming agent is injected at present, so that the liquid in the well can be brought out. This approach not only wastes human resources and financial resources, but also delays production time. For another example, the manual forced drainage is through the needle valve after the separator to adjust the flow of the spouting, directly discharges the mixture of natural gas and produced fluid into the atmosphere, presents a safety risk, and also causes environmental pollution. In addition, although automatic injection is realized, technological parameters such as start time, end time, duration of discharge and the like of the injection depend on experience, and the operation and control are inconvenient.
Disclosure of Invention
Aiming at part or all of the technical problems in the prior art, the invention provides a compound liquid discharge device and method for injecting agent and strongly discharging. The injection and forced drainage composite liquid drainage device and method can realize operations such as automatic injection, automatic liquid discharge by open injection and the like, and simultaneously, the method can reduce environmental and safety risks and improve the injection efficiency.
According to an aspect of the present invention, there is provided a composite liquid discharge apparatus of an injection agent and a strong discharge, comprising:
The control system is used for controlling the control system,
An injection line capable of selectively communicating with the oil jacket annulus, the injection line being controllable by the control system to determine the timing of the injection and the amount of injection,
A gas line capable of selectively communicating with the oil pipe, the gas line being controlled by the control system to be opened or closed,
The pressure relief pipeline can be selectively communicated with the oil pipe, can be opened or closed under the control of the control system, and is provided with a combustor so that combustible materials can be discharged after being combusted.
In one embodiment, a casing pressure sensor, an injection electric valve, an injection flowmeter and an injection device are sequentially arranged on the injection pipeline from the wellhead to the outside, wherein a control system can receive data from the casing pressure sensor, the control system can control the injection electric valve to be opened or closed, and the control system can monitor a signal of the injection flowmeter to control the injection electric valve to be closed after the injection amount is reached.
In one embodiment, a monitoring branch is provided between the casing pressure sensor on the injection line and the injection motor valve, the monitoring branch having a monitoring motor valve and a monitoring device in an out-going direction from the wellhead, wherein the monitoring motor valve is controllable by a control system to open or close, and the control system is operable to receive fluid level data from an annulus of an oil casing of the monitoring device.
In one embodiment, a discharge flow electric valve, a discharge flow meter and a burner are sequentially arranged on the pressure relief pipeline from a wellhead to the outside, a liquid storage tank is arranged at the lower end of the burner in a communicating manner, a liquid level sensor is arranged in the inner cavity of the liquid storage tank,
The control system can control the opening and closing of the open-flow electric valve, can receive data of the open-flow flowmeter, can control the opening and closing of the burner, and can receive data from the liquid level sensor.
In one embodiment, a temperature sensor is arranged between the burner and the open-flow electric valve, the control system adjusts the opening degree of the open-flow electric valve according to the data of the temperature sensor,
And/or further comprising a tubing pressure sensor for measuring pressure in the tubing, the tubing pressure sensor being connected to the control system for transmitting data to the control system.
According to another aspect of the present invention, there is provided a composite liquid discharge method for injecting and forcibly discharging a liquid according to the above-described apparatus, comprising:
Step one, the control system calculates the total accumulated liquid amount of the shaft and compares the total accumulated liquid amount with a threshold value,
Step two, when the total accumulated liquid amount of the shaft is not lower than a threshold value, the control system controls the injection pipeline to perform injection operation into the oil sleeve annulus,
Step three, after the injection is finished, the control system closes the gas pipeline, then performs the open-flow operation, and in the open-flow process, the combustible is discharged after the combustion treatment is required,
Step four, after the open flow is finished, the control system opens the gas pipeline for production,
And fifthly, repeating the first step to the fourth step.
In one embodiment, in step one, the total fluid production of the wellbore is the sum of the fluid production of the annulus of the oil casing, the fluid production in the tubing, and the fluid production below the tubing shoe, wherein,
Monitoring the liquid level depth of the oil sleeve annulus through monitoring branch lines and calculating the accumulated liquid volume of the annulus through a formula (1):
Wherein, Q 1: liquid accumulation volume of annulus, unit m 3;d1: the inner diameter of the sleeve, unit m; d 2: the outer diameter of the oil pipe is in unit of m; h: the oil pipe is deep downwards, and the unit is m; h 1: the annular liquid level depth, unit m,
Calculating the pressure P wf at the casing shoe through the casing pressure value measured by the casing pressure sensor, iteratively calculating to obtain a liquid column pressure distribution curve A upwards from the casing shoe, simultaneously, obtaining an oil pipe pressure distribution curve B downwards from a wellhead through iterative calculation, setting the depth corresponding to the intersection point of the curve A and the curve B as the actual accumulated liquid depth h 2 in the oil pipe, and calculating the accumulated liquid in the oil pipe through a formula (2):
Wherein, Q 2: accumulated liquid in oil pipe, unit: m 3;d2: oil pipe inside diameter, unit: m; h: deep down of oil pipe, unit: m; h 2: the actual liquid level depth of the oil pipe is determined by the curve intersection point, and the unit is: m.
