U.S. patent number 3,847,215 [Application Number 05/387,915] was granted by the patent office on 1974-11-12 for underwater well completion method and apparatus.
This patent grant is currently assigned to McEvoy Oilfield Equipment Co.. Invention is credited to David P. Herd.
United States Patent |
3,847,215 |
Herd |
November 12, 1974 |
**Please see images for:
( Certificate of Correction ) ** |
UNDERWATER WELL COMPLETION METHOD AND APPARATUS
Abstract
Extended casing method and apparatus for completing an
underwater well whereby complete and continuous pressure control is
maintained at the surface drilling platform. A conductor casing is
installed in the floor of a body of water with a casing head and
riser attached near the floor. Other casing is installed and
supported at the water floor by hanger heads and having other
risers extending upwardly therefrom. Pressure control equipment is
installed at the upper end of one of the risers. A tubing hanger
and tubing, designed to pass through the pressure control equipment
and riser to which it is attached is lowered into the innermost
hanger-head and remotely latched thereto. The tubing is plugged,
the riser and control equipment removed and a Christmas tree
assembly attached to the wellhead in fluidtight flow communication
with the tubing string.
Inventors: |
Herd; David P. (Houston,
TX) |
Assignee: |
McEvoy Oilfield Equipment Co.
(Pittsburgh, PA)
|
Family
ID: |
22297285 |
Appl.
No.: |
05/387,915 |
Filed: |
August 13, 1973 |
Related U.S. Patent Documents
|
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
Issue Date |
|
|
103839 |
Jan 4, 1971 |
3800869 |
|
|
|
792912 |
Jan 22, 1969 |
|
|
|
|
Current U.S.
Class: |
166/337; 166/387;
166/348 |
Current CPC
Class: |
E21B
33/043 (20130101); E21B 33/047 (20130101); E21B
33/035 (20130101) |
Current International
Class: |
E21B
33/035 (20060101); E21B 33/047 (20060101); E21B
33/03 (20060101); E21b 033/035 () |
Field of
Search: |
;166/.5,.6,313,315,89
;175/7 |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
Marine Completions - Cameron Marine Systems - Cameron Iron Works
Inc., 1966..
|
Primary Examiner: Leppink; James A.
Parent Case Text
This is a division of application Ser. No. 103,839 filed Jan. 4,
1971, now U.S. Pat. No. 3,800,869 which is a continuation of
application Ser. No. 792,912 filed Jan. 22, 1969, now abandoned.
Claims
We claim:
1. A method of suspending at least one string of pipe in a well
with only one trip into the well comprising the following
steps:
running a well pipe hanger assembly which suspends the pipe string
into the well on at least two handling strings;
aligning the well pipe hanger assembly in a predetermined position
within the well;
landing the well pipe hanger assembly within the well;
locking down the well pipe hanger assembly within the well;
testing the seals in the well pipe hanger assembly by pressurizing
the handling strings;
testing the integrity of the packer in the pipe string by
monitoring one of the handling strings; and
removing the handling strings.
2. An underwater well pipe hanger assembly for suspending at least
one string of pipe having a packer in a well comprising:
a hanger body;
support means for supporting said hanger body within the well;
securement means for securing said hanger body within the well;
locking means for locking said securement means in a secured
position;
actuator means for moving said locking means to its locking
position;
alignment means for aligning said hanger assembly;
suspension means on said hanger body for suspending the string of
pipe therefrom;
seal means between said hanger body and said suspension means;
and
testing means on said hanger body extending to the surface and
lowered with said hanger body into the well for testing the
integrity of said seal means and the packer.
3. A pipe hanger assembly according to claim 2 wherein said hanger
body is adapted for releasable connection to a well tool, and
wherein said actuator means includes means for releasably and
rotatably connecting said actuator means to the well tool, and
wherein said locking means is movable into its locking position by
longitudinal force applied to said actuator means by the well
tool.
4. A pipe hanger assembly according to claim 3 wherein rotation of
said well tool releases its connection to said hanger body.
5. A pipe hanger assembly according to claim 2 and including a
reference member disposed in a predetermined direction with the
well wherein said alignment means comprises an alignment key
protruding from said assembly, said alignment key cooperating with
said reference member to cause rotation of said hanger assembly
until said assembly is aligned within the well in a predetermined
direction, and then to preclude further rotation of said alignment
key and said hanger body.
6. A pipe hanger assembly according to claim 5 wherein said
reference member has a helically generated upwardly facing surface
cooperable with said alignment key causing said hanger assembly to
become aligned within the well in a predetermined direction.
7. An assembly according to claim 2 wherein said testing means
includes
at least two conduits extending to the surface;
one of said conduits being in fluid tight communication with the
pipe string; and
means providing communication between the space below said hanger
body and said second conduit.
8. An assembly according to claim 7 wherein said conduits lower
said hanger body into the well.
