U.S. patent application number 12/958802 was filed with the patent office on 2011-06-02 for assembly and method for subsea well drilling and intervention.
Invention is credited to GAVIN HUMPHREYS.
Application Number | 20110127040 12/958802 |
Document ID | / |
Family ID | 44067966 |
Filed Date | 2011-06-02 |
United States Patent
Application |
20110127040 |
Kind Code |
A1 |
HUMPHREYS; GAVIN |
June 2, 2011 |
ASSEMBLY AND METHOD FOR SUBSEA WELL DRILLING AND INTERVENTION
Abstract
An assembly suitable for subsea drilling and intervention
operations includes a dual blow out preventer system having an
upper blow out preventer located between a drill floor and a riser
string, and a lower blow out preventer located below the riser
string and above a wellhead. The dual BOP system is adapted to
enable advanced drilling and intervention operations such as
Managed Pressure Drilling ("MPD"), Underbalanced Drilling ("UBD"),
or Through Tubing Rotary Drilling ("TTRD") in an offshore deepwater
environment.
Inventors: |
HUMPHREYS; GAVIN; (Aberdeen,
GB) |
Family ID: |
44067966 |
Appl. No.: |
12/958802 |
Filed: |
December 2, 2010 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
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61265805 |
Dec 2, 2009 |
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Current U.S.
Class: |
166/345 |
Current CPC
Class: |
E21B 19/004 20130101;
E21B 33/038 20130101; E21B 17/017 20130101 |
Class at
Publication: |
166/345 |
International
Class: |
E21B 7/12 20060101
E21B007/12 |
Claims
1. A subsea assembly for use in subsea operations, the assembly
comprising: a slip joint assembly located beneath a vessel floor; a
rotating control head located beneath the slip joint assembly; an
upper blow out preventer ("UBOP") located beneath the rotating
control head; an upper stress joint located beneath the UBOP; a
riser string located beneath the upper stress joint; a lower stress
joint located beneath the riser string; a lower blow out preventer
("LBOP") located beneath the lower stress joint; and a wellhead
located beneath the LBOP.
2. An assembly as defined in claim 1, wherein the riser string has
a pressure rating that is the same as a pressure rating of the UBOP
and LBOP.
3. An assembly as defined in claim 1, wherein the assembly is used
in an offshore deepwater environment.
4. An assembly as defined in claim 1, wherein the assembly is
adapted to perform at least one of a Managed Pressure Drilling,
Underbalanced Drilling, or Through Tubing Rotary Drilling
operation.
5. An assembly as defined in claim 1, wherein the riser string is
sized for running casing having an API size less than or equal to
133/8''.
6. An assembly as defined in claim 1, wherein the vessel has a
length of no more than 148 meters and a width of no more than 28
meters.
7. An assembly as defined in claim 1, wherein the vessel is adapted
to drill wells in water depths of at least 7,500 ft.
8. A method for use in a subsea operation, the method comprising
the steps of: (a) providing a slip joint assembly located beneath a
vessel floor; (b) providing a rotating control head located beneath
the slip joint assembly; (c) providing an upper blow out preventer
("UBOP") located beneath the rotating control head; (d) providing
an upper stress joint located beneath the UBOP; (e) providing a
riser string located beneath the upper stress joint; (f) providing
a lower stress joint located beneath the riser string; (g) a lower
blow out preventer ("LBOP") located beneath the lower stress joint;
and (f) providing a wellhead located beneath the LBOP.
9. A method as defined in claim 8, wherein step (e) further
comprises the step of providing the riser string with a pressure
rating that is the same as a pressure rating of the UBOP and
LBOP.
10. A method as defined in claim 8, further comprising the step of
performing the subsea operation in an offshore deepwater
environment.
11. A method as defined in claim 8, further comprising the step of
performing at least one of a Managed Pressure Drilling,
Underbalanced Drilling, or Through Tubing Rotary Drilling
operation.
12. A method as defined in claim 8, further comprising the step of
tripping a liner having an API size less than or equal to 133/8''
through the riser string.
13. A method as defined in claim 8, further comprising the step of
providing the vessel with a length of no more than 148 meters and a
width of no more than 28 meters.
14. A subsea assembly for use in subsea operations, the assembly
comprising: an upper blow out preventer ("UBOP") located beneath a
vessel floor; a riser string located beneath the UBOP; and a lower
blow out preventer ("LBOP") located beneath the riser string and
operatively coupled to a wellhead.
15. An assembly as defined in claim 14, wherein the riser string
has a pressure rating that is the same as a pressure rating of the
UBOP and LBOP.
16. An assembly as defined in claim 14, wherein a pressure rating
of the UBOP, riser string, and LBOP is at least 10,000 psi.
