CA2073415A1 - Oil well production system - Google Patents
Oil well production systemInfo
- Publication number
- CA2073415A1 CA2073415A1 CA002073415A CA2073415A CA2073415A1 CA 2073415 A1 CA2073415 A1 CA 2073415A1 CA 002073415 A CA002073415 A CA 002073415A CA 2073415 A CA2073415 A CA 2073415A CA 2073415 A1 CA2073415 A1 CA 2073415A1
- Authority
- CA
- Canada
- Prior art keywords
- gas
- production
- tubing string
- mandrel
- gas lift
- Prior art date
- Legal status (The legal status is an assumption and is not a legal conclusion. Google has not performed a legal analysis and makes no representation as to the accuracy of the status listed.)
- Abandoned
Links
- 238000004519 manufacturing process Methods 0.000 title claims abstract description 130
- 239000003129 oil well Substances 0.000 title description 2
- XLYOFNOQVPJJNP-UHFFFAOYSA-N water Substances O XLYOFNOQVPJJNP-UHFFFAOYSA-N 0.000 claims description 33
- 238000000034 method Methods 0.000 claims description 19
- 230000015572 biosynthetic process Effects 0.000 claims description 9
- 238000002347 injection Methods 0.000 claims description 7
- 239000007924 injection Substances 0.000 claims description 7
- 230000006835 compression Effects 0.000 claims description 6
- 238000007906 compression Methods 0.000 claims description 6
- 238000004891 communication Methods 0.000 claims description 4
- 229930195733 hydrocarbon Natural products 0.000 claims description 4
- 150000002430 hydrocarbons Chemical class 0.000 claims description 4
- 238000000926 separation method Methods 0.000 claims description 4
- 239000004215 Carbon black (E152) Substances 0.000 claims description 3
- 238000010438 heat treatment Methods 0.000 claims description 3
- 230000000903 blocking effect Effects 0.000 claims 1
- 230000002708 enhancing effect Effects 0.000 claims 1
- 239000012530 fluid Substances 0.000 abstract description 11
- 239000007788 liquid Substances 0.000 description 3
- 239000000956 alloy Substances 0.000 description 2
- 229910045601 alloy Inorganic materials 0.000 description 2
- 230000000694 effects Effects 0.000 description 2
- 241000191291 Abies alba Species 0.000 description 1
- 229910000831 Steel Inorganic materials 0.000 description 1
- 230000002411 adverse Effects 0.000 description 1
- 229940094070 ambien Drugs 0.000 description 1
- 238000010276 construction Methods 0.000 description 1
- 239000000356 contaminant Substances 0.000 description 1
- 238000005260 corrosion Methods 0.000 description 1
- 230000007797 corrosion Effects 0.000 description 1
- 230000008878 coupling Effects 0.000 description 1
- 238000010168 coupling process Methods 0.000 description 1
- 238000005859 coupling reaction Methods 0.000 description 1
- 230000001419 dependent effect Effects 0.000 description 1
- 230000008030 elimination Effects 0.000 description 1
- 238000003379 elimination reaction Methods 0.000 description 1
- 230000008014 freezing Effects 0.000 description 1
- 238000007710 freezing Methods 0.000 description 1
- 238000009434 installation Methods 0.000 description 1
- 238000009413 insulation Methods 0.000 description 1
- 230000001105 regulatory effect Effects 0.000 description 1
- 230000000630 rising effect Effects 0.000 description 1
- 239000010959 steel Substances 0.000 description 1
- ZAFYATHCZYHLPB-UHFFFAOYSA-N zolpidem Chemical compound N1=C2C=CC(C)=CN2C(CC(=O)N(C)C)=C1C1=CC=C(C)C=C1 ZAFYATHCZYHLPB-UHFFFAOYSA-N 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
- E21B36/00—Heating, cooling or insulating arrangements for boreholes or wells, e.g. for use in permafrost zones
- E21B36/003—Insulating arrangements
-
- 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
- E21B43/40—Separation associated with re-injection of separated materials
-
- 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
- E21B23/00—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells
- E21B23/03—Apparatus for displacing, setting, locking, releasing or removing tools, packers or the like in boreholes or wells for setting the tools into, or removing the tools from, laterally offset landing nipples or pockets
-
- 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
- E21B43/121—Lifting well fluids
- E21B43/122—Gas lift
Landscapes
- Life Sciences & Earth Sciences (AREA)
- Engineering & Computer Science (AREA)
- Geology (AREA)
- Mining & Mineral Resources (AREA)
- Physics & Mathematics (AREA)
- Environmental & Geological Engineering (AREA)
- Fluid Mechanics (AREA)
- General Life Sciences & Earth Sciences (AREA)
- Geochemistry & Mineralogy (AREA)
- Earth Drilling (AREA)
Abstract
ICR 8289 & 90/004 Abstract Of The Disclosure A production system for a subsea well includes a concentric gas lift string and a production tubing string both located within a production riser. Lift gas injected down the annulus between the production tubing string and gas tubing string is injected into the production tubing string below the mud line and thus provides gas lift assistance to the produced fluid stream. Thus increased produced fluid flow is provided while simultaneously insulating the produced fluid from the surrounding ocean thus maintaining the temperature of the produced fluid which aids separator efficiencies once the produced fluid reaches a surface platform associated therewith. The use of the concentric gas tubing string avoids pressurizing of the production riser. A gas lift mandrel and associated apparatus are provided at the subsurface tubing hanger to permit gas to be selectively directed down to a lower gas lift valve located deeper within the well.
Description
3 ~ ~ ~
PATENT
ICR 8289 & 90/004 OIL WELL PRODUCTION_SYSTEM
Backqrou~Of The Invention 1. Field of The Invention The present invention relates generally to the production of oil from wells drilled utilizing subsea well-head equipment, and more particularly, but not by way oflimitation, to production from wells which utili e gas lift assistance to aid in the production of the oil.
PATENT
ICR 8289 & 90/004 OIL WELL PRODUCTION_SYSTEM
Backqrou~Of The Invention 1. Field of The Invention The present invention relates generally to the production of oil from wells drilled utilizing subsea well-head equipment, and more particularly, but not by way oflimitation, to production from wells which utili e gas lift assistance to aid in the production of the oil.
2. Description Of The Prior Art A typical production system for a well drilled utilizing subsea wellhead equipment includes a production riser extending upward from the ocean floor to a surface platform. A production tubing string is contained within the production riser and carries a production stream from the well up to the surface platform. An annulus between the production riser and the production tubing is typically filled with liquid. The production stream typically leaves the subsea wellhead at the ocean floor at an elevated temperature. As the fluid flows upward through the production tubing and production riser, a substantial amount of heat is lost to the surrounding body of water which may be at near freezing temperatures. Thus, the production stream will reach the production platform at a temperature much less than the temperature it had when it left the subsea wellhead. The reduced temperature of the production stream when it reaches the surface platform can adversely affect the performance of the platform's separation system thus requiring~substantially more separation treatment to meet acceptable oil quality standards.
The prior art also includes production systems ~ o r~ 3 4 providing for injection of gas into the production stream to aid in lif~ng th~ ~rodu~ n ~r~am ~o ~h~ ~ur~a~. Thi~
technique is generally referred to as a ga~ lift system.
Conventional ~as lift systsms on offshore w~lls have a productlon tubing string located w~thin a production riser.
