CN114991720A - Device and method for preventing and controlling hydrate in production pipeline of deepwater oil and gas well - Google Patents
Device and method for preventing and controlling hydrate in production pipeline of deepwater oil and gas well Download PDFInfo
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- CN114991720A CN114991720A CN202210703496.3A CN202210703496A CN114991720A CN 114991720 A CN114991720 A CN 114991720A CN 202210703496 A CN202210703496 A CN 202210703496A CN 114991720 A CN114991720 A CN 114991720A
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- 238000002347 injection Methods 0.000 claims abstract description 86
- 239000013043 chemical agent Substances 0.000 claims abstract description 68
- 239000000126 substance Substances 0.000 claims abstract description 49
- 238000012544 monitoring process Methods 0.000 claims abstract description 46
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- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 22
- 238000002485 combustion reaction Methods 0.000 claims description 12
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- 238000013329 compounding Methods 0.000 claims description 10
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- 230000000903 blocking effect Effects 0.000 claims description 8
- 238000001802 infusion Methods 0.000 claims description 7
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- NMJORVOYSJLJGU-UHFFFAOYSA-N methane clathrate Chemical compound C.C.C.C.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O.O NMJORVOYSJLJGU-UHFFFAOYSA-N 0.000 claims description 4
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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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/01—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells specially adapted for obtaining from underwater installations
-
- 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
- E21B37/00—Methods or apparatus for cleaning boreholes or wells
- E21B37/06—Methods or apparatus for cleaning boreholes or wells using chemical means for preventing or limiting, e.g. eliminating, the deposition of paraffins or like substances
-
- 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
- E21B43/00—Methods or apparatus for obtaining oil, gas, water, soluble or meltable materials or a slurry of minerals from wells
- E21B43/34—Arrangements for separating materials produced by the well
-
- 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
-
- 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
- E21B47/06—Measuring temperature or 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
- E21B47/00—Survey of boreholes or wells
- E21B47/09—Locating or determining the position of objects in boreholes or wells, e.g. the position of an extending arm; Identifying the free or blocked portions of pipes
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- Geology (AREA)
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- Geochemistry & Mineralogy (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geophysics (AREA)
- Chemical & Material Sciences (AREA)
- Chemical Kinetics & Catalysis (AREA)
- General Chemical & Material Sciences (AREA)
- Pipeline Systems (AREA)
Abstract
The invention discloses a device and a method for preventing and treating hydrate in a production pipeline of a deepwater oil and gas well, wherein the device comprises: a monitoring system, comprising: the pressure sensor, the temperature sensor and the micro-vibration sensor group are arranged on the shaft; a hydrate chemical injection system, comprising: the system comprises a hydrate chemical agent configuration tank and an injection pump, wherein one end of the injection pump is communicated with the hydrate chemical agent configuration tank, and the other end of the injection pump is communicated with a shaft and is configured to pump the hydrate chemical agent into the shaft; a calculation and control system coupled to the monitoring system and configured to receive the pressure signal and the temperature signal from the monitoring system and determine a hydrate formation zone within the wellbore based on the pressure signal and the temperature signal; coupled to the hydrate chemical injection device, is configured to receive the micro-vibration signal from the monitoring system and control the hydrate chemical injection system to inject the hydrate chemical into the wellbore based on the micro-vibration signal and the hydrate generation zone.
Description
Technical Field
The invention relates to the technical field of drilling and production of oil gas and natural gas hydrates, in particular to a device and a method for preventing and treating hydrates in a production pipeline of a deepwater oil and gas well.
Background
Most of the existing deepwater shaft hydrate control methods adopt the flow of 'hydrate generation area prediction → hydrate inhibitor compounding experiment → hydrate inhibitor injection parameter calculation' to design the shaft hydrate risk control scheme. The prediction of the hydrate generation area is to calculate the temperature and pressure field of the whole shaft by collecting the temperature and pressure of the well mouth, calculate the phase equilibrium temperature and pressure of the hydrate by combining the components of the gas produced by the stratum, and finally determine the well barrel section which is easy to generate the hydrate. The hydrate compounding experiment is to determine the hydrate inhibitor formula suitable for different stratums and production conditions by developing indoor hydrate generation experiments under different hydrate inhibitor formulas. The hydrate inhibitor injection parameter calculation is to determine the optimal injection rate and injection quantity of the hydrate inhibitor preparation liquid according to the oil-gas well production allocation scheme and the production parameters. The patents related to the method are as follows:
chinese patent CN104088623A discloses an automatic hydrate prevention and control device and method for testing a deepwater gas well, which solve the problems of low accuracy and long operation delay time of determining the injection amount of a hydrate inhibitor by field personnel through inquiring a chart. The device and the method can accurately judge and timely adjust the injection amount of the hydrate, and ensure the control effect of the hydrate inhibitor.
Chinese patent CN111749659A discloses a method for preventing and controlling hydrates in a shaft of a deep water gas field, which determines a hydrate generation area in the shaft by predicting a temperature field and a pressure field of the shaft, and reduces the partial pressure of methane gas by injecting nitrogen into the shaft so as to achieve the purpose of preventing and controlling the hydrates in the shaft.
Chinese patent CN104895560B discloses a method for simulating a wellbore pressure and a temperature field in deep water testing and predicting hydrates, which specifies a wellbore temperature field and pressure field calculation model, considers factors such as seawater temperature influence, unsteady heat transfer between a wellbore and a stratum, nonlinear change of a wellbore pressure field and the like, and accurately predicts the accuracy of the wellbore temperature field and the pressure field, thereby accurately predicting the accuracy of a hydrate generation area.
