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[0001]    This application is a Continuation-in-Part Application of my co-pending provisional application Ser. No. 60/826,289, filed on 20 Sep. 2006 by Inventor Ross Trewhella, and entitled “Method of Functioning and/or Monitoring Temporarily Installed Equipment Through a Tubing Hanger”. 
     
    
     BACKGROUND OF THE INVENTION 
       [0002]    This invention relates to a method of controlling equipment in offshore operations. More specifically, but without limitations, this invention relates to a system and method of landing and locking completions and other bottom hole assemblies with a landing string from a semi-submersible or dynamically positioned drilling vessel, wherein the landing string contains well control equipment. 
         [0003]    In the drilling and completion of wells located in bodies of water, operators find it necessary to incorporate safety measures. As those of ordinary skill in the art will readily appreciate, when wells are drilled and completed to subterranean reservoirs, the well will experience significant pressures which require containment. The uncontrolled release of pressure from subterranean reservoirs can lead to catastrophic damage. Hence, safety valves and safety systems are required. In offshore applications, many times it is necessary to secure the well due to exigent circumstances. For example, in the case of a hurricane, an operator may wish to shut-in the well as well as move off of location. 
         [0004]    Various prior art devices have been employed. However, all of the prior art devices are cumbersome, awkward and complex to manufacture and operate. Therefore, there is a need for a system and method of controlling an offshore well. There is also a need for a method and system that will allow for the deployment of a completion on a landing string, with the landing string containing well control equipment. There is also a need for well control equipment that is run as part of a landing string, and wherein the landing string is run in conjunction with the running, landing and locking of a sub-sea completion from a semi-submersible or dynamically positioned drilling vessel. 
       SUMMARY OF THE INVENTION 
       [0005]    A method of operating a landing string utilized on a floating platform, with the landing string being disposed within a marine riser, the marine riser having a first end connected to the floating platform and a second end connected to a subsea production tree, and wherein the subsea production tree contains internal conduits communicating controls through a series of stab passageways. In the preferred embodiment, the landing string contains a completion bottom hole assembly. The method comprises providing a tubing hanger operatively connected to the landing string, delivering hydraulic or electrical controls from the floating platform through a control system umbilical to a junction plate operatively attached to the subsea production tree. The method further comprises landing the tubing hanger into the subsea production tree, establishing control of the tubing hanger by providing the hydraulic controls to the tubing hanger with the series of stab passageways through the subsea production tree, and establishing control of the completion bottom hole assembly with the stab passageways. In this embodiment, the completion equipment includes surface controlled sub-surface valves, electrical gauges and chemical injection mandrels. 
         [0006]    The method may further comprise maintaining status of the unlatched elements during disconnect activities, wherein the disconnect point will require hydraulic checking stabs, and wherein the hydraulic checking stabs will trap hydraulic pressure allowing the latch to reconnect and re-establish communications. This method of control requires that during the initial deployment (prior to landing the tubing hanger), the operator will have no control over device functionality (i.e. control of the various devices); therefore, it is necessary to trap control fluid within some chambers to lock components in preset positions. After landing the tubing hanger, control is regained. The method may further comprise monitoring the pressure status of the production equipment, wherein pressure status is monitored with a pressure transducer, and wherein the pressure transducer can collect and transmit data to surface either by electrical conduit or other form of data transmission. 
         [0007]    A method of landing a landing string to a subsea production tree from a floating platform, wherein a marine riser is attached at a first end to the floating platform and at a second end to a blowout preventor system (BOP system) is also disclosed. The landing string has a subsea test tree and retainer valve operatively associated therewith, and wherein the landing string has attached thereto a tubing hanger, and wherein the tubing hanger is attached to a bottom hole assembly. The method includes providing an umbilical operatively attached to a junction plate on the subsea production tree, wherein the umbilical is positioned on an exterior portion of the marine riser, lowering the landing string into an interior portion of the marine riser, and landing the tubing hanger into the subsea production tree. The method further comprises establishing communication with the tubing hanger with the umbilical through stab means located within the subsea production tree and controlling the subsea test tree, retainer valve and bottom hole assembly with the umbilical. In this embodiment, the subsea production tree is connected to a subterranean well, and the bottom hole assembly contains a completion string concentrically placed within the well. 
