WO2005024289A1 - Positive pressure gas jacket for a natural gas pipeline - Google Patents
Positive pressure gas jacket for a natural gas pipeline Download PDFInfo
- Publication number
- WO2005024289A1 WO2005024289A1 PCT/CA2004/001567 CA2004001567W WO2005024289A1 WO 2005024289 A1 WO2005024289 A1 WO 2005024289A1 CA 2004001567 W CA2004001567 W CA 2004001567W WO 2005024289 A1 WO2005024289 A1 WO 2005024289A1
- Authority
- WO
- WIPO (PCT)
- Prior art keywords
- gas
- pipeline
- chamber
- positive pressure
- internal chamber
- Prior art date
Links
- 239000007789 gas Substances 0.000 title claims abstract description 185
- VNWKTOKETHGBQD-UHFFFAOYSA-N methane Chemical compound C VNWKTOKETHGBQD-UHFFFAOYSA-N 0.000 title claims abstract description 50
- 239000003345 natural gas Substances 0.000 title claims abstract description 25
- 238000004519 manufacturing process Methods 0.000 claims abstract description 63
- 238000000034 method Methods 0.000 claims abstract description 34
- 239000002343 natural gas well Substances 0.000 claims abstract description 8
- 238000012546 transfer Methods 0.000 claims abstract description 6
- 239000007788 liquid Substances 0.000 claims description 91
- 238000002347 injection Methods 0.000 claims description 56
- 239000007924 injection Substances 0.000 claims description 56
- 238000011144 upstream manufacturing Methods 0.000 claims description 39
- 239000012530 fluid Substances 0.000 claims description 18
- 238000004891 communication Methods 0.000 claims description 17
- 238000010276 construction Methods 0.000 claims description 6
- 229910000831 Steel Inorganic materials 0.000 claims description 4
- 230000001105 regulatory effect Effects 0.000 claims description 4
- 239000010959 steel Substances 0.000 claims description 4
- 238000007599 discharging Methods 0.000 claims 2
- 230000015572 biosynthetic process Effects 0.000 description 15
- 238000005755 formation reaction Methods 0.000 description 15
- 238000010586 diagram Methods 0.000 description 6
- 238000004880 explosion Methods 0.000 description 6
- 238000012545 processing Methods 0.000 description 6
- QVGXLLKOCUKJST-UHFFFAOYSA-N atomic oxygen Chemical compound [O] QVGXLLKOCUKJST-UHFFFAOYSA-N 0.000 description 5
- 239000001301 oxygen Substances 0.000 description 5
- 229910052760 oxygen Inorganic materials 0.000 description 5
- 238000011084 recovery Methods 0.000 description 5
- 230000007797 corrosion Effects 0.000 description 4
- 238000005260 corrosion Methods 0.000 description 4
- 230000004941 influx Effects 0.000 description 4
- 230000007257 malfunction Effects 0.000 description 3
- 239000000463 material Substances 0.000 description 3
- 238000005516 engineering process Methods 0.000 description 2
- 238000012986 modification Methods 0.000 description 2
- 230000004048 modification Effects 0.000 description 2
- 230000003068 static effect Effects 0.000 description 2
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 description 2
- 238000009825 accumulation Methods 0.000 description 1
- 238000004364 calculation method Methods 0.000 description 1
- 238000007796 conventional method Methods 0.000 description 1
- 239000010779 crude oil Substances 0.000 description 1
- 230000000779 depleting effect Effects 0.000 description 1
- 230000027734 detection of oxygen Effects 0.000 description 1
- 238000005553 drilling Methods 0.000 description 1
- 239000008187 granular material Substances 0.000 description 1
- 238000005259 measurement Methods 0.000 description 1
- 230000000116 mitigating effect Effects 0.000 description 1
- 239000000203 mixture Substances 0.000 description 1
- 239000003921 oil Substances 0.000 description 1
- 230000000149 penetrating effect Effects 0.000 description 1
- 239000011435 rock Substances 0.000 description 1
- 239000004576 sand Substances 0.000 description 1
- 238000000926 separation method Methods 0.000 description 1
Classifications
-
- 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
- E21B43/12—Methods or apparatus for controlling the flow of the obtained fluid to or in wells
Definitions
- the present invention relates to methods and apparatus for protecting against the influx of air into a pipeline carrying a combustible gas under negative pressure, and particularly to such methods and apparatus for use in association with a pipeline carrying natural gas under negative pressure from a natural gas well to a gas compressor.
