CN111520108B - Well group energy management method - Google Patents
Well group energy management method Download PDFInfo
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- CN111520108B CN111520108B CN202010360411.7A CN202010360411A CN111520108B CN 111520108 B CN111520108 B CN 111520108B CN 202010360411 A CN202010360411 A CN 202010360411A CN 111520108 B CN111520108 B CN 111520108B
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
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- E—FIXED CONSTRUCTIONS
- E21—EARTH DRILLING; MINING
- E21B—EARTH DRILLING, e.g. DEEP 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
- E21B43/30—Specific pattern of wells, e.g. optimizing the spacing of wells
Abstract
The application relates to the technical field of natural gas exploitation and discloses a well group energy management method. The method comprises the following steps: marking the natural gas well which is connected into the same compressor for pressurized exploitation as a pressurized exploitation well; selecting at least one natural gas well for self-injection production as a regulation well; monitoring the opening degree of a wellhead regulating valve of the pressurized production well for regulating the production flow; monitoring an intake pressure of the compressor; and when the opening degree of the wellhead regulating valve is reduced and the air inlet pressure of the compressor is reduced, the natural gas in the regulating well is sent into an air inlet pipeline of the compressor, and the air inlet pressure of the compressor is maintained within a preset pressure range. According to the well group energy management method provided by the embodiment of the application, the downward extraction process under the gathering and transportation pressurization background can be matched with the compressor, and the service life of the natural gas well is greatly prolonged.
Description
Technical Field
The application relates to the technical field of natural gas exploitation, in particular to a well group energy management method.
Background
The production pipeline of the conventional natural gas well is directly connected with an external transmission pipeline. When the oil pressure of a well mouth of the natural gas well is larger than the output pressure, the natural gas produced by the natural gas well can enter an external transmission pipeline, and the natural gas well can normally produce. Along with the continuous output of natural gas, the energy of the natural gas well is gradually reduced, and when the wellhead oil pressure and the output pressure of the natural gas well are kept flat, the natural gas produced by the natural gas well cannot enter an external transmission pipeline, namely the natural gas well cannot continue to produce.
The pressurized exploitation is that a production pipeline of a natural gas well is connected with an inlet of a compressor, and the pressure of the production pipeline of the natural gas well is reduced through the work of the compressor, so that natural gas in the natural gas well can be produced. The produced natural gas is pressurized by the compressor and then sent into an external pipeline, so that the condition that the oil pressure of the natural gas well is kept level with the output pressure and the natural gas well cannot be produced is avoided.
At present, a gathering and transportation pressurization mode is mostly adopted to carry out pressurization exploitation on a natural gas well. The gathering and transportation pressurization means that multiple natural gas wells are connected into the same compressor, namely, one compressor drives the multiple natural gas wells to produce.
The compressor is very sensitive to the intake pressure, which requires that the intake pressure not exceed its rated intake pressure range. Most natural gas wells suffer from downhole liquid buildup. If accumulated liquid at the bottom of the well can not be discharged smoothly, the oil pressure of the natural gas well is reduced continuously until the natural gas well stops producing completely. The drainage gas production processes such as the plunger lifting process, the intermittent production process or the open flow process and the like can cause that the natural gas well cannot normally produce in a period of time, namely, the wellhead regulating valve is closed or the opening degree is reduced. In the process of implementing the drainage and mining process, the air inlet pressure of the compressor is greatly reduced, and impact is caused on the compressor. When the intake pressure is lower than the rated intake pressure range, the compressor is stopped or damaged.
Disclosure of Invention
The embodiment of the application provides a well group energy management method, which aims to solve the problem that a drainage and production process is difficult to adapt to a compressor when a gathering and transportation pressurization mode is adopted to perform pressurization exploitation on a natural gas well.
In order to achieve the above purpose, the embodiments of the present application adopt the following technical solutions:
a well cluster energy management method for a well cluster comprising a plurality of natural gas wells, comprising: marking the natural gas well which is connected into the same compressor for pressurized exploitation as a pressurized exploitation well; selecting at least one natural gas well for self-injection production as a regulation well; monitoring the opening degree of a wellhead regulating valve of the supercharged production well for regulating the production flow; monitoring the inlet pressure of the compressor; when the opening degree of the wellhead regulating valve is reduced and the air inlet pressure of the compressor is reduced, natural gas in the regulating well is sent into an air inlet pipeline of the compressor, and the air inlet pressure of the compressor is maintained within a preset pressure range.
Further, when the air inlet pressure of the compressor is smaller than the minimum value of the preset pressure range, the natural gas in the regulating well is sent into an air inlet pipeline of the compressor, and the air inlet pressure of the compressor is maintained within the preset pressure range.