         [0008]    Also disclosed is a method of operating and/or monitoring temporarily installed equipment through a tubing hanger. The tubing hanger is operatively associated with a subsea production tree. The method includes delivering hydraulic or electrical controls from a vessel through a control system umbilical, and terminating at a junction plate mated to the subsea production tree. The production tree provides internal conduits communicating controls through a series of stabs. The control of the tubing hanger and other equipment is established by landing the completion within the production tree, which has the effect of enabling the stabs and establishing communications with the completion equipment, and wherein the completion equipment is typically surface controlled sub-surface valves (SCSSV), electrical gauges and chemical injection mandrels. The method further includes reconfiguring and adding stabs which diverts controls up the assembly into the tubing hanger running tool and ultimately to other equipment. By establishing communication and control in this way, full functional control of the devices is provided. In order to maintain status of any unlatched elements of the system during disconnect activities the disconnection points will require hydraulic checking stabs, these will trap hydraulic pressure allowing the latch to reconnect and re-establish communications. This method of control requires that during the initial deployment prior to landing the tubing hanger, the operator will have no control over device functionality, and as such it will be necessary to trap control fluids within some chambers to lock components in preset positions, control will be regained subsequent to landing the tubing hanger. Also, the operator may insist on monitoring pressure status, in this instance a pressure transducer could be fitted to transmit data to surface either by electrical conduit or other form of data transmission. 
         [0009]    An advantage of the present disclosure is that the system provides means for isolated and disconnecting from a live well in instances of severe weather or emergencies that necessitate the vessels moving out of its safe operating/watch circle. Another advantage is that the system meets government regulations pertaining to containing hydrocarbons during operations, such as during disconnecting operations. Yet another advantage is that deep water control systems do not need to be deployed within the marine riser. 
         [0010]    A feature of the present system is that the there is no umbilical in the marine riser which reduces project risk, allows for access to the umbilical, improves rig space and reduces string running and retrieval time. Another feature is that no annular slick joint is required. Yet another feature is that the system and method significantly reduces the number of thru ports required in the system thereby reducing risk of hydraulic failure. Another feature is that there is no risk of dropped umbilical clamps within the marine riser. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0011]      FIG. 1  is a well bore schematic of the preferred embodiment of the present system. 
           [0012]      FIG. 2  is an enlarged view of area denoted as “A” in  FIG. 1 . 
       
    
    
     DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS 
       [0013]    Referring now to  FIG. 1 , a well bore schematic of the preferred embodiment of the present system will now be described. As can be seen, a floating platform  2 , such as a semi-submersible drilling vessel, is positioned over a well. It should be noted that the platform  2  may be an offshore floating platform, an anchored vessel, or even a jack-up type of platform. A marine riser  4  extends from the floating platform  2 . The marine riser  4  is operatively connected to a subsea blow-out preventor system (BOP system), wherein the bop system is seen generally at  6 . The BOP system  6  is made up of individual BOP components as will be more fully set later in the description. The BOP system  6  will be operatively connected to subsea production tree  8 , and wherein the production tree  8  will in turn be operatively connected to the subterranean well  10 . The subsea production tree  8  is adjacent the sea bed. As very well understood by those of ordinary skill in the art, the subterranean well  10  may be completed to a reservoir  111  for production. Hence, the inner portion of the well  10  may be exposed to significant pressures as well as reservoir fluids and gas. 
         [0014]    The system of the most preferred embodiment includes a subsea test/intervention tree  12  (hereinafter subsea test tree  12 ) and a retainer valve  14  disposed within the BOP system  6 . The sub-sea test tree  12  is deployed via the landing string  16 , and wherein the landing string  16  is concentrically disposed within the marine riser  4 . 
         [0015]    Referring now to  FIG. 2 , an enlarged view of area denoted as “A” in  FIG. 1  will now be described. It should be noted that like numbers appearing in the various figures refer to like components. As seen in  FIG. 2 , the subsea test tree  12  and retainer valve  14  are utilized as a temporary part of a completion running string  17 , deployed into the well  10  from the floating platform  2 . The sub-sea test tree  12  and retainer valve  14  are located within the BOP system  6 , and more particularly, above the blind rams  18  and the pipe rams  20  of the BOP system  6 . The subsea test tree  12  and retainer valve  14  provide well isolation and unlatch function, as well as hydrocarbon retention thereby allowing the floating platform  2  to safely move off location in emergencies. 
