WO2016001630A2

WO2016001630A2 - Subsea landing string assembly

Info

Publication number: WO2016001630A2
Application number: PCT/GB2015/051829
Authority: WO
Inventors: Gavin David Cowie; John David Sangster
Original assignee: Interventek Subsea Engineering Limited
Priority date: 2014-06-30
Filing date: 2015-06-23
Publication date: 2016-01-07
Also published as: GB2540920A; WO2016001630A3; GB201411638D0; GB201620727D0; GB2540920B

Abstract

An improved landing string comprising a bypass conduit arranged to provide fluid communication between a first pressurised chamber defined between two landing string valves and a second chamber located below a BOP pipe ram. The landing string may further comprise a centraliser for reducing a gap between the landing string and a marine riser to thereby extend the fatigue lifetime of the landing string. The landing string may further comprise a valve actuation apparatus comprising a pressure generating material for operating a landing string valve such as a SSTT valve. The landing string may further compromise an explosively parting joint and/or an explosive cutter apparatus.

Description

SUBSEA LANDING STRING ASSEMBLY

FIELD The present invention relates to improvements in subsea landing strings. BACKGROUND

In subsea oil and gas operations such as intervention operations, running completions, clean-up, well testing, abandonment and the like, it is common to employ long tubulars known as landing strings.

Landing strings are typically deployed within a larger tubular known as a marine riser and extend from a surface vessel or platform to the subsea wellhead. At the vicinity of the wellhead the landing string is landed within a subsea blowout preventer (BOP).

A landing string may be used to flow fluids and/or convey tools from the surface to the wellhead and vice versa. Landing strings may also be used to deploy wellbore completion equipment and casings, into a wellbore.

A landing string may typically include a lower section which includes various valves for providing well control.

Because of the ever increasing need for offshore operations at deeper waters and harsher environmental conditions, the requirements for the design of landing strings have also been increasing. Thus there is a need for an improved landing string that exhibits an enhanced operability and/or safety envelope.

One problematic area associated with conventional landing strings relates to venting trapped fluid before unlatching the landing string. Typically, a conventional lower landing string generally consists of a tubing hanger running tool, a slick joint, a subsea test tree (SSTT) valve, a shear joint, and a retainer valve (RV). The landing string is typically deployed within a marine riser and is landed within a subsea BOP. One of the functions of the lower landing string is to have the ability to separate at a point below the BOP shear seal rams allowing the rams to close and provide a reliable seal. Due to the configuration of the lower landing string, when closing the main wellbore valves, a portion of the pressurised wellbore fluid is trapped within a chamber defined between the retainer valve and the SSTT valve, adjacent to the unlatch point. The pressure within this chamber has to be vented prior to unlatching to ensure the upper section of the landing string is not launched upwards due to the stored energy of the trapped pressurized fluid.

Existing landing strings incorporate a tool known as a vent sleeve. The vent sleeve can be opened on demand to vent the trapped fluid into a chamber within the BOP bore, whereby it can be subsequently vented back to the surface vessel or platform through one or more circulation lines commonly referred to as choke and kill lines. This practice poses some problems that need to be addressed in order to improve the safety envelope of landing string operations.

The BOP chamber into which the pressurised trapped fluid is passed lies between an annular BOP and a closed BOP pipe ram. Operators are aware that if the annular element of the annular BOP is activated once, there is no guarantee that it will retract to the fully open position thereafter. Thus, this operation may potentially damage the annular element which may have to be replaced thereafter. Also, the reliability of the annular BOP to contain the pressure of the trapped fluids may be questioned at the ever increasing deeper water operations. Another potential problem with the existing practice is that trapped fluid pressure is applied to the upper side of the closed BOP pipe ram. BOP rams are not generally designed to hold significant pressure from the reverse direction, i.e. from above. Thus, this operation may result in leakage, and/or deterioration of the pipe ram elastomers and possibly compromise the seal integrity of the pipe ram

Another problematic area for existing landing strings is fatigue performance. Of particular concern is that there is relatively little experience and limited knowledge of the fatigue life status of cyclically loaded landing string components and systems. One approach that has been proposed is to install monitoring tools to monitor the cyclical loads and to maintain records so that that the fatigue life consumed is always known. This is a rather cumbersome, expensive and uncertain approach and further improvements are needed to reduce fatigue risk due to cyclical loading on landing strings.

Yet another area for improvement relates to the various valves used in a landing string such as the SSTT valve. SSTT valves are generally configured as fail-safe- close (FSC) devices and typically mechanical springs provide the energy source required for valve closure when the primary hydraulic means are lost due to an unexpected event. There are many scenarios where spring force may be inadequate to cause full closure of the SSTT valve and the operator may then have to deliver the closure force via some other primary or secondary hydraulic arrangement. As such these known fail-safe-close devices in fact only provide closing in some but not all circumstances. Moreover, these are time consuming operations and are also dependent upon the presence of extensive infrastructure. Generally, the increased time to cause valve closure by these hydraulic means and the reliance on supporting infrastructure may result in increased risk to personnel and the environment.

US patent no. 3,122, 154 describes an explosive actuated valve.

Yet another area requiring improvements to be made, relate to landing string shear subs. A conventional landing string incorporates a shear sub which is located across the BOP shear rams when the landing string is landed within the BOP. The shear sub is a tubular component which has the very thinnest wall necessary to cope with the loads developed in the installed condition. This maximises the ability of the shear rams to cut the shear sub.

During handling of the landing string at surface, special measures must be taken to protect the shear sub from bending loads. Special braces are installed which limit the bending forces applied to the shear sub and these must be removed prior to development. This is expensive and inconvenient.

Moreover, during installation of the landing string as the shear sub passes through a BOP flex joint, the riser angle must be limited to restrict the bending loads developed in the shear sub. This is inconvenient as it restricts the opportunity for installation which adds to the expense of operations.

To confirm that the shear rams can in fact cut the shear sub a cutting trial is typically performed. This typically requires the execution of a destructive test of the shear sub assembly which is expensive and time consuming. In the event that a shear sub is cut in operations, then the end of the shear sub will be crimped over by the broadly flat edge of the cutting blades. It is difficult to engage a cylindrical fishing tool over such a profile. Additionally it is difficult to deliver fluid, such as kill mud, through such a crimped end. The act of cutting a sub thus creates situations which makes recovery more complex.

Typically shear subs are supplied with premium tubular connections at either end. Such connections are designed for broadly static service in down hole conditions. As landing string systems have matured, concern has emerged as to their fatigue capacity. The slender shear sub and its low profile, premium end connections are both designed to use the minimum possible amount of material. There is little or no excess capacity within the shear sub to provide any fatigue resistance.

Finally, there is increasing concern about the reliability of the shear rams to complete their intended function especially at harsher operational environments. Successful cutting and sealing is dependent on the presence of many features, such as accumulated hydraulic energy, control line integrity, and reliability of initiation all increasing the risk of a failure posing serious risks for the operations and the environment.

Yet another problematic area associated with conventional landing strings relates to the cutting valves used inside BOPs especially during oil well intervention operations. Existing cutting devices are generally limited in both their cutting capability and their ability to form a seal after cutting. The limited cutting capability imposes a restriction on the types of equipment which can be run through the valves. This in turn may also directly affect the maintainability and profitability of the well. SUMMARY

An aspect or embodiment relates to a landing string comprising:

a flow path;

an upper valve adapted to control fluid flow through the flow path;

a lower valve adapted to control fluid flow through the flow path;

a slick joint positioned below the lower valve, the slick joint defining a region to be sealingly engaged by a pipe ram; and

a bypass conduit arranged to provide fluid communication between a first chamber defined between said upper and lower valves and a second chamber located below the engageable slick joint region. The upper valve may be a retainer valve. The lower valve may be a SSTT valve. The lower valve may be one of more SSTT valves.