Further, the preset pressure range is within a rated intake pressure range of the compressor.
Further, at least one natural gas well produced by flowing is selected as a regulating well, and the method specifically comprises the following steps: and selecting at least one natural gas well with energy larger than that of the pressurized production well as a regulating well from the natural gas wells with flowing production.
Further, in a natural gas well produced by flowing, at least one natural gas well with energy greater than that of a pressurized production well is selected as a regulation well, and the method specifically comprises the following steps: detecting casing pressure of each pressurized production well after the shut-in time is preset, and taking the highest casing pressure as comparison casing pressure; detecting casing pressure of each natural gas well produced by blowout after the shut-in preset time, and taking the natural gas well with the casing pressure greater than the comparative casing pressure as a well to be selected; and selecting at least one well to be selected as a regulation well.
Further, at least one well to be selected is selected as a regulation well, and the method specifically comprises the following steps: and selecting the well to be selected with the highest casing pressure after the well is shut-in for a preset time as a regulating well.
Further, natural gas in a sleeve of the regulation well is sent into an air inlet pipeline of the compressor.
Further, the flow of the natural gas in the regulating well when being sent into an air inlet pipeline of the compressor is regulated and controlled through an output regulating valve; and when the natural gas in the regulating well is sent into the air inlet pipeline of the compressor, the opening degree of the output regulating valve is gradually increased.
Furthermore, the opening of the wellhead regulating valve is reduced at a constant speed, and the opening of the output regulating valve is increased at a constant speed.
Furthermore, only one pressurized production well is allowed to carry out the plunger lifting process, the interval production process or the blowout process each time, and after the pressurized production well recovers to normal production, the next pressurized production well carries out the plunger lifting process, the interval production process or the blowout process.
The technical scheme of the application has following advantage and beneficial effect at least:
according to the well group energy management method provided by the embodiment of the application, a regulation well is introduced. When the opening of the wellhead regulating valve is reduced and the air inlet pressure of the compressor is reduced, natural gas in the regulating well is sent into an air inlet pipeline of the compressor, and the air inlet pressure of the compressor is maintained within a preset pressure range. When the pressurized production well starts to implement drainage measures such as a plunger lifting process, an interval production process or a blowout process, the pressure lost by the pressurized production well implementing the drainage measures is supplemented by the regulating well, so that the impact of the great reduction of the air inlet pressure on the compressor is avoided, and the probability of the shutdown or damage of the compressor is greatly reduced. According to the well group energy management method provided by the embodiment of the application, the downward extraction process under the gathering and transportation pressurization background can be matched with the compressor, and the service life of the natural gas well is greatly prolonged.
Drawings
In order to more clearly describe the technical solutions of the embodiments of the present application, the drawings that need to be used in the embodiments are briefly described below. It is appreciated that the following drawings depict only certain embodiments of the application and are not to be considered limiting of its scope. From these figures, other figures can be derived by those skilled in the art without inventive effort.
Fig. 1 is a schematic structural diagram of a well group provided in an embodiment of the present application.
In the figure: 010-well group; 011-blowing pipeline; 012-external transport pipe; 100-natural gas wells; 101-valve number one; 102-valve number two; 103-valve number three; 104-valve number four; 105-five valve; 106-valve number six; no. 107-seven valve; 108-eighth valve; valve No. 109-nine; a No. 110-ten valve; valve No. 111-eleven; 112-tubing; 113-a cannula; 115-lubricator; 116-producing a branch; 117-wellhead regulating valve; 118-an oil pressure transmitter; 119-a pressure transmitter; 120-a casing pressure transmitter; 200-natural gas wells; 201-valve number one; 202-valve number two; 203-valve number three; 204-valve number four; 205-valve five; valve number 206-six; 207-seven valve; 208-eighth valve; 209-nine valve; 210-ten valves; valve number 211-eleven; 212-tubing; 213-a bushing; 215-lubricator; 216-production legs; 217-wellhead regulating valve; 218-an oil pressure transmitter; 219-pressure transmitter; 220-a casing pressure transmitter; 300-natural gas wells; 301-valve number one; 302-valve number two; 303-valve number three; 304-valve number four; 305-valve five; 306-valve number six; 307-seventh valve; 308-eighth valve; 309-nine valves; valve number 310-ten; 311-eleven valves; 312-tubing; 313-a cannula; 315-lubricator; 316-production manifold; 317-wellhead regulating valve; 318-oil pressure transmitter; 319-pressure transmission transmitter; 320-a casing pressure transmitter; 400-natural gas wells; 401-valve number one; 402-valve number two; 403-valve number three; 404-valve number four; 405-five valves; 406-valve number six; 407-valve seven; 408-eighth valve; 409-nine valves; a number 410-ten valve; valve number 411-eleven; 412-tubing; 413-a sleeve; 415-lubricator; 416-producing a branch pipe; 417-wellhead regulating valve; 418-oil pressure transmitter; 419-voltage transmission transmitter; 420-a casing pressure transmitter; 421-output regulating valve; 500-a compressor; 501-an air inlet pipeline; 502-an exhaust duct; 600-gas-liquid separator.
