Patent Abstract:
A subsea well safing method and apparatus to secure a subsea well in the event of a perceived blowout in a manner to mitigate the environmental damage and the physical damage to the subsea wellhead equipment to promote the ability to reconnect and recover control of the well. The safing assembly is connectable to a subsea well and a marine riser. Pursuant to a safing sequence, the well tubular is secured in the upper and lower safing assemblies and the tubular is then sheared between the locations at which it has been secured. Subsequently, an ejection device may be actuated to physically separate the upper safing assembly and the connected marine riser from the lower safing assembly the subsea well.

Full Description:
BACKGROUND 
     This section provides background information to facilitate a better understanding of the various aspects of the disclosure. It should be understood that the statements in this section of this document are to be read in this light, and not as admissions of prior art. 
     A blowout preventer is a large, specialized valve used to seal, control and monitor oil and gas wells. Blowout preventers are designed to cope with extreme erratic pressures and uncontrolled flow emanating from a well during drilling. Pressure kicks can lead to the uncontrolled release of oil and/or gas from a well resulting in a potentially subsea well event known as a blowout. Blowout preventers are critical to the safety of crew, equipment and environment, and to the monitoring and maintenance of well integrity. While blowout preventers are intended to be fail-safe devices, accidents may still occur if the blowout preventer fails to properly operate. For example, during the Apr. 20, 2010, Deepwater Horizon drilling rig explosion, it is believed that the blowout preventers may not have properly operated and/or were not activated in a timely fashion. In addition to loss of well control the wellhead equipment was damaged creating obstacles to recovering control of the well. 
     SUMMARY 
     In accordance to an aspect of the disclosure a subsea well safing package or system includes an assembly connector interconnecting a lower assembly and an upper assembly, the lower assembly is to be connected to a subsea well and includes lower slips to engage and secure a tubular suspended in a bore formed through the lower assembly and the upper assembly, the upper assembly having upper slips operable to engage and secure the tubular, and a shear positioned between the upper slips and the lower slips operable to shear the tubular. In accordance to aspects of one or more embodiments the well safing package is connected to a subsea well, for example the subsea wellhead. In accordance to an aspect of one or more embodiments the subsea well safing package is connected between the marine riser and a subsea well. In accordance to one or more aspects the subsea well safing package is connected between the marine riser and a blowout preventer stack that is connected to the subsea wellhead. 
     A method in accordance to one or more aspects includes securing a tubular suspended in a bore with lower slips of a lower assembly, securing the tubular in the bore with upper slips of an upper assembly, shearing the tubular in the bore between the positions at which the tubular is secured with the lower slips and the upper slips, and after shearing the tubular, disconnecting the upper assembly from the lower assembly. 
     The foregoing has outlined some of the features and technical advantages in order that the detailed description that follows may be better understood. Additional features and advantages will be described hereinafter which form the subject of the claims of the invention. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of claimed subject matter. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The disclosure is best understood from the following detailed description when read with the accompanying figures. It is emphasized that, in accordance with standard practice in the industry, various features are not drawn to scale. In fact, the dimensions of various features may be arbitrarily increased or reduced for clarity of discussion. 
         FIG. 1  a schematic illustration of a subsea safing system according to one or more aspects of the disclosure utilized in a subsea well drilling system. 
         FIG. 2  depicts a subsea safing system according to one or more aspects, wherein the safing sequence has been initiated and the marine riser and upper safing package are physically and hydraulically disconnected from the lower safing package, the BOP stack, and the well. 
         FIG. 3  illustrates a subsea well safing assembly according to one or more aspects of the disclosure. 
         FIG. 4A-4B  is a flow chart of a subsea well safing sequence according to one or more aspects of a subsea well safing system. 
         FIGS. 5-17  are schematic diagrams of safing sequence operations according to one or more aspects of a subsea well safing system. 
         FIG. 5A  is a sectional view of a vent system according to one or more aspects shown along the line I-I of  FIG. 5 . 
         FIG. 8A  is a sectional view of a shutter device shown along the line I-I of  FIG. 8 . 
         FIG. 8B  is a sectional, side view of a shutter device in accordance to one or more aspects. 
         FIG. 13A  illustrates the marine riser and upper safing package disconnected and separated from the lower safing package and the wellhead in response to progression of the subsea well safing sequence. 
     