9. A well pipe hanger assembly for suspending at least one string
of pipe having a packer in a well comprising:
a hanger body having at least one axial bore therethrough;
support means for supporting said hanger body within such well;
securement means for securing said hanger body within such
well;
locking means for locking said securement means in a secured
position;
actuator means for moving said locking means to its locking
position;
alignment means for aligning the hanger assembly;
suspension means on said hanger body for suspending the string of
pipe therefrom;
seal means between said hanger body and said suspension means;
and
testing means on said hanger body for testing the integrity of said
seal means and the packer;
said locking means including a sleeve member reciprocally mounted
within said hanger body and responsive to the longitudinal movement
of a well tool whereby said sleeve member has at least one position
in which it locks said securement means in said secured
position.
10. A well pipe hanger assembly for suspending at least one string
of pipe having a packer in a well comprising:
a hanger body having at least one axial bore therethorugh;
support means for supporting said hanger body within such well;
securement means for securing said hanger body within such
well;
locking means for locking said securement means in a secured
position;
actuator means for moving said locking means to its locking
position;
alignment means for aligning the hanger assembly;
suspension means on said hanger body for suspending the string of
pipe therefrom;
seal means between said hanger body and said suspension means;
and
testing means on said hanger body for testing the integrity of said
seal means and the packer;
supporting structure within the well wherein said alignment means
includes a first orientation means on the assembly cooperable with
a second orientation means disposed on said supporting structure in
a predetermined direction to position the assembly within the well
in a predetermined angular orientation relative thereto.
11. An underwater well apparatus for orienting and locking a well
pipe hanger in a predetermined angular position relative to a
reference member comprising:
hanger body means adapted to be supported within the well;
orienting means associated with said hanger body means engaging the
reference member to place said hanger body means in a predetermined
angular position relative to the reference member;
lock means for securing said hanger body means within the well;
an actuator reciprocally mounted on said hanger body means and
operatively connected to a handling string extending to the
surface; and
a sleeve member reciprocally mounted within said hanger body means
and responsive to the reciprocal movement of said actuator, said
sleeve member being engageable with said lock means whereby upon
the longitudinal movement of said sleeve member said lock means
secures said hanger body means within the well.
12. A well apparatus according to claim 11 wherein said actuator
prevents the rotation of said member relative to said hanger body
means.
13. The apparatus of claim 11 further including holding means for
holding said sleeve member in position in the well, said holding
means being responsive to the axial rotation of said actuator,
whereby upon the axial rotation of said actuator said hold down
means secures said sleeve member within the well.
14. An underwater well apparatus comprising:
a well pipe hanger assembly;
a well tool having a generally cylindrical body with at least one
axial bore therethrough, said body having upper and lower ends with
said lower end adapted for cooperatively engaging said well pipe
hanger assembly;
at least one nipple means rotatably extending through a bore in
said body;
means for releasably connecting said nipple means to a pipe
coupling mounted in said pipe hanger assembly; and
means associated with said assembly to secure said pipe coupling
within said assembly upon rotation of said nipple means.
15. A method of underwater testing of seals of a tubing hanger and
of underwater testing a packer packing around all tubing strings
suspended by the tubing hanger, comprising:
applying fluid pressure through a first testing string suspended
within a conduit extending to the surface and in fluid tight
communication with a tubing string suspended to an area below the
hanger;
monitoring the conduit above the hanger for leaks in the seals;
setting said packer to pack off the area between all the tubing
strings and the well;
applying fluid pressure through the first testing string; and
monitoring a second testing string in fluid communication through
and below said hanger and above said packer.
16. A method of testing a downhole packer comprising the steps
of:
setting a downhole packer to pack around a short and a long tubing
string suspended by a hanger within the well;
installing a back pressure valve in the long tubing string;
pressurizing a first testing string in fluid tight communication
with the short tubing string thereby applying a pressure below the
downhole packer;
passing any leakage of the downhole packer at the area below the
hanger and above the packer through the tubing hanger and into a
second testing string; and
monitoring the second testing string to detect any leaks.
17. A well apparatus for a well having a tubular member extending
into the well, comprising:
a well pipe hanger for suspending at least one pipe string within
the tubular member;
sealing means for sealing between the tubular member, said well
pipe hanger and said pipe string;
packer means for packing between said pipe string and the tubular
member; and
testing means on said well pipe hanger extending to the surface and
lowered with said hanger into the well for testing said sealing
means and said packer means individually.
18. An underwater well apparatus for suspending pipe string having
a packer within a well comprising:
a well pipe hanger suspending at least one pipe string;
a well tool having at least one bore therethrough and at least two
testing strings extending to the surface;
one of said testing strings passing through said bore and being
releasably connected to said hanger, said one of said testing
strings being in fluid tight communication with said pipe string;
and
means providing communication between said second testing string
and the space below said hanger and above the packer.
19. An underwater well apparatus for suspending pipe string within
a well comprising:
a well pipe hanger suspending at least a short and a long well pipe
string and having at least two axial bores therethrough;
a running and testing tool having passage means therein for
communicating with each well pipe string, said tool including a
first and a second handling string each passing through one of said
axial bores;
said first and second handling strings having lower ends releasably
connected to said hanger;
said first handling string being in fluid tight communication with
said short well pipe string;
said second handling string being in fluid tight communication with
said long well pipe string;
means providing communication between the space below said hanger
and said second handling string.