The gas for the gas lift system flows downward through the annulus between the production tubing string and the production riser to one or more gas lift valves which inject it into the rising production stream. An example of such an lo of~shore gas lift system is shown in U. S. Patent No.
4,125,162 to Groves, Sr., et al. A disadvantage of a system like that of Groves, Sr., et al., is that it results in a pressurized production riser.
Summary Of The Invention The present invention provides an offshore oil production system for a well extending ~rom the ocean ~loor downward into the earth and intersecting a subterranean hydrocarbon producing formation. The well is defined by a well casing set in place within the earth.
A production platform is located at the surface of the body of water above the well, and a production riser extends from the well at the ocean floor up through the body of water to the production platform.
The well includes a subsea wellhead which has a subsurface tubing hanger located near the mud line or floor of the body of water. A lower production tubing string is hung from the subsurface tubing hanger and extends downward to the producing formation. An upper production tubing string extends upward from the subsea wellhead through the production riser to the production platform.
A gas tubing string is concentrically disposed about the upper production tubing string and is located within the production riser.
A gas lift mandrel is mounted above the subsurface -- ~ ~3 r~ 3 4 ~ ~
tubing hanger and col~nunicates the upper and lower production tubing strings. The gas lift mandrel has its upper end connected to a lower end of the gas tubing string.
A gas lift valve is disposed in ~he gas lift mandrel for injecting gas from the gas tubing string into the production tubing string.
The gas lift mandrel preferably has a seal boxe defined therein for sealingly receiving the lower end of the upper production tubing strin~. The gas lift mandrel also has a gas passage means defined therein for communicating the annulus batween the upper production tubing string and the gas lift tubing with the gas lift valve.
The gas lift mandrel further preferably includes a bypass port by means of which the gas passage can be communicated with a lower annulus between the lower production tubing string and the well casing below the subsurface tubing hanger so that lift gas can be provided to a second gas lift valve located deeper within the well.
Numerous objects, features and advantages of the present invention will be readily apparent to tho~e ~kill~d in the art upon a reading of the following disclosure when taken in conjunction with th~ accompanying drawings.
Brief Description O~ The Drawin~s FIGS. lA-lB comprise a schematic, elevation, sectioned view of the production ~ystem of the present invention and an associated tension leg platform anchored in place over a subsea well.
FIG~ 2 is a view similar to FIG. 1 of an alternative embodiment of the invention constructed to only inject lift gas at the first gas lift valve adjacent the ocean floor.
FIG. 3 is a schematic, elevation, sectioned view of the gas lift mandrel used in the system of FIG. lA.
-- 2 ~rl3~1~
Detailed Description Of The Pre~erred Embodiments Referring now to the drawings, and particularly to FIGS. lA-lB, an offshore oil production system is shown and generally designated by the numeral lO. The system 10 includes a well 12 extending from a floor 14 of a body of water 16 downward into the earth 18 and intersecting a subterranean hydrocarbon producing for~tion 20. The w~ll 12 is defined by a casing 22 set in place within the earth by conventional cemanting techniquec.
The production system 10 further includes a production platform 24 which in the illustrated embodiment is a tension leg platform 24 located at the surface 26 of the body of water 16 and anchored in place over the well 12 by a plurality of tension legs 28 which function in a well known manner.
A production riser 30, which may be an extension of the well casing 22, extends from the well 12 at the ocean floor 14 up through the body of water 16 to the production platform 24.
A subsurface tubing hanger 32 is located in the well 12 very near an elevation to the subsea floor 14. The tubing hanger 32 is associated ~ith a conventional subsea wellhead (not shown) located adjacent floor 14. A lower production tubing string 34 is suspended from the subsurface tubing hanger 32 in a well known manner and extends downward therefrom to the producing formation 20.
A gas lift mandrel 36 is mounted above the subsurface tubing hanger 32. An upper production tubing string 38 extends up from the gas lift mandrel 36 through the production riser 30 to the production platform 24. The gas lift mandrel 36 communicates the upper and lower production tubing strings 38 and 34.
A gas tubing string 40 is concentrically disposed about the upper production tubing string 38 and is located within the production riser 30. A gas annulus 42 is defined : ~ 2~73'~ ~
between the upper production tubing string 38 and the gas tubing string 40.
The details of construction of the gas lift mandrel 36 and associated connections at its upper and lower end~ are best seen in the enlarged view of FIG. 3. A lower end 44 of gas tubing string 40 is connected to a threaded upper end 46 of gas ll~t mandrel 36 by threaded coupling 48.
The mandrel 36 has a seal bore 50, which may also be generally described as a receiving means 50, defined therein for seallngly receiving the lower end of the upper production tubing string 38. The upper production tubing string 38 carries one or more seals 52 which sealingly engage the seal bore 50.
A production flow passage 54 is defined within the mandrel 36 extending from a lower end 56 of mandrel 36 up to the seal bore 50 where production flow passage 54 communicates with an interior 58 of upper production tubing string 38 so that produced fluids from the subterranean formation 20 can flow upward through the lower production tubing string 34, then through production flow passage 54 and then up through the upper production tubing string 38.
Mandrel 36 includes a valve pocket means 60 defined therein and having a cylindrical bore 61 for receiving a gas lift valve schematically indicated at 62 in FIG. lA. The valve pocket means 60 i8 communicated with the production flow passage 54 by a pocket opening or valve entrance 63.
This permits the gas lift valve 62 to be run into the gas lift pocket 60 through the upper production tubing string 38 in a conventional manner. The valve pocket means 60 is of the type commonly referred to as a side pocket, and may have various indexing structures associated therewith to aid in installation and removal of valve 62.
The mandrèl 36 has a gas passage means 64 defined therein for communicating the annulus 42 between the upper production tubing string 38 and gas tubing string 40 with ~ ~ 7 3 ~
the valve pocket means 60 to supply gas to the gas lift valve 62. The gas passage means 64 includes a port 66 communicating with the annulus 42 above the seals 52. Gas passage means 64 further includes a longitudinal passage portion 68 extending downward from port 66. ~as passage means 64 further includes one or more supply ports 70 which supply the gas directly to the gas lift valve 62 in the valve pocket means 60~
One or more injection ports 72 communicate with the production flow passage, so that the gas lift valve 62 can selectively direct injection gas from gas passage means 64 through the i~jection port 72 into the produation flow passage 54.
The lower end 56 of mandrel 36 has an external thread 1 r~ 74, ~ b~t ~a~n .In ~a. lA, thc lowor ~n~ 56 o~ m~n~rel ~6 is connected to a tubing retrievable sur~ace controlled subsurface safety valve 74 which blocks the production tubing string 38,34 adjacent the subsurface tubing hanger 32. A control line 76 extends from the sur~ace down to safety valve 74 to control the same.
The safety valve 74 is connected to a mounting adapter 78 which has an enlarged diameter upper portion 80 and a smaller diameter lower portion 82.
The threaded connector 74 at the lower end 56 of mandrel 36 can generally be described as a lower connection means 74 for connecting the mandrel 36 to the lower production tubing string 34 via the other associated apparatus such as safety valve 74 and adapter 78 located therebetween.
The subsurface tubing hanger 32 has a seal bore member 84 connected to the upper end thereof. The enlarged diameter upper portion 80 of mounting adapter 78 is sealingly received within seal bore member 78.