The pipe ram may be one of a plurality of pipe rams of a BOP. The pipe ram may be a middle pipe ram.

The bypass conduit may comprise one or more bypass valves also referred to as circulation valves. In use, during landing string operations fluid may be trapped on a portion or chamber of the landing string defined between the upper and lower valves when the valves are closed.

The bypass conduit allows flowing any fluid or at least venting any pressure trapped between the upper and lower valves to a second chamber located below the slick joint region within the BOP bore that is sealed by the BOP pipe ram. The fluid may then be vented to the surface vessel or platform via a BOP circulation line, for example. An aspect or embodiment relates to a method for venting fluid trapped within a first chamber of a landing string defined between an upper and a lower valve, the method comprising:

opening a bypass valve to allow the trapped fluid to flow through a bypass conduit to a second chamber located below a slick joint region engaged by a pipe ram.

The bypass conduit offers significant advantages over an existing landing string venting systems. The proposed method of venting the pressure improves the safety, reliability and robustness of the elements involved by flowing the trapped fluid to a chamber below the closed BOP pipe rams. For example, this may remove the requirement to operate the annular BOP and directs the fluid into a chamber with a reliable sealing arrangement. Also, the BOP pipe ram is not required to hold pressure from the reverse direction thus the integrity of the pipe ram elastomers is preserved. An aspect or embodiment relates to a landing string comprising a centraliser. The centraliser may be an extendable centraliser. The centraliser may be mounted to the landing string at a location below a flex joint of a marine riser system. An aspect or embodiment relates to a landing string system deployed through a marine riser and landed within a BOP, the landing string comprising a flex joint, and a centraliser positioned below the flex joint.

The use of the centraliser may reduce a gap between the landing string and the marine riser thus reducing any transverse deflection and magnitude of any corresponding bending stresses. In this manner the fatigue lifetime of a landing string may substantially improve.

The centraliser may be positioned or positionable within the BOP.

The centraliser may be positioned or positionable outside the BOP.

The centraliser may be an extendable centraliser having a first retracted configuration and a second extended configuration.

The centraliser may be an activatable centraliser which may change configuration between a retracted and an expanded or extended configuration.

The centraliser may be mounted to a landing string in a retracted configuration and remain in the retracted configuration during deployment of the landing string. Upon coupling or landing of the landing string to or within a subsea BOP the centraliser may be activated to define obtain a second expanded or extended configuration.

In this manner, the centraliser may not interfere with the deployment and installation of the landing string. However, upon activation the centraliser may obtain an extended configuration that may limit the gap between the landing string and the marine riser thus limiting any transverse deflection of the landing string due to the movement of the surface vessel or platform. In this manner the fatigue lifetime of a landing string may substantially improve.

The centraliser may thus reduce any corresponding bending stresses on the landing string and extend its operational life time. One or more centralisers may be employed.

According to one embodiment, two centralisers may be positioned around the landing string below the flex joint and outside the BOP.

According to another embodiment two centralisers are mounted around a retainer valve of the landing string. An aspect or embodiment relates to a subsea system comprising:

a subsea BOP coupled to a subsea wellhead;

a marine riser coupled at one end to the BOP and at another end to a surface vessel or platform;

a landing string deployed through the marine riser from said surface vessel or platform the landing string being landed within the BOP, the landing string comprising a flex joint; and

a centraliser mounted to said landing string at a position below the flex joint.

An aspect or embodiment relates to a centraliser, comprising:

a body;

at least one extendable arm connected to the body; and

an actuator mechanism adapted upon activation to cause the at least one extendable arm to extend and obtain an extended configuration. The centraliser may be adapted to be mounted to another body such as a landing string.

For example the centraliser may have a through bore which may fluidly coupled to a through bore of a landing string to which the centralizer may be mounted.

According to one embodiment the centraliser may have a through bore of the same internal diameter as the through bore of a landing string to which the centralizer may be mounted. This may be advantageous since the centralizer may not restrict the available space within the landing string for fluid flow or deployment of tools.

The centraliser may have in its retracted configuration, a maximum outside diameter defined by the body of the centraliser. The centraliser may have in its retracted configuration a maximum outside diameter that is equal or smaller than the outside diameter of the landing string. The body of the centraliser may be made of a rigid material such as steel, steel alloys, and/or rigid plastic materials. Other rigid materials may be used.

The body may have connections for mounting the body to another body such as a landing string.

The connections may be of any suitable type depending upon the ultimate application of the centraliser.

For example the connections may be end connections such as flanges comprising a plurality of apertures for receiving fasteners such as for example bolt and nut fasteners.

The end connections may be threaded female or male connectors for connecting with corresponding landing string connectors.

The end connections may be quick coupling connectors for ready connection and disconnection.

The at least one extendable arm may be rotatably extendable. The at least one extendable arm may be axially extendable.

The actuator mechanism may be any suitable mechanism. The actuator mechanism may comprise at least one actuator. The at least one actuator may be of any suitable type for allowing axial and/or rotational extension of the at least one extendable arm.

The at least one actuator may be a single acting hydraulic actuator. The at least one actuator may be a double acting hydraulic actuator. The actuator mechanism may comprise a ring that is freely rotatable around the centraliser body. The at least one actuator may connect the ring to the body via pin joins at either end. The actuator mechanism may comprise a link connected at one end to the at least one extendable arm via a pin joint and at another end to the actuator via another pin joint.

According to an embodiment, the centraliser may comprise:

a body;

a hydraulic actuator mounted at a first end to the body via a pivotable connection;

a ring rotatably mounted to the body via the hydraulic actuator; and at least one rotatably extendable arm connected to the ring via a link, wherein extension of the hydraulic actuator via the supply of fluid causes the ring to rotate around the body which in turn causes the at least one extendable arm to extend to an extended configuration having a maximum outer dimension greater than the outer dimension of the body. An aspect or embodiment relates to a valve actuation apparatus, comprising:

an actuation chamber;

a pressure generating material contained within the actuation chamber, wherein the pressure generating material is arranged to generate pressure within the actuation chamber upon an initiation event;

an actuation member to be displaced by the increased pressure generated within the actuation chamber; and

a transmission arrangement for transmitting the movement of the actuation member to movement of a valve member to close or open a valve. The valve actuation apparatus may be used as the primary and/or secondary actuation mechanism for closing and/or opening a valve.

The valve actuation apparatus may be used in surface or downhole installations.

The valve actuation apparatus may be used in a subsea installation. The valve actuation apparatus may be used to close one or more valves in a subsea installation such as for example a SSTT valve.

The valve actuation apparatus may be particularly advantageous in closing a SSTT valve upon loss of a primary actuation means, such as hydraulic means for closing the SSTT valve.

Known SSTT valves are equipped with a spring stack that may provide the required energy to move a valve element and cause the valve to fail safe close upon loss of hydraulic power to the primary actuation control mechanism of the valve.

The present invention valve actuation apparatus may provide a closure mechanism that offers a number of advantages over a conventional spring stack mechanism. The present invention provides a fast acting, high powered energy source which ensures sufficient energy is supplied to allow full valve closure thereby reducing the risk to personnel and the environment.

The valve actuation apparatus may be used for opening and or closing a valve.

The valve actuation apparatus may be used as a primary and/or secondary valve opening or closing mechanism.

The valve actuation apparatus may be placed advantageously at a subsea installation.

The valve actuation apparatus may be placed within tight spaces because it is compact. The valve actuation apparatus may be placed within a landing string between the BOP rams and the BOP shear rams.

The valve actuation apparatus may be placed within a landing string at a location proximate and below the SSTT latch separation point.

The valve actuation apparatus may be placed inside a subsea BOP at the vicinity of a SSTT valve. The valve actuation apparatus may be mounted on a SSTT valve.