- Natural gas is commonly found in subsurface geological formations such as deposits of granular material (e.g., sand or gravel) or porous rock. Production of natural gas from these types of formations typically involves drilling a well a desired depth into the formation, installing a casing in the wellbore (to keep the well bore from sloughing and collapsing), perforating the casing in the production zone (i.e., the portion of the well that penetrates the gas-bearing formation) so that gas can flow into the casing, and installing a string of tubing inside the casing down to the production zone. Gas can then be made to flow up to the surface through a production chamber, which may be either the tubing or the annulus between the tubing and the casing. The gas flowing up the production chamber is conveyed through an intake pipeline running from the wellhead to the suction inlet of a wellhead compressor. The compressed gas discharged from the compressor is then conveyed through another pipeline to a gas processing facility and sales facility as appropriate.
- a production chamber
- the bottomhole flowing pressure In order to optimize total volumes and rates of gas recovery from a gas reservoir, the bottomhole flowing pressure should be kept as low as possible. The theoretically ideal case would be to have a negative bottomhole flowing pressure so as to facilitate 100% gas recovery from the reservoir, resulting in a final reservoir pressure of zero. In order to reduce the bottomhole pressure to a negative value, or to a very low positive value, it would be necessary to have a negative flowing pressure (i.e., less than atmospheric pressure) in the intake pipeline. This can be readily accomplished using well-known technology; i.e., by providing a wellhead compressor of sufficient power.
- One way of minimizing or eliminating the explosion and corrosion risks, while facilitating the use of negative pressures in the intake pipeline, would be to provide an oxygen sensor in association with the pipeline.
- the oxygen sensor would be adapted to detect the presence of oxygen inside the pipeline, and to shut down the compressor immediately upon detection of oxygen.
- This system thus would more safely facilitate the use of compressor suction to induce negative pressures in the intake pipeline and, therefore, to induce negative or low positive bottomhole flowing pressures.
- this system has an inherent drawback in that its effectiveness would rely on the proper functioning of the oxygen sensor. If the sensor malfunctions, and if the malfunction is not detected and remedied in timely fashion, the risk of explosion and/or corrosion will become manifest once again.
- the present invention provides a method and apparatus whereby the intake pipeline running between the production chamber of a natural gas well and the suction inlet of an associated wellhead compressor is completely enclosed, in vapour-tight fashion, within a jacket of natural gas under positive pressure (i.e., higher than atmospheric). Being enclosed inside this "positive pressure jacket", the intake pipeline is not exposed to the atmosphere at any point. This allows gas to be drawn into the compressor through the intake pipeline under a negative pressure, without risk of air entering the intake pipeline should a leak occur in the pipeline. If such a leak occurs, there would merely be a harmless transfer of gas from the positive pressure jacket into the intake pipeline.
- positive pressure i.e., higher than atmospheric
- the present invention is a positive pressure gas jacket apparatus for use in association with a natural gas well facility, said well facility comprising: (a) a wellbore extending from ground surface into a subsurface gas production zone; (b) a wellhead apparatus at the top of the wellbore; (c) a tubing string extending from the wellhead into the wellbore, for conveying gas from the production zone, said tubing string and wellbore defining an annulus; (d) an upstream pipeline in fluid communication with a production chamber selected from the tubing and the annulus, and connecting to the suction manifold of a gas compressor; and (e) a downstream pipeline extending from the discharge manifold of the compressor: said apparatus comprising: (f) a vapour-tight enclosure defining an internal chamber surrounding the upstream pipeline; and (g) a gas recirculation pipeline extending between a selected
- the invention is a method of preventing air leaks into the upstream pipeline of a natural gas well facility as described above, the method comprising the steps of: (f) providing a vapour-tight enclosure defining an internal chamber surrounding the upstream pipeline; and (g) providing a gas recirculation pipeline extending between a selected point on the downstream pipeline and a selected point on the vapour-tight enclosure, such that the gas recirculation pipeline is in fluid communication with both the downstream pipeline and the internal chamber of the vapour-tight enclosure; said method being characterized in that the upstream pipeline will be completely enveloped by pressurized natural gas introduced into the internal chamber from the downstream pipeline via the recirculation pipeline.
- a throttling valve is provided in the recirculation pipeline, for regulating the flow of gas from the downstream pipeline into the recirculation pipeline.