         [0016]    More specifically, the subsea test tree  12  is installed as an integral part of the completion landing string  16  and consists of dual fail-safe hydraulically operated ball valves. The upper section of the subsea test tree  12  is mated to a hydraulically actuated latch means for latching and unlatching to the landing string  16 . The latch means may be disconnected after well  10  is isolated to allow the vessel to ride out a storm or move off of location for any reason. The subsea test tree  12  is installed within the BOP system  6 , and in particular within the blind rams  18  and pipe rams  20  area. The subsea test tree  12  is spaced out such that the BOP pipe rams  20  can be closed upon a subsea test tree slick joint (i.e. the slick joint makes up part of the subsea test tree  12 ) in order to provide annulus isolation, whilst also being of a sufficient length and position that the blind/shear rams may be closed above. 
         [0017]    The retainer valve  14  is installed as an integral part of the completion landing string  16  and consist of a single fail as is hydraulically operated ball valve combined with a hydraulically operated vent sleeve. The retainer valve  14  is designed to function in conjunction with the unlatch feature if the subsea test tree  12  is unlatched for operational purposes. During the subsea test tree  12  unlatch procedure pressure is applied through the control umbilical  28  from surface to initiate the subsea test tree  12  unlatching. As seen in  FIGS. 1 and 2 , the umbilical  28  is located outside the marine riser  4 . This pressure initially acts upon the retainer valves ball piston to close the ball and contain the hydrocarbons within the marine riser  4 ; upon achieving full stroke, the pressure is then switched to the vent sleeve, which in turn opens venting trapped pressure between the subsea test tree&#39;s upper ball and the retainer valve ball. Finally, the control pressure is passed onto the subsea test tree&#39;s  12  valve unlatch piston. An additional feature within this valve is a “fail close” feature that activates only when the shear sub is sheared. This will override the “fail as-is” condition securing the pressurized hydrocarbons contained within the landing string and preventing it from entering the marine riser  4 . Additional overrides allow the latch to be activated without operating the retainer valve  14 . 
         [0018]      FIG. 2  also depicts the tubing hanger  22  that is operatively attached to the tubing hanger running tool  24 , wherein the running tool  24  is operatively attached to the subsea test tree  12 . At the lower end, the tubing hanger  22  is operatively attached to the completion string  17 . 
         [0019]    In the most preferred embodiment, the sub-sea test tree  12  and retainer valve  14  are hydraulically actuated. In the prior art, the test tree  12  and the retainer valve  14  traditionally rely on application and venting of hydraulic pressures supplied from either an “in marine riser” control system and/or umbilical terminated at the uppermost face of each valve. As seen in  FIG. 2 , in the most preferred embodiment of this disclosure, the umbilical  28  is on the outside of the marine riser  4 . In prior art embodiments, the umbilical is strapped or clamped to the tubing or casing string that makes up the landing string and sits on the inside of the marine riser, and as such, poses a high level of risk due to the movement between the physical components (i.e. riser, ss test trees, retainer valves, etc) and the sea currents which can cause damage to the umbilical. 
         [0020]    Referring again to the preferred embodiment depicted in  FIG. 2 , from the uppermost face of the assembly where the umbilical  28  is terminated (at the production tree  8 ?), internal porting through the assembly will carry the control fluids (or in an alternative embodiment, electrical conduits to transmit electrical signals) to the various functions (i.e. components) within the retainer valve  14 , subsea test tree  12 , tubing hanger running tool  24 , tubing hanger  22  and ultimately devices within the completion string  17 . This requirement for a large number of connections and intricate porting within the aforementioned devices (particularly the retainer valve  14 , sub-sea test tree  12  and tubing hanger  22 ) creates multiple potential leak paths or loss of electrical continuity for each conduit. 