The patents are closely related in the field of hydrate prevention and control in China, and obtain uncommon field application effects. The existing method for preventing and controlling the hydrate in the deep water shaft considers that the hydrate in the shaft is generated, namely the hydrate risk exists, and the hydrate inhibitor is injected into the shaft after the hydrate generation is determined, so that the method can accurately and effectively prevent and control the hydrate generation in the shaft, but still has the improvement:
1. hydrate inhibitors are injected when hydrates begin to generate, so that the using amount of the hydrate inhibitors is large, the economic cost is high, and the hydrate control in a deepwater oil and gas well casing becomes an important factor influencing the oil and gas exploitation cost in the periodic low-price period of the international crude oil price, so that a more economic hydrate control method is needed to be established;
2. hydrate blockage in a shaft is the final result of the evolution process of hydrate generation → migration → convergence → deposition → blockage, the existing method solves the problem of hydrate blockage from the root of hydrate generation, but ignores the concept that the hydrate generation does not necessarily cause the deposition, prevents and treats the hydrate blockage from the hydrate blockage process, and can provide a new idea of a hydrate prevention and treatment method;
3. the existing method indirectly judges the hydrate risk in the shaft through the modes of predicting the temperature field and the pressure field of the shaft or monitoring the flowing pressure of fluid produced by a wellhead and the like, and the generation and the blockage of the hydrate in the shaft are not monitored in a more intuitive mode.
Disclosure of Invention
The technical scheme aims at the problems and requirements, provides equipment and a method for preventing and treating hydrate in a production pipeline of a deepwater oil and gas well, and can achieve the technical purpose and bring other technical effects due to the adoption of the following technical characteristics.
One object of the present invention is to propose a hydrate control device in a production line of a deepwater oil and gas well, the production line of the oil and gas well comprising: the device comprises a shaft, a gas-liquid separator, a combustion arm and a liquid tank, wherein one end of the shaft extends to the bottom of the shaft, the other end of the shaft is connected with the gas-liquid separator, the gas-liquid separator is provided with a liquid conveying port and a gas conveying port, the liquid conveying port is communicated with the liquid tank, and the gas conveying port is communicated with the combustion arm; wherein the wellbore comprises: the oil-gas-water mixed transportation system comprises a first oil pipe, a second oil pipe and an oil-gas-water mixed transportation pipe, wherein one end of the first oil pipe is communicated with the second oil pipe through a mud line wellhead, the other end of the first oil pipe is communicated with the oil-gas-water mixed transportation pipe through a platform wellhead, and an adjustable oil nozzle is arranged on the oil-gas-water mixed transportation pipe and between the platform wellhead and a gas-liquid separator;
the control device includes:
a monitoring system, comprising: a pressure sensor, a temperature sensor and a micro-vibration sensor set mounted on the wellbore, the pressure sensor configured to monitor a pressure signal within the wellbore, the temperature sensor configured to monitor a temperature signal of the wellbore, the micro-vibration sensor set configured to monitor a micro-vibration signal of the wellbore;
a hydrate chemical injection system, comprising: the hydrate chemical agent preparation tank is communicated with the hydrate chemical agent preparation pump, and the other end of the hydrate chemical agent preparation tank is communicated with the shaft and is configured to pump the hydrate chemical agent into the shaft;
a calculation and control system coupled to the monitoring system and configured to receive the pressure signal and the temperature signal from the monitoring system and determine a hydrate generation zone within the wellbore based on the pressure signal and the temperature signal; coupled to the hydrate chemical injection system, configured to receive the micro-vibration signal from the monitoring system and control the hydrate chemical injection system to inject hydrate chemical into the wellbore based on the micro-vibration signal and the hydrate generation zone.
In one example of the present invention, the monitoring system further comprises:
a gas flow meter disposed between the gas delivery port and the combustion arm configured to monitor a gas flow at the gas delivery port;
a liquid flow meter disposed between the administration port and the liquid tank configured to monitor a liquid flow rate at the administration port.
In one example of the present invention, the monitoring system further comprises:
a gas composition measuring device disposed between the gas delivery port and the combustion arm, configured to measure a composition of the gas at the gas delivery port;
a liquid mineralization measuring device disposed between the infusion port and the liquid tank configured to measure the mineralization of liquid at the infusion port.
In one example of the present invention, the monitoring system comprises at least two sets of one set of one said temperature sensor and one said pressure sensor, at least one set of which is disposed between said adjustable choke and said platform wellhead, and at least another set of which is disposed between said adjustable choke and said gas-liquid separator.
In one example of the present invention, the micro-vibration sensor group includes a plurality of micro-vibration sensors, and the micro-vibration sensors are arranged in an array along an extending direction and a circumferential direction of the wellbore.
In one example of the present invention, the micro-vibration sensor group includes a plurality of micro-vibration sensors, and is respectively disposed at both sides of the mud line wellhead and/or the platform wellhead.
In one example of the present invention, the hydrate chemical injection system further comprises:
a flow valve disposed between the injection pump and the wellbore configured to control a flow of hydrate chemical injected into the wellbore;
a fluid flow meter disposed between the flow valve and the wellbore configured to monitor a flow rate of the hydrate chemical injected into the wellbore.
In one example of the present invention, the hydrate chemical injection system includes a plurality of hydrate chemical injection systems, and the hydrate chemical injection systems are arranged at intervals along the extension direction of the wellbore.