The subsurface tubing hanger 32 has a surface controlled annulus safety valve 86 associated therewith and ~73~
connec~ed thereto. The annulus sa~ety valve 86 i8 schematically illustrated in FIG. lA, and has the smaller diameter lower portion 82 of mounting adapter 78 sealingly received therein. A control line 104 extends ~rom the surface down to annulus safety valve 86.
The gas lift mandrel 36 has a bypass port 88 defin~d therein ~or allowing gas to flow from the gas passage means 64 into a lower annulus 90 between the lower production tubing string 34 and the well casing 22.
A length of tubing 92 is connected to port 88 by tubing connector 94 at its upper end. The lower end of tubing 92 is connected to a lower gas port 96 in mounting adapter 78 which provides communication via annulus safety valve port 98 of annulus safety valve 86 to the lower annulus 90.
Thus, when the annulus safety valve 86 is in an open position as illustrated in FIG. lA with the annulus safety port 98 open, and a dummy valve in place of valve 62, the gas flowing downward through gas annulus 42 and gas passage means 64 can flow down through tubing 92, lower gas port 96, and through annulus safety valve port 98, then down through lower annulus 90 to a lower gas lift valve means 100 schematically illustrated in FIG. lB as being located in a lower gas li~t mandrel 102. The gas will be injected into the lower pxoduction tubing string 34 at the elevation of lower valve 100 to assist in lifting the produced fluids up through the lower production tubing string 34.
The bypass port 88 can generally bs described as a bypass port means 88 defined in mandrel 36 for communicating the gas annulus 42 with the lower gas lift valve lOo located below mandrel 36.
one adv~nt~ge o~ th~ ~ystom 10 1~ that lt permlts th~
use of corrosion resistant alloy production tubing, which is desirable in many wells where the produced oil stream contains contaminants which would corrode conventional steel tubing. The system 10 allows the use o~ tubinq which is ~` 2 ~ r~ 3 ~ ~ ~
r~adily avallabl~ ln ~u~h alloy a~mpo~itivn~, - The lower portions of production system lo seen in FIG.
ls ln~lud~ ~ conv~ntlonul productlon packer 106 located above producing ~ormation 20. An anchor as~embly 108 is associated therewith. ~ ported tail pipe assembly 110 is located below production packer 106.
A gravel pack packer 112 is set within the casing 22 below ported tail pipe assembly 110. A gravel pack extension 114 with sliding sleeve valve is as~oclat~d lo therewith. A section of blank pipe 116 is located below the gravel pack extension 114. A main gravel pack screen 118 is located below blank pipe 116. An O-ring seal sub 120 is connected below main gravel pack screen 118. A lower telltale screen 122 and a sump packer 124 complete the system.
A plurality of perforations such as 126 extend through the well casing 22 into the producing formation 20 to communicate the producing formation 20 through the main gravel pack screen 118 with the lower production tubing string 34 located thereabove, so that produced fluids such as hydrocarbons and some water produced from the formation 20 flow through the perforations 126, then in through the main gravel pack screen 118 up through the various structures associated therewith and then up through the lower production tubing string 34, then subsequently up through the upper production tubing string 38 to the platform 24.
At the platform 24, a lower surface tubing hanger ~28 suspends the gas tubing string 40 withln the riser 30 and provides a seal therebetween. An upper surface tubing hanger 130 similarly suspends the upper production tubing string 38 withln the gas tubing string ~0 and provides a seal therebetween. Tubing hangers 128 and 130 are associated with a conventional surface wellhead and Christmas tree arrangement (not shown).
~ ~ 7 ~
The control line 76 and 104 extend downward through the lower surface tubing hanger 128 in a known manner. An additional communication line 132 is provided and i~
connected to permanently installed downhole pressure and temperature gauges (not shown) which are located at an appropriate position within the well 12.
Located on the platform 24 is a separator system 134 which is schematically illustrated. A produced ~luid ~tre~m 136 from upper production tubing string 38 is directed to 1(1 th~ 3p~r~tor EJyntom 13~1 which gono~lly aclrvau to u~p~r~to the production fluid stream 136 into an oil stream 138 and a gas stream 140. Additionally, there may be a reject water stream 142.
The gas stream 140 is generally taken through a plurality of compressors which comprise a gas compression train 144 and then it is cooled in a gas cooler 146 before being directed to a gas sales line 148.
In one preferred embodiment of the invention, the gas for gas lift injection is taken off the gas compression train 144 prior to the gas entering the gas cooler 146 as indicated by gas takeoff line 150 which is connected to a main gas supply connection 152 which communicates with the gas annulus 42. Gas supply is regulated to the gas annulus 42 by a pilot valve 151.
Sum~ary_Q~ Operation The methods of producing oil from the well 12 utilizing the ~ystem 10 can generally be described as follows.
One of the primary purposes of the system 10 is to minimize heat loss from the produced oil stream flowing upward through production tubing string 38 and through the body of water 16 which will typically be much colder than the produced oil stream. This can bs accomplished with the system lO by insulating the upwardly flowing produced oil stream by means o~ the downwardly flowing annular gas stream .,."., ~ .
j 2~r~
contained in gas annulus 42 which surrounds the upper production tubing string 38.
Thus, the method includes a step of flowing the produced oil stream up through the upper production tubing string 38 and thus up through the body of water 16 from the well 12 to the platform 24.
The method includes the step of simultaneously flowing an annular gas stream surrounding the produced oil stream down through the gas annulus 42 and thus down through the body of water 16.
The method further includes the step of insulating the upwardly flowing produced oil stream from the body of water 16 with the downwardly flowing annular gas stream. This reduces heat loss from the produced oil stream as it flows upwardly through the body of water 16, as compared to those prior art systems which merely have a production tubing string extending through a production riser with the annulus therebetween filled with a liquid which very readily conducts heat away from the oil stream to the surroundin~
body of water 16.
Thus the method of producing oil with the system 10 can be described as including a step of avoiding pr~ssurizing the production riser 30 with the gas stream by containing the gas stream in the gas tubing strlng 40.
There are also significant advantages as compared to those prior art systems like that of U. S. Patent No.
4,125,162 to Grove, Sr., et al., wherein gas lift gas is conveyed downwardly through an annulus between the production tubing string and the gas riser, because in the Grove, Sr., et al. type of system, the production riser itself is pressurized which has disadvantages.
It will be appreciated that in its broadest aspects, the present invention need not include the injection of the gas into the produced oil stream in sufficient ~uantities to provide gas lift assistance to the produced oil stream.
2~7 3~ 1là
However in a preferred embodiment, the gas lift mandrel 36 and associated gas li~t valve 62 are provided ~o that the method can include a step of injecting at least a portion of the gas from the annular gas stream into the upwardly flowing produced oil stream and thereby providing gas lift assistance to the produced oil stream.
The gas is preferably injected into the upwardly flowing produced oil stream at a location below the mud line 14 of the body of water 16, as indicated in FIG. lA by the location of gas lift valve 62 below the mud line 14.
Thus, the annular gas stream in gas annulus 42 can be described as surrounding and insulating the produced oil stream across the entire depth of the body of water 16 from the mud line 14 up to the surface 26.
Further, the method of utilizing the ~ystem lo can include a step of selectively bypassing at least a portion of the gas stream past the first gas lift valve 62 down into the well 12 through the lower annulus 90 to a second gas lift valve 100 located substantially deeper within the well.
Gas is again injected into the upwardly flowing produced oil ~tre~m ~t the ~econd ga~ lirt valve 110 thereby agaln providing gas lift assistance to the produced oil straam.