20. A well apparatus for completing a well having an outer casing,
an inner casing and tubing suspended within the well by hangers
comprising:
a tubular adapter lowerable to and engageable with one of such
casing hangers in fluidtight connection therewith; said adapter
being provided with packoff means engageable with a wall of the
casing hanger to which said adapter is attached and engageable with
such other casing hanger to prevent fluid passage through the
annulus created by such outer casing and inner casing;
flow control means for controlling the fluid flow from such
tubing;
nipple means for fluid tight communication between said flow
control means and such tubing;
orientation means for aligning said nipple means with such
tubing;
connection means for releasably connecting said flow control means
and said adapter; and
seal means for sealing said flow control means and said
adapter.
21. A well apparatus for completing a well having an outer casing,
an inner casing and tubing suspended within the well by hangers,
the hanger for said tubing having seals thereon for sealing
therearound, comprising:
a tubular adapter lowerable to and engageable with one of such
casing hangers in fluidtight connection therewith; said adapter
being provided with packoff means engageable with a wall of the
casing hanger to which said adapter is attached and with the other
casing hanger to prevent fluid passage through the annulus created
by such outer casing and inner casing; and
a running testing tool having releasable connection means for
lowering said adapter into the well and connecting said adapter to
such one of such casing hangers and testing means for testing of
said tubing hanger seals and said packoff means.
22. A well apparatus according to claim 21 wherein said packoff
means includes seal means for sealingly engaging such casing
hangers and seal retainer means attached to said adapter by bearing
means permitting said adapter to be rotated to compress said seal
means while said seal means remains stationary.
23. A well apparatus according to claim 21 and including a running
string attached to said tool, and means providing communication
between the running tool and the annulus between the casing hangers
above the seal means.
24. A well apparatus according to claim 21 further including lock
means for locking said adapter in position after said seal is
compressed thereby preventing rotation of said adapter in either
direction with respect to said casing hangers, and actuator means
on said tool for actuating said lock means.
25. A well apparatus according to claim 21 further including a
connection means between said adapter and said one of such casing
hangers fully engageable on less than 360.degree. rotation of said
adapter relative to said one of such casing hangers.
26. A well apparatus according to claim 25 wherein said connection
means is provided with locking means engageable with said adapter
and said one of such casing hangers to prevent disengagement of
said connection means.
27. A well apparatus according to claim 21 wherein such one of such
casing hangers is the outer casing hanger and wherein said
connection means comprises:
a plurality of circumferentially spaced groupings of teeth having
no lead angle disposed on the inner wall of said outer casing
hanger and on the circumference of said adapter;
said adapter teeth being insertable within said outer casing
hanger;
said outer casing hanger and said adapter being connectable upon
the rotation of said adapter and releasable upon a rotation of said
adapter in the opposite direction; and
at least one stop on said adapter engageable with said outer casing
hanger to limit the rotation of said adapter to less than one
revolution.
28. A well apparatus comprising:
a well pipe hanger assembly;
running means attachable to said well pipe hanger assembly for
running said assembly into a wellhead element;
at least one string of pipe suspended from said assembly;
packer means for packing around said pipe;
first seal means established between said assembly and the wellhead
element;
second seal means established between said assembly and said
pipe;
first testing means for testing the integrity of said first seal
means and said second seal means;
second testing means for testing the integrity of said packer by
monitoring said running means, said well apparatus facilitating the
testing of said packer means, said first seal means, and said
second seal means with only one trip into the well.
29. A well apparatus according to claim 28 wherein said second
testing means includes means for applying pressure below said
packer and means passing any leakage above the packer to said
running means to detect any leaks.
30. A well apparatus for a well having a tubular member extending
into the well and including at least one pipe string
comprising:
packer means for packing between the pipe string and the tubular
member;
a well pipe hanger for suspending the pipe string within the
tubular member, said well pipe hanger including a bore for each
pipe string suspended by said well pipe hanger within the well and
another passage through said well pipe hanger for transmitting any
leakage of said packer means;
sealing means for sealing between the tubular member, said well
pipe hanger and the pipe string; and
testing means for testing said sealing means and said packer means
individually.
31. A well apparatus for orientating and locking a well pipe hanger
in a predetermined angular position relative to said reference
member comprising:
hanger body means adapted to be supported within the well;
orientating means associated with said hanger body means engaging
the reference member to place said hanger body means in a
predetermined angular position relative to the reference
number;
securement means for securing said hanger body means within the
well, said securement means being movable into a locked position by
longitudinal force applied to said securement means, said
longitudinal force being applied from a position remote from said
securement means and through a handling string operatively
connected to said securement means.
32. A well apparatus according to claim 31 wherein said securement
means prevents the rotation of said member relative to said hanger
body means.