In one embodiment, in step two, the injection line is controlled to inject the injection agent into the oil jacket annulus by the control system, wherein the injection amount is:
qz＝c*(qw+Q)/w， (3)
Wherein, q z: the amount of the foaming agent is as follows: m 3; c: recommended concentration of experimental evaluation is usually 1-2 in units: kg/m 3;qw: daily water yield of gas well, unit: m 3; q: total fluid accumulation in wellbore, unit: m 3; w: the foaming agent and water filling ratio is unit-free.
In one embodiment, in step three, after closing the gas line, the control system fully opens the electronic valve and receives temperature data from the temperature sensor, and adjusts the opening of the electronic valve if the temperature of the gas line measured by the temperature sensor is less than the hydrate production temperature.
In one embodiment, in step three, a combustible gas detector is provided at the ignition port of the burner to ignite upon detecting that the gas concentration reaches the combustion concentration,
Or/and, in the third step, monitoring whether ignition is successful or not through a flame detector, and stopping ignition after the ignition is successful.
Compared with the prior art, the method has the advantages that the method for compounding the automatic injection and the automatic discharge of the liquid in the gas well is provided, the accurate control of the automatic injection and the automatic forced discharge of the low-pressure low-yield gas well is realized, the environment pollution is eliminated, the safety risk is reduced, and the efficiency and the reliability of an automatic pumping system are improved through forced discharge after combustion.
Drawings
Preferred embodiments of the present invention will be described in detail below with reference to the attached drawing figures, wherein:
FIG. 1 shows a composite liquid discharge device of the present invention with injection and forced drainage;
FIG. 2 is a flow chart showing the steps of the automatic injection of the present invention;
FIG. 3 is a flow chart showing the steps of the gas well automatic injection, automatic forced drainage and automatic ignition integration of the present invention.
In the drawings, like parts are designated with like reference numerals. The figures are not drawn to scale.
Detailed Description
The invention will be further described with reference to the accompanying drawings.
Fig. 1 shows a composite liquid discharge device of injection and forced discharge according to the present invention. As shown in fig. 1, the injection and forced drainage composite drainage device comprises a control system 20, an injection pipeline, a gas pipeline and a pressure relief pipeline. Wherein the injection line is selectively communicable with the oil jacket annulus for control at the control system 20 to determine the timing of the injection and the amount of injection. The gas line is in selective communication with the tubing and is controlled by the control system 20 to open or close for delivering gas to the environment. The pressure relief line can be selectively communicated with the oil line and can be opened or closed under the control of the control system 20 for forced purging operations. In addition, a burner 11 is provided on the pressure relief line to allow the combustible to be discharged after combustion.
Specifically, on the injection line, in the outward direction from the wellhead, a casing pressure sensor 1, an injection motor valve 4, an injection flowmeter 5, and an injection device 6 are provided in this order. Wherein the casing pressure sensor 1 is mainly used for sensing the pressure in the casing and transmitting data to the control system 20. The injection motor-operated valve 4 is opened by the control system 20 to start the injection operation when necessary, and is closed after the injection is completed to end the injection operation. The injection flowmeter 5 is used for monitoring the injection amount, and sending the monitoring result to the control system 20 in real time, so that after the control system 20 monitors that the injection amount reaches a specified value, a control command is timely sent to close the injection electric valve 4. The reagent injection device 6 is used for performing reagent injection operation.