The flow of gas down to this second gas lift valve 100 is permitted by opening the annulus sa~ety valve 86. It is noted that the upper gas lift valve 62 may if desired be replaced with a dummy valve to prevent any gas injection at the upper location. Also, the upper and lower gas lift valves 62 and 100 may be constructed to operate at differing gas supply pressures so that the lower gas lift valve 100 can operate without operating the upper gas li~t valve 62 i~
desired.
The gas provided to main gas supply connection 152 may be at ambient temperature if the insulation effect provided thereby is sufficient to maintain the temperature of the produced oil stream at the desired level when it reaches 2 or~3 platform 24. If ~urther heating o~ the produced oil stream is required, the lift gas can be taken off the gas compression train 1~4 as previously described. That gas from the gas compression train 144 may for example be at temperatures as high as 300O F., and thu~ can be de~cribed ao b~lng ho~ted to sub~tantially abova ambien~ atmospherl~
temperature.
The efficiency of the separator ~ystem 134 is significantly dependent upon the temperature of the produced lo oil stream which is provided thereto, since the heat enhances the separation process. I~ it were not for the insulating, and in some cases further heating, effect of the gas flowing downward through gas annulus 42, the temperature of the produced oil strQam would be signi~i~antly lower than it is with the use of tho sy6tQm 10, and thus the separ~tor system 134 located on the platform 24 would be required to be substantially larger than it needs to be with this system 10 of the present invention.
The space and weight capacity on an offshore platform, and particularly on a tension leg platform are at a premium and have a high cost associated therewith. Thus, the reduction in size of the necessary separator system 134 and elimination of certain ancillary equipment, i.e., aoala~c~r~ , h~at~r~ , ~'cc ., by m~n~ Or malnt~lning ~nd/sr increasing the heat of the produced oil stream provided th~r~to provlde~ slgn1~icant aconomlc advantage~.
It may, for example, be desired to maintain the temperature of the produced oil strsam at greater than or equal to 140 F. in order to achieve desired efficiencies (e.g., 0.5 Vol. % BS&W) in the separator system 134. The produced oil stream may enter the upper production tubing string 38 adjacent mud line 14 at a temperature of 165 F.
and in North Sea conditions having a water temperature of approximately 39 F. and a depth of approximately 1150 ft.
at a flow rate of approximately 15,000 BPD, a temperature of 2 ~ 7 3 ~
the produced fluid stream at the platform 12 of approximately 104 F. could be expected in the absence of the insulating gas annulus 42, with a system wherein the annulus between production string 38 and production riser 30 were filled with a conventional liquid. The presence of the insulating gas in gas annulus 42 ca~ reduce heat losses such that the produced oil stream has a temperature of no less than the required 140 F. necessary for efficient operation of separator system 134.
The Alternative Embodiment Of FIG. 2 In FIG. 2 a slightly modified system 10~ is illustrated in a manner similar to FIG. lA, except that surrounding structures such as the platform 24 have been eliminated for ease of illustration. The system lOA is similar to the system 10, except that the gas lift mandrel has been modified and i5 now indicated by the numeral 36A. The gas lift mandrel 36A has the port 88 closed by a plug. The tubing 92 has been eliminated and no communication is provided between gas passage means 64 and the lower annulus 90. The adapter 78A has also been modified to eliminate or plug the lower gas port 96.
Thus with the system lOA, gas is injected only at the location of upper gas lift valve 62. The lower components of system lOA will be substantially as shown in FIG. lB for the system 10. Similarly, the upper portion of the system lOA including separator system 134, etc., will be similar to that shown ln FIG. lA, but tho~ structure~ asso~iated wlth separator system 134 are not shown, again for ease of illustration.
Thus it is seen that the apparatus and methods of the present invention readily achieve the ends and advantages mentioned as well as those inherent therein. While certain preferred embodiments of the invention have been illustrated for purposes of the present disclosure, numerous changes may ~ 7 3 ~
be made by those skilled in the art which changes are encornpassed within the scope and spirit of the present invention as de~ined by the appended claims.
The prior art also includes production systems ~ o r~ 3 4 providing for injection of gas into the production stream to aid in lif~ng th~ ~rodu~ n ~r~am ~o ~h~ ~ur~a~. Thi~
technique is generally referred to as a ga~ lift system.
Conventional ~as lift systsms on offshore w~lls have a productlon tubing string located w~thin a production riser.
The gas for the gas lift system flows downward through the annulus between the production tubing string and the production riser to one or more gas lift valves which inject it into the rising production stream. An example of such an lo of~shore gas lift system is shown in U. S. Patent No.
4,125,162 to Groves, Sr., et al. A disadvantage of a system like that of Groves, Sr., et al., is that it results in a pressurized production riser.
Summary Of The Invention The present invention provides an offshore oil production system for a well extending ~rom the ocean ~loor downward into the earth and intersecting a subterranean hydrocarbon producing formation. The well is defined by a well casing set in place within the earth.
A production platform is located at the surface of the body of water above the well, and a production riser extends from the well at the ocean floor up through the body of water to the production platform.
The well includes a subsea wellhead which has a subsurface tubing hanger located near the mud line or floor of the body of water. A lower production tubing string is hung from the subsurface tubing hanger and extends downward to the producing formation. An upper production tubing string extends upward from the subsea wellhead through the production riser to the production platform.
A gas tubing string is concentrically disposed about the upper production tubing string and is located within the production riser.
A gas lift mandrel is mounted above the subsurface -- ~ ~3 r~ 3 4 ~ ~
tubing hanger and col~nunicates the upper and lower production tubing strings. The gas lift mandrel has its upper end connected to a lower end of the gas tubing string.
A gas lift valve is disposed in ~he gas lift mandrel for injecting gas from the gas tubing string into the production tubing string.
The gas lift mandrel preferably has a seal boxe defined therein for sealingly receiving the lower end of the upper production tubing strin~. The gas lift mandrel also has a gas passage means defined therein for communicating the annulus batween the upper production tubing string and the gas lift tubing with the gas lift valve.
The gas lift mandrel further preferably includes a bypass port by means of which the gas passage can be communicated with a lower annulus between the lower production tubing string and the well casing below the subsurface tubing hanger so that lift gas can be provided to a second gas lift valve located deeper within the well.
Numerous objects, features and advantages of the present invention will be readily apparent to tho~e ~kill~d in the art upon a reading of the following disclosure when taken in conjunction with th~ accompanying drawings.
Brief Description O~ The Drawin~s FIGS. lA-lB comprise a schematic, elevation, sectioned view of the production ~ystem of the present invention and an associated tension leg platform anchored in place over a subsea well.
FIG~ 2 is a view similar to FIG. 1 of an alternative embodiment of the invention constructed to only inject lift gas at the first gas lift valve adjacent the ocean floor.
FIG. 3 is a schematic, elevation, sectioned view of the gas lift mandrel used in the system of FIG. lA.
-- 2 ~rl3~1~
Detailed Description Of The Pre~erred Embodiments Referring now to the drawings, and particularly to FIGS. lA-lB, an offshore oil production system is shown and generally designated by the numeral lO. The system 10 includes a well 12 extending from a floor 14 of a body of water 16 downward into the earth 18 and intersecting a subterranean hydrocarbon producing for~tion 20. The w~ll 12 is defined by a casing 22 set in place within the earth by conventional cemanting techniquec.