Another object of the present invention is to provide a method for controlling hydrate control equipment in a production pipeline of a deepwater oil and gas well, which comprises the following steps:
s10: monitoring a pressure signal, a temperature signal and a micro-vibration signal in the shaft by a monitoring system;
s20: determining a hydrate formation zone within the wellbore based on the pressure signal and the temperature signal;
s30: obtaining the vibration frequency and amplitude of the shaft by the micro-vibration signal, and comparing the vibration frequency and amplitude of the shaft in a hydrate risk free period, thereby judging the hydrate blockage condition in the target shaft section and determining the specific position of the blockage of the hydrate; when there is no risk of hydrate blockage, returning to step S20; when the hydrate blockage risk exists, the next step is continuously executed;
s40: calculating the hydrate formation amount and the hydrate volume fraction in the target wellbore section according to the hydrate formation amount prediction model;
s50: determining the formula and the injection amount of the hydrate chemical agent through a hydrate chemical agent compounding experiment, and injecting the hydrate chemical agent into the shaft;
s60: monitoring the vibration frequency and amplitude of the target wellbore section after the hydrate chemical agent is injected by using the micro-vibration sensor group, and judging the hydrate blockage condition in the target wellbore section again; when the hydrate blockage risk exists, returning to the step S50 and increasing the injection amount of the hydrate chemical agent; and when the blocking risk of the hydrate chemical agent is reduced, the injection amount of the injected hydrate chemical agent is continuously kept, and normal oil and gas production work is maintained.
In one example of the present invention, in the step S20, the determining the hydrate formation zone in the wellbore based on the pressure signal and the temperature signal includes the steps of:
s201: respectively calculating a temperature field and a pressure field in the shaft according to the calculation models of the temperature field and the pressure field in the oil-gas shaft;
s202: obtaining gas components produced by the stratum, and calculating the temperature and pressure of hydrate generation phase equilibrium in the shaft according to a natural gas hydrate phase equilibrium prediction model;
s203: and determining a hydrate generation area in the shaft by combining the temperature and pressure field in the shaft and the temperature and pressure field of hydrate phase equilibrium.
The following description of the preferred embodiments for carrying out the present invention will be made in detail with reference to the accompanying drawings so that the features and advantages of the present invention can be easily understood.
Drawings
In order to more clearly illustrate the technical solutions of the embodiments of the present invention, the drawings of the embodiments of the present invention will be briefly described below. Wherein the drawings are only for purposes of illustrating some embodiments of the invention and are not to be construed as limiting the invention to all embodiments thereof.
FIG. 1 is a schematic diagram of a hydrate control device in a production line of a deepwater oil and gas well according to an embodiment of the present invention;
FIG. 2 is a schematic diagram of a hydrate control method in a production pipeline of a deepwater oil and gas well according to an embodiment of the invention;
FIG. 3 is a flow chart of a hydrate control method in a production pipeline of a deepwater oil and gas well according to an embodiment of the invention.
List of reference numerals:
an oil and gas well production pipeline 200;
a wellbore 210;
first oil pipe 211;
an oil-gas-water mixed transportation pipe 213;
a mud line wellhead 220;
a platform wellhead 230;
an adjustable oil nipple 240;
a gas-liquid separator 250;
an infusion port 252;
a combustion arm 260;
a liquid tank 270;
a control device 100;
a monitoring system 10;
a pressure sensor 11;
a temperature sensor 12;
a micro-vibration sensor group 13;
a gas flow meter 14;
a liquid flow meter 15;
a gas component measuring device 16;
a liquid mineralization measuring device 17;
a pressure gauge support cylinder 18;
a hydrate chemical injection system 20;
a hydrate chemical agent preparation tank 21;
an injection pump 22;
a flow valve 23;
a fluid flow meter 24;
an inhibitor injection nipple 25;
a computing and control system 30;
a signal transmission device 40.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present invention clearer, the technical solutions of the embodiments of the present invention will be clearly and completely described below with reference to the accompanying drawings of specific embodiments of the present invention. Like reference symbols in the various drawings indicate like elements. It should be noted that the described embodiments are part of the embodiments of the present invention, and not all of the embodiments. All other embodiments, which can be derived by a person skilled in the art from the described embodiments of the invention without any inventive step, are within the scope of protection of the invention.
Unless defined otherwise, technical or scientific terms used herein shall have the ordinary meaning as understood by one of ordinary skill in the art to which this invention belongs. The use of "first," "second," and similar terms in the description and in the claims of the present application does not denote any order, quantity, or importance, but rather the terms are used to distinguish one element from another. Also, the use of the terms "a" or "an" and the like do not necessarily denote a limitation of quantity. The word "comprising" or "comprises", and the like, means that the element or item listed before the word covers the element or item listed after the word and its equivalents, but does not exclude other elements or items. The terms "connected" or "coupled" and the like are not restricted to physical or mechanical connections, but may include electrical connections, whether direct or indirect. "upper", "lower", "left", "right", and the like are used only to indicate relative positional relationships, and when the absolute position of the object being described is changed, the relative positional relationships may also be changed accordingly.
In a deepwater hydrocarbon well production line hydrate control apparatus 100 according to a first aspect of the present invention, as shown in fig. 1, a hydrocarbon well production line 200 comprises: the gas-liquid separator 250 is provided with a liquid inlet port 252 and a liquid outlet port 251, the liquid inlet port 252 is communicated with the liquid tank 270, and the gas outlet port 251 is communicated with the combustion arm 260; wherein the wellbore 210 comprises: the oil-gas-water mixed transportation system comprises a first oil pipe 211, a second oil pipe 212 and an oil-gas-water mixed transportation pipe 213, wherein one end of the first oil pipe 211 is communicated with the second oil pipe 212 through a mud line wellhead 220, the other end of the first oil pipe 211 is communicated with the oil-gas-water mixed transportation pipe 213 through a platform wellhead 230, and an adjustable oil nozzle 240 is arranged on the oil-gas-water mixed transportation pipe 213 and between the platform wellhead 230 and a gas-liquid separator 250;
the control apparatus 100 includes:
a monitoring system 10, comprising: a pressure sensor 11, a temperature sensor 12 and a micro-vibration sensor group 13 mounted on the wellbore 210, wherein the pressure sensor 11 is configured to monitor a pressure signal in the wellbore 210, the temperature sensor 12 is configured to monitor a temperature signal in the wellbore 210, and the micro-vibration sensor group 13 is configured to monitor a micro-vibration signal in the wellbore 210;
a hydrate chemical injection system 20, comprising: a hydrate chemical agent configuration tank 21 and an injection pump 22, wherein one end of the injection pump 22 is communicated with the hydrate chemical agent configuration tank 21, and the other end is communicated with the wellbore 210, and is configured to pump a hydrate chemical agent into the wellbore 210; for example, the pump speed of the injection pump 22 is 0 to 50m 3 The injection pressure is 30MPa, the temperature is 0-100 ℃, and the diameter of an injection pipeline is 30-100 mm.