A monitoring branch line is arranged between the sleeve pressure sensor 1 on the injection line and the injection motor-operated valve 4. The monitoring branch has a monitoring motor valve 2 and a monitoring device 3 in the direction from the wellhead to the outside. That is, the monitoring branch line is provided in parallel with the injection motor valve 4, the injection flowmeter 5, and the injection device 6. Before the injection, the control system 20 can control the monitoring electric valve 2 to be opened, automatically test the primary oil sleeve annulus liquid level data by using the monitoring device 3, and send the liquid level data to the control system 20 for calculating the accumulated liquid volume of the oil sleeve annulus. For example, the monitoring device 3 may be an echo meter.
And a discharge flow meter 9, a temperature sensor 10 and a burner 11 are sequentially arranged on the pressure relief pipeline from the wellhead to the outside. A liquid storage tank 15 is provided at the lower end of the burner 11 in communication. A liquid level sensor 16 is provided in the inner cavity of the liquid reservoir 15. After the injection is finished and the gas transmission electric valve 18 is closed, the control system 20 opens the injection electric valve 8 to start the open-flow operation. Wherein the temperature sensor 10 senses the temperature of the pressure relief line and transmits data to the control system 20. If the blowout line temperature is less than the hydrate generation temperature, the control system 20 continuously adjusts the opening of the blowout electric valve 8 until the blowout line is not frozen, so as to ensure safety. A combustible gas detector 12 is provided at the gas outlet end of the burner 11. The gas detector 12 is used to detect the gas concentration and send a signal to the control system 20. When the gas concentration reaches a preset natural gas combustion concentration, the control system 20 controls the high energy igniter 14 to ignite at the ignition window 13. After the flame detector 17 detects the flame, a signal is sent to the control system 20, and the control system 20 controls the high-energy igniter 14 to stop igniting.
For example, the high energy igniter 14 includes a high energy generator, an ignition cable, two phase electrodes, a discharge disk. The ignition cable is a high-temperature-resistant and high-pressure-resistant cable, and consists of a high-temperature-resistant and high-pressure-resistant ignition cable, a high-temperature-resistant and high-pressure-resistant silicon ion ignition hose and a stainless steel fireproof hose. The high-energy generator comprises an alternating-current primary transformer, an alternating-current secondary conditioning circuit and a high-voltage line protection circuit.
The gas transmission pipeline is provided with a gas transmission electric valve 18. The gas delivery electric valve 18 is connected to a control system 20 to be opened or closed under the control of the control system 20.
A tubing pressure sensor 7 is provided on the left side of the upper jacket gauge 19 for monitoring the pressure in the tubing and transmitting the resulting pressure value to the control system 20. The different lines in the apparatus are also provided with one or more valves 21 for controlling the opening or closing of the respective lines. And it is easy to understand that the gas transmission electric valve 18 is normally open, the monitoring electric valve 2 and the injection electric valve 4 are normally closed, and the open-flow electric valve 8 is normally closed with adjustable opening.
The method of composite drainage of the injection and the forced drainage is described in detail below with reference to fig. 1-3.
Before each injection, the monitoring motor-operated valve 2 is controlled by the control system 20 to be opened. The primary annulus fluid level data is automatically tested by the monitoring device 3 and sent to the control system 20. After the test is completed, the control system 20 closes the monitoring motor-operated valve 2. Based on the tubing run-in depth H, the casing inside diameter D 1, the tubing outside diameter D 2, and the annulus fluid level depth H 1 measured by the monitoring device 3, the control system 20 calculates the oil casing annulus fluid accumulation Q 1 according to equation (1).
Wherein:
Q 1: annular fluid accumulation, unit: m 3;d1: inside diameter of the sleeve, unit: m; d 2: oil pipe outer diameter, unit: m; h: deep down of oil pipe, unit: m; h 1: annular liquid level depth measured by an echo instrument, unit: m.
And calculating the pressure P wf at the casing shoe through an annular space static column pressure model according to the casing pressure value measured by the casing pressure sensor 1. The pressure at the shoe of the oil pipe is equal to the pressure at the shoe of the sleeve pipe. Starting from the oil pipe shoe (H, P wf), taking a micro-segment with the length of delta H upwards, assuming that the corresponding pressure drop of the segment is delta P 1, calculating the average pressure and average temperature of the segment and the corresponding parameters of gas-liquid two-phase flow such as compression factor, density and the like, and iteratively calculating to obtain the liquid column pressure distribution curve A upwards from the oil pipe shoe.