Description
BACKGROUND OF THE INVENTION
1. Field of the Invention
This invention concerns underwater drilling of oil and gas wells.
Specifically, it pertains to methods and apparatus used in
underwater extended casing operations.
2. Description of the Prior Art
Increased activity in offshore drilling has resulted in a
continuous search for better methods and apparatus in this area. To
cope with the unique problems associated with underwater drilling
various extended casing methods have been developed. Basically,
extended casing methods have a well conductor anchored to the sea
floor which provides support for a special underwater wellhead. The
wellhead, in turn, supports a multiple number of casing strings and
their respective casing hangers. The drilling platform is thus
relieved of much of the structural support responsibilities of
other methods. After drilling is completed, the well may be
permanently abandoned, temporarily abandoned or immediately
completed. For any of these options, the completion equipment may
be installed at the sea floor, leaving the drilling platform free
for relocation and freeing the underwater wellhead from the hazards
of ocean going traffic and structural support problems. One such
extended casing method is fully described in copending U.S. Pat.
application Ser. No. 572,599.
In the extended casing methods of the prior art, one or more
intermediate casing strings, in addition to the conductor casing
and the innermost production casing string, are usually supported
in the wellhead. Casing extensions or risers are attached to these
strings as they are lowered into place and landed. The extensions
are connected at the surface to a blowout preventer for pressure
control and also serve as a return for cement circulation. In the
past it has been necessary to remove all casing extensions, except
possibly the outer conductor riser, for installation of the tubing
hanger and tubing strings. Since blowout preventers of the
conductor riser size are not usually available, the well hole has
no pressure control during the installation of the tubing strings
unless a bridge plug is installed in the production casing string.
If a bridge plug is installed it must be removed by drilling or
otherwise. These operations require additional equipment, time and,
consequently, expenses. Other time delays are encountered in
removing each casing extension since blowout preventers must be
disconnected and other size preventers connected to the next casing
string extension.
Some methods have utilized underwater blowout preventers installed
near the underwater wellhead. However, such preventers are very
expensive and more complex to operate though than the conventional
above water type.
SUMMARY OF THE INVENTION
The present invention concerns a method of completing an underwater
well comprising the steps of: locating drilling means at an
underwater well site; installing conductor casing in the floor of a
body of water with a casing head and riser attached thereto at a
point near the floor, the conductor riser extending upwardly to the
drilling means; drilling holes for, suspending within the conductor
casing and cementing in place other casing, each of the other
casing being suspended by hanger means above which other risers,
extending upwardly to the drilling means, are connected; attaching
blowout pressure control equipment to the top of at least one of
the other risers; running a tubing hanger and at least one tubing
string, through the control equipment and the riser to which it is
attached, into the innermost casing; suspending and latching the
tubing hanger and tubing string in the innermost hanger means; and
removing the pressure control equipment and the other risers.
This method provides complete and continuous pressure control
throughout completion by providing apparatus whereby the tubing
hanger and tubing string may be lowered through blowout preventers
and a riser to their support positions. After latching the tubing
hanger and tubing string in place the tubing is plugged and the
riser and pressure control equipment is removed for installation of
the Christmas tree assembly.
BRIEF DESCRIPTION OF THE DRAWINGS
Other objects and advantages of the invention will become apparent
from the description which follows when taken in conjunction with
the drawing in which:
FIGS. 1 through 6 are step by step sectional elevation views of an
underwater well showing a method and apparatus for completing a
dual tubing string well according to a preferred embodiment of the
invention, and
FIGS. 7 through 10 are step by step sectional elevation views of an
underwater well showing a method and apparatus for tubingless
completion of a well according to a preferred embodiment of the
invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
The present invention is an extended casing completion system for
use when drilling from a bottom supported rig with blowout
prevention control equipment at the surface. Several options on the
method of completion are available, including:
1. Easy permanent abandonment,
2. Temporary abandonment,
3. Completion by extension of casing, risers to a platform,
4. Casing-tubing sub-surface completion with optional diver support
or fully remote operation, and
5. Tubingless sub-surface completion with optional diver support or
fully remote operation.
The apparatus of the present invention permits installation of one
or more tubing strings through blowout prevention control equipment
and extended risers, eliminating the necessity of removing the
risers and blowout preventers when preparing the well for
completion. Because all operations are conducted through the risers
and blowout preventers, well pressure control is continuous and
remote guidance systems are not necessary when temporarily
abandoning the well or preparing it for completion. A guide base is
not installed until a decision is made to complete the well. This
allows a selection at that time of either fully remote Christmas
tree installation or diver support Christmas tree installation.
Referring first to FIGS. 1 through 6, a step by step description of
casing-tubing sub-surface completion, according to a preferred
embodiment of the invention, will be given. The system described
will be a 30 inches .times. 16 inches .times. 10 3/4 inches .times.
7 inches casing program with two 2 3/8 inches tubing strings.
However, it is to be understood that the size and number of casing
and tubing may vary without departing from the principles of the
invention.