The production system 10 further includes a production platform 24 which in the illustrated embodiment is a tension leg platform 24 located at the surface 26 of the body of water 16 and anchored in place over the well 12 by a plurality of tension legs 28 which function in a well known manner.
A production riser 30, which may be an extension of the well casing 22, extends from the well 12 at the ocean floor 14 up through the body of water 16 to the production platform 24.
A subsurface tubing hanger 32 is located in the well 12 very near an elevation to the subsea floor 14. The tubing hanger 32 is associated ~ith a conventional subsea wellhead (not shown) located adjacent floor 14. A lower production tubing string 34 is suspended from the subsurface tubing hanger 32 in a well known manner and extends downward therefrom to the producing formation 20.
A gas lift mandrel 36 is mounted above the subsurface tubing hanger 32. An upper production tubing string 38 extends up from the gas lift mandrel 36 through the production riser 30 to the production platform 24. The gas lift mandrel 36 communicates the upper and lower production tubing strings 38 and 34.
A gas tubing string 40 is concentrically disposed about the upper production tubing string 38 and is located within the production riser 30. A gas annulus 42 is defined : ~ 2~73'~ ~
between the upper production tubing string 38 and the gas tubing string 40.
The details of construction of the gas lift mandrel 36 and associated connections at its upper and lower end~ are best seen in the enlarged view of FIG. 3. A lower end 44 of gas tubing string 40 is connected to a threaded upper end 46 of gas ll~t mandrel 36 by threaded coupling 48.
The mandrel 36 has a seal bore 50, which may also be generally described as a receiving means 50, defined therein for seallngly receiving the lower end of the upper production tubing string 38. The upper production tubing string 38 carries one or more seals 52 which sealingly engage the seal bore 50.
A production flow passage 54 is defined within the mandrel 36 extending from a lower end 56 of mandrel 36 up to the seal bore 50 where production flow passage 54 communicates with an interior 58 of upper production tubing string 38 so that produced fluids from the subterranean formation 20 can flow upward through the lower production tubing string 34, then through production flow passage 54 and then up through the upper production tubing string 38.
Mandrel 36 includes a valve pocket means 60 defined therein and having a cylindrical bore 61 for receiving a gas lift valve schematically indicated at 62 in FIG. lA. The valve pocket means 60 i8 communicated with the production flow passage 54 by a pocket opening or valve entrance 63.
This permits the gas lift valve 62 to be run into the gas lift pocket 60 through the upper production tubing string 38 in a conventional manner. The valve pocket means 60 is of the type commonly referred to as a side pocket, and may have various indexing structures associated therewith to aid in installation and removal of valve 62.
The mandrèl 36 has a gas passage means 64 defined therein for communicating the annulus 42 between the upper production tubing string 38 and gas tubing string 40 with ~ ~ 7 3 ~
the valve pocket means 60 to supply gas to the gas lift valve 62. The gas passage means 64 includes a port 66 communicating with the annulus 42 above the seals 52. Gas passage means 64 further includes a longitudinal passage portion 68 extending downward from port 66. ~as passage means 64 further includes one or more supply ports 70 which supply the gas directly to the gas lift valve 62 in the valve pocket means 60~
One or more injection ports 72 communicate with the production flow passage, so that the gas lift valve 62 can selectively direct injection gas from gas passage means 64 through the i~jection port 72 into the produation flow passage 54.
The lower end 56 of mandrel 36 has an external thread 1 r~ 74, ~ b~t ~a~n .In ~a. lA, thc lowor ~n~ 56 o~ m~n~rel ~6 is connected to a tubing retrievable sur~ace controlled subsurface safety valve 74 which blocks the production tubing string 38,34 adjacent the subsurface tubing hanger 32. A control line 76 extends from the sur~ace down to safety valve 74 to control the same.
The safety valve 74 is connected to a mounting adapter 78 which has an enlarged diameter upper portion 80 and a smaller diameter lower portion 82.
The threaded connector 74 at the lower end 56 of mandrel 36 can generally be described as a lower connection means 74 for connecting the mandrel 36 to the lower production tubing string 34 via the other associated apparatus such as safety valve 74 and adapter 78 located therebetween.
The subsurface tubing hanger 32 has a seal bore member 84 connected to the upper end thereof. The enlarged diameter upper portion 80 of mounting adapter 78 is sealingly received within seal bore member 78.
The subsurface tubing hanger 32 has a surface controlled annulus safety valve 86 associated therewith and ~73~
connec~ed thereto. The annulus sa~ety valve 86 i8 schematically illustrated in FIG. lA, and has the smaller diameter lower portion 82 of mounting adapter 78 sealingly received therein. A control line 104 extends ~rom the surface down to annulus safety valve 86.
The gas lift mandrel 36 has a bypass port 88 defin~d therein ~or allowing gas to flow from the gas passage means 64 into a lower annulus 90 between the lower production tubing string 34 and the well casing 22.
A length of tubing 92 is connected to port 88 by tubing connector 94 at its upper end. The lower end of tubing 92 is connected to a lower gas port 96 in mounting adapter 78 which provides communication via annulus safety valve port 98 of annulus safety valve 86 to the lower annulus 90.
Thus, when the annulus safety valve 86 is in an open position as illustrated in FIG. lA with the annulus safety port 98 open, and a dummy valve in place of valve 62, the gas flowing downward through gas annulus 42 and gas passage means 64 can flow down through tubing 92, lower gas port 96, and through annulus safety valve port 98, then down through lower annulus 90 to a lower gas lift valve means 100 schematically illustrated in FIG. lB as being located in a lower gas li~t mandrel 102. The gas will be injected into the lower pxoduction tubing string 34 at the elevation of lower valve 100 to assist in lifting the produced fluids up through the lower production tubing string 34.
The bypass port 88 can generally bs described as a bypass port means 88 defined in mandrel 36 for communicating the gas annulus 42 with the lower gas lift valve lOo located below mandrel 36.
one adv~nt~ge o~ th~ ~ystom 10 1~ that lt permlts th~
use of corrosion resistant alloy production tubing, which is desirable in many wells where the produced oil stream contains contaminants which would corrode conventional steel tubing. The system 10 allows the use o~ tubinq which is ~` 2 ~ r~ 3 ~ ~ ~
r~adily avallabl~ ln ~u~h alloy a~mpo~itivn~, - The lower portions of production system lo seen in FIG.
ls ln~lud~ ~ conv~ntlonul productlon packer 106 located above producing ~ormation 20. An anchor as~embly 108 is associated therewith. ~ ported tail pipe assembly 110 is located below production packer 106.
A gravel pack packer 112 is set within the casing 22 below ported tail pipe assembly 110. A gravel pack extension 114 with sliding sleeve valve is as~oclat~d lo therewith. A section of blank pipe 116 is located below the gravel pack extension 114. A main gravel pack screen 118 is located below blank pipe 116. An O-ring seal sub 120 is connected below main gravel pack screen 118. A lower telltale screen 122 and a sump packer 124 complete the system.
A plurality of perforations such as 126 extend through the well casing 22 into the producing formation 20 to communicate the producing formation 20 through the main gravel pack screen 118 with the lower production tubing string 34 located thereabove, so that produced fluids such as hydrocarbons and some water produced from the formation 20 flow through the perforations 126, then in through the main gravel pack screen 118 up through the various structures associated therewith and then up through the lower production tubing string 34, then subsequently up through the upper production tubing string 38 to the platform 24.