17. An assembly as defined in claim 14, wherein the assembly is
used in an offshore deepwater environment.
18. An assembly as defined in claim 14, wherein the assembly is
adapted to perform at least one of a Managed Pressure Drilling,
Underbalanced Drilling, or Through Tubing Rotary Drilling
operation.
19. An assembly as defined in claim 14, wherein the riser string is
sized for running casing having an API size less than or equal to
133/8''.
20. An assembly as defined in claim 14, further comprising a
rotating control head.
21. An assembly as defined in claim 14, wherein the vessel has a
length of no more than 148 meters and a width of no more than 28
meters.
22. An assembly as defined in claim 14, wherein the vessel is
adapted to drill wells in water depths of at least 7,500 ft.
23. A method for use in subsea operations, the method comprising
the steps of: (a) providing a vessel having a floor; (b) providing
an upper blow out preventer ("UBOP") located beneath the floor; (c)
providing a riser string located beneath the UBOP; (d) providing a
lower blow out preventer ("LBOP") located beneath the riser
assembly; and (e) connecting the LBOP to a wellhead beneath the
LBOP.
24. A method as defined in claim 23, further comprising the step of
providing the riser string with a pressure rating that is the same
as a pressure rating of the UBOP and LBOP.
25. A method as defined in claim 23, further comprising the step of
providing the UBOP, riser string, and LBOP with a pressure rating
of at least 10,000 psi.
26. A method as defined in claim 23, further comprising the step of
performing the subsea operations in an offshore deepwater
environment.
27. A method as defined in claim 23, further comprising the step of
performing at least one of a Managed Pressure Drilling,
Underbalanced Drilling, or Through Tubing Rotary Drilling
operation.
28. A method as defined in claim 23, further comprising the step of
tripping liner down the riser string, the liner having an API size
less than or equal to 133/8''.
29. A method as defined in claim 23, further comprising the step of
locating a rotating control head beneath the UBOP.
30. A method as defined in claim 23, wherein step (a) further
comprises the step of providing the vessel with dimensions of no
more than 148 meters in length and no more than 28 meters in
width.
31. A method as defined in claim 23, further comprising the step of
drilling a well at a water depth of at least 7,500 ft.
32. A subsea assembly for use in subsea operations, the assembly
comprising: a vessel having a floor; and a riser string located
beneath the floor, wherein the assembly is adapted to perform at
least one of a Managed Pressure Drilling, Underbalanced Drilling,
or Through Tubing Rotary Drilling operation.
33. An assembly as defined in claim 32, wherein the assembly
further comprises: an upper blow out preventer ("UBOP") located
above the riser string; a lower blow out preventer ("LBOP") located
below the riser string; and a wellhead located beneath the
LBOP.
34. An assembly as defined in claim 32, wherein the riser string is
adapted to withstand at least 10,000 psi.
35. A method for use in subsea operations, the method comprising
the steps of: (a) providing a vessel having a floor; (b) providing
a riser string located beneath the floor; and (c) performing at
least one of a Managed Pressure Drilling, Underbalanced Drilling,
or Through Tubing Rotary Drilling operation.
36. A method as defined in claim 35, further comprising the steps
of: providing an upper blow out preventer ("UBOP") located above
the riser string; providing a lower blow out preventer ("LBOP")
located beneath the riser string; and providing a wellhead located
beneath the LBOP.
37. A method as defined in claim 35, further comprising the step of
adapting the riser string to withstand at least 10,000 psi.
Description
PRIORITY
[0001] The present application claims the benefit of U.S.
Provisional Patent Application Ser. No. 61/265,805, entitled
"SUBSEA WELL DRILLING AND INTERVENTION METHOD AND APPARATUS," filed
on Dec. 2, 2009, naming Gavin Humphreys as inventor, which is
hereby incorporated by reference in its entirety.
FIELD OF THE INVENTION
[0002] The invention relates to subsea assemblies used in offshore
deepwater operations and the production of hydrocarbons.
DESCRIPTION OF THE RELATED ART
[0003] Hydrocarbon production often requires the placement of
drilling equipment in an offshore location. In shallow waters, the
rigs and production facilities can be placed on freestanding
offshore platforms. As the water becomes deeper, however, use of
such platforms becomes impractical. As a result, floating
structures, such as drill ships, must be used.
[0004] As the desire to drill at greater water depths increases
(e.g., to at least 7,500 ft water depth), floatable support
structures have become larger due to the amount of pipe required to
drill at such depths. In addition, the physical size and height of
the drilling derrick or other type of hoisting tower of the ship
also limits the locations in which it can travel. For example,
large drillships may not be able to travel through such waterways
as the Suez or Panama Canals due to height constraints across the
canals, and likewise may not be able to travel under the bridge in
the Bosphorous (mouth of the Black sea) due to the height of their
drilling derricks or hoisting tower on the drillship. It is often
necessary to travel around such waterways, which greatly increases
the travel costs and time.