Detailed Description
In order to make the objects, technical solutions and advantages of the embodiments of the present application clearer, the technical solutions in the embodiments of the present application will be clearly and completely described below with reference to the accompanying drawings. It should be apparent that the described embodiments are only some of the embodiments of the present application, and not all of the embodiments.
Thus, the following detailed description of the embodiments of the application is not intended to limit the scope of the application as claimed, but is merely representative of some embodiments of the application. All other embodiments, which can be derived by a person skilled in the art from the embodiments given herein without making any creative effort, shall fall within the protection scope of the present application.
It should be noted that, in the embodiments and the features and technical solutions in the embodiments of the present application may be combined with each other without conflict.
It should be noted that: like reference numbers and letters refer to like items in the following figures, and thus, once an item is defined in one figure, it need not be further defined and explained in subsequent figures.
In the description of the present application, it should be noted that the terms "upper", "lower", and the like refer to orientations or positional relationships based on those shown in the drawings, or orientations or positional relationships that are conventionally arranged when the product of the present invention is used, or orientations or positional relationships that are conventionally understood by those skilled in the art, and such terms are used for convenience of description and simplification of the description, and do not refer to or imply that the referred device or element must have a specific orientation, be constructed and operated in a specific orientation, and thus should not be construed as limiting the present application.
In the description of the present application, a natural gas well may be a natural gas well for collecting conventional natural gas, and may also be a natural gas well for collecting unconventional natural gas (shale gas, coal bed gas, etc.).
Example 1:
the embodiment provides a well group energy management method which is used for a well group comprising a plurality of natural gas wells. In the following, gas wells and well groups are described. It should be noted that the following natural gas wells and well groups are only an example for illustrating the well group energy management method, and it is not meant that the well group energy management method provided in this embodiment is only applicable to the following natural gas wells and well groups.
Fig. 1 is a schematic structural diagram of a well group 010 provided in this embodiment. In the present embodiment, the well group 010 includes four natural gas wells, i.e., a natural gas well 100, a natural gas well 200, a natural gas well 300, and a natural gas well 400.
The downhole portion of gas well 100 includes an oil pipe 112 and a casing 113. The wellhead section of the gas well 100 includes a first valve 101, a fourth valve 104, and a seventh valve 107 connected to the upper end of an oil pipe 112 and arranged in this order from bottom to top. And a fifth valve 105, a second valve 102, a third valve 103 and a sixth valve 106 which are arranged from left to right. The upper end of the sleeve 113 is connected between the second valve 102 and the third valve 103. And the valve also comprises a ten-valve 110, an eight-valve 108, a nine-valve 109 and an eleven-valve 111 which are sequentially arranged from left to right. Wherein, the pipeline connecting the fourth valve 104 and the seventh valve 107 is in cross communication with the pipeline connecting the eighth valve 108 and the ninth valve 109. The No. six valve 106 and the No. eleven valve 111 are connected to the blowout pipeline 011. Valve number five 105 and valve number ten 110 are connected to the intake conduit 501 of the compressor 500. A lubricator 115 is provided above the No. seven valve 107. A pressure transmitter 119 is provided on the pipe connecting between the ten-way valve 110 and the eight-way valve 108. One end of the production branch pipe 116 is connected to the pipeline above the valve No. seven 107, and the other end of the production branch pipe 116 is connected to the pipeline between the valve No. eight 108 and the pressure transmitter 119. A wellhead regulating valve 117 and an oil pressure transmitter 118 are provided on the production branch 116. Wherein the oil pressure transmitter 118 is closer to the valve number seven 107. A casing pressure transmitter 120 is provided on top of the casing 113. The first valve 101 to the eleventh valve 111 are all flat plate valves. Under normal production conditions, the first valve 101, the fourth valve 104, the seventh valve 107 and the tenth valve 110 are opened, and the rest of the flat valves are closed.