At the platform 24, a lower surface tubing hanger ~28 suspends the gas tubing string 40 withln the riser 30 and provides a seal therebetween. An upper surface tubing hanger 130 similarly suspends the upper production tubing string 38 withln the gas tubing string ~0 and provides a seal therebetween. Tubing hangers 128 and 130 are associated with a conventional surface wellhead and Christmas tree arrangement (not shown).
~ ~ 7 ~
The control line 76 and 104 extend downward through the lower surface tubing hanger 128 in a known manner. An additional communication line 132 is provided and i~
connected to permanently installed downhole pressure and temperature gauges (not shown) which are located at an appropriate position within the well 12.
Located on the platform 24 is a separator system 134 which is schematically illustrated. A produced ~luid ~tre~m 136 from upper production tubing string 38 is directed to 1(1 th~ 3p~r~tor EJyntom 13~1 which gono~lly aclrvau to u~p~r~to the production fluid stream 136 into an oil stream 138 and a gas stream 140. Additionally, there may be a reject water stream 142.
The gas stream 140 is generally taken through a plurality of compressors which comprise a gas compression train 144 and then it is cooled in a gas cooler 146 before being directed to a gas sales line 148.
In one preferred embodiment of the invention, the gas for gas lift injection is taken off the gas compression train 144 prior to the gas entering the gas cooler 146 as indicated by gas takeoff line 150 which is connected to a main gas supply connection 152 which communicates with the gas annulus 42. Gas supply is regulated to the gas annulus 42 by a pilot valve 151.
Sum~ary_Q~ Operation The methods of producing oil from the well 12 utilizing the ~ystem 10 can generally be described as follows.
One of the primary purposes of the system 10 is to minimize heat loss from the produced oil stream flowing upward through production tubing string 38 and through the body of water 16 which will typically be much colder than the produced oil stream. This can bs accomplished with the system lO by insulating the upwardly flowing produced oil stream by means o~ the downwardly flowing annular gas stream .,."., ~ .
j 2~r~
contained in gas annulus 42 which surrounds the upper production tubing string 38.
Thus, the method includes a step of flowing the produced oil stream up through the upper production tubing string 38 and thus up through the body of water 16 from the well 12 to the platform 24.
The method includes the step of simultaneously flowing an annular gas stream surrounding the produced oil stream down through the gas annulus 42 and thus down through the body of water 16.
The method further includes the step of insulating the upwardly flowing produced oil stream from the body of water 16 with the downwardly flowing annular gas stream. This reduces heat loss from the produced oil stream as it flows upwardly through the body of water 16, as compared to those prior art systems which merely have a production tubing string extending through a production riser with the annulus therebetween filled with a liquid which very readily conducts heat away from the oil stream to the surroundin~
body of water 16.
Thus the method of producing oil with the system 10 can be described as including a step of avoiding pr~ssurizing the production riser 30 with the gas stream by containing the gas stream in the gas tubing strlng 40.
There are also significant advantages as compared to those prior art systems like that of U. S. Patent No.
4,125,162 to Grove, Sr., et al., wherein gas lift gas is conveyed downwardly through an annulus between the production tubing string and the gas riser, because in the Grove, Sr., et al. type of system, the production riser itself is pressurized which has disadvantages.
It will be appreciated that in its broadest aspects, the present invention need not include the injection of the gas into the produced oil stream in sufficient ~uantities to provide gas lift assistance to the produced oil stream.
2~7 3~ 1là
However in a preferred embodiment, the gas lift mandrel 36 and associated gas li~t valve 62 are provided ~o that the method can include a step of injecting at least a portion of the gas from the annular gas stream into the upwardly flowing produced oil stream and thereby providing gas lift assistance to the produced oil stream.
The gas is preferably injected into the upwardly flowing produced oil stream at a location below the mud line 14 of the body of water 16, as indicated in FIG. lA by the location of gas lift valve 62 below the mud line 14.
Thus, the annular gas stream in gas annulus 42 can be described as surrounding and insulating the produced oil stream across the entire depth of the body of water 16 from the mud line 14 up to the surface 26.
Further, the method of utilizing the ~ystem lo can include a step of selectively bypassing at least a portion of the gas stream past the first gas lift valve 62 down into the well 12 through the lower annulus 90 to a second gas lift valve 100 located substantially deeper within the well.
Gas is again injected into the upwardly flowing produced oil ~tre~m ~t the ~econd ga~ lirt valve 110 thereby agaln providing gas lift assistance to the produced oil straam.
The flow of gas down to this second gas lift valve 100 is permitted by opening the annulus sa~ety valve 86. It is noted that the upper gas lift valve 62 may if desired be replaced with a dummy valve to prevent any gas injection at the upper location. Also, the upper and lower gas lift valves 62 and 100 may be constructed to operate at differing gas supply pressures so that the lower gas lift valve 100 can operate without operating the upper gas li~t valve 62 i~
desired.
The gas provided to main gas supply connection 152 may be at ambient temperature if the insulation effect provided thereby is sufficient to maintain the temperature of the produced oil stream at the desired level when it reaches 2 or~3 platform 24. If ~urther heating o~ the produced oil stream is required, the lift gas can be taken off the gas compression train 1~4 as previously described. That gas from the gas compression train 144 may for example be at temperatures as high as 300O F., and thu~ can be de~cribed ao b~lng ho~ted to sub~tantially abova ambien~ atmospherl~
temperature.
The efficiency of the separator ~ystem 134 is significantly dependent upon the temperature of the produced lo oil stream which is provided thereto, since the heat enhances the separation process. I~ it were not for the insulating, and in some cases further heating, effect of the gas flowing downward through gas annulus 42, the temperature of the produced oil strQam would be signi~i~antly lower than it is with the use of tho sy6tQm 10, and thus the separ~tor system 134 located on the platform 24 would be required to be substantially larger than it needs to be with this system 10 of the present invention.
The space and weight capacity on an offshore platform, and particularly on a tension leg platform are at a premium and have a high cost associated therewith. Thus, the reduction in size of the necessary separator system 134 and elimination of certain ancillary equipment, i.e., aoala~c~r~ , h~at~r~ , ~'cc ., by m~n~ Or malnt~lning ~nd/sr increasing the heat of the produced oil stream provided th~r~to provlde~ slgn1~icant aconomlc advantage~.
It may, for example, be desired to maintain the temperature of the produced oil strsam at greater than or equal to 140 F. in order to achieve desired efficiencies (e.g., 0.5 Vol. % BS&W) in the separator system 134. The produced oil stream may enter the upper production tubing string 38 adjacent mud line 14 at a temperature of 165 F.
and in North Sea conditions having a water temperature of approximately 39 F. and a depth of approximately 1150 ft.
at a flow rate of approximately 15,000 BPD, a temperature of 2 ~ 7 3 ~
the produced fluid stream at the platform 12 of approximately 104 F. could be expected in the absence of the insulating gas annulus 42, with a system wherein the annulus between production string 38 and production riser 30 were filled with a conventional liquid. The presence of the insulating gas in gas annulus 42 ca~ reduce heat losses such that the produced oil stream has a temperature of no less than the required 140 F. necessary for efficient operation of separator system 134.
The Alternative Embodiment Of FIG. 2 In FIG. 2 a slightly modified system 10~ is illustrated in a manner similar to FIG. lA, except that surrounding structures such as the platform 24 have been eliminated for ease of illustration. The system lOA is similar to the system 10, except that the gas lift mandrel has been modified and i5 now indicated by the numeral 36A. The gas lift mandrel 36A has the port 88 closed by a plug. The tubing 92 has been eliminated and no communication is provided between gas passage means 64 and the lower annulus 90. The adapter 78A has also been modified to eliminate or plug the lower gas port 96.