[0005] In addition, conventional deepwater rigs cannot efficiently
perform some advanced drilling operations. For example, in recent
years, Managed Pressure Drilling ("MPD") and Underbalanced Drilling
("UBD") have become increasingly more relevant to drilling wells
that were previously deemed un-drillable or to drill wells where
subsurface pore pressures and fracture gradients have converged
requiring drilling fluid weights to be tailored to drill through
very tight subsurface pressure windows. The conventional deepwater
rigs that utilize a single subsea blowout preventer ("BOP") on the
seabed which is tied back to the drillship with a relatively low
pressure marine riser that is not designed to withstand closed in
internal pressure (designed for flow only) lack the pressure
integrity in the riser to routinely carry out either MPD nor UBD
due to the marine risers' lack of internal pressure integrity
(typically a 211/4 inch marine riser has a burst pressure at the
time of manufacture of approximately 1,000 psi, which cannot be
field tested during the riser's life-time). Limited MPD is also
performed where a rotating control head ("RCH") is installed on to
a collapsed telescopic joint; however, costly pressurized mud cap
drilling technology is required.
[0006] Although some pressurized interventions are being done from
rigs, they involve dedicated intervention risers (typically slim
completion/production riser for intervention with electric or slick
wire-line, Coil Tubing, or Through Tubing Rotary Drilling ("TTRD"))
generally with increased costs as they are provided by a third
party contractor to compliment the conventional drilling BOP
system.
[0007] In view of the foregoing, a need exists for highly mobile
floatable structures capable of drilling in deepwater environments.
It would be advantageous if the structures were smaller than
conventional floatable structures and cost substantially less to
build and operate. In addition, there is a need for a floatable
structure capable of utilizing drilling technologies such as MPD
and UBD in deepwater environments.
SUMMARY OF THE INVENTION
[0008] Floatable structures used in deepwater drilling and
intervention are provided as embodiments of the present invention.
The systems and methods described herein allow operators to perform
MPD, UBD, or TTRD) in deep water applications. In an exemplary
embodiment, the floatable structure includes a dual BOP system
comprising an upper blow out preventer ("UBOP") and a lower blow
out preventer ("LBOP"). The UBOP is located between a drill floor
and above a riser string, while the LBOP is located below the riser
string and above a wellhead. The riser utilizes a slim design
adapted to withstand a high pressure environment. The UBOP, LBOP,
and riser combine to form a riser system that has the same high
pressure integrity from top to bottom, essentially forming an
extension of the wellbore. In addition, an expandable intermediate
liner may be tripped down the riser and installed below a slim
surface casing, thus saving a casing string size. Also, the present
invention allows the well to be designed to effectively reduce the
number of casing strings by using MPD or UBD drilling
technology.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] FIG. 1 is a diagram of a dual BOP system made in accordance
with an exemplary embodiment of the present invention; and
[0010] FIG. 2 is a diagram of an expandable casing string as run in
accordance with an exemplary methodology of the present
invention.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0011] Illustrative embodiments and methodologies of the invention
are described below as they might be employed to allow users to
perform advanced drilling and intervention operations in deep water
environments. In the interest of clarity, not all features of an
actual implementation or methodology are described in this
specification. It will of course be appreciated that in the
development of any such actual embodiment, numerous
implementation-specific decisions must be made to achieve the
developers' goals, such as compliance with system-related and
business-related constraints, which will vary from one
implementation to another. Moreover, it will be appreciated that
such a development effort might be complex and time-consuming, but
would nevertheless be a routine undertaking for those of ordinary
skill in the art having the benefit of this disclosure. Further
aspects and advantages of the various embodiments of the invention
will become apparent from consideration of the following
description and drawings.
[0012] Referring to FIG. 1, an exemplary embodiment of the present
invention is illustrated. As shown in FIG. 1, a floatable structure
includes a vessel (not shown), such as a drill ship, and a dual
BOP/riser system 5 coupled beneath the floor of the vessel. Dual
BOP/riser system 5 comprises an upper blow out preventer ("UBOP")
10 and a lower blow out preventer ("LBOP") 20. As will be described
in detail later, the drill ship may be a DrillSLIM.TM. or
SLIMDRILL.TM. drill ship designed by Stena Drilling Ltd. of
Scotland, U.K., which is the Assignee of the present invention. The
UBOP 10 is located below drill floor 35 and above riser string 40.
