Note: Descriptions are shown in the official language in which they were submitted.
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.
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
--2--
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 ~
-6-
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~
--10--
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
-12-
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 ~
-13-
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 ~
-14-
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.