Thus with the system lOA, gas is injected only at the location of upper gas lift valve 62. The lower components of system lOA will be substantially as shown in FIG. lB for the system 10. Similarly, the upper portion of the system lOA including separator system 134, etc., will be similar to that shown ln FIG. lA, but tho~ structure~ asso~iated wlth separator system 134 are not shown, again for ease of illustration.
Thus it is seen that the apparatus and methods of the present invention readily achieve the ends and advantages mentioned as well as those inherent therein. While certain preferred embodiments of the invention have been illustrated for purposes of the present disclosure, numerous changes may ~ 7 3 ~
be made by those skilled in the art which changes are encornpassed within the scope and spirit of the present invention as de~ined by the appended claims.
Claims (21)
1. A gas lift mandrel for use with a concentric tubing system having a gas lift tubing and an upper production tubing concentrically disposed in said gas lift tubing so that an annulus is defined therebetween, comprising:
an upper end with an upper connection means for connecting said mandrel to said gas lift tubing;
a lower end with a lower connection means for connecting said mandrel to a lower production tubing;
receiving means, defined within said mandrel, for sealingly receiving said upper production tubing;
a production flow passage, defined within said mandrel from said lower end of said mandrel to said receiving means;
a valve pocket means defined in said mandrel for receiving a gas lift valve therein, said valve pocket means being communicated with said production flow passage; and a gas passage means, defined within said mandrel, for communicating said annulus with said valve pocket means to supply gas to said gas lift valve.
an upper end with an upper connection means for connecting said mandrel to said gas lift tubing;
a lower end with a lower connection means for connecting said mandrel to a lower production tubing;
receiving means, defined within said mandrel, for sealingly receiving said upper production tubing;
a production flow passage, defined within said mandrel from said lower end of said mandrel to said receiving means;
a valve pocket means defined in said mandrel for receiving a gas lift valve therein, said valve pocket means being communicated with said production flow passage; and a gas passage means, defined within said mandrel, for communicating said annulus with said valve pocket means to supply gas to said gas lift valve.
2. The gas lift mandrel of claim 1, wherein:
said valve pocket means is a side pocket having a valve entrance communicated with said production flow passage.
said valve pocket means is a side pocket having a valve entrance communicated with said production flow passage.
3. The gas lift mandrel of claim 1, wherein:
said valve pocket means includes a cylindrical pocket bore for receiving said gas lift valve, a supply port communicating said pocket bore with said gas passage means, and an injection port communicating said pocket bore with said production flow passage.
said valve pocket means includes a cylindrical pocket bore for receiving said gas lift valve, a supply port communicating said pocket bore with said gas passage means, and an injection port communicating said pocket bore with said production flow passage.
4. The gas lift mandrel of claim 1, further comprising:
bypass port means, defined in said mandrel, for communicating said annulus with a lower gas lift valve located below said mandrel.
bypass port means, defined in said mandrel, for communicating said annulus with a lower gas lift valve located below said mandrel.
5. The gas lift mandrel of claim l, wherein:
said receiving means is a seal bore.
said receiving means is a seal bore.
6. A method of producing oil from a well located below a body of water up through a production riser extending from said well up through said body of water, comprising:
(a) flowing a produced oil stream up through said body of water, said produced oil stream flowing through a production tubing string extending from said well up through said production riser;
(b) flowing an annular gas stream surrounding said produced oil stream down through said body of water, said annular gas stream flowing through a gas tubing string located within said production riser, said gas tubing string having said production tubing string located therein; and (c) insulating said upwardly flowing produced oil stream from said body of water with said downwardly flowing annular gas stream, thereby reducing heat loss from said produced oil stream as it flows upwardly through said body of water.
(a) flowing a produced oil stream up through said body of water, said produced oil stream flowing through a production tubing string extending from said well up through said production riser;
(b) flowing an annular gas stream surrounding said produced oil stream down through said body of water, said annular gas stream flowing through a gas tubing string located within said production riser, said gas tubing string having said production tubing string located therein; and (c) insulating said upwardly flowing produced oil stream from said body of water with said downwardly flowing annular gas stream, thereby reducing heat loss from said produced oil stream as it flows upwardly through said body of water.
7. The method of claim 6, further comprising:
(d) injecting at least a portion of the gas from said gas stream into said upwardly flowing produced oil stream and thereby providing gas lift assistance to said produced oil stream; and (e) avoiding pressurizing said production riser with said gas stream by containing said gas stream in said gas tubing string.
(d) injecting at least a portion of the gas from said gas stream into said upwardly flowing produced oil stream and thereby providing gas lift assistance to said produced oil stream; and (e) avoiding pressurizing said production riser with said gas stream by containing said gas stream in said gas tubing string.
8. The method of claim 7, wherein:
said step (d) is further characterized as injecting said gas into said upwardly flowing produced oil stream at a location below a mud line of said body of water.
said step (d) is further characterized as injecting said gas into said upwardly flowing produced oil stream at a location below a mud line of said body of water.
9. The method of claim 7, wherein:
said step (d) is further characterized as injecting said gas into said produced oil stream at a first location adjacent a mud line of said body of water; and wherein said method further comprises steps of:
(f) selectively bypassing at least a portion of said gas stream past said first location down into said well to a second location substantially deeper than said first location; and (g) injecting gas into said upwardly flowing produced oil stream at said second location and thereby providing gas lift assistance to said produced oil stream.
said step (d) is further characterized as injecting said gas into said produced oil stream at a first location adjacent a mud line of said body of water; and wherein said method further comprises steps of:
(f) selectively bypassing at least a portion of said gas stream past said first location down into said well to a second location substantially deeper than said first location; and (g) injecting gas into said upwardly flowing produced oil stream at said second location and thereby providing gas lift assistance to said produced oil stream.
10. The method of claim 9, wherein:
said step (f) is further characterized as opening an annulus safety valve to let said gas stream pass downward between said production tubing string and a casing string of said well.
said step (f) is further characterized as opening an annulus safety valve to let said gas stream pass downward between said production tubing string and a casing string of said well.
11. The method of claim 6, wherein:
said steps (b) and (c) are further characterized in that said annular gas stream surrounds and insulates said produced oil stream across the entire depth of said body of water from a mud line of said body of water to the surface of said body of water.
said steps (b) and (c) are further characterized in that said annular gas stream surrounds and insulates said produced oil stream across the entire depth of said body of water from a mud line of said body of water to the surface of said body of water.
12. The method of claim 6, further comprising:
prior to step (b) heating said gas to substantially above ambient atmospheric temperature.
prior to step (b) heating said gas to substantially above ambient atmospheric temperature.
13. The method of claim 12, wherein:
said gas is taken off a gas compression train of a production platform prior to the gas entering a gas cooler of said gas compression train.
said gas is taken off a gas compression train of a production platform prior to the gas entering a gas cooler of said gas compression train.