First, a 30 inch conductor casing 10, casing head 11, and conductor
riser 12 are lowered from the drilling platform (not shown) and
driven or jetted into the sea floor 1 until casing head 11 rests
near the floor. If bottom conditions require it, a hole may be
drilled for conductor casing 10. Casing head 11 is provided with an
upwardly facing stop shoulder 13 for locating the surface
casing.
Riser 12 is connected to casing head 11 by an easily disengageable
connection 14. One type of easily disengageable joint is shown in
FIG. 1A. This type of joint, which we refer to as a breech block
joint, reduces drilling costs by eliminating on-site welding,
permitting easy recovery of casing risers and reducing rig time
during making, running and recovering casing risers. The joint
comprises a female member 20 and a male member 30. Segmented
threads 21 of a square nonlead profile spaced 30.degree. apart are
milled in the female member for engagement with corresponding
segmented threads 31 on the male member. Smooth milled out areas
22, 32 are provided between the thread segments 21, 31. For
descriptive purposes the thread segments 21, 31 are referred to as
lands and milled out areas 22, 32 as grooves. Engagement is
accomplished by inserting the lands of the male member 30 in the
grooves of the female member 20, then rotating the male member 30
thirty degrees in either direction until the lands of each member
are in full engagement. A positional stop 33 on the male member
cooperates with lugs 35 around the female member to limit rotation
to thirty degrees. A pivotable anti-rotation latch 34 may be
provided to engage the opposite side of lugs 35 preventing
disengagement of the joint.
After the 30 inch conductor casing is set, a hole is drilled for 16
inch surface casing 40, which is lowered into place with surface
casing head 41, back-off joint 42 and surface casing riser 43
attached thereto. Back-off joint 42 and head 41 may be connected by
a breech block joint 46 similar to that shown in FIG. 1A. Landing
lugs 44 are provided on surface casing head 41 cooperating with
stop shoulder 13 to locate surface casing 40. The surface casing 40
is then cemented in place. The remaining strings will be supported
by the cement around surface casing 40. Casing head 41 is provided
with internal annular recesses to receive hanging latches for the
next string.
Next a hole is drilled for the 103/4 inch intermediate casing
string 50 which is lowered into the hole attached to hanger-head
51, back-off joint 52, and riser 53 and cemented in place.
Hanger-head 51 and back-off joint 52 are connected with another
breech block connection 54. Hanger-head 51 is provided with spring
biased latches 55 which support the casing string 50 within the
well. As the latches 55 engage recesses 45, a locking rib 56 on the
hanger-head body locks them into positive engagement. Hanger-head
51 may be provided with internal circulation ducts 57 or the
latches 55 may be fluted for cement circulation. Internal latch
recess 58 and circulation ducts 59 may be provided for ducting
around the next hanger-head. Blowout prevention control equipment
is attached to the top of riser 53 at the drilling platform (not
shown).
Next the hole for production casing string 60 is drilled and the
production string is landed and cemented in place attached to
hanger-head 61, back-off joint 62 and riser 63. Production string
hanger-head 61 is similar to hanger-head 51 having spring latches
65 a locking rib 66 and if necessary flow ducts 67. However, it has
no internal latch recesses and it is connected to back-off joint 62
by a left hand thread connection 64 rather than a breech block
joint. Immediately above the connection 64 two internal tubing
hanger hold down recesses 68 are cut. An external key 69 provides
orientation for a subsequently installed tubing hanger. Therefore,
the production string 60 must be properly oriented while running in
place.
The aforementioned drilling is done through the blowout prevention
equipment at the drilling platform. At this stage of the drilling,
the wellhead equipment would be as shown in FIG. 1. At this time
the production string riser 63 is removed by rotating the riser 63
and back-off joint 62 to the right.
Referring specifically now to FIG. 2, an orientation sleeve 70
connected by a "J" slot arrangement 76 to running tool 71 and
running string 72 is run through 10 3/4 inch riser 53. A
longitudinal slot at the base of sleeve 70 engages hanger-head key
69 and the sleeve comes to rest against hanger-head shoulder 73. An
orientation bushing 74 is affixed to the interior of sleeve 70 for
automatic guidance of a tubing hanger which is to be installed. It
has a dual 180.degree. ramp 75 and a vertical slot 76 communicating
with the ramp at its lowermost intersection. Tool 71 is then
disconnected from orientation sleeve 70 and removed.
Referring now to FIG. 3, a tubing hanger 80, tubing 90, 91 and
annular access nipple 92 are installed along with tubing running
tool 93. Tubing hanger 80 is provided with three vertical bores 81,
82 (one not shown) communicating with annular access nipple 92 and
tubing strings 90, 91. Long tubing handling string 94 is connected
to hanger 80 by a handling nipple (not shown) similar to handling
nipple 95 connected to short string handling string 96. Both
nipples pass through running tool 93. However, nipple 95 is screwed
into a landing nipple 96 whereas the long string handling nipple is
screwed directly in hanger 80. Both tubing strings 90, 91 are
lowered together. However, short string 91 is displaced upwardly a
slight amount from the position shown in FIG. 3.