The valve actuation apparatus, because of the capability to provide substantially instantaneous activation by use of a pressure generating material and the proximity to a valve to be acted upon, the time required to close and/or open the valve may be reduced. This may have substantial benefits in improving operations and reducing operational risks. The actuation chamber may be any chamber capable of containing the generated pressure. For example, the actuation chamber may be a pressure cylinder made of steel or a steel alloy.

The pressure generating material may be any suitable pressure generating material.

The pressure generating material may be an explosive, a propellant and/or an oxidizer.

The pressure generating material may be an oxidizer.

The pressure generating material may be a gas generating material such as an oxidiser.

The pressure generating material may generate and/or cause the expansion of a gas. Generation or expansion of a gas can result from combustion, decomposition, or oxidation or any other rapid chemical reaction resulting in generation of heat and/or production/evolution of gas. Generation of heat and/or production/evolution of gas and may be triggered by an appropriate stimulus or initiation event. The initiation event may comprise hydraulic, electrical, acoustic, electronic including but not limited to RF, and/or the like.

The signals may be transmitted via a plurality of well-known means such as for example a primary control umbilical, or hydraulic signals from a BOP.

The signal may be initiated at the surface or subsea via a remote operated vehicle (ROV). An initiation event may include one or more of; contact with another chemical (for example water, an oxidant (e.g. oxygen) or a combustible material, an acidic or a basic material); an energy input, such as an electrical energy input, a mechanical energy input, heating (for example electrical heating or heating caused by a secondary chemical reaction, such as combustion of another chemical); a pressure drop or a pressure increase.

Gas generation may for example be caused by combustion of a first chemical (e.g. consequent to ignition by an electrical energy input or a mechanical energy input), the heat generated by said combustion initiating reaction of a second chemical.

Propellant, oxidizing or explosive high-energy materials are well known in the art and may be liquid or solid. Such materials may be composed of a single chemical or may be composed of a mixture.

According to one embodiment, the pressure generating material may comprise a hydrocarbon material such as a polymer material such as a rubber material, or a high-energy polymer such as a nitrated polymer, and a chemical oxidizing agent (such as perchlorate or a nitrate material). Initiation of a gas-generating chemical reaction may be triggered by an external stimulus as mentioned above or may be stimulated by contact between the oxidizing agent and the hydrocarbon material. The pressure generating material may comprise or further comprise a reactive particulate, such as a metal powder (e.g. aluminium or magnesium).

The actuation member may be disposed within the actuation chamber. For example, the actuation member may be a piston slidably disposed within the actuation chamber which for example may be a pressure cylinder. The actuation member may be disposed outside the first actuation chamber. For example, the actuation member may be disposed within a second chamber which may be operatively connected with the first actuation chamber with a pressure communicating link that allows communication of the generated pressure to the actuation member to cause the actuation member to move.

The transmission arrangement may differ depending upon the precise configuration used. For example, the valve actuation apparatus may be used as the primary valve actuator i.e. the generated pressure may be applied directly to an actuation member that is part of the primary valve actuator. In this case the transmission arrangement may be any conventional transmission arrangement used in valve actuators to move a primary valve element.

The valve actuation apparatus may be used as a secondary actuation mechanism such as a fail close or on demand close mechanism. According to such embodiment, the transmission arrangement may comprise a hydraulic or mechanical link between the valve actuation member and the valve primary actuator.

For example, a primary valve actuator may comprise a second actuation chamber containing a second actuation member that it is actuatable via an initiation signal such as pressure, electrical, acoustic, electronic including but not limited to RF, and/or the like.

The transmission arrangement may thus for example comprise a hydraulic link for transmitting the movement of the first actuation member to the second actuation member of the primary actuator.

According to an embodiment, the first actuation member of the actuation apparatus may be mechanically connected to an override mechanism of a primary valve actuator. Thus, rather than delivering a pressurised fluid, this arrangement delivers mechanical force directly onto the primary actuator override.

An aspect or embodiment relates to a landing string comprising an explosive cutter apparatus. The explosive cutter apparatus may be mounted to a landing string, at a location proximate to an obstruction to be cut.

The explosive cutter apparatus may be mounted inside the landing string at a location proximate to an obstruction to be cut.

The explosive cutter apparatus may comprise:

a housing; and an explosive charge disposed within the housing, the explosive charge being designed to direct substantially all explosive energy upon detonation inwardly towards the obstruction to be cut. The charge may be sized to provide only sufficient energy to cause complete separation of the obstruction with a small margin of excess.

Detonation of the explosive charge may be achieved directly from a surface control system using one of a plurality of signals including hydraulic, electrical, acoustic, electronic including but not limited to RF and/or the like.

Detonation of the explosive charge may be achieved via secondary means such as the application of pressure through the BOP choke and kill lines or through the use of a tertiary system such as acoustics or RF signals.

Detonation may be dependent on other events performed in a sequence to provide maximum safety.

Alternatively, it may be desirable that the system only becomes armed in the presence or absence of pressure in a particular line.

The explosive cutter apparatus may provide a separate, compact, high powered cutting device which is capable of cutting a larger range of tooling and obstructions in the bore of the intervention systems.

The explosive cutter apparatus may enable the use previously un-deployable equipment to be considered for intervention operations because of the enhanced cutting capabilities it offers. Additionally, the use of a separate cutter preserves the integrity of the landing string valves since the operators do not have to use the valves to provide a cutting function which is potentially damaging.

The explosive cutter apparatus may be utilised as part of an automated or time sensitive well control sequence. Upon completion of the cutting of an obstruction such as wireline or coiled-tubing, the upper portion of the obstruction may then be removed, and the necessary landing string valves such as the SSTT valves may then be closed to contain the well.

According to one embodiment the explosive cutter may be employed to cut a landing string joint such as a shear sub.

An aspect or embodiment relates to a landing string comprising:

an explosively parting joint; and

an explosive charge positioned adjacent to the explosively parting joint wherein the explosive charge is designed upon detonation to direct substantially all explosive energy towards the explosively parting joint to weaken and/or separate the joint.

The explosively parting joint may be housed within a rigid tubular body.

The tubular body may include end connections for connection to the landing string.

The explosive charge may be housed outside the joint within a rigid housing. The charge may be designed to direct upon detonation substantially all explosive energy inwardly towards the joint.

The charge may be a continuous length of explosive material. The charge may be an array of individual shaped charges.

The explosively parting joint may be a landing string shear sub.

According to one embodiment the explosively parting joint may be a landing string shear sub, and the explosive charge may be positioned below the shear rams so that the plane of separation may lie below the shear rams. This ensures that once separation is completed and the upper fish is removed then the shear rams can close without obstruction. By not employing the shear rams to do the cutting it is ensured that the shear rams may effect a full seal upon closing.

According to one embodiment the explosively parting joint may be or comprise or be an explosively parting bolt. According to an embodiment the explosively parting or separating joint may comprise an array of explosively parting bolts joining a flanged type connection, whereby detonation of the explosive charges causes the bolts to shear and disconnect the flanged connection.