14. The method of claim 6, wherein:
said step (a) is further characterized as flowing said produced oil stream up through said production tubing string to a tension leg platform floating on the surface of said body of water; and said steps (b) and (c) are further characterized as enhancing an efficiency of separation of said produced oil stream on said tension leg platform due to the increased temperature of said produced oil stream when it reaches said tension leg platform, thereby allowing separated oil quality standards to be met with a reduced amount of separator equipment located on said tension leg platform as compared to what would be required in the absence of said steps (b) and (c).
said step (a) is further characterized as flowing said produced oil stream up through said production tubing string to a tension leg platform floating on the surface of said body of water; and said steps (b) and (c) are further characterized as enhancing an efficiency of separation of said produced oil stream on said tension leg platform due to the increased temperature of said produced oil stream when it reaches said tension leg platform, thereby allowing separated oil quality standards to be met with a reduced amount of separator equipment located on said tension leg platform as compared to what would be required in the absence of said steps (b) and (c).
15. An offshore oil production system, comprising:
a well extending from a floor of a body of water downward into the earth and intersecting a subterranean hydrocarbon producing formation, said well being defined by a well casing set in place within the earth;
a production platform located at the surface of said body of water;
a production riser extending from said well at said floor up through said body of water to said production platform;
a subsurface tubing hanger located in said well;
a lower production tubing string extending downward from said subsurface tubing hanger to said producing formation;
an upper production tubing string extending upward through said production riser to said production platform;
and a gas tubing string concentrically disposed about said upper production tubing string and located within said production riser, said gas tubing being filled with gas.
a well extending from a floor of a body of water downward into the earth and intersecting a subterranean hydrocarbon producing formation, said well being defined by a well casing set in place within the earth;
a production platform located at the surface of said body of water;
a production riser extending from said well at said floor up through said body of water to said production platform;
a subsurface tubing hanger located in said well;
a lower production tubing string extending downward from said subsurface tubing hanger to said producing formation;
an upper production tubing string extending upward through said production riser to said production platform;
and a gas tubing string concentrically disposed about said upper production tubing string and located within said production riser, said gas tubing being filled with gas.
16. The system of claim 15, further comprising:
a gas lift mandrel connected to said subsurface tubing hanger and communicating said upper and lower production tubing strings, said gas lift mandrel being connected to a lower end of said gas tubing string; and a gas lift valve means disposed in said gas lift mandrel for injecting gas from said gas tubing string into said upper production tubing string.
a gas lift mandrel connected to said subsurface tubing hanger and communicating said upper and lower production tubing strings, said gas lift mandrel being connected to a lower end of said gas tubing string; and a gas lift valve means disposed in said gas lift mandrel for injecting gas from said gas tubing string into said upper production tubing string.
17. The system of claim 16, wherein:
said gas lift mandrel includes a side pocket communicated with said upper production tubing string, said gas lift valve being retrievable and installable by running through said upper production tubing string.
said gas lift mandrel includes a side pocket communicated with said upper production tubing string, said gas lift valve being retrievable and installable by running through said upper production tubing string.
18. The system of claim 17, wherein:
said gas lift mandrel includes a seal bore in which a lower end of said upper production tubing string in sealingly received.
said gas lift mandrel includes a seal bore in which a lower end of said upper production tubing string in sealingly received.
19. The system of claim 15, further comprising:
a surface controlled subsurface safety valve means for blocking flow through said upper and lower production tubing strings adjacent said subsurface tubing hanger.
a surface controlled subsurface safety valve means for blocking flow through said upper and lower production tubing strings adjacent said subsurface tubing hanger.
20. The system of claim 15, further comprising:
a bypass port defined in said gas lift mandrel for allowing gas to flow into a lower annulus between said lower production tubing string and said well casing; and a lower gas lift valve means, disposed in said lower production tubing string, for injecting gas from said lower annulus into said lower production tubing string.
a bypass port defined in said gas lift mandrel for allowing gas to flow into a lower annulus between said lower production tubing string and said well casing; and a lower gas lift valve means, disposed in said lower production tubing string, for injecting gas from said lower annulus into said lower production tubing string.
21. The system of claim 20, further comprising:
a surface controlled annulus safety valve means for controlling communication between said bypass port and said lower annulus.
a surface controlled annulus safety valve means for controlling communication between said bypass port and said lower annulus.
Applications Claiming Priority (2)
| Application Number | Priority Date | Filing Date | Title |
|---|---|---|---|
| US72778591A | 1991-07-10 | 1991-07-10 | |
| US07/727,785 | 1991-07-10 |
Publications (1)
| Publication Number | Publication Date |
|---|---|
| CA2073415A1 true CA2073415A1 (en) | 1993-01-11 |
Family
ID=24924054
Family Applications (1)
| Application Number | Title | Priority Date | Filing Date |
|---|---|---|---|
| CA002073415A Abandoned CA2073415A1 (en) | 1991-07-10 | 1992-07-08 | Oil well production system |
Country Status (3)
| Country | Link |
|---|---|
| CA (1) | CA2073415A1 (en) |
| GB (1) | GB2257449A (en) |
| NO (1) | NO922478L (en) |
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN110984925A (en) * | 2019-12-30 | 2020-04-10 | 库尔勒中油能源技术服务有限公司 | Double-layer oil pipe gas injection oil production process |
Families Citing this family (8)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| FR2694785B1 (en) * | 1992-08-11 | 1994-09-16 | Inst Francais Du Petrole | Method and system of exploitation of petroleum deposits. |
| US6328107B1 (en) * | 1999-09-17 | 2001-12-11 | Exxonmobil Upstream Research Company | Method for installing a well casing into a subsea well being drilled with a dual density drilling system |
| NO313767B1 (en) | 2000-03-20 | 2002-11-25 | Kvaerner Oilfield Prod As | Process for obtaining simultaneous supply of propellant fluid to multiple subsea wells and subsea petroleum production arrangement for simultaneous production of hydrocarbons from multi-subsea wells and supply of propellant fluid to the s. |
| GB0227394D0 (en) | 2002-11-23 | 2002-12-31 | Weatherford Lamb | Fluid removal from gas wells |
| CN100449117C (en) * | 2005-10-31 | 2009-01-07 | 中国科学院广州能源研究所 | Extracting and conveying method and device of sea-bottom natural gas hydrate |
| WO2021053314A1 (en) * | 2019-09-16 | 2021-03-25 | Pickernell Paul | Wellhead boosting apparatus and system |
| BR102019028102A2 (en) * | 2019-12-27 | 2021-07-06 | Petróleo Brasileiro S.A. - Petrobras | concentric chuck for intermittent pneumatic lifting with accumulation chamber |
| CN114278250B (en) * | 2021-04-16 | 2023-11-17 | 中国海洋石油集团有限公司 | Marine low-pressure gas well fixed-point dragging continuous liquid drainage pipe column and liquid drainage method thereof |
-
1992
- 1992-06-23 NO NO92922478A patent/NO922478L/en unknown
- 1992-07-08 CA CA002073415A patent/CA2073415A1/en not_active Abandoned
- 1992-07-09 GB GB9214596A patent/GB2257449A/en not_active Withdrawn
Cited By (1)
| Publication number | Priority date | Publication date | Assignee | Title |
|---|---|---|---|---|
| CN110984925A (en) * | 2019-12-30 | 2020-04-10 | 库尔勒中油能源技术服务有限公司 | Double-layer oil pipe gas injection oil production process |
Also Published As
| Publication number | Publication date |
|---|---|
| GB9214596D0 (en) | 1992-08-19 |
| NO922478D0 (en) | 1992-06-23 |
| NO922478L (en) | 1993-01-11 |
| GB2257449A (en) | 1993-01-13 |
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