LBOP 20 is located below riser string 40 and above a wellhead (not
shown). A bag preventer (not shown) may also be located above UBOP
10. Extending below drill floor 35 is a diverter assembly 12 having
a flex joint 14 coupled beneath it. Diverter assembly 12 may
include, for example, 16 inch overboard lines to the port and
starboard sides of the ship.
[0013] Flex joint 14 connects to slip joint assembly 16, which can
be a triple barrel slip joint assembly having a 50 ft stroke.
Assembly 18 is coupled beneath slip joint assembly 16 and includes
a high pressure spacer joint with a load ring and blafro flange.
This exemplary embodiment also includes a rotating control head
("RCH") in assembly 18, which is installed above the high pressure
spacer joint to enable MPD or UBD. In addition to MPD and UBD,
other drilling techniques can be used with the present invention as
will be apparent to those of skill in the art having the benefit of
this disclosure. A flexible line 21 is tied into an independent
choke manifold 23, which may be located in the substructure of the
drill ship, to facilitate the application of MPD or UBD drilling
technology and is totally independent from the main rig kill and
choke lines.
[0014] Further referring to the exemplary embodiment of FIG. 1,
UBOP 10 is coupled beneath assembly 18 and includes at least three
sets of rams, 25a, 25b, 25c, wherein at least two of the three sets
of rams comprise variable bore rams ("VBR") rated at 10K psi. In
the alternative, rams 25a, 25b, and 25c include one 95/8 inch
casing ram and two 27/8-5.5 inch VBR. UBOP 10 can also include, for
example, a 135/8 inch annular preventer rated at 5K psi. Upper
stress joint 22 is coupled beneath UBOP 10 and connects to riser
string 40, and may be a 135/8 inch triple barreled telescopic joint
with up to a 50 ft stroke. UBOP 10 also includes a choke/kill
manifold with inlets from below the rotating elements of the RCH
and an independent choke manifold with self-adjusting chokes for
MPD and UBD.
[0015] Riser string 40 may be a 135/8 inch inner diameter ("ID"),
high pressure 10K riser, having kill and choke lines from the
seabed to the surface. Conventional drilling marine risers
(generally utilized with a subsea BOP on the seabed) are designed
to control drilling fluid flow and have sufficient burst pressure
strength at the seabed to hold the pressure differential between
the heaviest drilling mud inside the riser against seawater
pressure outside the riser. A high pressure riser can also
withstand these physical properties, but it can also be sealed up
at the top of the riser and be subjected to up to 10,000 psi
additional pressure in the event that an activity may require the
riser to be pressured. Riser string 40 may also include a design
that includes a 10,000 psi burst rating, and also be able to comply
with stringent dimensional requirements for handling and storage on
the deck of the drill ship to keep the ship size to a minimum.
[0016] For example, the riser can be approximately 7,500 ft of
135/8 inch ID.times.10K (120 joints) with two choke/kill lines
which would allow for high pressure pumping outside riser string
40. The joints can be 65 ft long with high strength connectors,
weigh +/-21 T (dry), and have a 45 inch outer diameter ("OD") with
buoyancy. Riser string 40 is kept in tension by a substructure
mounted tensioner system, rated to 2.4 million lbs with 14.0 ppg
(1.68 specific gravity (SG)) fluid inside the riser.
[0017] The riser system also has 10,000 psi kill and choke line
(generally associated with subsea BOP control systems) to
facilitate conventional seabed well control techniques or to
monitor and control pressures below a sealed LBOP if the riser
system is used as a lubricator while using MPD or UBD drilling
technologies.
[0018] In further reference to the exemplary embodiment of FIG. 1,
lower stress joint 24 is coupled beneath riser string 40 and
connects to high pressure ball valve 26 to contain the mud when
emergency disconnect is initiated. LBOP 20 includes at least three
sets of rams 30a, 30b, 30c, which can include, for example, one
pipe ram to hang-off the drill pipe and two blind shear rams with
fail safe closed connections to monitor pressure build up in the
event the well is closed in on the blind rams. LBOP also includes
an emergency disconnect and a wellhead connector. In the
alternative, LBOP 20 may be comprised of super shear blind/shear
rams in order to shear and seal on the 9.5/8 inch casing and
heavier drill pipe. LBOP 20 and the lower riser package enable the
well to be closed in at seabed level, and the high pressure riser
string 40 to be disconnected.
[0019] In this exemplary embodiment, LBOP 20 and the lower riser
package are controlled by a multiplex system with acoustic backup
including: duplicate umbilical control reels for approximately 7500
ft water depth and a modular emergency subsea accumulator pack (set
on seabed) that is connected using a remotely operated vehicle
(ROV). UBOP 10 can be controlled by a pilot hydraulic control
system. The controls for both UBOP 10 and LBOP 20 can be adjacent
to each other on the same panels. The hydraulic disconnect package
or lower riser package can include an inverted connector with
acoustic control back up. Those ordinarily skilled in the art
having the benefit of this disclosure realize these and a variety
of other components may be utilized within the riser package of the
present invention.