The downhole portion of gas well 200 includes an oil pipe 212 and a casing 213. The wellhead part of the natural gas well 200 comprises a first valve 201, a fourth valve 204 and a seventh valve 207 which are connected to the upper end of an oil pipe 212 and are sequentially arranged from bottom to top. And a fifth valve 205, a second valve 202, a third valve 203 and a sixth valve 206 which are arranged from left to right. The upper end of sleeve 213 is connected between valve No. two 202 and valve No. three 203. And the valve also comprises a ten-valve 210, an eight-valve 208, a nine-valve 209 and an eleven-valve 211 which are arranged from left to right in sequence. Wherein, the pipeline connecting the fourth valve 204 and the seventh valve 207 is in cross communication with the pipeline connecting the eighth valve 208 and the ninth valve 209. The sixth valve 206 and the eleventh valve 211 are connected to the blowout conduit 011. Valve number five 205 and valve number ten 210 are connected to intake conduit 501 of compressor 500. A lubricator 215 is provided above the No. seven valve 207. A pressure transmitter 219 is provided on the pipe connecting between the ten-way valve 210 and the eight-way valve 208. One end of a production branch pipe 216 is connected to a pipeline above the valve No. seven 207, and the other end of the production branch pipe 216 is connected to a pipeline between the valve No. eight 208 and the pressure transmission transmitter 219. A wellhead regulating valve 217 and an oil pressure transmitter 218 are provided on the production branch 216. Wherein the oil pressure transmitter 218 is closer to valve number seven 207. A casing pressure transmitter 220 is provided on top of the casing 213. The first valve 201 to the eleventh valve 211 are all flat plate valves. Under normal production conditions, the first valve 201, the fourth valve 204, the seventh valve 207 and the tenth valve 210 are opened, and the rest of the flat valves are closed.
The downhole portion of gas well 300 includes an oil pipe 312 and a casing 313. The wellhead part of the natural gas well 300 comprises a first valve 301, a fourth valve 304 and a seventh valve 307 which are connected to the upper end of an oil pipe 312 and are arranged from bottom to top in sequence. And a fifth valve 305, a second valve 302, a third valve 303 and a sixth valve 306 which are arranged from left to right. The upper end of sleeve 313 is connected between valve No. two 302 and valve No. three 303. And a ten-valve 310, an eight-valve 308, a nine-valve 309 and an eleven-valve 311 which are arranged from left to right in sequence. Wherein, the pipeline connecting the fourth valve 304 and the seventh valve 307 is in cross communication with the pipeline connecting the eighth valve 308 and the ninth valve 309. Valve six 306 and valve eleven 311 are connected to the blow-off line 011. Valve nos. 305 and 310 are connected to the intake conduit 501 of the compressor 500. A lubricator 315 is provided above the No. seven valve 307. A pressure transmitter 319 is provided on the pipe connecting between the ten-way valve 310 and the eight-way valve 308. One end of the production branch pipe 316 is connected to a pipeline above the valve No. seven 307, and the other end of the production branch pipe 316 is connected to a pipeline between the valve No. eight 308 and the pressure transmitter 319. A wellhead regulating valve 317 and an oil pressure transmitter 318 are provided on the production manifold 316. Wherein the oil pressure transmitter 318 is closer to the valve 307 # seven. A casing pressure transmitter 320 is provided on top of the casing 313. The first valve 301 to the eleventh valve 311 are all flat plate valves. Under normal production conditions, the first valve 301, the fourth valve 304, the seventh valve 307 and the tenth valve 310 are opened, and the rest of the flat valves are closed.
The downhole portion of gas well 400 includes tubing 412 and casing 413. The wellhead section of the natural gas well 400 comprises a first valve 401, a fourth valve 404 and a seventh valve 407 which are connected to the upper end of an oil pipe 412 and are arranged in sequence from bottom to top. And a fifth valve 405, a second valve 402, a third valve 403 and a sixth valve 406 which are arranged from left to right. The upper end of the sleeve 413 is connected between the second valve 402 and the third valve 403. And the valve comprises a ten-valve 410, an eight-valve 408, a nine-valve 409 and an eleven-valve 411 which are sequentially arranged from left to right. Wherein, the pipeline connecting the fourth valve 404 and the seventh valve 407 is in cross communication with the pipeline connecting the eighth valve 408 and the ninth valve 409. Valve six 406 and valve eleven 411 are connected to the blow-off line 011. Valve number five 405 is connected to the intake conduit 501 of the compressor 500. The ten-way valve 410 is connected to an outgoing line 012. The discharge duct 502 of the compressor 500 is also connected to the outgoing duct 012. A lubricator 415 is provided above the seventh valve 407. A pressure transmitter 419 is provided in the piping connecting between the ten-way valve 410 and the eight-way valve 408. One end of the production branch pipe 416 is connected to a pipeline above the valve 407, and the other end of the production branch pipe 416 is connected to a pipeline between the valve 408 and the pressure transmitter 419. A wellhead regulating valve 417 and an oil pressure transmitter 418 are provided on the production branch 416. Wherein the oil pressure transmitter 418 is closer to the number seven valve 407. A casing pressure transmitter 420 is provided on top of the casing 413. On a pipe where the No. five valve 405 is connected to the intake pipe 501 of the compressor 500, an output regulating valve 421 is provided. The first valve 401 to the eleventh valve 411 are all flat plate valves. Under normal production conditions, the first valve 401, the second valve 402, the fourth valve 404, the fifth valve 405, the seventh valve 407 and the tenth valve 410 are opened, and the rest of the flat valves are closed. The output regulator valve 421 is normally closed, i.e., has an opening degree of 0.