The use of the explosively parting joint may be advantageous because it may leave a clean interface thus facilitating subsequent re-entry and fishing operations.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other aspects will now be described, by way of example only, with reference to the accompanying drawings, in which:

Figure 1 shows a simplified schematic of a conventional landing string;

Figures 2 to 5 show a simplified schematic of a conventional landing string and a conventional venting sequence prior to unlatching the landing string;

Figures 6 to 12 show a simplified schematic of an improved landing string and an improved venting sequence prior to unlatching the landing string, according to an embodiment of the present invention; Figures 13 and 14 show a simplified schematic of a conventional landing string as it is being installed within a BOP;

Figure 15 shows a simplified schematic of an improved landing string according to an embodiment of the present invention;

Figure 16 shows a simplified schematic of a centraliser in a retracted configuration according to an embodiment of the present invention;

Figure 17 shows a simplified schematic of a centraliser in an extended configuration according to an embodiment of the present invention; Figures 18 and 19 show a simplified schematic of a valve actuation apparatus in a first in a first non-actuated configuration and a second actuated configuration respectively, according to an embodiment of the present invention; Figures 20 and 21 show a simplified schematic of a valve actuation apparatus in a first non-actuated configuration and a second actuated configuration respectively, according to an embodiment of the present invention;

Figures 22 and 23 show a simplified schematic of a valve actuation apparatus in a first non-actuated configuration and a second actuated configuration respectively, according to an embodiment of the present invention;

Figure 24 shows a simplified schematic of an improved landing string comprising a valve actuation apparatus according to an embodiment of the present invention;

Figure 25 shows a simplified schematic of an improved landing string comprising an explosive cutter apparatus according to an embodiment of the present invention;

Figure 26 is an enlarged view of a section of the landing string proximate the explosive cutter according to an embodiment of the present invention;

Figure 27 shows a simplified schematic of an improved landing string comprising an explosive shear sub joint according to an embodiment of the present invention; Figure 28 shows an enlarged simplified schematic of an explosive shear sub joint according to an embodiment of the present invention; and

Figure 29 shows a simplified schematic of a flanged joint comprising an array of explosively parting bolts according to an embodiment of the present invention.

DETAILED DESCRIPTION OF THE DRAWINGS

Referring to Figure 1 , a simplified schematic of a lower section of a typical landing string 1 is shown deployed through a marine riser 5 and landed within a typical blowout preventer stack ("BOP") generally designated by numeral 3. The lower landing string generally consists of a tubing hanger running tool 27, a slick joint 20, a SSTT valve 19, a shear joint 15, and a retainer valve (RV) 11. Other well- known components are also shown such as a XT connector 33 and re-entry spool 31.

The BOP comprises both an annular BOP 9 and a ram BOP comprising a shear ram 13, and a plurality of pipe rams, i.e. an upper pipe ram 21 , a middle pipe ram 23 and a lower pipe ram 25. One of the functions of the lower landing string is to have the ability to separate at a SSTT latch 17 located below the BOP shear ram 13, allowing the shear ram 13 to close and provide a reliable seal. Due to the configuration of the lower landing string 1 , when closing the main wellbore valves, a portion of the pressurised wellbore fluid is trapped adjacent to the unlatch point 17 within a landing string section defined between the RV 1 1 and the SSTT valve 19. The pressure of the trapped fluid should be vented prior to unlatching the landing string 1 to ensure that the upper section of the landing string is not launched upwards due to the stored energy.

Referring now to Figures 2 to 5, a conventional landing string venting system and its operation will be described. A conventional landing string typically incorporates a vent sleeve 47 that may be opened on demand to vent the trapped fluids of pressurised chamber 45 into the BOP bore, whereby it can be subsequently vented back to a surface vessel (not shown) through a circulation line 39 commonly known as choke and kill line.

As shown in Figure 2, when venting is initiated, the upper and lower SSTT valves 19b and 19a, respectively, and the RV 1 1 are closed and the vent sleeve 47 is opened. As a result, the pressure between the RV 11 and the upper SSTT valve 19b is vented into the BOP bore. The vented pressure is held between the closed annular BOP 9 and the closed middle pipe ram 23. This may be problematic, because annular BOP's are not normally rated to the full working pressure of the BOP. Moreover, the middle BOP pipe ram 23 may be subjected to a substantial pressure differential in the non-preferred direction which may damage its sealing elements. An isolation valve 37 on the upper circulation line 39 is then opened to vent the retained pressure in the BOP bore to the surface via the upper circulation line 39 as shown in Figure 3. The pressure between the RV 11 and the SSTT upper valve 19b is fully vented as shown in Figure 4. Once the pressure is fully vented, it is then safe to release the SSTT latch 17 to unlatch and raise the upper portion of the lower landing string 1 clear of the BOP shear ram 13 as shown in Figure 5.

The aforementioned procedure is accepted practise however it may present the operators with a number of problems.

For example, the BOP chamber into which the pressure and bore fluid is vented lies between the annular BOP 9 and the closed middle BOP pipe ram 23.

With regard to utilising an annular BOP, operators are aware that if you activate the annular element of the annular BOP, there is no guarantee that it will retract to the fully open position thereafter. This may damage the annular element and may have to be replaced.

Also in terms of reliability, the annular BOP is a flexible, variable bore device, designed to provide some sealing on a variety pipes having different outside diameter (OD) rather than provide high integrity sealing which may be demanded in today's operation.

Another problem of a conventional venting method may be that the vented pressure is applied to the upper side of a closed BOP pipe ram. BOP rams are not generally designed to hold significant pressure from the reverse direction, i.e. from above. This may cause leakage, deterioration of the ram elastomers and possibly compromise the seals.

Referring now to Figures 6 to 12, an improved landing string apparatus designated generally with numeral 100 and its operation will be described. Figures 6 to 12 employ many features that are identical or similar to features shown in Figures 1 to 6. For simplicity and ease of reference, common or similar features are denoted with the same numerals as in Figures 1 to 6 augmented by 100.

The landing string 101 , as shown in Figure 6, is deployed within a marine riser 105 and landed within a subsea BOP generally designated with numeral 103. The landing string 101 comprises a RV 1 11 and a SSTT valve 119 comprising an upper, a middle, and a lower SSTT valve 119b, 1 19c and 1 19a, respectively. The landing string 101 further comprises a slick joint 155 positioned below the lower SSTT valve 1 19a. The slick joint 155 defines a surface that may be engaged by a middle pipe ram 123.

The landing string 101 further comprises a bypass conduit or circulation loop 153 connecting pressurized chamber 145 defined between the upper SSTT valve 119b and the RV 1 11 to a BOP chamber located below the slick joint surface that is engageable by the closed middle BOP pipe ram 123.

The bypass conduit comprises an upper SSTT circulation valve 149 and a lower SSTT circulation valve 151.

Figure 6 shows the configuration of all the main valves before the venting operation may commence. Specifically, the main landing string bore is pressurized while all main bore valves are open while the SSTT circulation valves 149 and 151 are closed and the BOP middle pipe ram 123 is closed around the SSTT slick joint 155.

In use, before unlatching the landing string 101 , all SSTT valves 1 19a, 119b and 1 19c and the RV 1 1 1 are first closed as shown in Figure 7 resulting in trapping fluid inside the landing string section 145 between the upper SSTT valve 119b and the RV 11 1. Then the SSTT circulation valves 149 and 151 are opened and the pressure between the RV 1 11 and the upper SSTT valve 119b is vented via the bypass conduit 153 into the BOP bore below the closed middle pipe ram 123 as illustrated in Figure 8.

Figure 9 shows an enlarged view of the bypass conduit 153 and related circulation valves 149 and 151. The circulation outlet valve 151 is located below the middle pipe ram sealing position ensuring any trapped pressure is vented in a controlled BOP chamber below the BOP sealing position. As shown in Figure 10, the isolation valve 141 is then opened to vent the retained pressure in the BOP chamber to the surface via line 143. The isolation vale 141 may remain open until all trapped pressure is fully vented as shown in Figure 11. With the pressure fully vented, the isolation valve 141 and the circulation valves 149, 153 may be closed and then may the SSTT latch 1 17 be safely released to disconnect and raise the upper portion of the lower landing string 101 clear of the BOP shear ram 113 as shown in Figure 12.

Another problem associated with subsea landing strings is landing string fatigue due to the bending stresses exerted on the landing string as a result of the movement of the surface vessel or platform such as a dynamic mobile offshore drilling unit (MODU) holding the landing string. The landing string may be subjected to such bending forces both during deployment and after installation during operations. The present invention provides a landing string centralizer which does not interfere with the deployment of the landing string through the marine riser and its positioning within the subsea BOP.