A calculation and control system 30 coupled to the monitoring system 10 and configured to receive the pressure signal and the temperature signal from the monitoring system 10 and determine a hydrate formation zone within the wellbore 210 based on the pressure signal and the temperature signal; coupled to the hydrate chemical injection system 20, configured to receive the micro-vibration signal from the monitoring system 10 and control the hydrate chemical injection system 20 to inject hydrate chemical into the wellbore 210 based on the micro-vibration signal and the hydrate generation zone;
monitoring, by a monitoring system 10, a pressure signal, a temperature signal, and a micro-vibration signal within a wellbore 210, determining a hydrate formation zone within the wellbore 210 based on the pressure signal and the temperature signal; obtaining the vibration frequency and amplitude of the shaft 210 through the micro-vibration signal, and comparing the vibration frequency and amplitude of the shaft 210 in a period without hydrate risk, thereby judging the hydrate blockage condition in the target shaft 210 section and determining the specific position of the blockage of the hydrate; wherein, when there is no risk of hydrate blockage, returning to the previous step; when the hydrate blockage risk exists, the next step is continuously executed; calculating the hydrate formation amount and the hydrate volume fraction in the target shaft 210 section according to the hydrate formation amount prediction model; determining the formula and the injection amount of the hydrate chemical agent through a hydrate chemical agent compounding experiment, and controlling the hydrate chemical agent injection system 20 to inject the hydrate chemical agent into the well bore 210 by the calculation and control system 30; monitoring the vibration frequency and amplitude of the target shaft 210 section after the hydrate chemical agent is injected by using the micro-vibration sensor, and re-judging the hydrate blocking condition in the target shaft 210 section; when the risk of hydrate blockage exists, returning to the previous step and increasing the injection amount of the hydrate chemical agent; and when the blocking risk of the hydrate chemical agent is reduced, the injection amount of the injected hydrate chemical agent is continuously kept, and normal oil and gas production work is maintained.
The prevention and treatment device 100 is based on the idea of hydrate prevention and treatment that hydrate is generated but not necessarily caused to be blocked, can quickly judge the formation stage of hydrate risk in an oil and gas production pipeline by using a micro-vibration monitoring means, and can purposefully optimize the using amount of a hydrate chemical agent through the hydrate chemical agent injection system 20, improve the using effect of the hydrate chemical agent and more effectively prevent and treat the problem of hydrate blocking; by using the monitoring system 10, the generation, migration, coalescence and deposition of hydrates in the pipeline can be directly monitored through pipeline vibration parameters, and the development degree of the hydrate blocking process in the pipeline can be judged; the device is different from the device which completely inhibits the generation of hydrate, and the device can be used for carrying out the hydrate blockage prevention and treatment work in the coalescence and deposition processes of the hydrate, reducing the dosage of a hydrate chemical agent and improving the prevention and treatment effect of the hydrate chemical agent; and the method has the advantages of accurate injection amount of the hydrate chemical agent, automatic control, labor saving, quick response and the like, and meets the engineering requirements.
In one example of the present invention, the monitoring system 10 further comprises:
a gas flow meter 14 disposed between the gas delivery port 251 and the combustion arm 260, configured to monitor a gas flow rate at the gas delivery port 251;
a liquid flow meter 15 disposed between the administration fluid port 252 and the liquid tank 270, configured to monitor liquid flow at the administration fluid port 252;
the gas flow meter 14 can feed back the gas flow information at the gas transmission port 251 to the calculation and control system 30, and the calculation and control system 30 refers to the gas flow and determines the blockage condition of the shaft 210 by combining the temperature and the pressure of the shaft 210;
the fluid flow meter 15 can feed fluid flow information at the fluid delivery port 252 back to the calculation and control system 30, and the calculation and control system 30 can reference the fluid flow and determine the blockage of the wellbore 210 by combining the temperature and pressure of the wellbore 210.
In one example of the present invention, the monitoring system 10 further comprises:
a gas composition measuring device 16 disposed between the gas delivery port 251 and the combustion arm 260, configured to measure a composition of the gas at the gas delivery port 251;
a liquid mineralization measuring device 17 disposed between the fluid delivery port 252 and the liquid tank 270 and configured to measure the mineralization of the liquid at the fluid delivery port 252;
the gas component measuring device 16 can accurately measure the components of the gas in the oil gas collected from the bottom of the shaft 210, and the liquid mineralization measuring device 17 measures the mineralization of the liquid in the oil gas collected from the bottom of the shaft 210; thereby facilitating the calculation of hydrate formation and hydrate volume fraction.
In one example of the present invention, the monitoring system 10 comprises at least two sets of one set of one temperature sensor 12 and one pressure sensor 11, at least one set of which is disposed between the variable nozzle tip 240 and the platform wellhead 230, and at least another set of which is disposed between the variable nozzle tip 240 and the gas-liquid separator 250;
by arranging the temperature sensor 12 and the pressure sensor 11 on both sides of the adjustable oil nipple 240, the temperature difference and the pressure difference on both sides of the adjustable oil nipple 240 can be measured; due to the long length of the wellbore 210, multiple sets of temperature sensors 12 and pressure sensors 11 may be provided as references.
Of course, the present invention is not limited thereto, and a temperature sensor 12 and a pressure sensor 11 are further provided on the gas-liquid separator 250 so as to obtain the temperature and pressure inside the gas-liquid separator 250 for use in calibrating the temperature and pressure at the platform wellhead 230.