The following describes a well group energy management method provided in this embodiment, where the method includes:
s01: and marking the natural gas well which is connected into the same compressor for supercharging exploitation as a supercharging exploitation well.
Specifically, in the well group 010 provided in the present embodiment, the natural gas wells 100, 200, and 300 are connected to the compressor 500. Gas well 100, gas well 200, and gas well 300 are all labeled as boosted producing wells.
S02: at least one natural gas well produced by flowing is selected as a regulating well.
Specifically, in this embodiment, the natural gas well 400 is capable of self-blowout production, with the natural gas well 400 acting as a conditioning well.
S03: the opening of a wellhead regulating valve for monitoring the pressurized production well is used for regulating the production flow.
Specifically, in the present embodiment, the opening degrees of the wellhead adjustment valve 117, the wellhead adjustment valve 217, and the wellhead adjustment valve 317 are monitored.
S04: monitoring the inlet pressure of the compressor;
specifically, in the present embodiment, the intake pressure of the compressor 500 is monitored.
S05: when the opening degree of the wellhead regulating valve is reduced and the air inlet pressure of the compressor is reduced, natural gas in the regulating well is sent into an air inlet pipeline of the compressor, and the air inlet pressure of the compressor is maintained within a preset pressure range.
Specifically, in the present embodiment, when the opening degree of any one of the wellhead regulating valve 117, the wellhead regulating valve 217, or the wellhead regulating valve 317 is decreased while the intake pressure of the compressor 500 is decreased, the opening degree of the output regulating valve 421 is increased, the natural gas in the natural gas well 400 is sent to the intake pipe 501 of the compressor 500, and the intake pressure of the compressor 500 is maintained within the preset pressure range.
The compressor 500 has a rated intake pressure range, and in the present embodiment, the rated intake pressure range of the compressor 500 is 1.5Mpa to 3 Mpa. Intake air above 3Mpa or below 1.5Mpa can cause the compressor 500 to malfunction or shut down. In this embodiment, the predetermined pressure range is 2MPa to 2.5 MPa. The natural gas introduced into the natural gas well 400 (the conditioning well) maintains the inlet pressure of the compressor 500 within a preset pressure range, so that the inlet pressure of the compressor 500 can be effectively prevented from being lower than 1.5Mpa when the opening degree of any one of the wellhead regulating valve 117, the wellhead regulating valve 217 or the wellhead regulating valve 317 is reduced. The impact on the compressor 500 caused by the great reduction of the air inlet pressure is avoided, and the probability of the shutdown or damage of the compressor 500 is greatly reduced.
The opening degree of the wellhead regulating valve 117, the wellhead regulating valve 217 or the wellhead regulating valve 317 is reduced because the natural gas well to which the natural gas well belongs needs to implement drainage measures such as a plunger lifting process, an intermittent production process or a blowout process. The following describes a plug lift process, a break-open production process, and a blowout process, taking gas well 100 as an example. The ram lift process, the production interval process, and the blow-out process of gas wells 200 and 300 are the same as those of gas well 100 and will not be described in detail herein.
