U.S. patent application number 11/901393 was filed with the patent office on 2008-05-15 for method of controlling landing strings in offshore operations.
Invention is credited to Ross John Trewhella.
Application Number | 20080110633 11/901393 |
Document ID | / |
Family ID | 39714580 |
Filed Date | 2008-05-15 |
United States Patent
Application |
20080110633 |
Kind Code |
A1 |
Trewhella; Ross John |
May 15, 2008 |
Method of controlling landing strings in offshore operations
Abstract
A method and system of operating a landing string utilized on a
floating platform. The landing string is disposed within a marine
riser, with the marine riser being connected to a subsea production
tree, and wherein the subsea production tree contains internal
conduits communicating controls through a series of stab
passageways. The method comprises providing a tubing hanger
operatively connected to the landing string, delivering hydraulic
or electrical controls from the floating platform through a control
system umbilical to a junction plate operatively attached to the
subsea production tree. The method further comprises landing the
tubing hanger into the subsea production tree, establishing control
of the tubing hanger by providing the hydraulic controls to the
tubing hanger with the series of stab passageways through the
subsea production tree, and establishing control of the completion
bottom hole assembly with the stab passageways. In the preferred
embodiment, the landing string has attached thereto a completion
bottom hole assembly that will be placed in the well.
Inventors: |
Trewhella; Ross John;
(Houston, TX) |
Correspondence
Address: |
C. Dean Domingue;U.S. Registered Patent Attorney
Perret Doise, APLC, Post Office Box 3408
Lafayette
LA
70502-3408
US
|
Family ID: |
39714580 |
Appl. No.: |
11/901393 |
Filed: |
September 17, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
11818955 |
Sep 20, 2006 |
|
|
|
Current U.S.
Class: |
166/336 ;
166/345 |
Current CPC
Class: |
E21B 33/04 20130101;
E21B 33/038 20130101 |
Class at
Publication: |
166/336 ;
166/345 |
International
Class: |
E21B 7/128 20060101
E21B007/128 |
Claims
1. A method of operating a landing string utilized on a floating
platform, with the landing string being disposed within a marine
riser, the marine riser having a first end connected to the
floating platform and a second end connected to a subsea production
tree, said subsea production tree containing internal conduits
communicating controls through a series of stab passageways, and
wherein the landing string contains a completion bottom hole
assembly, the method comprising: providing a tubing hanger
operatively connected to the landing string; delivering hydraulic
controls from the floating platform through a control system
umbilical to a junction plate operatively attached to the subsea
production tree; landing a tubing hanger attached to the landing
string into the subsea production tree; establishing control of the
tubing hanger by providing the hydraulic controls to the tubing
hanger with the series of stab passageways through the subsea
production tree; establishing control of the completion bottom hole
assembly with the series of stab passageways.
2. The method of claim 1 wherein the completion bottom hole
assembly includes a surface controlled sub-surface valve (SCSSV),
electrical gauges and chemical injection mandrels.
3. The method of claim 2 further comprising: maintaining status of
the unlatched elements during disconnect activities, wherein the
disconnect point will require hydraulic checking stabs, wherein the
hydraulic checking stabs will trap hydraulic pressure allowing the
latch to reconnect and re-establish communications.
4. The method of claim 2 further comprising: monitoring the
pressure status of the completion bottom hole assembly, wherein
pressure status is monitored with a pressure transducer, and
wherein the pressure transducer can collect and transmit data to
surface either by electrical conduit or other form of data
transmission.
5. A method of landing a landing string to a subsea production tree
from a floating platform, wherein a marine riser is attached at a
first end to the floating platform and at a second end to a blowout
preventor system (BOP system), with the landing string having a
subsea test tree and retainer valve operatively associated
therewith, and wherein the landing string has attached thereto a
tubing hanger, and wherein the tubing hanger is attached to a
bottom hole assembly, the method comprising: providing an umbilical
operatively attached to a junction plate on the subsea production
tree, wherein said umbilical is positioned on an exterior portion
of the marine riser; lowering the landing string into an interior
portion of the marine riser; landing the tubing hanger into the
subsea production tree; establishing communication with the tubing
hanger with the umbilical through stab means located within the
subsea production tree; controlling the subsea test tree, the
retainer valve and the bottom hole assembly with the umbilical.