In order to monitor the safety of the liquid tank 270 in real time, a temperature sensor 12 and a pressure sensor 11 are also provided on the liquid tank 270.
In one example of the present invention, the monitoring system 10 further comprises: a pressure gauge stinger 18, mounted in first tubing 211 of wellbore 210, configured to measure pressure information within first tubing 211, the pressure information being acquired by calculation and control system 30 and facilitating calculation determination of a hydrate formation zone within said wellbore 210.
In one example of the present invention, the micro-vibration sensor group 13 includes a plurality of micro-vibration sensors, and the micro-vibration sensors are arranged in an array along the extending direction and the circumferential direction of the wellbore 210;
the plurality of micro-vibration sensors may be used to monitor micro-vibration signals from a section of the wellbore 210 to determine the formation of hydrates in the wellbore 210.
It will be appreciated that the micro-vibration sensor group 13 is comprised of a displacement sensor and a signal transmission device 40. The displacement sensor consists of an anti-static high-pressure-resistant sealed shell, a waterproof insulating layer, a circuit board, a transmission line and a displacement induction chip. The displacement sensors are arranged on the pipe wall, four displacement sensors are arranged in the east, south, west and north directions at the same well position, and four displacement sensors are arranged at the target well section position at intervals of 1 meter along the well. The precision of the displacement sensor is 0.1-10 um, the range of the sensor is 0-30mm, the pressure resistance is 20MPa, and the temperature resistance is 0-80 ℃. The installation quantity, performance and specific positions of the displacement sensors in the micro-vibration sensor group depend on specific situations of a field, and the general orientations of the displacement sensors are three regions with frequent hydrate risk, namely a lower position of the mud-line wellhead 220, an upper position of the mud-line wellhead 220 and an outlet position of the platform wellhead 230.
In one example of the present invention, the micro-vibration sensor group 13 includes a plurality of micro-vibration sensors, and is respectively disposed at both sides of the mud line wellhead 220 and/or the platform wellhead 230;
because the common hydrate blockage occurs at the connection part of the well bore 210, and the phenomena of hydrate blockage easily occur at the two parts of the mud line well head 220 and the platform well head 230, the micro-vibration sensor group 13 is arranged at the two sides of the well bore, so that the blockage condition of the well bore 210 can be conveniently monitored; preferably, micro-vibration sensor groups 13 are disposed on both sides of the mudline wellhead 220 and on both sides of the platform wellhead 230.
For example, in the embodiment of the present invention, the micro-vibration sensor group 13 at the section below the mud line wellhead 220, the section above the mud line wellhead 220 and the section of the platform mixing transportation pipeline at the three sections monitors the vibration frequency and amplitude of the pipeline in real time.
In one example of the present invention, the hydrate chemical injection system 20 further comprises:
a flow valve 23 disposed between the injection pump 22 and the wellbore 210, configured to control a flow rate of hydrate chemical injected into the wellbore 210;
a fluid flow meter 24 disposed between the flow valve 23 and the wellbore 210 configured to monitor the flow rate of the hydrate chemical injected into the wellbore 210;
the calculation and control system 30 controls the amount of the hydrate chemical agent injected into the wellbore 210 by the hydrate chemical agent injection system 20 based on the micro-vibration signal and the hydrate generation region, that is, the flow rate of the hydrate chemical agent injected into the wellbore 210 by the injection pump 22 can be conveniently controlled by calculating the opening and closing size of the flow valve 23 controlled by the calculation and control system 30 and combining the fluid flow meter 24, so that the injection amount of the hydrate chemical agent is accurately controlled, the dosage of the hydrate chemical agent is reduced, and the control effect of the hydrate chemical agent is improved.
To facilitate the connection between the hydrate chemical injection system 20 and the wellbore 210, an inhibitor injection nipple 25 is provided on the wellbore 210 to facilitate injection of hydrate chemical into the wellbore 210 by the injection pump 22.
In an example of the present invention, the hydrate chemical injection system 20 includes a plurality of hydrate chemical injection systems, and the hydrate chemical injection systems are arranged at intervals along the extension direction of the wellbore 210;
that is, since the hydrate chemical injection system 20 includes a plurality of injection ports, the hydrate chemical may be injected simultaneously or individually at a plurality of points spaced along the extending direction of the wellbore 210, so that the injection amount of the hydrate chemical may be more accurately injected, thereby better preventing the hydrate blockage situation.
In one example of the present invention, the control apparatus 100 further includes: a signal transmission device 40, one end of which is coupled to the infusion pump 22 and the other end of which is coupled to the calculation and control system 30, is used for transmitting information transmission between the infusion pump 22 and the calculation and control system 30.
A method of controlling a hydrate controlling apparatus 100 in a production line 200 of a deepwater oil and gas well according to a second aspect of the present invention, as described above, as shown in fig. 2 and 3, comprises the steps of:
s10: monitoring, by the monitoring system 10, a pressure signal, a temperature signal, and a micro-vibration signal within the wellbore 210; that is, the production data such as temperature, pressure, micro-vibration frequency, micro-vibration amplitude, gas-liquid flow and the like in the production process of the oil production gas are obtained through sensors and flow meters at the bottom, the top and the platform well 230, specifically including a temperature sensor 12, a pressure sensor 11, a gas-liquid flow meter, a micro-vibration sensor and the like
S20: determining a hydrate formation region within the wellbore 210 based on the pressure signal and the temperature signal;
s30: obtaining the vibration frequency and amplitude of the shaft 210 through the micro-vibration signal, and comparing the vibration frequency and amplitude of the shaft 210 in a period without hydrate risk, thereby judging the hydrate blockage condition in the target shaft 210 section and determining the specific position of the blockage of the hydrate; when there is no risk of hydrate blockage, returning to step S20; when the hydrate blockage risk exists, the next step is continuously executed;
the vibration of the pipeline in the hydrate generation area is monitored by the micro-vibration sensor group 13. When the hydrate is generated, the vibration frequency and the vibration amplitude of the pipeline begin to increase, because the fluid in the pipeline is converted into gas-liquid-solid three-phase flow from gas-liquid two-phase flow, the solid-phase particles of the hydrate generated in the pipeline continuously collide the pipe wall in the flowing process, the vibration frequency and the vibration amplitude of the pipeline are aggravated, in addition, along with the coalescence of the hydrate particles and the falling of a deposition layer, large blocks of hydrate particles collide the pipe wall, and the vibration of the pipeline is aggravated, therefore, when the micro-vibration sensor begins to feed back the aggravated vibration condition of the pipeline, and the calculated temperature and pressure condition of the shaft 210 is combined with the hydrate generation condition, at the moment, the risk of generating the hydrate is possessed.