The plunger is positioned within the lubricator 115 prior to performing the lift process. The opening of the wellhead adjustment valve 117 is reduced until the wellhead adjustment valve 117 is fully closed, or the wellhead adjustment valve 117 is maintained at a smaller opening. At this time, the thrust force applied to the plunger is reduced, and the plunger can move downward to the bottom of the well under the action of its own weight. After reaching the well bottom, the opening of the wellhead regulating valve 117 is increased, and the plunger moves upwards under the push of the fluid at the well bottom, and simultaneously lifts the liquid above the plunger to the wellhead. A gas-liquid separator 600 is provided in the intake duct 501 of the compressor 500. The liquid is left in the gas-liquid separator 600 and does not enter the compressor 500. After the plunger is returned to the lubricator 115, the gas well 100 is again normally produced. After the opening of the wellhead adjusting valve 117 is decreased and the intake pressure of the compressor 500 starts to decrease, the opening of the output adjusting valve 421 is increased, and the natural gas introduced into the natural gas well 400 (conditioning well) maintains the intake pressure of the compressor 500 within the preset pressure range. In the process of the plunger ascending, the air inlet pressure of the compressor 500 is monitored, and when the air inlet pressure of the compressor 500 is larger than the preset pressure range, the opening degree of the output regulating valve 421 is reduced, so that the air inlet pressure of the compressor 500 is controlled within the preset pressure range. If the inlet pressure of the compressor 500 is still greater than the preset pressure range after the output regulating valve 421 is closed (the opening is 0), the opening of the wellhead regulating valve 117 is reduced to return the inlet pressure of the compressor 500 to the preset pressure range. It should be noted that when the inlet pressure of the compressor 500 is greater than the preset pressure range, if the opening degree of the wellhead adjusting valve 117 is reduced and the inlet pressure of the compressor 500 is lowered, the natural gas in the natural gas well 400 (conditioning well) is not required to be fed into the inlet pipeline 501 of the compressor 500. Only when the inlet pressure of the compressor 500 is greater than or less than the preset pressure range, if the opening degree of the wellhead adjusting valve 117 is reduced and the inlet pressure of the compressor 500 is lowered, the natural gas in the natural gas well 400 (conditioning well) needs to be fed into the inlet pipe 501 of the compressor 500.
The production process is separated by closing the wellhead choke valve 117 of the gas well 100 for a period of time to recover the bottom-hole energy. After the wellhead regulating valve 117 is opened again, the natural gas can be produced at a high flow rate, and the natural gas at a high flow rate can carry accumulated liquid at the bottom of the well. The liquid is left in the gas-liquid separator 600 and does not enter the compressor 500. After wellhead adjustment valve 117 is reopened, gas well 100 is producing normally. After the opening of the wellhead adjusting valve 117 is decreased and the intake pressure of the compressor 500 starts to decrease, the opening of the output adjusting valve 421 is increased, and the natural gas introduced into the natural gas well 400 (conditioning well) maintains the intake pressure of the compressor 500 within the preset pressure range. In the process of reopening the wellhead adjusting valve 117, the intake pressure of the compressor 500 is monitored, and when the intake pressure of the compressor 500 is greater than the preset pressure range, the opening degree of the output adjusting valve 421 is reduced, so that the intake pressure of the compressor 500 is controlled within the preset pressure range. If the inlet pressure of the compressor 500 is still greater than the preset pressure range after the output regulating valve 421 is closed (the opening is 0), the opening of the wellhead regulating valve 117 is reduced to return the inlet pressure of the compressor 500 to the preset pressure range. It should be noted that when the inlet pressure of the compressor 500 is greater than the preset pressure range, if the opening degree of the wellhead adjusting valve 117 is reduced and the inlet pressure of the compressor 500 is lowered, the natural gas in the natural gas well 400 (conditioning well) is not required to be fed into the inlet pipeline 501 of the compressor 500. Only when the inlet pressure of the compressor 500 is greater than or less than the preset pressure range, if the opening degree of the wellhead adjusting valve 117 is reduced and the inlet pressure of the compressor 500 is lowered, the natural gas in the natural gas well 400 (conditioning well) needs to be fed into the inlet pipe 501 of the compressor 500.
The blowout process refers to closing wellhead adjustment valve 117, closing valve seven 107, opening valve nine 109 and valve eleven 111 of gas well 100. The gas well 100 is in direct communication with the atmosphere through the blowout conduit 011, creating a significant pressure differential. The natural gas in the natural gas well 100 is ignited after being ejected at a high speed through the blowout pipeline 011. The natural gas flows at high speed, so that the accumulated liquid at the bottom of the well is taken out of the well. After the blowout is completed, the ninth valve 109 and the eleventh valve 111 are closed, the seventh valve 107 is opened, and then the wellhead regulating valve 117 is gradually opened, so that the natural gas well 100 is normally produced. After the opening of the wellhead adjusting valve 117 is decreased and the intake pressure of the compressor 500 starts to decrease, the opening of the output adjusting valve 421 is increased, and the natural gas introduced into the natural gas well 400 (conditioning well) maintains the intake pressure of the compressor 500 within the preset pressure range. In the process of reopening the wellhead adjusting valve 117, the intake pressure of the compressor 500 is monitored, and when the intake pressure of the compressor 500 is greater than the preset pressure range, the opening degree of the output adjusting valve 421 is reduced, so that the intake pressure of the compressor 500 is controlled within the preset pressure range. If the inlet pressure of the compressor 500 is still greater than the preset pressure range after the output regulating valve 421 is closed (the opening is 0), the opening of the wellhead regulating valve 117 is reduced to return the inlet pressure of the compressor 500 to the preset pressure range. It should be noted that when the inlet pressure of the compressor 500 is greater than the preset pressure range, if the opening degree of the wellhead adjusting valve 117 is reduced and the inlet pressure of the compressor 500 is lowered, the natural gas in the natural gas well 400 (conditioning well) is not required to be fed into the inlet pipeline 501 of the compressor 500. Only when the inlet pressure of the compressor 500 is greater than or less than the preset pressure range, if the opening degree of the wellhead adjusting valve 117 is reduced and the inlet pressure of the compressor 500 is lowered, the natural gas in the natural gas well 400 (conditioning well) needs to be fed into the inlet pipe 501 of the compressor 500.