6. The method of claim 5 wherein the subsea production tree is
connected to a subterranean well, and the bottom hole assembly
contains a completion string concentrically placed within the well
in order to produce fluids and gas from the subterranean well.
Description
[0001] This application is a Continuation-in-Part Application of my
co-pending provisional application Ser. No. 60/826,289, filed on 20
Sep. 2006 by Inventor Ross Trewhella, and entitled "Method of
Functioning and/or Monitoring Temporarily Installed Equipment
Through a Tubing Hanger".
BACKGROUND OF THE INVENTION
[0002] This invention relates to a method of controlling equipment
in offshore operations. More specifically, but without limitations,
this invention relates to a system and method of landing and
locking completions and other bottom hole assemblies with a landing
string from a semi-submersible or dynamically positioned drilling
vessel, wherein the landing string contains well control
equipment.
[0003] In the drilling and completion of wells located in bodies of
water, operators find it necessary to incorporate safety measures.
As those of ordinary skill in the art will readily appreciate, when
wells are drilled and completed to subterranean reservoirs, the
well will experience significant pressures which require
containment. The uncontrolled release of pressure from subterranean
reservoirs can lead to catastrophic damage. Hence, safety valves
and safety systems are required. In offshore applications, many
times it is necessary to secure the well due to exigent
circumstances. For example, in the case of a hurricane, an operator
may wish to shut-in the well as well as move off of location.
[0004] Various prior art devices have been employed. However, all
of the prior art devices are cumbersome, awkward and complex to
manufacture and operate. Therefore, there is a need for a system
and method of controlling an offshore well. There is also a need
for a method and system that will allow for the deployment of a
completion on a landing string, with the landing string containing
well control equipment. There is also a need for well control
equipment that is run as part of a landing string, and wherein the
landing string is run in conjunction with the running, landing and
locking of a sub-sea completion from a semi-submersible or
dynamically positioned drilling vessel.
SUMMARY OF THE INVENTION
[0005] A method of operating a landing string utilized on a
floating platform, with the landing string being disposed within a
marine riser, the marine riser having a first end connected to the
floating platform and a second end connected to a subsea production
tree, and wherein the subsea production tree contains internal
conduits communicating controls through a series of stab
passageways. In the preferred embodiment, the landing string
contains a completion bottom hole assembly. The method comprises
providing a tubing hanger operatively connected to the landing
string, delivering hydraulic or electrical controls from the
floating platform through a control system umbilical to a junction
plate operatively attached to the subsea production tree. The
method further comprises landing the tubing hanger into the subsea
production tree, establishing control of the tubing hanger by
providing the hydraulic controls to the tubing hanger with the
series of stab passageways through the subsea production tree, and
establishing control of the completion bottom hole assembly with
the stab passageways. In this embodiment, the completion equipment
includes surface controlled sub-surface valves, electrical gauges
and chemical injection mandrels.
[0006] The method may further comprise maintaining status of the
unlatched elements during disconnect activities, wherein the
disconnect point will require hydraulic checking stabs, and wherein
the hydraulic checking stabs will trap hydraulic pressure allowing
the latch to reconnect and re-establish communications. This method
of control requires that during the initial deployment (prior to
landing the tubing hanger), the operator will have no control over
device functionality (i.e. control of the various devices);
therefore, it is necessary to trap control fluid within some
chambers to lock components in preset positions. After landing the
tubing hanger, control is regained. The method may further comprise
monitoring the pressure status of the production equipment, wherein
pressure status is monitored with a pressure transducer, and
wherein the pressure transducer can collect and transmit data to
surface either by electrical conduit or other form of data
transmission.
[0007] A method of landing a landing string to a subsea production
tree from a floating platform, wherein a marine riser is attached
at a first end to the floating platform and at a second end to a
blowout preventor system (BOP system) is also disclosed. The
landing string has a subsea test tree and retainer valve
operatively associated therewith, and wherein the landing string
has attached thereto a tubing hanger, and wherein the tubing hanger
is attached to a bottom hole assembly. The method includes
providing an umbilical operatively attached to a junction plate on
the subsea production tree, wherein the umbilical is positioned on
an exterior portion of the marine riser, lowering the landing
string into an interior portion of the marine riser, and landing
the tubing hanger into the subsea production tree. The method
further comprises establishing communication with the tubing hanger
with the umbilical through stab means located within the subsea
production tree and controlling the subsea test tree, retainer
valve and bottom hole assembly with the umbilical. In this
embodiment, the subsea production tree is connected to a
subterranean well, and the bottom hole assembly contains a
completion string concentrically placed within the well.