And further judging the blocking risk of the hydrate, and comparing the vibration frequency and amplitude of the pipeline when the hydrate is generated. And when the vibration amplitude of the pipeline is 2-3 times of that of the hydrate generated and the vibration frequency begins to be reduced to 50% of the original frequency, increasing the risk of blockage of the hydrate in the pipeline, and needing hydrate control measures, and performing the fourth step. Otherwise, in the second step, the oil gas production condition is monitored again, and the hydrate generation area is judged in real time.
S40: calculating the hydrate formation amount and the hydrate volume fraction in the target shaft 210 section according to the hydrate formation amount prediction model;
s50: determining the formula and injection amount of a hydrate chemical agent through a hydrate chemical agent compounding experiment, and injecting the hydrate chemical agent into the shaft 210; the formula and the injection amount of the hydrate chemical agent are determined by compounding key component proportions such as a hydrate inhibitor, a hydrate polymerization inhibitor, a dispersing agent, water and the like through a hydrate chemical agent compounding experiment. The method is characterized in that a low-temperature high-pressure loop system is utilized to develop a hydrate chemical agent compounding experiment under the condition of multiphase flow, the hydrate generation state and the effect of the hydrate chemical agent in an actual production pipeline can be simulated under the condition of multiphase flow, the experiment method adopts two forms of a hydrate generation constant-temperature method and a constant-pressure method, the hydrate chemical agent compounding experiment is a conventional technology, and details are not repeated here.
During normal production, a gas-liquid two-phase annular fog flow system is in the gas well shaft 210, and an oil-gas-water three-phase mixed flow system is in the oil well shaft 210. Based on the differences in the flow system in the wellbore 210 and experimental measurements, the hydrate concentration in the annular mist stream is 5 during normal production vol % and hydrate concentration in oil, gas and water mixed stream of 7 vol % of the total amount of the components do not cause hydrateThe risk of clogging.
S60: monitoring the vibration frequency and amplitude of the target shaft 210 section after the hydrate chemical agent is injected by the micro-vibration sensor group 13, and re-judging the hydrate blockage condition in the target shaft 210 section; when the hydrate blockage risk exists, returning to the step S50 and increasing the injection amount of the hydrate chemical agent; and when the blocking risk of the hydrate chemical agent is reduced, the injection amount of the injected hydrate chemical agent is continuously kept, and normal oil and gas production work is maintained.
In short, the prevention and control method utilizes the micro-vibration sensor to monitor the vibration frequency and amplitude of the well pipeline in real time, screens and compares the pipeline fluctuation characteristics in the normal production period and the stages of hydrate generation, coalescence, deposition, falling and the like, establishes a method for judging the hydrate risk by utilizing micro-vibration, and forms a corresponding hydrate prevention and control method.
The method uses the monitoring system 10, can realize the direct monitoring of the generation, migration, coalescence and deposition of the hydrate in the pipeline through the pipeline vibration parameters, and can judge the development degree of the blockage process of the hydrate in the pipeline; the device is different from the device which completely inhibits the generation of hydrate, and the device can be used for carrying out the hydrate blockage prevention and treatment work in the coalescence and deposition processes of the hydrate, reducing the dosage of a hydrate chemical agent and improving the prevention and treatment effect of the hydrate chemical agent; and the method has the advantages of accurate injection amount of the hydrate chemical agent, automatic control, labor saving, quick response and the like, and meets the engineering requirements.
In one example of the present invention, in the step S20, the determining the hydrate formation zone in the wellbore 210 based on the pressure signal and the temperature signal includes the steps of:
s201: respectively calculating the temperature field and the pressure field in the oil-gas well bore 210 according to the calculation models of the temperature field and the pressure field in the oil-gas well bore 210;
the computational model expression for the pressure field of the wellbore 210 is:
in the formulaP is the pressure of the wellbore 210, Pa, L is the depth of the wellbore 210, m, ρ ave Is the average density of the mixed fluid in the wellbore 210 in kg/m 3 G is the acceleration of gravity, m/s 2 θ is the wellbore 210 inclination angle, °, τ s For mixing shearing forces of the fluid with the tube wall, S p M, A is the circumference of the oil pipe p M2, v is the cross-sectional area of the oil pipe ave Is the average velocity of the mixed fluid, m/s, P t Is throttling pressure drop, Pa;
the computational model expression for the temperature field of wellbore 210 is:
wherein T is the temperature of the fluid in the wellbore 210, K, q are the heat transfer rates, W/m, W m Is the fluid mass flow rate, kg/s, C p Is the specific heat capacity of the fluid, J/kg K, mu j The Joule-Thomson coefficient, K/MPa, s is the distance, m, from the entrance to the wellbore 210.
S202: obtaining gas components produced by the formation, and calculating the temperature and pressure of hydrate formation phase equilibrium in the wellbore 210 according to the natural gas hydrate phase equilibrium prediction model;
the natural gas hydrate phase equilibrium prediction model has the expression:
Ω a ＝0.42748
Ω b ＝0.08664
wherein v is the molar volume, m 3 R is a molar gas constant of 8.3142J/(mol K), T c Is the critical temperature of gas, K, P c Critical pressure of gas, Pa.