[0020] Accordingly, through the use of LBOP 20, high pressure riser
string 40, UBOP 10, and an RCH designed into the riser system, the
present invention provides the ability to utilize MPD and UBD in
deep water offshore applications. Riser string 40 and UBOP 10 act
as an extension of the wellbore for drilling operations
facilitating MPD and UBD operations. As such, the riser system
between UBOP 10 and LBOP 20 holds the same pressure as UBOP 10 and
LBOP 20, thereby creating a deepwater drilling BOP and riser system
that has the same high pressure integrity from top to bottom.
Similarly, riser string 40 can act as a very long lubricator for
pressurized well interventions by also using LBOP 20 and UBOP 10
together with an RCH for MPD, UBD, and TTRD well intervention
applications.
[0021] Referring to the exemplary embodiment of FIG. 2, the present
invention provides the ability to drill a slimmed down (top hole)
well design where an expandable intermediate liner is installed
below slim surface casing, thus saving a casing string size. An
exemplary method of the present invention will now be described.
Expandable liners, as understood in the art, are utilized in this
exemplary methodology. The well of FIG. 2 is located at a water
depth of approximately 7,500 ft, having a total depth ("TD") of
approximately 22,500 ft. Surface casing 42 and intermediate casing
44 are run and cemented prior to running the 13.5/8
inch.times.10,000 psi dual BOP/riser system 5. Generally,
intermediate casing 44 will be one API size smaller than the
typical casing run before the placing of a BOP in a conventional
well design. For example, intermediate casing 44 may be a 133/8
inch casing string, while such casing would typically be a 20 inch
casing string in a conventional well design.
[0022] After setting surface casing 42 and intermediate casing 44
(13.3/8 inch), dual BOP/riser system 5 is run. Thereafter, if
required, the next hole section is drilled with a bi-centered bit
or under-reamed to 16 inches/171/2 inches. Then, solid expandable
liner 48 is run and expanded to seal at the junction of shoe 46. In
this exemplary embodiment, expandable liner 48 is an 113/4 inch OD
solid expandable liner that when expanded has the same drift
diameter as the previously set 133/8 inch casing. This now makes
the casing shoe depth of the present invention equivalent to that
of a conventional casing design. Those skilled in the art having
the benefit of this disclosure realize that in wells that only
require four casing/liner strings to get to TD, or have a TD liner
smaller than 7 inches, the use of expandable liner may not be
necessary. Additionally, those same skilled persons realize other
casing/liner types may be utilized with the present invention. Once
expandable liner 48 is set, then all further drilling activity will
be performed as understood in the art.
[0023] Further referring to the exemplary methodology of FIG. 2, in
order to secure the 121/4 inch drift for expanded casing/liner, the
expansion system and method must be taken into account to determine
the necessary surface casing size, as would be understood by one
skilled in the art having the benefit of this disclosure. The well
can then be drilled with a 121/4 inch bit for a 95/8 inch casing
string 50 or a 95/8 inch liner string (subject to well design
criteria) at approximately 17,500 ft, for example, and finished
using a 81/2 inch hole and 7 inch production liner 52 at
approximately 22,500 ft, for example. The sizes and methods used
herein are exemplary in nature as would be understood by one
skilled in the art having the benefit of this disclosure. For
example, the systems and methods described herein can be used in
water depths less than or greater than approximately 7,500 ft.
Accordingly, the present invention allows the well to be designed
to effectively reduce the number of casing strings by using MPD or
UBD drilling technology to continually monitor subsurface pore
pressures and set casing in the appropriate subsurface pressure
regime.
[0024] The drill ship or drilling semi-submersible with identical
drilling technology functionality utilized with the present
invention will now be described. The drill ship may include various
types of equipment useful in deep water drilling. As previously
stated, an exemplary drill ship is the 145-8.times.29-31 m
DrillSLIM.TM.. Use of DrillSLIM.TM., or similar designs, allows
efficient movement around the world by the most direct routes
(e.g., through the Suez and Panama Canals and under the Bosporus
Bridge), which substantially reduces transit times and costs. The
ship's hoisting tower arrangement mounted to a deck of the drill
ship is specifically designed to telescope inward to ensure when
collapsed the top of the hoist sheaves can pass under the bridges
on the Panama and Suez canals and under the Bosphorous bridge into
the Black Sea while the drill ship is in transit draft. The
hoisting tower would include sufficient racking capacity for a full
drill string for water depths of at least about approximately 7,500
ft. As an example using approximately 7,500 ft water depth as a
basis, the heaviest load of 355 tons (T) occurs when the
approximately 7,500 ft of riser, two sets of BOP's, ancillary and
travelling equipment are run. A 500 ton hoist rating can be used to
allow some margin of safety. The hoisting tower would further
include hoisting capacity to hoist double drill pipe joints for use
in drilling wells in water depths of at least approximately 7,500
ft; a hoisting capacity to hoist casing for use in drilling wells
in water depths of at least approximately 7,500 ft; or combinations
thereof.