As can be seen from the above description, the well group energy management method provided in this embodiment enables drainage and production measures such as a plunger lifting process, an intermittent production process, or a blowout process to be adapted to the compressor 500 in the background of gathering, transportation, and pressurization, so as to greatly improve the service life of the natural gas well.
Further, in step S02, at least one natural gas well produced by flowing is selected as the control well, specifically, at least one natural gas well with energy greater than that of the pressurized production well is selected as the control well. The method specifically comprises the following steps:
s021: and detecting the casing pressure of each pressurized production well after the shut-in time is preset, and taking the highest casing pressure as the comparison casing pressure.
After the gas wells 100, 200 and 300 are shut in for a preset time (for example, 1 day), the casing pressures of the gas wells 100, 200 and 300 are acquired by the casing pressure transmitter 120, 220 and 320, respectively. The highest casing pressure was taken as the comparative casing pressure.
S022: and detecting casing pressure of the natural gas wells produced by respective blowout for a preset time, and taking the natural gas wells with the casing pressure greater than the comparative casing pressure as wells to be selected.
In this embodiment, the well cluster 010 has only one flowing well, i.e., the natural gas well 400. The natural gas well 400 is shut in for a preset time (the shut-in time is the same as that of the pressurized production well), and the casing pressure of the natural gas well 400 is obtained through the casing pressure transmitter 420. The casing pressure of gas well 400 is greater than the comparative casing pressure. Then gas well 400 is considered as the candidate well. And when a plurality of flowing wells exist in the well group 010, all flowing wells with casing pressure larger than the contrast casing pressure after closing the wells for preset time are taken as the wells to be selected.
S023: and selecting at least one well to be selected as a regulation well.
In this embodiment, as only one candidate well, i.e., the natural gas well 400, is present in the well group 010, the natural gas well 400 is selected as the control well. When a plurality of wells to be selected exist, at least one well to be selected can be selected as a regulating well according to the situation. Preferably, the well to be selected with the highest casing pressure after the well shut-in preset time is selected as the regulating well. In this way, other wells to be selected can be normally produced, and the yield is ensured. The regulation and control wells supplement pressure loss of the pressurized production wells caused by the implementation of drainage measures when needed, so that the yield of the whole well group 010 is improved.
Further, when the inlet pressure of the compressor 500 is less than the minimum value of the preset pressure range, the natural gas in the regulation well is sent into the inlet pipe 501 of the compressor 500, and the inlet pressure of the compressor 500 is maintained within the preset pressure range.
When no drainage and production measures such as a plunger lifting process, an interval production process, a blowout process and the like are adopted by the supercharged production well, if the air inlet pressure of the compressor 500 is smaller than the minimum value of the preset pressure range, the output of the supercharged production well is suddenly reduced, and at the moment, the lost pressure also needs to be supplemented, so that the compressor 500 is prevented from being impacted by the pressure, and the air inlet pressure of the compressor 500 is prevented from being lower than the rated air inlet pressure range.
Further, in this embodiment, natural gas in the casing 413 of the natural gas well 400 (conditioning well) is fed into the inlet pipe 501 of the compressor 500. In other embodiments, natural gas from the tubing 412 of the gas well 400 (a conditioning well) may also be fed into the inlet conduit 501 of the compressor 500. However, if the natural gas in the oil pipe 412 of the natural gas well 400 (the control well) is fed into the intake pipe 501 of the compressor 500, the natural gas well 400 (the control well) cannot normally produce, and the overall yield of the well group 010 is reduced. Thus, natural gas in the casing 413 of the natural gas well 400 (pilot well) is preferably fed into the inlet conduit 501 of the compressor 500.
Further, the flow rate of the natural gas in the regulation well (natural gas well 400) when the natural gas is sent into the inlet pipeline 501 of the compressor 500 is regulated and controlled through the output regulating valve 421. When natural gas in the conditioning well (natural gas well 400) starts to be fed into the intake pipe 501 of the compressor 500, the opening degree of the output regulating valve 421 is gradually increased.