[0008] Also disclosed is a method of operating and/or monitoring
temporarily installed equipment through a tubing hanger. The tubing
hanger is operatively associated with a subsea production tree. The
method includes delivering hydraulic or electrical controls from a
vessel through a control system umbilical, and terminating at a
junction plate mated to the subsea production tree. The production
tree provides internal conduits communicating controls through a
series of stabs. The control of the tubing hanger and other
equipment is established by landing the completion within the
production tree, which has the effect of enabling the stabs and
establishing communications with the completion equipment, and
wherein the completion equipment is typically surface controlled
sub-surface valves (SCSSV), electrical gauges and chemical
injection mandrels. The method further includes reconfiguring and
adding stabs which diverts controls up the assembly into the tubing
hanger running tool and ultimately to other equipment. By
establishing communication and control in this way, full functional
control of the devices is provided. In order to maintain status of
any unlatched elements of the system during disconnect activities
the disconnection points will require hydraulic checking stabs,
these will trap hydraulic pressure allowing the latch to reconnect
and re-establish communications. This method of control requires
that during the initial deployment prior to landing the tubing
hanger, the operator will have no control over device
functionality, and as such it will be necessary to trap control
fluids within some chambers to lock components in preset positions,
control will be regained subsequent to landing the tubing hanger.
Also, the operator may insist on monitoring pressure status, in
this instance a pressure transducer could be fitted to transmit
data to surface either by electrical conduit or other form of data
transmission.
[0009] An advantage of the present disclosure is that the system
provides means for isolated and disconnecting from a live well in
instances of severe weather or emergencies that necessitate the
vessels moving out of its safe operating/watch circle. Another
advantage is that the system meets government regulations
pertaining to containing hydrocarbons during operations, such as
during disconnecting operations. Yet another advantage is that deep
water control systems do not need to be deployed within the marine
riser.
[0010] A feature of the present system is that the there is no
umbilical in the marine riser which reduces project risk, allows
for access to the umbilical, improves rig space and reduces string
running and retrieval time. Another feature is that no annular
slick joint is required. Yet another feature is that the system and
method significantly reduces the number of thru ports required in
the system thereby reducing risk of hydraulic failure. Another
feature is that there is no risk of dropped umbilical clamps within
the marine riser.
BRIEF DESCRIPTION OF THE DRAWINGS
[0011] FIG. 1 is a well bore schematic of the preferred embodiment
of the present system.
[0012] FIG. 2 is an enlarged view of area denoted as "A" in FIG.
1.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0013] Referring now to FIG. 1, a well bore schematic of the
preferred embodiment of the present system will now be described.
As can be seen, a floating platform 2, such as a semi-submersible
drilling vessel, is positioned over a well. It should be noted that
the platform 2 may be an offshore floating platform, an anchored
vessel, or even a jack-up type of platform. A marine riser 4
extends from the floating platform 2. The marine riser 4 is
operatively connected to a subsea blow-out preventor system (BOP
system), wherein the bop system is seen generally at 6. The BOP
system 6 is made up of individual BOP components as will be more
fully set later in the description. The BOP system 6 will be
operatively connected to subsea production tree 8, and wherein the
production tree 8 will in turn be operatively connected to the
subterranean well 10. The subsea production tree 8 is adjacent the
sea bed. As very well understood by those of ordinary skill in the
art, the subterranean well 10 may be completed to a reservoir 111
for production. Hence, the inner portion of the well 10 may be
exposed to significant pressures as well as reservoir fluids and
gas.
[0014] The system of the most preferred embodiment includes a
subsea test/intervention tree 12 (hereinafter subsea test tree 12)
and a retainer valve 14 disposed within the BOP system 6. The
sub-sea test tree 12 is deployed via the landing string 16, and
wherein the landing string 16 is concentrically disposed within the
marine riser 4.
[0015] Referring now to FIG. 2, an enlarged view of area denoted as
"A" in FIG. 1 will now be described. It should be noted that like
numbers appearing in the various figures refer to like components.