Dividing the oil pipe from the wellhead to the pipe shoe into a certain number of sections, taking one of the micro-sections with the length of delta h, assuming that the pressure drop corresponding to the section is delta P 2, calculating the average pressure and average temperature of the section and the corresponding parameters of gas-liquid two-phase flow such as compression factors, density and the like, and iteratively calculating to obtain the pressure distribution curve B of the oil pipe from the wellhead downwards. The depth corresponding to the intersection point of the curve A and the curve B is the actual liquid accumulation depth h 2 in the oil pipe.
And obtaining the fluid accumulation amount Q 2 in the oil pipe according to the calculated fluid accumulation depth h 2 of the oil pipe.
Wherein: q 2: oil pipe accumulated liquid, unit: m 3;d2: oil pipe inside diameter, unit: m; h: deep down of oil pipe, unit: m; h 2: the calculated actual liquid level depth of the oil pipe is as follows: m.
And then calculating the accumulated liquid quantity Q 3 below the shoe through the formula (3).
Wherein: q 3: oil pipe accumulated liquid, unit: m 3;d1: inside diameter of the sleeve, unit: m; h: deep down of oil pipe, unit: m; h': manual well bottom, unit: m.
Thus, the formula by which the total fluid volume Q in the wellbore can be calculated is: q=q 1+Q2+Q3, wherein: q 1: liquid accumulation in the sleeve, unit: m 3;Q2: fluid accumulation in oil pipe, unit: m 3;Q3: the accumulated liquid of the following parts of the oil pipe shoes is as follows: m 3.
When the wellbore fluid volume Q reaches a preset start threshold Q 0, the control system 20 gives a command to open the injection motor valve 4 and start automatic injection into the casing.
The control system 20 receives real-time data of the injection flowmeter 5, and closes the injection motor-operated valve 4 when the actual single injection flow reaches the calculated single injection dose q z. Wherein the single shot dose Q z is calculated by Q z＝c*(qw +q)/w. In the above formula, q z: the amount of the foaming agent is as follows: m 3; c: recommended concentration of experimental evaluation is usually 1-2 in units: kg/m 3;qw: daily water yield of gas well, unit: m 3; q: total fluid accumulation in wellbore, unit: m 3; w: the foaming agent and water filling ratio is unit-free.
After the injection is completed, the gas-delivery electric valve 18 is automatically closed by the control system 20. The control system 20 controls opening of the open-injection motor valve 8. The discharge electric valve 8 is initially fully opened and discharge is started. And transmitting data of the temperature sensor 10 to the control system 20, and if the temperature of the blowout pipe line is smaller than the hydrate generation temperature, controlling the opening of the blowout electric valve 8 by the control system 20 to continuously reduce until the pipeline is not frozen.
When the gas concentration detected by the combustible gas detector 12 reaches the natural gas combustion concentration, the ignition device can be remotely controlled by the control system 20 to start the ignition of the high-energy igniter 14. After the flame detector 17 detects a flame, the control system 20 controls the high energy igniter 14 to stop igniting.
In the automatic open-flow process, the liquid level sensor 16 records the real-time liquid level L and open-flow time t in the liquid storage tank 15 and timely transmits data to the control system 20. The control system 20 is as followsAnd calculating the real-time discharge capacity Q f. In the formula, Q f: instantaneous discharge displacement, unit: m 3/h; a: cross-sectional area of the liquid storage tank, unit: m 2;L2: liquid level in liquid storage tank corresponding to stop time t 2 of open flow, unit: m; l 1: liquid level in liquid storage tank corresponding to instantaneous time t 1 of open flow, unit: m; t 2: discharge stop time, unit: s; t 1: discharge transient time, unit: s.
Step nine:
when the calculated real-time discharge displacement data Q f≤0.01m3/h, the control system 20 controls to close the discharge electric valve 8 to stop the discharge operation. The gas-operated electrically operated valve 18 is then opened and gas well production is resumed.
The automatic injection, automatic forced discharge and automatic ignition are integrated. And carrying out the next round of construction according to the injection period.
According to the automatic injection starting threshold and injection flow rate determined according to the accumulated liquid volume of the shaft, the automatic injection starting threshold and injection flow rate are simple and convenient to monitor and calculate, and the automatic injection starting threshold and injection flow rate are high in pertinence and efficiency. The liquid in the liquid storage tank 15 can be monitored in real time, and the liquid discharge time can be controlled by calculating the liquid discharge flow. The open-flow pipeline is prevented from icing by temperature real-time monitoring and electric ball valve opening control, and pipeline blockage risks are reduced. The gas real-time detection and automatic open-flow ignition are realized through the remote control system 20, the high-energy igniter and the like, so that the safety risk and the environmental pollution are reduced. The automatic injection, automatic forced drainage and automatic ignition integration of the low-pressure gas well are realized without closing the well in operation, the foam drainage process effect of the low-pressure gas well is improved, and the stable production of the gas well is ensured.