Hanger 80 is provided with a longitudinal key 83 which rides on
orientation bushing ramp 75 until it engages orientation slot 76
orienting the tubing hanger 80. The tubing hanger comes to rest on
the upper shoulder 85 hanger-head 61. A hold down latch 86 and
locking sleeve 87 are mounted in a skirt portion of hanger 80 near
its base. In the running position the latch 86 is retracted and
locking sleeve 87 is held up against the body of hanger 80 by
engagement with landing nipple 95. When the hanger 80 is landed,
short tubing string 91 and landing nipple 96 are allowed to move
downwardly to the position shown in FIG. 3, where it is supported
by shoulder 88, causing locking sleeve 87 to force hold down latch
86 into engagement with hanger-head hold down recesses 68. Up to
this point handling nipple 96 and landing nipple 96 are fully made
up so that the upper edge of landing nipple 96 is abutting
downwardly facing shoulder 97 on handling nipple 95. By rotating
handling nipple 95 to the right these shoulders are separated
allowing a snap ring 89 in hanger 80 to spring out engaging the
upper edge of landing nipple 96 and holding the short tubing string
91 down. At this point all wellhead components appear as shown in
FIG. 3.
Next the tubing hanger seals would be tested by pressurizing
through short tubing string 91. Pressure would then be applied
below the tubing hanger 80 and through annular access nipple 92 and
tubing 90. Testing tool 93 is provided with a vertical port 98 and
a horizontal port 99 which communicates with long tubing string 90
through a port in the handling nipple (not shown) attached to
handling string 94. Should any of the seals around hanger 80 and
landing nipple 96 leak it will be detected in riser 53.
Next, the downhole tubing packer is set, usually by hydraulic
means, a back pressure valve is installed in long string 90 and the
packer pressure tested. Pressure is applied through short string
91. If the packer leaks the test fluid passes through annular
access nipple 92 and through test tool ports 98, 99 into handling
string 94 for detection.
If all tests are positive, the tubing handling strings 94, 96,
their respective handling nipples, and test tool 93 are removed
from the hole by rotating the handling strings to the right. The
tubing strings 90, 91 and annulus access nipple 92 are plugged. It
will be noticed that throughout running and setting of the tubing
hanger and tubing strings complete pressure control is maintained
at the surface by blowout prevention equipment connected to 10 3/4
inch riser 53.
Next, the pressure control equipment, 10 3/4 inch riser 53 and 16
inch riser 43 are removed by 30.degree. rotation to the right for
disengagement of breech block connections 54 and 46. At this stage,
the wellhead will appear as shown in FIG. 4 with conductor
extension 12 being the only remaining riser.
Referring now to FIG. 5, a tubular Christmas tree adapter 100 is
run on drill pipe 120 using a combination running testing tool 130.
The external midportion of adapter 100 is provided with the male
part of a breech block connection 101 for engagement with the
female part of the connection 101 in the 10 3/4 inch head 51.
Rotatably connected by ball bearings 102 to the lower part of
adapter 100 is an annular packoff assembly comprising a resilient
seal member 104 sandwiched between upper and lower retainer members
103, 105. Lower retainer 105 is stopped against hangerhead shoulder
106 and as the breech block connection 101 is engaged upper
retainer ring 104 presses against seal member 104 causing it to
sealingly engage the walls of hanger-heads 51 and 61. A port 131
connects the bore 132 of tool 130 with the annular space between
adapter 100 and tubing hanger 80. This space is sealed at 133, 134
by O-rings, allowing adapter seals 104, 108, 109 and tubing hanger
seals 110 to be tested.
Christmas tree adapter 100 has an upper flange member 111 and
internal connection threads 112 to which tool 130 is connected.
Christmas tree adapter 100 also has stop lugs 113 which cooperate
with stop lugs 114 on the top of hanger-head 51 when the
breech-block connection is made to stop rotation at full
engagement. To prevent disengagement, a locking ring 115 with
depending lugs 116, is mounted around adapter 100 and held upwardly
thereon as shown by radial pins 117 which ride in an "L" slot 135
in sleeve skirt 136 of tool 130. A shear pin 137 is sheared on
further right hand rotation of tool 130. This allows skirt 136 to
rotate to a position where pins 117 drop out of the "L" slot
allowing the locking ring 115 to drop downwardly so that its lugs
116 fall between the back of adapter lugs 113 and the next closest
hanger-head lug 114. This prevents rotation of adapter 100 in
either direction thus locking it in position. Further rotation of
tool 130, to the right, releases it for removal from the well.
If it is decided to temporarily abandon the well, rather than
immediately complete it, a corrosion cap (not shown) may be run on
drill pipe using a "J" type running tool. It would be connected to
the internal threads 112 of tubing head adapter 100. The corrosion
cap could be provided with a port for spotting oil within the
wellhead to prevent corrosion. This port would, of course, be
plugged after the oil was injected. After installation of the
corrosion cap, conductor riser 12 would be removed by rotating
30.degree. to the right. A corrosion cap top could be installed by
a diver and the well could be temporarily abandoned.