         [0021]    The tubing hanger running tool  24  is located directly below the subsea test tree  12  and provides a facility to latch and unlatch the landing string  16  from the tubing hanger  22 . This design allows for the temporary landing string  16  to be removed leaving the production completion string  17  and associated completion devices (not seen) installed and locked. According to the invention, the tubing hanger running tool  24  can be mechanically or hydraulically actuated. Hydraulically actuated tubing hanger running tools receive control pressure via conduits fed through the subsea test tree  12  and also provides conduits for controlling the tubing hanger  22  and devices within the completion string  17 . These conduits represent multiple potential leak paths for each conduit??? 
         [0022]    The tubing hanger  22  forms the uppermost part of the permanent completion and facilitates the locking of the completion into the subsea production tree  8 . The tubing hanger  22  is traditionally hydraulically operated. In the prior art, the tubing hanger  22  receives hydraulic control pressure from the surface via the conduits passed through the tubing hanger running tool  24 , the subsea test tree  12 , the retainer valve  14  and the “in riser” umbilical ????? It can be seen that this supply represents a torturous path with a multiple of potential leak paths. 
         [0023]    In the present preferred embodiment, the interface between the tubing hanger  22  and the production tree  8  contains a series of stabs  30 , and wherein these stabs  30  facilitate the hydraulic (or electrical in the alternative embodiment) communication between the subsea production tree  8  and the tubing hanger  22 . Control pressures in the preferred embodiment (or electrical conduits in the alternative embodiment) are received from the subsea production tree  8  and then passed from the stabs  30  down the completion string  17  via a series of small-bore tubing or electrical conduits to control the various devices that comprise the completion string. 
         [0024]    Referring again to  FIG. 1 , the control system  32  is made-up of a power unit comprising a pump  34  and accumulators  36  combined with hydraulic valves and regulators configured to control hydraulic pressures feeding various hydraulically operated devices. In the alternative embodiment, the control system  32  can regulate and supply electrical power to feed various electrically driven devices. The control system  32  will also generally include means for delivering the hydraulics (or electrical power in the alternative embodiment), and the delivering means in the preferred embodiment is the umbilical  28  which is made up of hydraulic control lines or a combination of hydraulic control lines. In the alternative embodiment, the conduits may contain electrical conduits for supply the electrical signal. 
         [0025]    In operation, and referring collectively to  FIGS. 1 and 2 , during the completion running and/or pulling, or during workover operations, control elements (i.e. the hydraulic fluid in the preferred embodiment, electrical signal in the alternative embodiment) are transferred from a floating offshore installation via a single or series of conduits (i.e. umbilical  28 ) to a junction plate  38 . The junction plate  38  is removable and attached to the subsea production tree  8 . It should be noted that the production tree  8  may include, but not limited to, a horizontal or spool type of sub-sea tree. 
         [0026]    The junction plate  38  locks the conduit/umbilical  28  to the subsea production tree  8  and facilitates communication to a series of hydraulic ports/electrical conduits within the wall of the subsea production tree  8 . These ports will link to a set of stabs/receptacles  30  located within or around the inner wall of the subsea production tree  8  and are isolated until such time as the mating tubing hanger  22  is landed within its bore. In operation, the tubing hanger  22  is deployed from the rig floor of the floating platform  2  (at the surface), through the bore of the marine riser  4 , into the BOP stack  6  and landed on a location within the inner bore of the subsea production tree  8 . 
         [0027]    Typically, a completion string  15  will be attached to the lower end of the tubing hanger  22  and a running tool  24 ? attached to the landing string  16 , and wherein the well isolation devices (namely, the subsea test tree  12  and retainer valve  14 ) is attached to the upper end. 
         [0028]    The action of landing the tubing hanger  22  within the subsea production tree  8  will establish communication between the aforementioned stabs/receptacles  30  and the tubing hanger  22 . Alternatively, these stabs/receptacles  30  may be energized to engage using external forces. These established communications provide monitoring or control to equipment located within the completion part or lower part of the inner assembly. 
         [0029]    As will be readily appreciated to those skilled in the art, the present invention may easily be produced in other specific forms without departing from its spirit or essential characteristics. The present embodiment is, therefore, to be considered as merely illustrative and not restrictive. The scope of the invention is indicated by the claims that follow rather than the foregoing description, and all changes which come within the meaning and range of equivalents of the claims are therefore intended to be embraced therein.

Summary:
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.