S203: the combination of the temperature and pressure field in the wellbore 210 and the temperature and pressure field of the hydrate phase equilibrium determines the hydrate formation zone in the wellbore 210.
In an example of the invention, in step S40, the hydrate formation amount in the target well section and the volume fraction of hydrate in the pipeline are calculated through a hydrate formation amount prediction model, and the amount of the inhibitor for preventing and controlling hydrate blockage can be effectively calculated by determining the specific hydrate formation amount in the pipeline. The expression of the hydrate formation prediction model is as follows:
in the formula, m hydr Mass of hydrate formation, kg, M gas Is the number of moles of gas, g/mol, f trans Is the comprehensive mass transfer coefficient between gas and liquid, X 1 And X 2 Is the kinetic formation constant of hydrate, kg/(m) 2 K s)，T s Is the temperature of the fluid, A i Is the interfacial area between gas and liquid, m 2 ，T sub Is the supercooling degree, K;
in the formula, alpha hydr Is the volume fraction of hydrate in the pipeline, vol ％，V hydr is the hydrate volume, m 3 ，v L Is the volume of the liquid phase in the pipeline, m 3 。
In one example of the present invention, injecting a hydrate chemical into the wellbore 210 in step S50 includes: injecting hydrate chemical agents to a plurality of positions at the bottom of the well, on two sides close to the mud line well mouth 220 and on two sides close to the platform well mouth 230 by using a hydrate chemical agent segmented injection method;
specifically, in the present invention, inhibitor injection nipples 25 are provided at the bottom of the well, at the lower end of the mud line wellhead 220, and near the platform wellhead 230 and on the oil, gas, and water commingling pipe 213, to inject hydrate chemicals at these three locations. For example, the three positions are specifically installed at a position 3 meters above the packer at the bottom of the well, a position 20 meters below the mud-line wellhead 220, or a position 3 meters at the outlet of the platform wellhead 230, which is installed integrally with the mud-line wellhead 220.
The principle of the hydrate chemical agent segmented injection method is 'sequential injection from the well bottom to the injection short section of the platform well head 230'.
1) The pup joint is injected from the bottom of the well first. Typically, there is no risk of hydrate downhole, and injection of the hydrate chemical from there may be sufficient mixing of the hydrate chemical with the fluid in the wellbore 210 to maximize hydrate inhibition.
2) After the hydrate chemical agent is injected, monitoring the vibration condition of a pipeline and the pressure change condition of a wellhead, and if the hydrate blockage risk is relieved, continuously injecting from the bottom of the well; if hydrate risk is not mitigated or is mitigated more slowly, injection from the mud-line wellhead 220 is commenced; if the hydrate risk remains unrelieved and the hydrate risk occurs within the platform flowline, injection continues from the platform wellhead 230.
In one example of the present invention, in step S50, a determined hydrate chemical injection amount is needed, the injection amount calculation needs to take into account wellbore 210 temperature, pressure and production plan during wellbore 210 production, and the injection rate of hydrate chemical is calculated as follows:
in the formula, q c The injection rate of the hydrate chemical agent is shown, L/s and c are the injection concentration of the hydrate chemical agent, wt ％，q w to produce water at a rate of L/s, q g As hydrate chemical in the gas phaseLoss rate of (1), L/s, q o Is the rate of loss of hydrate chemical in the oil phase, L/s.
The exemplary embodiments of the hydrate control apparatus 100 and the control method in a deepwater oil and gas well production pipeline 200 proposed by the present invention have been described in detail hereinabove with reference to preferred embodiments, however, it will be understood by those skilled in the art that many variations and modifications may be made to the specific embodiments described above, and that many combinations of the various technical features and structures proposed by the present invention may be made without departing from the inventive concept, the scope of which is defined by the appended claims.
Claims (10)
1. An apparatus for hydrate control in a production line of an oil and gas well in deep water, the production line (200) of the oil and gas well comprising: the gas-liquid separator comprises a shaft (210), a gas-liquid separator (250), a combustion arm (260) and a liquid tank (270), wherein one end of the shaft (210) extends to the bottom of the well, the other end of the shaft (210) is connected with the gas-liquid separator (250), the gas-liquid separator (250) is provided with a liquid conveying port (252) and a gas conveying port (251), the liquid conveying port (252) is communicated with the liquid tank (270), and the gas conveying port (251) is communicated with the combustion arm (260); wherein the wellbore (210) comprises: the oil-gas-water mixed transportation system comprises a first oil pipe (211), a second oil pipe (212) and an oil-gas-water mixed transportation pipe (213), wherein one end of the first oil pipe (211) is communicated with the second oil pipe (212) through a mud line wellhead (220), the other end of the first oil pipe (211) is communicated with the oil-gas-water mixed transportation pipe (213) through a platform wellhead (230), and an adjustable oil nozzle (240) is arranged on the oil-gas-water mixed transportation pipe (213) and positioned between the platform wellhead (230) and a gas-liquid separator (250);
characterized in that said control device (100) comprises:
monitoring system (10), comprising: a pressure sensor (11), a temperature sensor (12) and a micro-vibration sensor group (13) mounted on the wellbore (210), the pressure sensor (11) configured to monitor a pressure signal within the wellbore (210), the temperature sensor (12) configured to monitor a temperature signal of the wellbore (210), the micro-vibration sensor group (13) configured to monitor a micro-vibration signal of the wellbore (210);
a hydrate chemical injection system (20), comprising: a hydrate chemical agent configuration tank (21) and an injection pump (22), one end of the injection pump (22) being in communication with the hydrate chemical agent configuration tank (21) and the other end being in communication with the wellbore (210) and configured to pump hydrate chemical into the wellbore (210);
a calculation and control system (30) coupled to the monitoring system (10) and configured to receive the pressure signal and the temperature signal from the monitoring system (10) and determine a hydrate formation zone within the wellbore (210) based on the pressure signal and the temperature signal; coupled to a hydrate chemical injection system (20) and configured to receive the micro-vibration signal from the monitoring system (10) and control the hydrate chemical injection system (20) to inject hydrate chemical into the wellbore (210) based on the micro-vibration signal and the hydrate generation zone.