- a pressure regulator valve is disposed between the internal chamber of the vapour-tight enclosure and a well injection chamber selected from the tubing and the annulus, said injection chamber not being the production chamber.
- the PRV is adapted to prevent gas pressure in the internal chamber from exceeding a selected pre-set value, by allowing gas from the internal chamber to enter the well injection chamber when the internal chamber pressure exceeds the pre-set value.
- the vapour-tight enclosure is preferably of welded steel construction. However, other materials and known fabrication methods may be used without departing from the scope of the invention.
- the positive pressure gas jacket apparatus also comprises a gas-liquid separator apparatus connected into the upstream pipeline for separating liquids out of raw gas from the well, with a liquid discharge line for removing separated liquids, and with the internal chamber of the vapour-tight enclosure surrounding the separator apparatus as well as the upstream pipeline.
- pressurized gas introduced into the internal chamber from the downstream pipeline via the recirculation pipeline will completely envelope both the separator apparatus and the discharge line.
- the separator apparatus comprises a separator vessel, a blow case, and a liquid transfer line for carrying separated liquids from tlie separator vessel to the blow case.
- the blow case is of a type well known in the art, being a pressure vessel for retaining the separated liquids under positive pressure.
- the liquid discharge line connects to the blow case and extends therefrom through the vapour- tight enclosure for conveying liquids from the blow case under positive pressure to a liquid disposal point (which may be a storage tank, or alternatively may be a connection to the downstream pipeline) . Since the liquids leave the blow case under positive pressure, it is not necessary for the vapour-tight enclosure to enclose any portion of the liquid discharge line.
- liquids removed by the separator apparatus are discharged into the liquid discharge line under negative pressure, and the liquid discharge line connects to a vacuum pump, which in turn discharges the liquids under positive pressure into a liquid return line.
- the internal chamber of the vapour-tight enclosure surrounds the liquid discharge line as well as the separator apparatus and the upstream pipeline, such that pressurized gas introduced into the internal chamber from the downstream pipeline via the recirculation pipeline will completely envelope the upstream pipeline, the separator apparatus, and the discharge line.
- FIGURE 1 is a schematic diagram of a well producing natural gas in accordance with prior art methods and apparatus.
- FIGURE 2 is a schematic diagram of a well producing natural gas in accordance with a preferred embodiment of the method and apparatus of the present invention.
- FIGURE 3 is a schematic diagram of a well producing natural gas in accordance with an alternative embodiment of the method and apparatus of the invention.
- FIGURE 4 is a partial cutaway schematic diagram of a separator having a positive pressure gas jacket in accordance with a preferred embodiment of the invention.
- FIGURE 5 is a schematic diagram of a gas well producing natural gas using a prior art gas injection system.
- FIGURE 6 is a schematic diagram of the gas well shown in FIG. 5, producing natural gas using a prior art gas injection system, modified to incorporate the positive pressure jacket of the present invention.
- FIG. 1 schematically illustrates a typical natural gas well W configured in accordance with prior art methods and apparatus.
- the well W penetrates a subsurface formation F containing natural gas (typically along with water and crude oil in some proportions).
- the well W is lined with a casing 20 which has a number of perforations conceptually illustrated by short lines 22 within a production zone (generally corresponding to the portion of the well penetrating the formation F).
- formation fluids including gas, oil, and water may flow into the well through the perforations 22.
- a string of tubing 30 extends inside the casing 20, terminating at a point within the production zone.
- the bottom end of the tubing 30 is open such that fluids in the wellbore may freely enter the tubing 30.
- An annulus 32 is formed between the tubing 30 and the casing 20.
- the upper end of the tubing 30 runs into a surface termination apparatus or "wellhead" (not illustrated), of which various types are known in the field of gas wells.
- wellhead (not illustrated)
- the diameter of the casing 20 is commonly in the range of 4.5 to 7 inches (114 to 178 mm)
- the diameter of the tubing 30 is commonly in the range of 2.375 to 3.5 inches (60 to 89 mm)
- the well W typically penetrates hundreds or thousands of feet into the ground.
- the arrows in the Figures denote the direction of flow within various components of the apparatus.
- the tubing 30 serves as the production chamber to carry gas from the well W, under positive pressure, via the wellhead (not shown) to a production pipeline 40 having an upstream section 40U which carries the gas through a gas-liquid separator 70 to the suction manifold 42S of a gas compressor 42.