Referring now to Figure 13 a simplified schematic of a conventional lower landing string 201 is shown as it is being deployed through a marine riser 205 and positioned within a subsea BOP generally designated with numeral 203.

At its bottom end the lower landing string 201 connects to the completion tubing and the tubing hanger 229. The landing string 201 is run through the marine riser 205 into the subsea BOP 203 until the tubing hanger 229 lands inside a subsea wellhead or Xmas tree 231.

During this operation the lower landing string passes through a flex joint 207 at the top of the BOP 203. The flex joint 207 maintains the connection between the marine riser 205, which is suspended from a MODU (not shown), and the marine BOP 205 which is fixed to the seabed wellhead 231. The flex joint 207 maintains the continuity of the conduit whilst allowing the riser 205 to subtend a modest angle to the BOP 203 as shown in Figure 14. When the lower components of the lower landing string 201 enter the BOP 203, they typically engage closely with the bore of the BOP 203. This essentially establishes the bottom end of the lower landing string as concentric with the BOP bore and permits it to move essentially only axially within the BOP 203. During the installation phase, the lower landing string 201 is located both within the BOP 203 and the marine riser 205 which may be offset at the aforementioned modest angle. If the lower landing string components were a close fit to the BOP 203 and the marine riser 205 then the landing string would be forced to adopt the prevailing angle of the marine riser.

Thus, it is advantageous that the upper components of the lower landing string have bodies with reduced outside diameters. This reduction in diameter allows larger flex joint angles to develop before the drilling riser contacts the surfaces of the upper components of the lower landing string. The reduced diameter therefore increases the available operational installation window or alternatively reduces the prevailing deflection and stress within the lower landing string for installation at a given flex joint angle.

Once the lower landing string 201 is entirely within the BOP 203 and the system is landed out, the reduced diameter of the upper components is a disadvantage. In this installed condition, the bottom end of the lower landing string 201 essentially becomes fixed in place by the activation of the tubing hanger locking system and/or the BOP pipe rams 123 closing on the slick joint. The top end of the lower landing string with its reduced OD components is a relatively loose fit inside the BOP 203. The lower landing string 201 is of course still directly connected to the MODU via the high pressure riser (205). Riser systems (both drilling and high pressure) are subject to transverse reciprocating movement as a result of the action of the MODU and the effects of current.

The clearance between the reduced OD of the top components and the bore of the marine BOP allows a greater bending deflection to occur within the lower landing string components. This bending may be distributed along the length of the lower landing string, between the deflected upper end and the lower end. This results in the development of undesirable bending stresses.

Although relatively small in magnitude, there is increasing concern within the industry that the cyclical nature of theses bending stresses may contribute to a fatigue failure of the lower landing string.

It is an object of the current invention to maintain the advantages (larger installation angle/reduced installation stresses) of the reduced OD lower landing string components but to overcome the disadvantages (allows deflection and stress in the installed condition). The invention provides an improved landing string as shown in Figure 15 comprising two activatable centralisers 208, 210 mounted to the RV 211. Each centralizer remains collapsed during installation and is expanded once the lower landing string 201 is fully installed. In the expanded condition the centraliser substantially limits the deflection of the top end of the lower landing string and thereby effectively eliminates the bending stress and its associated fatigue concerns.

Referring to Figure 16, a landing string centraliser 300 is shown in its retracted configuration according to an embodiment of the present invention. The centralizer 300 comprises a body 308 with a through bore 309 and end connections 311 for unitising the centraliser with adjacent components. End connections 311 include a plurality of apertures 312 for receiving bolt and nut fasteners. Rotationally extendable arms 307 are attached via pin joints (not shown) to the outside of the body 308. A link 305 is connected at one end via a pin joint 313 to a corresponding arm 307 and at its other end via a pin joint 315 to a ring 393.

A double acting hydraulic actuator 302 connects the ring 303 back to the body 308, also employing pin joints 317 at either end.

In a first position, as shown in Figure 16, the hydraulic actuator 302 is retracted, establishing the ring 303 in a first position in which the links 305 lie broadly tangentially to the maximum outside diameter (OD) of the body defined by the end connections 311 and the arms 307 are in a retracted configuration. In the retracted configuration, the arms 307 may be within a maximum diametric envelope defined by the body and may correspond to a reduced dimension or OD configuration.

Fluid may be supplied to the hydraulic ram 319 to cause it to extend and force the ring 303 to rotate around the OD of the body 308. As a result of the rotation of the ring 303 the links 305 are displaced and the arms 307 rotate around their respective pin joints with the body 308 to extend and establish an increased dimension or OD at multiple points around the circumference of the centralizer 300.

In use with a landing string, the landing string comprising one or more centralizers may be deployed within a marine riser and be coupled with the subsea BOP with the centralizer being at its retracted configuration. Once the landing string is fully installed and landed out within the BOP the centralizer may be activated to obtain its extended configuration.

The centralizer in its extended configuration reduces the gap between the landing string and the BOP to thereby limit the transverse deflection and magnitude of any corresponding bending stresses. Thus a substantial improvement in fatigue life may be achieved.

One or more centralizers may be employed. The position of the centralizer may vary but should be below the flex joint of a marine riser so as not to interfere with the operation of the flex joint.

According to the embodiment shown in Figure 15, two centralizers 210 and 208 may be employed and positioned at a top end of the lower landing string immediately below the flex joint 207 around the RV 21 1 as shown to establish a two point contact arrangement. Such arrangement may substantially reduce or prevent the landing string 201 rotating (in elevation) within the BOP 203.

Many variations of the centralizer may be implemented by a skilled person after having read the present disclosure without departing from the scope of the present invention.

For example, according to another embodiment, the arms of the centralizer may be aligned to move in an axial plane as opposed to a horizontal plane.

The centralizer may have one or more arms. According to a particular embodiment the centralizer comprises three rotating arms.

A further variation would be to utilise a single acting, spring return hydraulic actuator as this would require only one control line.

Referring now to Figure 18 to 24 yet another improved landing string assembly is provided, the landing string assembly comprising a valve actuation apparatus that may provide an alternative or primary close mechanism for a SSTT valve of the landing string. It should be understood however, that the valve actuation apparatus may also be used with any other type of valve employed not only in subsea installations but also in surface or downhole installations. Referring now to Figures 18 and 19 a simplified schematic of the valve actuation apparatus 400 and its operation is provided according to one embodiment of the invention.

The apparatus 400 comprises a cylinder 403 having a piston 405 slidably disposed therein. The piston 405 divides the cylinder 403 into first and second chambers 403a and 403b. First chamber 403a comprises a gas generating material 401 and a detonator 409 for igniting the gas generating material. The detonator 409 may be in contact with the gas generating material 401 and may be mounted on a wall of the first chamber cylinder 403a as shown in Figure 18. However, the positioning and operational principle of the detonator may vary.

A seal 407, such as an O-ring, is arranged at the interface between the piston 405 and the internal wall of the cylinder 403 for ensuring fluid isolation between the first and second chambers 403a and 403b of the cylinder 403.

In the embodiment, shown in Figures 18 and 19, there is no intermediate, valve actuator present, i.e. the valve actuation apparatus 400 is directly connected to the valve control mechanism. The gas generating material is the sole source of energy available for closing the valve and it acts directly on the valve to cause closure as shown diagrammatically in Figure 19.

In use, the detonator ignites the gas generating material which almost instantaneously generates sufficient gas to cause the piston 405 to be displaced and act directly upon a valve closing element or mechanism generally designated by the line 416.