The opening degree of the output regulating valve 421 is gradually increased, so that the large fluctuation of the air inlet pressure of the compressor 500 can be avoided, the pressure impact on the compressor 500 is reduced, and the working stability of the compressor 500 is improved.
Further, the opening of the wellhead regulating valve is decreased at a constant speed, and the opening of the output regulating valve 421 is increased at a constant speed. Therefore, the large fluctuation of the air inlet pressure of the compressor 500 can be further avoided, the pressure impact on the compressor 500 is reduced, and the working stability of the compressor 500 is improved.
Furthermore, only one pressurized production well is allowed to carry out the plunger lifting process, the intermittent production process, the open flow process or the well closing and pressure restoring process each time, and after the normal production is recovered, the next pressurized production well carries out the plunger lifting process, the intermittent production process, the open flow process or the well closing and pressure restoring process.
When a plunger lifting process, an interval opening production process, a blowout process or a well closing and re-pressing process is simultaneously carried out on a plurality of pressurized production wells, the control well may not be capable of compensating the lost pressure. In order to ensure that the well group 010 energy management method provided by the embodiment can be effectively implemented, only one pressurized production well is allowed to implement the plunger lifting process, the interval production process, the blowout process or the well closing and pressure recovery process each time, and after the pressurized production well recovers to normal production, the plunger lifting process, the interval production process, the blowout process or the well closing and pressure recovery process is implemented on the next pressurized production well.
In this embodiment, the natural gas wells in the well group 010 are located on the same platform. It is understood that in other embodiments, the natural gas wells in well cluster 010 may be located on different platforms.
The above description is given for the sole purpose of illustrating the invention and is not to be construed as limiting the application, since numerous modifications and variations will readily occur to those skilled in the art. Any modification, equivalent replacement, improvement and the like made within the spirit and principle of the present application shall be included in the protection scope of the present application.
Claims (8)
1. A well cluster energy management method for a well cluster comprising a plurality of natural gas wells, comprising:
marking the natural gas well which is connected into the same compressor for pressurized exploitation as a pressurized exploitation well;
selecting at least one natural gas well for self-injection production as a regulation well;
monitoring the opening degree of a wellhead regulating valve of the pressurized production well for regulating the production flow;
monitoring an intake pressure of the compressor;
when the opening degree of the wellhead regulating valve is reduced and the air inlet pressure of the compressor is reduced, the natural gas in the regulating well is sent into an air inlet pipeline of the compressor, and the air inlet pressure of the compressor is maintained within a preset pressure range;
At least one natural gas well produced by flowing is selected as the regulating well, and the method specifically comprises the following steps: selecting at least one natural gas well with energy greater than that of the pressurized production well as the regulation well from natural gas wells produced by flowing;
the method comprises the following steps of selecting at least one natural gas well with energy larger than that of a pressurized production well as a regulation well from natural gas wells produced by flowing, and specifically comprises the following steps: detecting the casing pressure of each pressurized production well after the well shut-in preset time, and taking the highest casing pressure as a comparison casing pressure; detecting casing pressure of each gas well produced by jetting after the gas well is shut down for the preset time, and taking the gas well with the casing pressure greater than the comparative casing pressure as a well to be selected; selecting at least one of the candidate wells as the conditioning well.
2. The well group energy management method of claim 1, further comprising:
and when the air inlet pressure of the compressor is smaller than the minimum value of the preset pressure range, sending the natural gas in the regulating well into an air inlet pipeline of the compressor, and maintaining the air inlet pressure of the compressor within the preset pressure range.
3. The well group energy management method of claim 1, wherein:
The preset pressure range is within a rated air inlet pressure range of the compressor.
4. The well group energy management method according to claim 1, wherein selecting at least one of the candidate wells as the conditioning well comprises:
and selecting the well to be selected with the highest casing pressure after the well is closed for the preset time as the regulating well.
5. The well group energy management method of claim 1, wherein:
and sending the natural gas in the casing of the regulating well into an air inlet pipeline of the compressor.
6. The well group energy management method of claim 1, wherein:
the flow of the natural gas in the regulating well when the natural gas is sent into an air inlet pipeline of the compressor is regulated through an output regulating valve;
and when the natural gas in the regulating well is sent into the air inlet pipeline of the compressor, the opening degree of the output regulating valve is gradually increased.
7. The well group energy management method of claim 6, wherein:
the opening degree of the wellhead regulating valve is reduced at a constant speed, and the opening degree of the output regulating valve is increased at a constant speed.
8. The well group energy management method of claim 1, wherein:
And allowing only one pressurized production well to perform a plunger lifting process, an interval production process or a blowout process each time, and after the pressurized production well recovers to normal production, performing the plunger lifting process, the interval production process or the blowout process on the next pressurized production well.
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