The above is only a preferred embodiment of the present invention, but the scope of the present invention is not limited thereto, and any person skilled in the art can easily make modifications or variations within the technical scope of the present invention disclosed herein, and such modifications or variations are intended to be included in the scope of the present invention. Therefore, the protection scope of the invention is subject to the protection scope of the claims.
Claims (7)
1. A method of composite liquid discharge of a dosing agent and a forced drain, the method being implemented by a composite liquid discharge apparatus of a dosing agent and a forced drain, the apparatus comprising: a control system; an injection line selectively communicable with the oil jacket annulus, the injection line controllable by the control system to determine a time of injection and an amount of injection; a gas line selectively communicable with the oil pipe, the gas line being controlled by the control system to be opened or closed; the pressure relief pipeline can be selectively communicated with the oil pipe, the pressure relief pipeline can be opened or closed under the control of the control system, the pressure relief pipeline is provided with a burner so as to enable combustible materials to be discharged after being combusted, the pressure relief pipeline is sequentially provided with a blowout electric valve, a blowout flowmeter and the burner from a wellhead to the outside, the lower end of the burner is communicated with a liquid storage tank, a liquid level sensor is arranged in an inner cavity of the liquid storage tank,
Characterized in that the method comprises:
Step one, the control system calculates the total accumulated liquid amount of the shaft and compares the total accumulated liquid amount with a threshold value,
Step two, when the total accumulated liquid amount of the shaft is not lower than a threshold value, the control system controls the injection pipeline to perform injection operation into the oil sleeve annulus,
Step three, the control system closes the gas pipeline after the injection is completed, then performs an open flow operation, discharges the combustible after combustion treatment in the open flow process, and the liquid level sensor records the real-time liquid level L and the open flow time t in the liquid storage tank and transmits the liquid level L and the open flow time t to the control system, wherein the control system is used for controlling the fuel injection according to the following steps of
Calculate instantaneous discharge displacement Q f, where Q f: instantaneous discharge capacity, unit m 3/h; a: cross-sectional area of the liquid storage tank, unit m 2;L2: the liquid level in the liquid storage tank corresponding to the blowout stopping time t 2 is in unit of m; l 1: the liquid level in the liquid storage tank corresponding to the instantaneous time t 1 of the open flow is in unit of m; t 2: stopping time of the discharge, unit s; t 1: discharge transient time, unit s; when the calculated instantaneous discharge capacity Q f≤0.01m3/h is reached, the control system enables the discharge electric valve to be closed, the discharge operation is stopped,
Step four, after the open flow is finished, the control system opens the gas pipeline for production,
Step five, repeating the steps from the first step to the fourth step,
Wherein in the first step, the total accumulated liquid amount of the shaft is the sum of the accumulated liquid amount of the oil sleeve annulus, the accumulated liquid amount in the oil pipe and the accumulated liquid amount below the oil pipe shoe, wherein,
Monitoring the liquid level depth of the oil sleeve annulus through monitoring branch lines and calculating the accumulated liquid volume of the annulus through a formula (1):
（1）
In formula (1), Q 1: liquid accumulation volume of annulus, unit m 3;d1: the inner diameter of the sleeve, unit m; d 2: the outer diameter of the oil pipe is in unit of m; h: the oil pipe is deep downwards, and the unit is m; h 1: annular liquid level depth, unit m;
calculating the pressure P wf at the casing shoe through the casing pressure value measured by the casing pressure sensor, iteratively calculating to obtain a liquid column pressure distribution curve A upwards from the casing shoe, simultaneously, obtaining an oil pipe pressure distribution curve B downwards from a wellhead through iterative calculation, setting the depth corresponding to the intersection point of the curve A and the curve B as the actual accumulated liquid depth h 2 in the oil pipe, and calculating the accumulated liquid in the oil pipe through a formula (2):
（2）
In formula (2), Q 2: accumulated liquid in oil pipe, unit: m 3;d2: oil pipe inside diameter, unit: m; h: deep down of oil pipe, unit: m; h 2: the actual liquid level depth of the oil pipe is determined by the curve intersection point, and the unit is: m;
calculating the accumulated liquid amount of the following parts of the oil pipe shoes according to the formula (3):
（3）
in formula (3), Q 3: the accumulated liquid of the following parts of the oil pipe shoes is as follows: m 3;d1: inside diameter of the sleeve, unit: m; h: deep down of oil pipe, unit: m; h': manual well bottom, unit: m;
In the second step, the injection pipeline is controlled to inject the injection into the oil sleeve annulus through the control system, wherein the injection amount is calculated through a formula (4):
（4）
In formula (4), q z: the amount of the foaming agent is as follows: m 3; c: recommended concentration of experimental evaluation is usually 1-2 in units: kg/m 3;qw: daily water yield of gas well, unit: m 3; q: total fluid accumulation in wellbore, unit: m 3; w: the foaming agent and water filling ratio is unit-free.