Alternatively, the second chamber 403b may be the closed chamber of a conventional primary valve actuator and the gas generating material may act as a secondary energy source for generating the energy required for closing the valve 415 in circumstances where the primary energy source for operating the primary valve actuator is lost. Referring now to Figures 20 and 21 another embodiment of the valve actuation apparatus is provided. Specifically, Figure 20 is a simplified schematic of a valve actuation apparatus 500 according to an embodiment of the present invention. The apparatus 500 comprises a first cylinder 503 having a first piston 505 slidably disposed therein. The first piston 505 divides the first cylinder 503 into a first chamber 503a comprising a gas generating material 501 and a second chamber 503b comprising a hydraulic fluid 51 1. A seal 507, such as an O-ring, may be arranged at the interface between the first piston 505 and the internal wall of the first cylinder 503 for ensuring fluid isolation between the two chambers 503a and 503b of the first cylinder 503.

A detonator 509 may be mounted on a wall of the first cylinder 503. The detonator 109 may be in contact with the gas generating material 501. The positioning and operational principle of the detonator may vary.

The apparatus 500 may be connected via a hydraulic line 521 to a primary valve actuator generally designated with numeral 520.

The primary valve actuator 520 may be any of many well-known valve actuators. For example, the primary valve actuator 520 may comprise a second cylinder 513 having a second piston 517 slidably disposed therein. The second piston 517 may divide the second cylinder 513 into a second chamber 513a comprising hydraulic fluid 51 1 and a second chamber 513b containing hydraulic fluid 514. Hydraulic fluids 51 1 and 514 may differ or may be the same.

The second cylinder 513 and chamber 513b may be part of a primary actuator designed to close the valve 515 under normal operations.

A seal 519, such as an O-ring, may be arranged at the interface between the second piston 517 and the internal wall of the second cylinder 513 for ensuring fluid isolation between the two chambers 513a and 513b of the second cylinder 513. The first chamber 513a of the second cylinder 513 may be operatively connected with the second chamber 503b of the first cylinder 503 via a first hydraulic line 521. A valve 515 may be operatively connected to the fluid 514 via a second hydraulic line 516. Referring now to Figure 21 , the detonator 509 may be activated and cause the gas generating material to generate gas 502. As a result a high pressure develops practically instantaneously inside the first chamber 503a of the first cylinder 503 that is acting on the first side 507a of the piston 507 forcing the first piston 507 to move to a second position 503d as shown in Figure 21.

The first piston 503, may thus displace the pressurised hydraulic fluid 51 1 out of the second chamber 503b of the first cylinder 503a, through the hydraulic line 521 into the primary valve actuator 520 to provide the necessary energy to cause the closing of the valve 515.

For example, the pressurised hydraulic fluid may be directed through the hydraulic line 521 into the first part 513a of the second cylinder 513 to cause the second piston 517 to act upon a valve closing element generally designated by line 516 to cause the valve 515 to close.

The actuation apparatus may be supplementary to a primary control system employing direct hydraulic controls which may also deliver fluid to, and vent fluid from, the same valve actuator.

In order for this supplementary system to work properly, it may be necessary to block the primary close chamber control line and vent the primary open chamber control line. Such an arrangement is known in the art and typically utilises the pressure developed in the supplementary system to actuate control valves located in the primary lines to the aforementioned blocked and vented condition.

Thus, fast acting, high power energy is supplied to the valve actuator and valve closure results.

Another embodiment of the valve actuation apparatus is provided in a simplified schematic in Figures 22 and 23. Figures 22 and 23 employ many common or similar features with the embodiment of Figures 20 and 21. For simplicity and for ease of reference any common or similar features are denoted using the same numerals used in Figures 20 and 21 augmented by 100. In the embodiment illustrated in Figures 22 and 23, the piston of the supplementary system 600 is mechanically connected via a coupling member or mechanism 651 to an override member or mechanism 652 of a primary valve actuator 620. Rather than delivering pressurised fluid as in the embodiment of Figures 20 and 21 , this arrangement delivers a mechanical force directly onto the actuator override. The resulting actuated condition is shown in Figure 23. Multiple means of initiating detonation may be employed.

For example, hydraulic and/or electrical signals may be provided or removed through the primary control umbilical. If the umbilical is not available, then hydraulic signals may also be provided via the BOP.

The signal may be provided via acoustics or RF means initiated at the rig or an ROV. These are independent of hydraulics and therefore do not require any of the hydraulic infrastructure to be present in order to work.

The present invention valve actuation apparatus is particularly advantageous in the field of in-riser intervention wherein the valve/actuator combination must be sufficiently compact that it can be installed in the bore of the drilling BOP. In the case of SSTT valves, there is a further constraint on the available envelope as they must typically be located entirely between the BOP pipe rams and shear rams.

The confined envelope then restricts the bore size and pressure rating which can be achieved by the SSTT design. Generally, larger bore sizes and higher pressure ratings will mandate the provision of higher forces from the pressure generating source. Inconveniently, the larger the bore size, the less room remains available for the provision of the pressure generating source. Additionally inconvenient is that the provision of increased pressure capacity typically mandates thicker housings, which again leaves less room available for the pressure generating source.

This limitation on available envelope has profound and disadvantageous effects, for existing fail safe close (FSC) mechanisms used for ball valves actuated by cylindrical pistons. First, it may limit the offset of the element (typically a slider) which connects the piston and ball and thereby it may reduce the torque it develops. Second, it may limit the available volume and hence the potential energy capacity of the springs. The consequence of this conflict is that the energy source becomes a compromise, unable to provide the requisite force to ensure closure in all conditions. The present invention valve actuation apparatus overcomes these disadvantages of existing FSC systems. The present invention valve actuation apparatus provides a compact, high powered energy source which may provide the requisite closure force in all conditions. Referring to Figure 24, an improved landing string is provided comprising a valve actuation apparatus 400 mounted to a SSTT valve 269 below the SSTT latch 267. Many features shown in Figure 24 are identical or similar to the features shown in Figure 15. For simplicity and ease of reference such features are denoted by the same numerals augmented by 50.

The present invention apparatus may be used with any types of valves.

The present invention apparatus may be used with ball valves.

Fail safe closure of ball valves may be particularly problematic with existing spring stack designs. Many ball valves are actuated by applying an axial force tangentially to a spherical member which produces both a turning torque and a contact force between the spherical member and the valve seat. Ball valves actuated in this way are subject to binding incidents under certain frequently encountered conditions wherein the restraining effect of the contact force may often be greater than the torque developed. Application of excessive force due to binding may break the connecting element. Even previously improved valves which are rotated at a smaller diameter than the seat typically may suffer from similar problems under certain operational scenarios e.g. when closing in flow and cutting obstructions. It is evident that in these most onerous operating conditions that the so called improvement is not in fact available.

Thus, the ability of the present invention valve actuation apparatus to independently initiate a locally available valve closure energy source is advantageous

Yet another aspect of the present invention is directed to a compact, high powered cutting device which may cut a larger range of tooling, conveyances and or other obstructions in the bore of the intervention systems.

The cutting device may be used in conjunction with a landing string and may provide a separate primary or a secondary means for cutting through tooling, conveyances and or other obstructions. The cutting device because of its enhanced cutting capability may enable previously un-deployable equipment to be considered for intervention operations. Additionally the present invention cutting device may preserve the integrity of the valves and enable them to provide improved sealing integrity as they would not be used to provide the cutting function which may be potentially damaging.

The cutting device may be used as part of an automated or time sensitive well control sequence. The device may require the upper portion of the obstruction to be removed before any valves could then be closed to effect well containment.

Nevertheless, the provision of an enhanced cutting capability only is of significant benefit for well operations.

Referring now to Figures 24 and 25, an embodiment of the cutting device 700 will be described. Many features in the Figures 24 and 25 are identical or similar to the features used in Figures 6, and for simplicity and ease of reference these features are denoted using the same numerals as in Figure 6 augmented by 600.

Specifically the cutter device 700 may be mounted to a landing string 701 and positioned within the BOP 703 below the middle pipe ram 725. The cutting device comprises an explosive charge 706. The charge 706 is designed such that, once detonated, its explosive energy is directed inwards towards the bore and onto any obstruction present.