- the separator 70 divides the upstream pipeline into section 40U' on the wellhead side of the separator, and section 40U" on the compressor side of the separator 70.
- the production pipeline 40 also has a downstream section 40D which connects at one end to the discharge manifold 42D of the compressor 42 and continues therefrom to a gas processing facility (not shown).
- liquids 72 separated from the gas flowing in the intake pipeline 40U' will accumulate in a lower section of the separator 70. In the usual case, the liquids 72 flow from the separator 70 to a storage tank 80 on the well site.
- the present invention may be best understood from reference to FIG. 2.
- the invention provides for production of gas under negative pressure, in which case the liquids 72 removed from the gas stream by the separator 70 will also be under negative pressure, and for this reason a vacuum pump 74 is provided as shown.
- the liquids 72 flow under negative pressure through a pump inlet line 78 to the pump 74, which pumps the liquids 72, now under positive pressure, through a liquid return line 76 into the downstream section 40D of production pipeline 40 at a point Z downstream of the compressor 42.
- the liquids 72 may be pumped to an on-site storage tank 80. As illustrated in FIG.
- a gas recirculation pipeline 60 extends between, and is in fluid communication with, the downstream section 40D of production pipeline 40 (at point X located between the compressor 42 and point Z) and a selected pressure connection point Y on the positive pressure jacket 50. As shown in FIG. 2, pressure connection point Y may be located in upstream pipeline section 40U" between the compressor 42 and the separator 70.
- pressure connection point Y may be at any convenient location on the positive pressure jacket 50 ⁇ such as, for example, on the portion of the positive pressure jacket 50 surrounding the separator 70, as schematically indicated by broken lines (marked 61), which depict an optional alternative routing of the recirculation pipeline 60.
- the positive pressure jacket 50 By means of the recirculation pipeline 60, a portion of the gas discharged from the discharge manifold 42D of the compressor 42 may be diverted into the positive pressure jacket 50, such that the upstream pipeline sections 40U' and 40U", the separator 70, and the pump inlet line 78 are entirely enclosed by a "blanket” of gas under positive pressure.
- the positive pressure jacket 50 thus enshrouds all components of the apparatus containing combustible fluids under negative pressure between the wellhead and the suction manifold 42S of compressor 42 with a blanket of gas under positive pressure, thereby preventing the entry of air into the combustible fluids present in any of those components.
- the positive pressure jacket 50 also encloses any portions of tlie wellhead containing gas under negative pressure.
- FIG. 2 provides for what may be termed a "static" positive pressure blanket, as the gas inside the positive pressure jacket 50 will be essentially stationary.
- the internal chamber 52 of the positive pressure jacket 50 is in fluid communication with the annulus 32 of the well W, such that gas from the internal chamber 52 of the positive pressure jacket 50 can be injected into the annulus 32.
- a pressure regulator valve 54 is provided to regulate the gas pressure inside the positive pressure jacket 50.
- the pressure regulator valve 54 may be set such that it will open, thus allowing gas to enter the annulus 32, only when the gas pressure in the internal chamber 52 of the positive pressure jacket 50 is above a selected value. Under either static conditions (as in FIG.
- a throttling valve (or “choke”) 62 optionally may be provided in association with the recirculation pipeline 60, to regulate the flow of gas from the downstream section 40D of production pipeline 40 into the recirculation pipeline 60 and thence into the internal chamber 52 of the positive pressure jacket 50 and ultimately into the well W.
- FIG. 4 schematically illustrates a preferred construction of the separator 70 and the corresponding section of the positive pressure jacket 50 in accordance with the present invention.
- the separator 70 comprises two main components, a vertical separator 90 and a blow case 100, the construction and operation of which are in accordance with well known technology.
- Upstream pipeline section 40U' delivers raw well gas under negative pressure to the separator.
- Upstream pipeline section 40U" delivers dry gas from the separator 70 to the suction manifold 42S of the compressor 42.
- the vertical separator 90 and blow case 100 are enclosed within a separator jacket 55 forming part of the overall positive pressure jacket 50.
- Injection pipeline 60 carrying gas under pressure from the downstream pipeline 40D, is connected to the positive pressure jacket 50 at pressure connection point Y (which in the embodiment shown in FIG.
- a check valve 106 prevents liquids from being discharged from the blow case 100 unless the pressure in the blow case exceeds a pre-set value.