Alternatively, if it is desired to immediately complete the well,
rather than install a corrosion cap, the Christmas tree would be
installed. To do this, conductor riser 12 would be removed. Now
referring also to FIG. 6, a small guide base 140 with two guide
posts 141 would be clamped around the lower part of adapter 100 or
hanger-head 51 by a diver. The guide base would be oriented by a
tool with two pins adapted to engage tubing hanger receiving
pockets 118, 119.
Next, Christmas tree 150 would be lowered to the wellhead. It would
be provided with guide arms 151 and bell bottom sleeves 152 which
would engage guide posts 141 to assist a diver in installing the
tree 150. The base of tree 150 carries two long nipples 153, 154
which sealingly engage the corresponding receiving sockets 118, 119
in hanger 80. The base of tree 150 would come to rest against the
upper face of adapter 100. An annular seal ring 155 would be
provided at the joint. The tree 150 is then clamped to Christmas
tree adapter 100 by a standard type clamp 160. A remote hydraulic
connector could be used as an option eliminating the need for a
diver to torque up clamp bolts. Thus, as shown in FIG. 6, the well
is ready for production.
Should it be necessary at a future date to perform workover
operations, tubing strings 90, 91 would be plugged and the
Christmas tree 150 removed. Then a workover riser with a built in
orientation sleeve and bushing similar to sleeve 70 and bushing 74
in FIGS. 2 and 3 would be attached to tree adapter 100. The
orientation bushing would have a slot to engage key 83 of tubing
hanger 80. In this manner, after the tubing hanger 80 is
re-installed, following workover operations, it is landed in the
same position as it was before workover operations.
If a tubingless sub-surface completion is desired, instead of a
casing-tubing sub-surface completion, a somewhat different
procedure is followed. However, with reference to FIG. 7, the first
steps are the same as in the casing-tubing sub-surface completion
just described. A 30 inch conductor casing 210, casing head 211,
and conductor riser 212 connected by breech-block joint 214 are
installed. A 16 inch surface casing 240, casing head 241, back-off
joint 242, and riser 243 are installed. Next, the 10 3/4 inch
casing string 250, hanger-head 251, back-off joint 252, and riser
253 are installed as in the conventional completion.
There is a slight difference in hanger-head 251 and back-off joint
252. Hanger-head 251 is provided with an internal vertical slot 259
immediately above the hanging recesses 258. Orientation in this
method will be obtained by orienting the 10 3/4 hanger-head 25
rather than the 7 inch hanger-head in the afore-described
casing-tubing sub-surface completion. Backoff joint 252 is provided
with an orientating bushing 260 which has a double ramp orienting
slot 261 cut on a 45.degree. angle. A vertical slot 262 is cut at
the bottom or ramp 261 for alignment with hanger head slot 259. A
hanger-head and back-off joint equipped with the modifications of
hanger-head 251 and back-off joint 252 could be used with the
casing-tubing sub-surface completion previously described,
providing an option, at this point, of either casing-tubing
completion or tubingless completion.
Blowout prevention equipment (not shown) is attached at the upper
end of riser 253 at the drilling platform. Running of tubing will
be performed through this blowout prevention equipment so that full
pressure control is maintained at all times as in the previously
described method.
In the next step, two strings of tubing 270, 271 are clamped
together and run in the well tied by shear pins 273 to a tubing
hanger assembly 280. Tubing hanger 280 is provided with outwardly
biased hanging latches 281 and inwardly biased tubing latches 282
around openings 284, 285 through which tubing strings 270, 271
pass. An offset opening (not shown) through the hanger 280 provides
access to the annulus between the tubing string 270, 271 and 10 3/4
inch casing 250. This allows both cementing circulation and limited
gas lift production.
Also provided on hanger 280 is an external spring loaded dog 290.
Referring also to FIG. 7A dog 290 is beveled at the top 291 and
bottom 292 so that it is cammed inwardly by any horizontal shoulder
it encounters as the hanger is lowered into the well. However,
looking at the face of dog 290, its bottom 292 is "V" shaped
providing 45.degree. angle edges 293, 294. If these angle edges
293, 294 encounter a matching 45.degree. angle shoulder such as
orienting ramp 261, the dog 290 will not be cammed inwardly but
will ride down the ramp causing the tubing hanger 280 to rotate
therewith. Thus, as the tubing strings 270, 271 and hanger 280 are
lowered into the well, dog 290 engages ramp slot 261 rotating the
hanger 280 until dog 290 falls through vertical slot 262 and into
slot 259 as shown. Latches 281 engage hanging recesses 258 in a
proper orientation.
Attached to the upper end of tubing strings 270, 271 are tubing
hanging nipples 275, 276 which are provided with external hanging
grooves 277, 278. One of the nipples, in this case 275, is longer
than the other for reasons to be described subsequently. Running
tools 286, 287 connect the hanging nipples 275, 276 to running
strings 296, 297.