As seen in FIG. 2, the subsea test tree 12 and retainer valve 14
are utilized as a temporary part of a completion running string 17,
deployed into the well 10 from the floating platform 2. The sub-sea
test tree 12 and retainer valve 14 are located within the BOP
system 6, and more particularly, above the blind rams 18 and the
pipe rams 20 of the BOP system 6. The subsea test tree 12 and
retainer valve 14 provide well isolation and unlatch function, as
well as hydrocarbon retention thereby allowing the floating
platform 2 to safely move off location in emergencies.
[0016] More specifically, the subsea test tree 12 is installed as
an integral part of the completion landing string 16 and consists
of dual fail-safe hydraulically operated ball valves. The upper
section of the subsea test tree 12 is mated to a hydraulically
actuated latch means for latching and unlatching to the landing
string 16. The latch means may be disconnected after well 10 is
isolated to allow the vessel to ride out a storm or move off of
location for any reason. The subsea test tree 12 is installed
within the BOP system 6, and in particular within the blind rams 18
and pipe rams 20 area. The subsea test tree 12 is spaced out such
that the BOP pipe rams 20 can be closed upon a subsea test tree
slick joint (i.e. the slick joint makes up part of the subsea test
tree 12) in order to provide annulus isolation, whilst also being
of a sufficient length and position that the blind/shear rams may
be closed above.
[0017] The retainer valve 14 is installed as an integral part of
the completion landing string 16 and consist of a single fail as is
hydraulically operated ball valve combined with a hydraulically
operated vent sleeve. The retainer valve 14 is designed to function
in conjunction with the unlatch feature if the subsea test tree 12
is unlatched for operational purposes. During the subsea test tree
12 unlatch procedure pressure is applied through the control
umbilical 28 from surface to initiate the subsea test tree 12
unlatching. As seen in FIGS. 1 and 2, the umbilical 28 is located
outside the marine riser 4. This pressure initially acts upon the
retainer valves ball piston to close the ball and contain the
hydrocarbons within the marine riser 4; upon achieving full stroke,
the pressure is then switched to the vent sleeve, which in turn
opens venting trapped pressure between the subsea test tree's upper
ball and the retainer valve ball. Finally, the control pressure is
passed onto the subsea test tree's 12 valve unlatch piston. An
additional feature within this valve is a "fail close" feature that
activates only when the shear sub is sheared. This will override
the "fail as-is" condition securing the pressurized hydrocarbons
contained within the landing string and preventing it from entering
the marine riser 4. Additional overrides allow the latch to be
activated without operating the retainer valve 14.
[0018] FIG. 2 also depicts the tubing hanger 22 that is operatively
attached to the tubing hanger running tool 24, wherein the running
tool 24 is operatively attached to the subsea test tree 12. At the
lower end, the tubing hanger 22 is operatively attached to the
completion string 17.
[0019] In the most preferred embodiment, the sub-sea test tree 12
and retainer valve 14 are hydraulically actuated. In the prior art,
the test tree 12 and the retainer valve 14 traditionally rely on
application and venting of hydraulic pressures supplied from either
an "in marine riser" control system and/or umbilical terminated at
the uppermost face of each valve. As seen in FIG. 2, in the most
preferred embodiment of this disclosure, the umbilical 28 is on the
outside of the marine riser 4. In prior art embodiments, the
umbilical is strapped or clamped to the tubing or casing string
that makes up the landing string and sits on the inside of the
marine riser, and as such, poses a high level of risk due to the
movement between the physical components (i.e. riser, ss test
trees, retainer valves, etc) and the sea currents which can cause
damage to the umbilical.
[0020] Referring again to the preferred embodiment depicted in FIG.
2, from the uppermost face of the assembly where the umbilical 28
is terminated (at the production tree 8?), internal porting through
the assembly will carry the control fluids (or in an alternative
embodiment, electrical conduits to transmit electrical signals) to
the various functions (i.e. components) within the retainer valve
14, subsea test tree 12, tubing hanger running tool 24, tubing
hanger 22 and ultimately devices within the completion string 17.
This requirement for a large number of connections and intricate
porting within the aforementioned devices (particularly the
retainer valve 14, sub-sea test tree 12 and tubing hanger 22)
creates multiple potential leak paths or loss of electrical
continuity for each conduit.