- the flow in the liquid return line 76 will always be under positive pressure as it exits the separator jacket 55.
- the method and apparatus of the present invention can be particularly advantageous when used in conjunction with gas wells in which gas injection is used to enhance recovery of gas from the formation F.
- Gas injection provides this benefit by further reducing bottomhole pressures in the well W.
- Formation pressures in virgin gas reservoirs tend to be relatively high. Therefore, upon initial completion of a well, the gas will commonly rise naturally to the surface provided that the characteristics of the reservoir and the wellbore are suitable to produce stable flow (meaning that the gas velocity at all locations in the production chamber remains equal to or greater than the critical velocity - in other words, velocity-induced flow).
- FIG. 5 illustrates a gas well producing natural gas using an embodiment of the gas injection system disclosed in PCT/CA2004/000478.
- the tubing 30 serves as the production chamber to carry gas from the well W to an above-ground production pipeline 40, which has an upstream section 40U and a downstream section 40D.
- the tubing 30 connects in fluid communication with one end of the upstream section 40U (via wellhead apparatus, not shown), and the other end of the upstream section 40U is connected to the suction manifold 42S of a gas compressor 42.
- the downstream section 40D of the production pipeline 40 connects at one end to the discharge manifold 42D of the compressor 42 and continues therefrom to a gas processing facility (not shown).
- a gas injection pipeline 16 for diverting production gas from the production pipeline 40 for injection into the injection chamber is connected at one end to the downstream section 40D of the production pipeline 40 at a point Q, and at its other end to the top of the injection chamber.
- a throttling valve or “choke" 12 which is operable to regulate the flow of gas from the production pipeline 40 into the injection pipeline 16 and the injection chamber.
- the choke 12 may be of any suitable type.
- the choke 12 may be of a manually-actuated type, which may be manually adjusted to achieve desired rates of gas injection, using trial-and-error methods as may be necessary or appropriate; with practice, a skilled well operator can develop a sufficiently practical ability to determine how the choke 12 needs to be adjusted to achieve stable gas flow in the production chamber, without actually quantifying the necessary minimum gas injection rate or the flow rate in the production chamber.
- the choke 12 may be an automatic choke; e.g., a Kimray® Model 2200 flow control valve. In the preferred embodiment, however, a flow controller 150 is provided for operating the choke 12.
- the flow controller 150 may be a pneumatic controller of any suitable type; e.g., a FisherTM Model 4194 differential pressure controller.
- the critical flow rate which may be expressed in terms of either gas velocity or volumetric flow, is a parameter corresponding to the minimum velocity V cr that must be maintained by a gas stream flowing up the production chamber (i.e., the tubing 30, in FIG. 5) in order to carry formation liquids upward with the gas stream (i.e., by velocity- induced flow).
- This parameter is determined in accordance with well-established methods and formulae taking into account a variety of quantifiable factors relating to the well construction and the characteristics of formation from which the well is producing.
- a minimum total flow rate (or "set point") is then selected, based on the calculated critical flow rate, and flow controller 150 is set accordingly.
- the selected set point will preferably be somewhat higher than the calculated critical rate, in order to provide a reasonable margin of safety, but also preferably not significantly higher than the critical rate, in order to minimize friction loading in the production chamber.
- the flow controller 150 will adjust the choke 12 to increase the gas injection rate if and as necessary to increase the total flow rate to a level at or above the set point. If the total flow rate is at or above the set point, there may be no need to adjust the choke 12.
- the flow controller 50 may be adapted such that if the total gas flow is considerably higher than the set point, the flow controller 150 will adjust the choke 12 to reduce the gas injection rate, thus minimizing the amount of gas being recirculated to the well through injection, and maximizing the amount of gas available for processing and sale.
- the flow controller 150 has a computer with a microprocessor (conceptually illustrated by reference numeral 160) and a memory (conceptually illustrated by reference numeral 162).
- the flow controller 150 also has a meter communication link (conceptually illustrated by reference numeral 152) for receiving gas flow measurement data from the meter 14.
- the meter communication link 152 may comprise a wired or wireless electronic link, and may comprise a transducer.
- the flow controller 150 also has a choke control link (conceptually illustrated by reference numeral 154), for communicating a control signal from the computer 160 to a choke control means (not shown) which actuates the choke 12 in accordance with the control signal from the computer.