The charge 706 may be sized such that only sufficient energy is provided to cause complete separation of the obstruction, with a small margin of excess. The charge 706 may be positioned within a housing 708 capable to contain the energy of the explosion to simultaneously provide pressure containment and structural continuity for the intervention system.

Detonation or initiation of the explosive charge 706 may be directly controlled from a surface control system, via secondary means such as the application of pressure through the BOP choke and kill lines, if present or through tertiary systems such as acoustics or RF signals.

Detonation may be dependent upon the performance of other events in a sequence to provide maximum safety. Alternatively, it may be desirable that the system only becomes armed in the presence or absence of pressure in a particular line. Figure 25 shows the explosive bore cutter device 700 installed in a landing string system. Figure 26 is an enlarged view additionally showing the presence of an obstruction 710 which is to be cut. Referring now to Figure 27, a further aspect of the present invention is shown comprising a landing string 801 having an explosive shear sub joint 1 generally designated with numeral 810. The explosive joint 810 is housed in a strong tubular body 820 with stout end connections 830 as better shown in Figure 27. The explosive joint is equipped with an explosive charge 840 designed to cut through the wall of the joint when it is detonated. The charge 840 is located on the outside of the joint and housed in a thick structural housing 860.

The charge 840 may be a continuous length of an explosive material or an array of individual shaped charges. Control lines 850 conveying fluid from the control system to the SSTT latch may be located in the path of the charge and will be cut simultaneously with the housing.

Moreover, by proper positioning of the charges, it can be ensured that the plane of separation is located below the shear rams 813. This may ensure that once separation has completed and the upper fish has been removed that the shear rams can close without obstruction. The fact that the shear rams have not been required to cut improves the likelihood of them achieving a full seal. Detonation of either embodiment may be directly from the control system, via secondary means such as the application of pressure through the BOP choke and kill lines or through a tertiary system such as acoustics or RF signals. Detonation may be interlocked with other events in a sequence to provide maximum safety. For example, it may be desirable to ensure that the retainer valve is closed prior to initiating separation. Alternatively, it may be desirable that the system only becomes armed in the presence or absence of pressure in a particular line.

With reference to Figure 29, another embodiment of an explosive joint is shown, whereas an array of explosively separating bolts 910 is utilised to join a flanged type connection 920. The charges 930 may comprise a continuous length of an explosive material or an array of individual shaped charges. The use of the explosive joint may be advantageous as it may leave a clean interface for subsequent re-entry and fishing operations.

It should be understood that the embodiments described herein are merely exemplary and that various modifications may be made thereto, without departing from the scope of the present invention.

Claims

1. A landing string comprising:

a flow path;

an upper valve adapted to control fluid flow through the flow path;

a lower valve adapted to control fluid flow through the flow path;

a bypass conduit arranged to provide fluid communication between a first chamber defined between said upper and lower valves and a second chamber located below the engageable slick joint region.

2. The landing string as claimed in claim 1 , wherein the upper valve is a retainer valve.

3. The landing string as claimed in claims 1 or 2, wherein the lower valve is one or more SSTT valves.

4. The landing string as claimed in any of the preceding claims, wherein the pipe ram is one of a plurality of pipe rams of a BOP.

5. The landing string as claimed in any of the preceding claims, wherein the pipe ram is a middle pipe ram of a BOP comprising an upper pipe ram valve, a middle pipe ram valve and a lower pipe ram valve.

6. The landing string as claimed in any of the preceding claims, wherein the bypass conduit comprises one or more bypass valves.

7. The landing string as claimed in any of the preceding claims further comprising a centraliser.

8. The landing string as claimed in claim 7, wherein the centraliser is an extendable centraliser.

9. The landing string as claimed in claims 7 or 8, wherein the centraliser is mounted to the landing string at a location below a flex joint of a marine riser system.

10. The landing string as claimed in any of the claims 7 to 9, wherein the centraliser is positioned or positionable within a BOP.

1 1. The landing string as claimed in any of the claims 7 to 9, wherein the centraliser is positioned or positionable outside the BOP.

12. The landing string as claimed in any of the claims 8 to 1 1 , wherein the extendable centraliser has a first retracted configuration and a second extended configuration.

13. The landing string as claimed in claim 12, wherein the extendable centraliser is an activatable centraliser changing configuration between a retracted and an expanded or extended configuration.

14. The landing string as claimed in any of the claims 7 to 13, wherein one or more centralisers are employed.

15. The landing string as claimed in any of the claims 9 to 14, comprising two centralisers positioned around the landing string below the flex joint.

16. The landing string as claimed in claim 15, wherein the two centralizers are positioned outside the BOP.

17. The landing string as claimed in any of the claims 7 to 16, comprising two centralisers mounted around a retainer valve of the landing string.

18. A subsea system comprising:

a subsea BOP coupled to a subsea wellhead;

a marine riser coupled at one end to the BOP and at another end to a surface vessel or platform; and

a landing string as claimed in any of the claims 1 to 17 deployed through the marine riser from said surface vessel or platform and landed within the BOP.

19. The landing string as claimed in any of the claims 1-17, the landing string deployed through a marine riser and landed within a BOP.

20. A method for operating a landing string comprising:

mounting a centraliser to a landing string in a retracted configuration;

keeping the centraliser in the retracted configuration during deployment of the landing string through a marine riser;

coupling the landing string to or within a subsea BOP; and activating the centraliser to obtain a second expanded or extended configuration.

21. A centraliser comprising:

a body;

at least one extendable arm connected to the body; and

an actuator mechanism adapted upon activation to cause the at least one extendable arm to extend and obtain an extended configuration.

22. The centraliser as claimed in claim 21 , wherein the centraliser is adapted to be mounted to a landing string.

23. The centraliser as claimed in claims 21 or 22, wherein the centraliser has a through bore fluidly coupled to a through bore of a landing string to which the centralizer is mounted.

24. The centraliser as claimed in any of the claims 21 to 23, wherein the centraliser has a through bore of the same internal diameter as the through bore of a landing string to which the centralizer is mounted.

25. The centraliser as claimed in any of the claims 21 to 24, wherein the centraliser has in a retracted configuration a maximum outside diameter defined by the body of the centraliser.

26. The centraliser as claimed in any of the claims 21 to 24, wherein the centraliser has in a retracted configuration a maximum outside diameter that is equal or smaller than the outside diameter of the landing string.

27. The centraliser as claimed in any of the claims 21 to 26, wherein the body of the centraliser is made of a rigid material comprising steel, steel alloys, and/or rigid plastic materials.

28. The centraliser as claimed in any of the claims 21 to 27, wherein the body of the centraliser has connections for mounting the body of the centralizer to another body.

29. The centraliser as claimed in claim 28, wherein the connections are end connections.

30. The centraliser as claimed in claim 29, wherein the end connections are threaded female or male connectors for connecting with corresponding landing string connectors.

31. The centraliser as claimed in claim 29, wherein the end connections comprise quick coupling connectors for ready connection and disconnection.

32. The centraliser as claimed in any of the claims 21 to 31 , wherein the at least one extendable arm is rotatably extendable.

33. The centraliser as claimed in any of the claims 21 to 33, wherein the at least one extendable arm is axially extendable.

34. The centraliser as claimed in any of the claims 21 to 33, wherein the actuator mechanism comprises at least one actuator.

35. The centraliser as claimed in claim 34, wherein the at least one actuator allows axial and/or rotational extension of the at least one extendable arm.

36. The centraliser as claimed in any of the claims 34 or 35, wherein the at least one actuator comprises a single acting hydraulic actuator.

37. The centraliser as claimed in any of the claims 34 or 35, wherein the at least one actuator comprises a double acting hydraulic actuator.

38. The centraliser as claimed in any of the claims 21 to 37, wherein the actuator mechanism comprises a ring that is freely rotatable around the centraliser body.