[0025] In addition, the drill ship can also include active pit tank
capacity to fully displace a largest hole volume over to another
mud or brine system for use in drilling wells in water depths of at
least approximately 7,500 ft; full mud treatment and cuttings
containment, with the ability to mix new mud and brine
simultaneously, for use in drilling wells in water depths of at
least approximately 7,500 ft; liquid and dry bulk storage for use
in drilling wells in water depths of at least approximately 7,500
ft; deck space and services for electric and slick line, cementing,
well testing, well simulation, coiled tubing, MPD/UBD operations,
drill cutting operations, or combinations thereof for use in
drilling wells in water depths of at least approximately 7,500 ft;
or combinations thereof. The floatable structure may further
include various combinations of the types of equipment described
herein.
[0026] For example, the active pit system can be 6,460 bbls (1027
m.sup.3) plus five treatment tanks of 60 bbls (9.5 m.sup.3) each.
The active pits can be split in half for two independent mud/brine
systems with two independent automated mud/brine mixing facilities
for concurrent operations. Liquid storage can include 9,749 bbls
(1,550 m.sup.3) of drill water, 2,139 bbls (340 m.sup.3) of base
oil, and 1,572 bbls (250 m.sup.3) of brine. Three conventional
triplex pumps with approximately 7,500 psi fluid ends can provide
for all downhole pumping operations. Solids control can be provided
by four linear motion shale shakers, a desander, a desilter, a
degasser, and space for two contractor supplied centrifuges. Solids
disposal can be via one double self cleaning screw conveyor feeding
into a big bag turntable station. Dry bulk storage can include
six.times.60 m.sup.3 tanks, (one bentonite, three barite and two
cement) with three.times.6 m.sup.3 surge tanks The cement unit can
be contractor supplied and also provide pressure testing and
emergency pumping services. Those ordinarily skilled in the art
having the benefit of this disclosure realize other types of
equipment can be used with the present invention, such as those
used in controlling mud and solids, as well as cement systems.
[0027] The exemplary drill ship may further include hoisting and
handling equipment. A single hoisting tower with a ram type hoist
having a clear working height of 120 ft for drilling, along with a
top drive and double joints of range two drill pipe, can be
included. Dead line compensation can be included for drill string
motion compensation. The hoisting tower can further include a
hydraulic racking system with setback for 22,500 ft of 5 inch drill
pipe and drill collars. A remote operated iron roughneck can be
provided on the drill floor 35 for tubular make-up and break-out. A
skidding and trolley system below the substructure can be provided
for handling and storing the two.times.135/8 BOP stacks and up to
two subsea Xmas trees. Additionally, at moon pool level, there can
be a retractable dummy riser spider trolley to hang off the BOP
while the load ring and telescopic joints are installed.
[0028] The exemplary drill ship described herein can further
include three hydraulic knuckle boom cranes: a compensated crane
rated to 120 T in port/60 T offshore for handling BOP equipment,
Xmas trees, and for construction activities; a 20 T rated crane to
serve the aft deck and mud treatment deckhouse; and a 25 T rated
crane for loading tubulars from the quay to the riser racks. The
systems and methods described herein can also include two
horizontal catwalks, one forward for riser transport and one aft
for drill pipe/casing both at drill floor 35 elevation. One gantry
crane can be installed on the riser storage area and one gantry
crane over the aft pipe storage area. A tubular handling overhead
crane and a vertical pipe elevator can be installed in the pipe
hold in the hull. Other types of hoisting and handling equipment
that can be used in the present invention will be apparent to those
of skill in the art having the benefit of this disclosure.
[0029] The exemplary drill ship described herein will also include
rotating equipment. For example, rotating the drill string can be a
500 tons AC motor driven top drive. A conventional 491/2 inch
rotary table can be fitted for tubular support and can be driven by
a hydraulic motor for limited rotational capability. Other suitable
types of rotating equipment will be apparent to those of skill in
the art having the benefit of this disclosure.