- the choke control link 154 may comprise a mechanical linkage, and may comprise a wired or wireless electronic link.
- the computer 160 receives a signal from the meter 14 (via the meter communication link 152) corresponding to the measured total gas flow rate in the production chamber, and, using software programmed into the computer 160, compares this value against the set point. The computer 160 then calculates a minimum injection rate at which supplementary gas must be injected into the injection chamber, or to which the injection rate must be increased in order to keep the total flow rate at or above the set point. This calculation takes into account the current gas injection rate (which would be zero if no gas is being injected at the time).
- the computer 160 will convey a control signal, via the choke control link 154, to the choke control means, which in turn will adjust the choke 12 to deliver injection gas, at the calculated minimum injection rate, into the injection pipeline 16, and thence into the injection chamber of the well (i.e., the annulus 32, in FIG. 1). If the measured total gas flow equals or exceeds the set point, no adjustment of the choke 12 will be necessary, strictly speaking.
- the computer 160 may also be programmed to reduce the injection rate if it is substantially higher than the set point, in order to minimize the amount of gas being recirculated to the well W, thus maximizing the amount of gas available for processing and sale, as well as to minimize friction loading.
- gas production would be optimized by producing gas up both chambers, thus reducing gas velocities and resultant friction loading (provided of course that the gas velocity — which will be naturally lower than when producing through only one chamber - - remains above V cr at all points in at least one of the chambers; i.e., so that there is stable flow in at least one chamber).
- FIG. 6 illustrates the well and gas injection system shown in FIG. 5, but modified to incorporate the positive pressure jacket of the present invention, with separator and positive pressure jacket components corresponding to those described and illustrated in connection with FIG. 2 and FIG. 5.
- the recirculation pipeline 60 ties in to the injection pipeline 16, but this is only a representative illustration of one means of providing gas under positive pressure to the internal chamber 52 of the positive pressure jacket 50.
- the recirculation pipeline 60 could be a separate line connecting to downstream pipeline 40D, independent of injection pipeline 16.
- FIGURES 3, 4, and 6 can be readily adapted for use in association with a gas well in which the annulus 32 serves as the production chamber.
- the upstream section 40U of intake pipeline 40 will be in fluid communication with the annulus 32
- the internal chamber 52 of the positive pressure jacket 50 will be in fluid communication with the production tubing 30.
- pressurized gas diverted into the internal chamber 52 will be injected into the well W through the tubing 30, with the same production-enhancing benefits as described previously in connection with embodiments wherein the tubing 30 serves as the production chamber.
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Abstract
Description
Claims
Priority Applications (6)
Application Number | Priority Date | Filing Date | Title |
---|---|---|---|
US10/568,588 US7275599B2 (en) | 2003-09-04 | 2004-08-27 | Positive pressure gas jacket for a natural gas pipeline |
AU2004270771A AU2004270771B2 (en) | 2003-09-04 | 2004-08-27 | Positive pressure gas jacket for a natural gas pipeline |
CA002536496A CA2536496C (en) | 2003-09-04 | 2004-08-27 | Positive pressure gas jacket for a natural gas pipeline |
AT04761731T ATE557234T1 (en) | 2003-09-04 | 2004-08-27 | PRESSURE GAS JACKET FOR A NATURAL GAS PIPE |
MXPA06002547A MXPA06002547A (en) | 2003-09-04 | 2004-08-27 | Positive pressure gas jacket for a natural gas pipeline. |
EP04761731A EP1668287B1 (en) | 2003-09-04 | 2004-08-27 | Positive pressure gas jacket for a natural gas pipeline |
Applications Claiming Priority (2)
Application Number | Priority Date | Filing Date | Title |
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CA2,439,487 | 2003-09-04 | ||
CA2439487 | 2003-09-04 |
Publications (1)
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WO2005024289A1 true WO2005024289A1 (en) | 2005-03-17 |