[0021] The tubing hanger running tool 24 is located directly below
the subsea test tree 12 and provides a facility to latch and
unlatch the landing string 16 from the tubing hanger 22. This
design allows for the temporary landing string 16 to be removed
leaving the production completion string 17 and associated
completion devices (not seen) installed and locked. According to
the invention, the tubing hanger running tool 24 can be
mechanically or hydraulically actuated. Hydraulically actuated
tubing hanger running tools receive control pressure via conduits
fed through the subsea test tree 12 and also provides conduits for
controlling the tubing hanger 22 and devices within the completion
string 17. These conduits represent multiple potential leak paths
for each conduit???
[0022] The tubing hanger 22 forms the uppermost part of the
permanent completion and facilitates the locking of the completion
into the subsea production tree 8. The tubing hanger 22 is
traditionally hydraulically operated. In the prior art, the tubing
hanger 22 receives hydraulic control pressure from the surface via
the conduits passed through the tubing hanger running tool 24, the
subsea test tree 12, the retainer valve 14 and the "in riser"
umbilical ????? It can be seen that this supply represents a
torturous path with a multiple of potential leak paths.
[0023] In the present preferred embodiment, the interface between
the tubing hanger 22 and the production tree 8 contains a series of
stabs 30, and wherein these stabs 30 facilitate the hydraulic (or
electrical in the alternative embodiment) communication between the
subsea production tree 8 and the tubing hanger 22. Control
pressures in the preferred embodiment (or electrical conduits in
the alternative embodiment) are received from the subsea production
tree 8 and then passed from the stabs 30 down the completion string
17 via a series of small-bore tubing or electrical conduits to
control the various devices that comprise the completion
string.
[0024] Referring again to FIG. 1, the control system 32 is made-up
of a power unit comprising a pump 34 and accumulators 36 combined
with hydraulic valves and regulators configured to control
hydraulic pressures feeding various hydraulically operated devices.
In the alternative embodiment, the control system 32 can regulate
and supply electrical power to feed various electrically driven
devices. The control system 32 will also generally include means
for delivering the hydraulics (or electrical power in the
alternative embodiment), and the delivering means in the preferred
embodiment is the umbilical 28 which is made up of hydraulic
control lines or a combination of hydraulic control lines. In the
alternative embodiment, the conduits may contain electrical
conduits for supply the electrical signal.
[0025] In operation, and referring collectively to FIGS. 1 and 2,
during the completion running and/or pulling, or during workover
operations, control elements (i.e. the hydraulic fluid in the
preferred embodiment, electrical signal in the alternative
embodiment) are transferred from a floating offshore installation
via a single or series of conduits (i.e. umbilical 28) to a
junction plate 38. The junction plate 38 is removable and attached
to the subsea production tree 8. It should be noted that the
production tree 8 may include, but not limited to, a horizontal or
spool type of sub-sea tree.
[0026] The junction plate 38 locks the conduit/umbilical 28 to the
subsea production tree 8 and facilitates communication to a series
of hydraulic ports/electrical conduits within the wall of the
subsea production tree 8. These ports will link to a set of
stabs/receptacles 30 located within or around the inner wall of the
subsea production tree 8 and are isolated until such time as the
mating tubing hanger 22 is landed within its bore. In operation,
the tubing hanger 22 is deployed from the rig floor of the floating
platform 2 (at the surface), through the bore of the marine riser
4, into the BOP stack 6 and landed on a location within the inner
bore of the subsea production tree 8.
[0027] Typically, a completion string 15 will be attached to the
lower end of the tubing hanger 22 and a running tool 24? attached
to the landing string 16, and wherein the well isolation devices
(namely, the subsea test tree 12 and retainer valve 14) is attached
to the upper end.
[0028] The action of landing the tubing hanger 22 within the subsea
production tree 8 will establish communication between the
aforementioned stabs/receptacles 30 and the tubing hanger 22.
Alternatively, these stabs/receptacles 30 may be energized to
engage using external forces. These established communications
provide monitoring or control to equipment located within the
completion part or lower part of the inner assembly.
[0029] As will be readily appreciated to those skilled in the art,
the present invention may easily be produced in other specific
forms without departing from its spirit or essential
characteristics. The present embodiment is, therefore, to be
considered as merely illustrative and not restrictive. The scope of
the invention is indicated by the claims that follow rather than
the foregoing description, and all changes which come within the
meaning and range of equivalents of the claims are therefore
intended to be embraced therein.
* * * * *