[0030] The exemplary drill ship described herein further includes
drilling tools. In an aspect, for example, approximately 22,500 ft
each of 5 inch and 31/2 inch high grade drill pipe, and ten each of
8 inch, 61/2 inch and 43/4 inch drill collars, all with handling
and fishing tools can be included. The types and amounts of
drilling tools included will vary depending upon the needs of each
system as will be apparent to those of skill in the art having the
benefit of this disclosure.
[0031] The exemplary drill ship also includes utility systems. The
electrical power system can include variable speed AC drives for
the mud pumps and top drive, with a normal drilling load of 3.0
Megawatts (MW). The hoisting system can be hydraulically powered
through a central HPU. The types and amounts of utility systems
included in embodiments of the present invention will vary
depending upon the needs of each system as will be apparent to
those of skill in the art having the benefit of this
disclosure.
[0032] The exemplary drill ship can be powered by six 4.7 MW main
diesel electric alternator sets with propulsion from five fixed
pitch, variable speed thrusters with a combined power of 17.3 MW.
The thrusters can be configured for independent and integrated
operation with the dynamically positioned vessel to IMO class 3.
All systems can be designed and installed to ensure that adequate
redundancy is maintained and that no single failure will result in
loss of positional keeping or operational performance.
[0033] The exemplary drill ship can also have an endurance of sixty
days (typically thirty days transit and thirty days dynamically
positioned), and operations can be designed to be carried out
without assistance from other vessels. The ship's service speed can
be around fourteen knots. The heli-deck can be rated for S61, S92,
EC225 & Super Puma helicopters. One 25 m burner boom can be
mounted on the port stern for flaring operations.
[0034] Using embodiments of the present invention, smaller riser
strings are used and less casing strings are necessary. As a
result, smaller drill ships can be used, in less hostile geological
and pore pressure regime environments where less casing is
required, thereby cutting conventional operating costs in half and
reducing well costs by half Conventional dual activity drill ships
have four drill crews (two well centers), while the drill ships
constructed and used in accordance with embodiments of the present
invention are expected to have only two drill crews (one well
centre). The crew rate will be +/-70% of that of the larger drill
ships. Furthermore, the all up day spread rate (including services
and fuel) for the large drill ship are expected to be in the region
of $750-$800,000/day, while the expectation for use of the systems
and methods described herein is expected to be one-half to
two-thirds that spread rate.
[0035] In addition, well intervention workovers into an existing
subsea well to move the "drainage point" in the reservoir using
TTRD technology to increase reserves base also becomes viable as
the dual BOP/riser system 5 will enable an RCH to be installed at
surface to facilitate MPD drilling technology, which is relevant
when reservoir pore pressures are in decline causing convergences
of the pore pressure-fracture gradient window. Without the high
pressure riser of the present invention, this cannot be achieved
using conventional subsea stack-marine riser systems.
[0036] An exemplary embodiment of the present invention provides a
subsea assembly for use in subsea operations, the assembly
comprising a slip joint assembly located beneath a vessel floor; a
rotating control head located beneath the slip joint assembly; an
upper blow out preventer ("UBOP") located beneath the rotating
control head; an upper stress joint located beneath the UBOP; a
riser string located beneath the upper stress joint; a lower stress
joint located beneath the riser string; a lower blow out preventer
("LBOP") located beneath the lower stress joint; and a wellhead
located beneath the LBOP. In another embodiment, the riser string
has a pressure rating that is the same as a pressure rating of the
UBOP and LBOP. In yet another embodiment, the assembly is used in
an offshore deepwater environment. In the alternative, the assembly
is adapted to perform at least one of a Managed Pressure Drilling,
Underbalanced Drilling, or Through Tubing Rotary Drilling
operation. In yet another embodiment, the riser string is sized for
running casing having an API size less than or equal to 133/8'. The
vessel may also have a length of no more than 148 meters and a
width of no more than 28 meters. In yet another embodiment, the
vessel is adapted to drill wells in water depths of at least 7,500
ft.
[0037] An exemplary methodology of the present invention provides a
method for use in a subsea operation, the method comprising the
steps of (a) providing a slip joint assembly located beneath a
vessel floor; (b) providing a rotating control head located beneath
the slip joint assembly; (c) providing an upper blow out preventer
("UBOP") located beneath the rotating control head; (d) providing
an upper stress joint located beneath the UBOP; (e) providing a
riser string located beneath the upper stress joint; (f) providing
a lower stress joint located beneath the riser string; (g) a lower
blow out preventer ("LBOP") located beneath the lower stress joint;
and (f) providing a wellhead located beneath the LBOP. In another
methodology, step (e) further comprises the step of providing the
riser string with a pressure rating that is the same as a pressure
rating of the UBOP and LBOP. In yet another methodology, the method
further comprises the step of performing the subsea operation in an
offshore deepwater environment. In another methodology, the method
further comprises the step of performing at least one of a Managed
Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary
Drilling operation. In another methodology, the method further
comprises the step of tripping a liner having an API size less than
or equal to 133/8'' through the riser string. In yet another, the
method further comprises the step of providing the vessel with a
length of no more than 148 meters and a width of no more than 28
meters.
