Title:
Method of controlling landing strings in offshore operations
Kind Code:
A1


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, US)
Application Number:
11/901393
Publication Date:
05/15/2008
Filing Date:
09/17/2007
Primary Class:
Other Classes:
166/345
International Classes:
E21B7/128
View Patent Images:
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Primary Examiner:
BEACH, THOMAS A
Attorney, Agent or Firm:
Jones Walker LLP (Baton Rouge, LA, US)
Claims:
I claim:

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:

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

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.

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.

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

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.

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.

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.

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.

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.

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

FIG. 1 is a well bore schematic of the preferred embodiment of the present system.

FIG. 2 is an enlarged view of area denoted as “A” in FIG. 1.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

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.

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.

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.

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.

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.

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.

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.

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.

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???

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.

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.

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.

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.

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.

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.

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.

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.