39. The centraliser as claimed in any of the claims 34 to 38, wherein the at least one actuator connects the ring to the body via pin joins at either end.

40. The centraliser as claimed in any of the claims 21 to 39, wherein the actuator mechanism comprises a link connected at one end to the at least one extendable arm via a pin joint and at another end to the actuator via another pin joint.

41. A centraliser comprising:

a body;

a ring rotatably mounted to the body via the hydraulic actuator; and at least one rotatably extendable arm connected to the ring via a link, wherein extension of the hydraulic actuator via the supply of fluid causes the ring to rotate around the body which in turn causes the at least one extendable arm to extend to an extended configuration having a maximum outer dimension greater than the outer dimension of the body.

42. A valve actuation apparatus, the apparatus comprising:

an actuation chamber;

a pressure generating material contained within the actuation chamber, the pressure generating material being adapted to generate pressure within the actuation chamber upon an initiation event;

a transmission arrangement for transmitting the movement of the actuation member to movement of a valve member to close or open a valve.

43. The valve actuation apparatus as claimed in claim 42, wherein the actuation chamber is made of steel or steel alloy.

44. The valve actuation apparatus as claimed in claim 42 or 43, wherein the actuation chamber comprises a pressure cylinder.

45. The valve activation apparatus as claimed in any of the claims 42 to 44, wherein the pressure generating material comprises an explosive, a propellant and/or an oxidizer.

46. The valve activation apparatus as claimed in any of the claims 42 to 45, wherein the pressure generating material comprises an oxidizer.

47. The valve activation apparatus as claimed in any of the claims 42 to 45, wherein the pressure generating material comprises a gas generating material.

48. The valve actuation apparatus as claimed in any of the claims 42 to 47, wherein the initiation event comprises a hydraulic, electrical, acoustic, electronic including but not limited to RF signal and/or the like.

49. The valve actuation apparatus as claimed in any of the claims 42 to 48, wherein the initiation event comprises a signal transmitted via a primary control umbilical, or hydraulic signals from a BOP.

50. The valve actuation apparatus as claimed in any of the claims 42 to 48, wherein the initiation event comprises a signal initiated at a surface location or a subsea location.

51. The valve actuation apparatus as claimed in any of the claims 42 to 50, wherein the initiation event comprises one or more of:

contact with another chemical comprising water, an oxidant or a combustible material, an acidic or a basic material;

an energy input, comprising an electrical energy input, a mechanical energy input, heating; and

a pressure drop or a pressure increase.

52. The valve actuation apparatus as claimed in any of the claims 42 to 51 , wherein the initiation event comprises gas generation caused by combustion of a first chemical the heat generated by said combustion initiating a reaction of a second chemical.

53. The valve actuation apparatus as claimed in any of the claims 42 to 52, wherein the pressure generating material comprises a hydrocarbon material comprising a polymer material and a chemical oxidizing agent.

54. The valve actuation apparatus as claimed in claim 53, wherein the polymer is a high energy polymer such as nitrated polymer.

55. The valve actuation apparatus as claimed in any of the claims 42 to 54, wherein the actuation member is disposed within the actuation chamber.

56. The valve actuation apparatus as claimed in any of the claims 42 to 54, wherein the actuation member is disposed outside the first actuation chamber.

57. The valve actuation apparatus as claimed in any of the claims 42 to 54, wherein the actuation member is disposed within a second chamber operatively connected with the first actuation chamber with a pressure communicating link that allows communication of the generated pressure to the actuation member to cause the actuation member to move.

58. The valve actuation apparatus as claimed in any of the claims 42 to 57, wherein the transmission arrangement comprises a hydraulic or a mechanical link between the valve actuation member and a valve primary actuator.

59. The use of the valve actuation apparatus as claimed in any of the claims 42 to 58 as the primary and/or secondary actuation mechanism for closing and/or opening a valve.

60. The use of the valve actuation apparatus as claimed in any of the claims 42 to 58 in a surface or a downhole installation.

61. The use of the valve actuation apparatus as claimed in any of the claims 42 to 58 in a subsea installation.

62. The use of the valve actuation apparatus of any one of claims 42 to 58 to close one or more valves in a subsea installation.

63. The use of the valve activation apparatus of any one of claims 42 to 58 to close a SSTT valve.

64. The use of the valve actuation apparatus of any one of claims 42 to 58 to close a SSTT valve upon loss of a primary actuation means.

65. A landing string comprising a valve actuation apparatus as claimed in any of the claims 42 to 58 mounted between a BOP ram and a BOP shear ram.

66. A landing string comprising a valve actuation apparatus as claimed in any of the claims 42 to 58 mounted at a location proximate and below a SSTT latch separation point.

67. A landing string comprising a valve actuation apparatus as claimed in any of the claims 42 to 58 mounted inside a subsea BOP at the vicinity of a SSTT valve.

68. An SSTT valve comprising a valve actuation apparatus as in any of the claims 42 to 58.

69. A landing string comprising an explosive cutter apparatus.

70. The landing string as claimed in claim 69, wherein the explosive cutter apparatus is mounted inside the landing string at a location proximate to an obstruction to be cut.

71. An explosive cutter apparatus comprising:

a housing; and

an explosive charge disposed within the housing, the explosive charge being adapted to direct substantially all explosive energy upon detonation inwardly towards the obstruction to be cut.

72. The explosive cutter apparatus as claimed in claim 71 , wherein the charge is sized to provide only sufficient energy to cause complete separation of the obstruction with a small margin of excess.

73. The explosive cutter apparatus as claimed in claim 71 or 72, wherein detonation of the explosive charge is achieved directly from a surface control system using a signal selected from the group comprising hydraulic, electrical, acoustic, electronic including but not limited to RF and/or the like.

74. The explosive cutter apparatus as claimed in claim 71 , 72 or 73, wherein detonation of the explosive charge is achieved via the application of pressure through a BOP choke and kill line or through the use of acoustics or RF signals.

75. The explosive cutter apparatus as claimed in any one of claims 71 to 74, wherein detonation is dependent on other events performed in a sequence.

76. The use of the explosive cutter as claimed in any one of claims 71 to 75, for cutting a landing string joint.

77. A landing string comprising an explosive cutter as claimed in any one of claims 71 to 75.

78. A landing string comprising:

an explosively parting joint; and

an explosive charge positioned adjacent to the explosively parting joint, wherein the explosive charge is adapted upon detonation to direct substantially all explosive energy towards the explosively parting joint to weaken and/or separate the joint.

79. The landing string as claimed in claim 78, wherein the explosively parting joint is housed within a rigid tubular body.

80. The landing string as claimed in claim 79, wherein the tubular body includes at least one connection for connection to the landing string.

81. The landing string as claimed in claim 78, wherein the explosive charge is housed outside the explosively parting joint, optionally within a rigid housing.

82. The landing string as claimed in claim 81 , wherein the explosive charge is designed to direct, upon detonation, substantially all explosive energy inwardly towards the joint.

83. The landing string as claimed in any one of claims 78 to 82, wherein the explosive charge comprises a continuous length of explosive material.

84. The landing string as claimed in any one of claims 78 to 83, wherein the charge comprises an array of individual shaped charges.

85. The landing string as claimed in any one of claim 78 to 84, wherein the explosively parting joint comprises a landing string shear sub.

86. The landing string as claimed in any one of claims 78 to 85, wherein the explosive charge is positioned below shear rams so that the plane of separation lies below the shear rams.

87. The landing string as claimed in any of the claims 78 to 86, wherein the explosively parting joint comprises an explosively parting bolt.

88. The landing string as claimed in any of the claims 78 to 87, wherein the explosively parting joint comprises an array of explosively parting bolts joining a flanged type connection, whereby detonation of the explosive charges causes the bolts to shear and disconnect the flanged connection.