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Family Applications (1)
Application Number | Title | Priority Date | Filing Date |
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PCT/CA2004/001567 WO2005024289A1 (en) | 2003-09-04 | 2004-08-27 | Positive pressure gas jacket for a natural gas pipeline |
Country Status (7)
Country | Link |
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US (1) | US7275599B2 (en) |
EP (1) | EP1668287B1 (en) |
AT (1) | ATE557234T1 (en) |
AU (1) | AU2004270771B2 (en) |
CA (1) | CA2536496C (en) |
MX (1) | MXPA06002547A (en) |
WO (1) | WO2005024289A1 (en) |
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AU2010220792B2 (en) * | 2009-03-04 | 2014-10-09 | Optimum Production Technologies Inc. | Control valve assembly |
US20110186305A1 (en) | 2010-01-29 | 2011-08-04 | Optimum Production Technologies Inc. | Gas-blanketed piping connections |
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US9359876B2 (en) | 2010-08-27 | 2016-06-07 | Well Control Technologies, Inc. | Methods and apparatus for removing liquid from a gas producing well |
US20120067569A1 (en) * | 2010-09-22 | 2012-03-22 | Alan Keith Brown | Well De-Liquefying System and Method |
WO2014113545A1 (en) * | 2013-01-16 | 2014-07-24 | Cnx Gas Company Llc | Methods and apparatus for removing liquid from a gas producing well |
US9181786B1 (en) * | 2014-09-19 | 2015-11-10 | Baker Hughes Incorporated | Sea floor boost pump and gas lift system and method for producing a subsea well |
US10036406B1 (en) | 2014-10-29 | 2018-07-31 | Jeremie Thornburg | Aligned-outlet and distal-flushable blow case |
US10921829B1 (en) | 2014-10-29 | 2021-02-16 | Jeremie Thornburg | Aligned-outlet and distal-flushable blow case |
CA3039771C (en) * | 2016-10-11 | 2021-03-23 | Baker Hughes, A Ge Company, Llc | Chemical injection with subsea production flow boost pump |
CA3075655A1 (en) * | 2017-09-15 | 2019-03-21 | IntelliGas CSM Services Limited | System and method for low pressure gas lift artificial lift |
CN113496076B (en) * | 2020-04-03 | 2022-08-19 | 中国石油化工股份有限公司 | Gas well productivity evaluation method for eliminating influence of accumulated liquid |
RU2748792C1 (en) * | 2020-09-07 | 2021-05-31 | Владимир Александрович Чигряй | Method for production of low-pressure gas |
CN117298799B (en) * | 2023-11-20 | 2024-03-29 | 武汉齐达康能源装备有限公司 | Well head gas integrated treatment equipment with large water content and use method thereof |
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-
2004
- 2004-08-27 US US10/568,588 patent/US7275599B2/en not_active Expired - Fee Related
- 2004-08-27 AT AT04761731T patent/ATE557234T1/en active
- 2004-08-27 WO PCT/CA2004/001567 patent/WO2005024289A1/en active Application Filing
- 2004-08-27 EP EP04761731A patent/EP1668287B1/en not_active Not-in-force
- 2004-08-27 MX MXPA06002547A patent/MXPA06002547A/en active IP Right Grant
- 2004-08-27 AU AU2004270771A patent/AU2004270771B2/en not_active Ceased
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Patent Citations (5)
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US5890549A (en) | 1996-12-23 | 1999-04-06 | Sprehe; Paul Robert | Well drilling system with closed circulation of gas drilling fluid and fire suppression apparatus |
CA2242745A1 (en) | 1998-08-13 | 2000-02-13 | William Rieben | One step gold pan |
US6293341B1 (en) | 1998-09-21 | 2001-09-25 | Elf Exploration Production | Method of controlling a hydrocarbons production well activated by injection of gas |
CA2350453A1 (en) | 2000-07-18 | 2002-01-18 | Alvin C. Liknes | Method and apparatus for removing water from well-bore of gas wells to permit efficient production of gas |
US6672392B2 (en) | 2002-03-12 | 2004-01-06 | Donald D. Reitz | Gas recovery apparatus, method and cycle having a three chamber evacuation phase for improved natural gas production and down-hole liquid management |
Also Published As
Publication number | Publication date |
---|---|
US7275599B2 (en) | 2007-10-02 |
EP1668287B1 (en) | 2012-05-09 |
MXPA06002547A (en) | 2006-08-31 |
CA2536496C (en) | 2008-07-15 |
AU2004270771B2 (en) | 2010-07-08 |
AU2004270771A1 (en) | 2005-03-17 |
ATE557234T1 (en) | 2012-05-15 |
CA2536496A1 (en) | 2005-03-17 |
EP1668287A1 (en) | 2006-06-14 |
US20060237195A1 (en) | 2006-10-26 |
EP1668287A4 (en) | 2011-03-30 |
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