After the tubing hanger 280 is in place as shown in FIG. 7, the
weight of tubing 270, 271 shears pins 273. Both strings 270, 271
are then run to bottom and tubing latches 282 engage the latch
grooves 277, 278 in hanging nipples 275, 276, supporting the tubing
strings as shown in FIG. 8. Both strings can then be cemented and
handling strings 296, 297 and running tools 286, 287 removed by
rotation to the right. At this stage of completion the wellhead
equipment appears as in FIG. 8.
If for any reason tubing strings 270, 271 should become stuck after
tubing hanger 280 is latched in, and cannot be freed, both strings
would be cemented in. Then a standard outside tubing cutter would
be run over one of the tubing strings. The cutter would be modified
slightly to support tubing slips at its bottom. These tubing slips
(not shown) would be lowered to engage tapered receiving bowls 288,
289 in the top of the hanger 280. The slips would be set and then
the tubing string would be cut off at a distance from hanger 280
equal to the height of hanging nipples 275, 276, one longer than
the other. After one tubing is set and cut the same procedure would
be followed for the other tubing string.
Next, tubing strings 270, 271 are plugged and risers 253 and 243
are removed by 30.degree. rotational disengagement of breech-block
connections 246, 254 as in the casing-tubing sub-surface completion
previously discussed. This leaves only the 30 inch riser 212.
As now shown in FIG. 9, a Christmas tree adapter 300, similar to
the adapter 100 (FIGS. 5 and 6), is lowered through riser 212 on
drill pipe 320 and combination running and testing tool 330. The
external midportion of adapter 300 is provided with the male part
of breech-block connection 301 for engagement with head 251.
Rotatably connected by ball bearings 302, at the lower part of
adapter 300, is annular packoff assembly 303. Assembly 303 differs
from the casing-tubing sub-surface completion apparatus in that it
is designed to also packoff around hanging nipples 275, 276 as well
as against head 251. The lower retaining ring 304 of packoff
assembly 303 is provided with an offset frusto-conical surface, the
axis of which coincides with the axis of landing nipple 275. Thus,
if the packoff assembly is not properly oriented as tubing head
adapter 300 is lowered into place, the frusto-conical surface 305
contacts one of the tubing nipples, and is cammed around to the
proper orientation. Nipple 275 is longer than nipple 276 to prevent
the possibility of both nipples contacting surface 305 at the same
time should assembly 300 be exactly ninety degrees out of proper
orientation. Packoff assembly 300 also has an annular access port
306.
Running tool 330 seals on the inside diameter of adapter 300 at 307
and on the outside diameter of hanging nipples 275, 276 at 308,
309. Internal porting 310 within the tool 330 permits pressure
testing of the packoff assembly 303.
Christmas tree adapter 300 has an upper flange member 311 and
internal connection threads 312 to which tool 330 is connected. The
adapter 300 also has stop lugs 313 which cooperate with hanger-head
stop lugs 314 to limit stop rotation at full engagement as
explained with reference to FIG. 5 in the casing-tubing sub-surface
completion method previously described herein. Also provided is a
lock ring 315 held first in an upward position by sleeve skirt 336
of the tool 330. After shearing of pin 337 right hand rotation of
tool 330 allows pins 317 to drop out of "L" slots 335 in sleeve 336
allowing its lugs 316 to drop between the back of adapter lugs 313
and the next closest hanger-head lugs 314, locking the adapter in
its fully engaged position. Further rotation of tool 330 frees it
for retrieval from the well.
The well can then be temporarily abandoned as explained in the
casing-tubing sub-surface method previously described or it can be
completed for production. If it is to be completed for production,
at this point, conductor riser 212 is disconnected from conductor
head 211 by 30.degree. rotation and removed.
Now referring to FIG. 10, a spool piece 350, and Christmas tree 360
is guided into place and attached to adapter flange 311 by standard
type diver assist clamp 351. Spool piece 350 may be lowered by
itself first with Christmas tree 360 being lowered afterward.
Alternatively, Christmas tree 360 may be assembled with spool piece
350 by clamp 361, then lowered together into place for attachment
to adapter 300. Spool piece 350 is provided with nipples 352, 353
which stab and seal over hanging nipples 275, 276. It is also
provided with a side opening outlet 354 and bore 355 communicating
with port 306 and tubing-casing annulus below hanger 280 through a
port (not shown) in hanger 280. A valve removal plug 356 allows for
future installation of a side outlet valve. Christmas tree 360 is
provided with short nipples 362, 363 which sealingly engage pockets
provided for this purpose in spool piece 350. Nipples 362, 363,
352, 353, 275, 276 and spool bores 357, 358 provide unobstructed
full opening into tubing strings 270, 271.
The foregoing methods and apparatus for completing an underwater
well for both the casing-tubing sub-sea completion or tubingless
completion offer definite advantages in both speed and safety.
Complete pressure control at the drilling platform is maintained at
all times and the apparatus used permits fast connection and
disconnection for reduction of expensive rig time.
* * * * *