2. The deepwater oil and gas well production pipeline hydrate control device as claimed in claim 1,
the monitoring system (10) further comprises:
a gas flow meter (14) disposed between the gas delivery port (251) and the combustion arm (260) configured for monitoring a gas flow at the gas delivery port (251);
a liquid flow meter (15) disposed between the administration port (252) and the liquid tank (270) configured to monitor a liquid flow rate at the administration port (252).
3. The apparatus for hydrate control in deepwater oil and gas well production lines as claimed in claim 1 or 2,
the monitoring system (10) further comprises:
a gas composition determination device (16) disposed between the gas delivery port (251) and the combustion arm (260) configured for determining a composition of the gas at the gas delivery port (251);
a liquid mineralization measuring device (17) disposed between the infusion port (252) and the liquid tank (270) configured to measure the mineralization of liquid at the infusion port (252).
4. The deepwater oil and gas well production pipeline hydrate control device as claimed in claim 1,
the monitoring system (10) comprises at least two groups, at least one group is arranged between the adjustable choke (240) and the platform wellhead (230), and at least another group is arranged between the adjustable choke (240) and the gas-liquid separator (250).
5. The deepwater oil and gas well production pipeline hydrate control device as claimed in claim 1,
the micro-vibration sensor group (13) includes a plurality of micro-vibration sensors, and the micro-vibration sensors are arranged in an array along an extending direction and a circumferential direction of the wellbore (210).
6. The deepwater oil and gas well production pipeline hydrate control device as claimed in claim 1,
the micro-vibration sensor group (13) comprises a plurality of micro-vibration sensors, and the micro-vibration sensors are respectively arranged on two sides of the mud line wellhead (220) and/or the platform wellhead (230).
7. The deepwater oil and gas well production line hydrate control device as claimed in claim 1,
the hydrate chemical injection system (20) further comprises:
a flow valve (23) disposed between the injection pump (22) and the wellbore (210) configured to control a flow rate of hydrate chemical injected into the wellbore (210);
a fluid flow meter (24) disposed between the flow valve (23) and the wellbore (210) configured to monitor a flow rate of a hydrate chemical injected into the wellbore (210).
8. The deepwater oil and gas well production line hydrate control device according to claim 7,
the hydrate chemical injection system (20) comprises a plurality of hydrate chemical injection systems, and the hydrate chemical injection systems are arranged at intervals along the extension direction of the well bore (210).
9. A method of controlling a hydrate control device (100) in a deepwater oil and gas well production line as claimed in any one of claims 1 to 8, comprising the steps of:
s10: monitoring, by a monitoring system (10), a pressure signal, a temperature signal, and a micro-vibration signal within a wellbore (210);
s20: determining a hydrate generation zone within the wellbore (210) based on the pressure signal and the temperature signal;
s30: obtaining the vibration frequency and amplitude of the shaft (210) through the micro-vibration signal, and comparing the vibration frequency and amplitude of the shaft (210) in a period without hydrate risk, thereby judging the hydrate blockage condition in the target shaft (210) section, and determining the specific position of the blockage of the hydrate; when there is no risk of hydrate blockage, returning to step S20; when the hydrate blockage risk exists, the next step is continuously executed;
s40: calculating the hydrate formation and the hydrate volume fraction in the target shaft (210) section according to the hydrate formation prediction model;
s50: determining the formula and the injection amount of a hydrate chemical agent through a hydrate chemical agent compounding experiment, and injecting the hydrate chemical agent into the shaft (210);
s60: monitoring the vibration frequency and amplitude of the target shaft (210) section after the hydrate chemical agent is injected by using the micro-vibration sensor group (13), and judging the hydrate blockage condition in the target shaft (210) section again; when the hydrate blockage risk exists, returning to the step S50 and increasing the injection amount of the hydrate chemical agent; and when the blocking risk of the hydrate chemical agent is reduced, the injection amount of the injected hydrate chemical agent is continuously kept, and normal oil and gas production work is maintained.
10. The method for hydrate control in deepwater oil and gas well production pipelines according to claim 9,
in the step S20, the determining a hydrate formation zone within the wellbore (210) based on the pressure signal and the temperature signal comprises the steps of:
s201: respectively calculating a temperature field and a pressure field in the oil-gas well shaft (210) according to the calculation model of the temperature field and the pressure field in the oil-gas well shaft (210);
s202: obtaining gas components produced by the stratum, and calculating the temperature and pressure of hydrate generation phase equilibrium in the shaft (210) according to a natural gas hydrate phase equilibrium prediction model;
s203: and determining a hydrate generation area in the well bore (210) by combining the temperature and pressure field in the well bore (210) and the temperature and pressure field of the hydrate phase equilibrium.
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| CN117266810A (en) * | 2023-08-30 | 2023-12-22 | 中国石油大学(华东) | Natural gas hydrate prevention device and method in deepwater shallow gas test process |
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| Publication number | Priority date | Publication date | Assignee | Title |
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| CN117266810A (en) * | 2023-08-30 | 2023-12-22 | 中国石油大学(华东) | Natural gas hydrate prevention device and method in deepwater shallow gas test process |
| CN117266810B (en) * | 2023-08-30 | 2024-05-07 | 中国石油大学(华东) | Natural gas hydrate prevention device and method in deepwater shallow gas test process |
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