[0038] Another exemplary embodiment of the present invention
provides a subsea assembly for use in subsea operations, the
assembly comprising an upper blow out preventer ("UBOP") located
beneath a vessel floor; a riser string located beneath the UBOP;
and a lower blow out preventer ("LBOP") located beneath the riser
string and operatively coupled to a wellhead. In another
embodiment, the riser string has a pressure rating that is the same
as a pressure rating of the UBOP and LBOP. In yet another
embodiment, a pressure rating of the UBOP, riser string, and LBOP
is at least 10,000 psi. In another embodiment, the assembly is used
in an offshore deepwater environment. In yet another embodiment,
the assembly is adapted to perform at least one of a Managed
Pressure Drilling, Underbalanced Drilling, or Through Tubing Rotary
Drilling operation. In yet another embodiment, the riser string is
sized for running casing having an API size less than or equal to
133/8''. An exemplary embodiment may also comprise a rotating
control head. In another embodiment, the vessel has a length of no
more than 148 meters and a width of no more than 28 meters. In yet
another embodiment, the vessel is adapted to drill wells in water
depths of at least 7,500 ft.
[0039] Another exemplary methodology of the present invention
provides a method for use in subsea operations, the method
comprising the steps of (a) providing a vessel having a floor; (b)
providing an upper blow out preventer ("UBOP") located beneath the
floor; (c) providing a riser string located beneath the UBOP; (d)
providing a lower blow out preventer ("LBOP") located beneath the
riser assembly; and (e) connecting the LBOP to a wellhead beneath
the LBOP. In another methodology, the method further comprises the
step of providing the riser string with a pressure rating that is
the same as a pressure rating of the UBOP and LBOP. In yet another,
the method further comprises the step of providing the UBOP, riser
string, and LBOP with a pressure rating of at least 10,000 psi. In
another methodology, the method further comprises the step of
performing the subsea operations in an offshore deepwater
environment. In yet another, the method further comprises the step
of performing at least one of a Managed Pressure Drilling,
Underbalanced Drilling, or Through Tubing Rotary Drilling
operation. In another methodology, the method further comprises the
step of tripping liner down the riser string, the liner having an
API size less than or equal to 133/8''. In yet another methodology,
the method further comprises the step of locating a rotating
control head beneath the UBOP. In another exemplary methodology,
step (a) further comprises the step of providing the vessel with
dimensions of no more than 148 meters in length and no more than 28
meters in width. In yet another, the method further comprises the
step of drilling a well at a water depth of at least 7,500 ft.
[0040] Another exemplary embodiment of the present invention
provides a subsea assembly for use in subsea operations, the
assembly comprising a vessel having a floor; and a riser string
located beneath the floor, wherein the assembly is adapted to
perform at least one of a Managed Pressure Drilling, Underbalanced
Drilling, or Through Tubing Rotary Drilling operation. In another
embodiment, the assembly further comprises an upper blow out
preventer ("UBOP") located above the riser string; a lower blow out
preventer ("LBOP") located below the riser string; and a wellhead
located beneath the LBOP. In yet another, the riser string is
adapted to withstand at least 10,000 psi.
[0041] Another exemplary methodology of the present invention
provides a method for use in subsea operations, the method
comprising the steps of (a) providing a vessel having a floor; (b)
providing a riser string located beneath the floor; and (c)
performing at least one of a Managed Pressure Drilling,
Underbalanced Drilling, or Through Tubing Rotary Drilling
operation. In another exemplary methodology, the method further
comprises the steps of providing an upper blow out preventer
("UBOP") located above the riser string; providing a lower blow out
preventer ("LBOP") located beneath the riser string; and providing
a wellhead located beneath the LBOP. In yet another, the method
further comprises the step of adapting the riser string to
withstand at least 10,000 psi.
[0042] All of the embodiments and methodologies of the present
invention disclosed and claimed herein can be made and executed
without undue experimentation in light of the present disclosure.
While the invention is susceptible to various modifications and
alternative forms, specific embodiments have been shown by way of
example in the drawings and have been described in detail herein.
However, it should be understood that the invention is not intended
to be limited to the particular forms disclosed. For example, it
will be apparent that certain components that are useful in
drilling can be substituted for the components described herein, or
additional components can be used to drill the deep water wells,
while achieving the same or similar results. Accordingly, the
intention is to cover all modifications, equivalents and
alternatives falling within the spirit and scope of the invention
as defined by the appended claims.
* * * * *