2. The method of claim 1, wherein a casing pressure sensor, an injection motor-operated valve, an injection flow meter, and an injection device are sequentially disposed on the injection line from the wellhead to the exterior, wherein the control system is capable of receiving data from the casing pressure sensor, the control system is capable of controlling the injection motor-operated valve to open or close, and the control system is capable of monitoring the signal of the injection flow meter to control the injection motor-operated valve to close after an injection dose is reached.
3. A method according to claim 2, wherein a monitoring branch is provided between the casing pressure sensor and the injection motor valve on the injection line, the monitoring branch having a monitoring motor valve and a monitoring device in the wellhead-to-exterior direction, wherein the control system is capable of controlling the monitoring motor valve to open or close, and the control system is capable of receiving fluid level data from an oil casing annulus of the monitoring device.
4. The method of claim 1, wherein the control system is capable of controlling the opening and closing of the electronic valve, wherein the control system is capable of receiving data from the discharge flow meter, wherein the control system is capable of controlling the opening and closing of the burner, and wherein the control system is capable of receiving data from the level sensor.
5. The method of claim 4 wherein a temperature sensor is disposed between the burner and the electronic valve, the control system adjusting the opening of the electronic valve based on data received from the temperature sensor,
And/or further comprising a tubing pressure sensor for measuring pressure in the tubing, the tubing pressure sensor being connected to the control system for transmitting data to the control system.
6. The method according to claim 5, wherein in step three, after closing the gas line, the control system fully opens the open electric valve and receives temperature data from a temperature sensor, and adjusts the opening degree of the open electric valve if the temperature of the gas line measured by the temperature sensor is less than the hydrate production temperature.
7. A method according to claim 1, wherein in step three, a combustible gas detector is provided at the ignition port of the burner to ignite upon detecting that the gas concentration reaches the combustion concentration,
Or/and, in the third step, monitoring whether ignition is successful or not through a flame detector, and stopping ignition after the ignition is successful.
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| CN106894774A (en) * | 2017-02-17 | 2017-06-27 | 中国石油集团川庆钻探工程有限公司长庆井下技术作业公司 | A kind of underbalance changes pipe string technology method |
| CN111058814A (en) * | 2018-10-16 | 2020-04-24 | 中国石油化工股份有限公司 | Intelligent agent injection system and agent injection method for gas well foam drainage gas production |
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| WO2006062893A2 (en) * | 2004-12-06 | 2006-06-15 | Baker Hughes Incorporated | Method and apparatus for preventing slug flow in pipelines |
| CN202900218U (en) * | 2012-11-16 | 2013-04-24 | 中国石油天然气股份有限公司 | Automatic chemical feeding device for gas well mouth |
| CN103590812B (en) * | 2013-10-21 | 2016-06-08 | 中国石油天然气股份有限公司 | Calculation method, calculation device and determination method for gas well liquid accumulation amount |
| CN204877409U (en) * | 2015-08-25 | 2015-12-16 | 盘锦百利化工有限公司 | Foam drainage system |
| CN209130892U (en) * | 2018-09-07 | 2019-07-19 | 中国石油化工股份有限公司 | A kind of aqueous gas well open flow combustion barrel |
| CN111364959B (en) * | 2020-03-30 | 2022-08-02 | 中国石油天然气集团有限公司 | Foam drainage gas production device for simulating shaft injection and rod throwing and simulation method |
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