    
    
     DETAILED DESCRIPTION 
     It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, the disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. 
     As used herein, the terms “up” and “down”; “upper” and “lower”; “top” and “bottom”; and other like terms indicating relative positions to a given point or element are utilized to more clearly describe some elements. Commonly, these terms relate to a reference point as the surface from which drilling operations are initiated as the top point and the total depth of the well as the lowest point, wherein the well (e.g., wellbore, borehole) is vertical, horizontal or slanted relative to the surface. 
     In this disclosure, “hydraulically coupled” or “hydraulically connected” and similar terms, may be used to describe bodies that are connected in such a way that fluid pressure may be transmitted between and among the connected items. The term “in fluid communication” is used to describe bodies that are connected in such a way that fluid can flow between and among the connected items. It is noted that hydraulically coupled may include certain arrangements where fluid may not flow between the items, but the fluid pressure may nonetheless be transmitted. Thus, fluid communication is a subset of hydraulically coupled. 
     A subsea well safing system is disclosed to provide a means for mitigating the environmental and economic damage that can result from the loss of control of a well, such as occurred in the Macondo well being drilled from the Deepwater Horizon on 20 Apr. 2010. According to one or more aspects, the subsea well safing system provides a mechanism to separate the marine riser from the blowout preventer stack and the well in a manner intended to mitigate the physical damage to the well drilling system and to enhance the potential for successfully reconnecting to the well, for example via the BOP stack, to regain control of the well. 
       FIG. 1  is a schematic illustration of a subsea well safing system, generally denoted by the numeral  10 , being utilized in a subsea well drilling system  12 . In the depicted embodiment drilling system  12  includes a BOP stack  14  which is landed on a subsea wellhead  16  of a well  18  (i.e., wellbore) penetrating seafloor  20 . BOP stack  14  conventionally includes a lower marine riser package (“LMRP”)  22  and blowout preventers (“BOP”)  24 . The depicted BOP stack  14  includes subsea test valves (“SSTV”)  26 . As will be understood by those skilled in the art with benefit of this disclosure, BOP stack  14  is not limited to the devices depicted. 
     Subsea well safing system  10  includes a safing package, or assembly, generally referred to herein as a catastrophic safing package (“CSP”)  28  that is landed on BOP system  14  and operationally connects a marine riser  30  extending from platform  31  (e.g., vessel, rig, ship, etc.) to BOP stack  14  and thus well  18 . CSP  28  includes an upper CSP  32  and a lower CSP  34  that are configured to separate from one another in response to initiation and implementation of a safing sequence thereby disconnecting marine riser  30  from the BOP stack  14  and well  18 , for example as illustrated in  FIG. 2 . The safing sequence is initiated in response to parameters indicating the occurrence of a failure in well  18  with the potential of leading to a blowout of the well. Subsea well safing system  10  may automatically initiate the safing sequence in response to the correspondence of monitored parameters to selected safing triggers. CSP  28  may include an accumulator  29 , see e.g.  FIGS. 3 and 7 , hydraulically connected to wellhead  16  to operate the wellhead connector lock as further described below. In  FIG. 7 , wellhead accumulator  29  is depicted as a standalone, accumulator located proximate to seafloor  20  and wellhead  16 . 
     Wellhead  16  is a termination of the wellbore at the seafloor and generally has the necessary components (e.g., connectors, locks, etc.) to connect components such as BOPs  24 , valves (e.g., test valves, production trees, etc.) to the wellbore. The wellhead also incorporates the necessary components for hanging casing, production tubing, and subsurface flow-control and production devices in the wellbore. 
     BOP stack  14  commonly includes a set of two or more BOPs  24  utilized to ensure pressure control of well  18 . A typical stack might have one to six ram-type preventers and, optionally, one or two annular-type preventers. A typical stack configuration has the ram preventers on the bottom and the annular preventers at the top. The configuration of the stack preventers is optimized to provide maximum pressure integrity, safety and flexibility in the event of a well control incident. For example, one set of rams may be fitted to close on the drillpipe, blind rams to close on the open hole, and another set of shear rams to cut and hang-off the drillpipe. It is also common to have an annular preventer at the top of the stack to close over a wide range of tubular (e.g., drillpipe) sizes and the open hole. BOP stack  14  also includes various spools, adapters, and piping ports to permit circulation of wellbore fluids under pressure in the event of a well control incident. 
     LMRP  22  and BOP stack  14  are coupled together by a wellbore connector that is engaged with a corresponding mandrel on the upper end of BOP stack  14 . LMRP  22  typically provides the interface (i.e., connection) of the BOPs  24  and the bottom end  30   a  of marine riser  30  via a riser connector  36  (i.e., riser adapter). Riser connector  36  may include a flex joint that provides for a range of angular movement of riser  30  (e.g., 10 degrees) relative to BOP stack  14 , for example to compensate for vessel  31  offset and current effects along the length of marine riser  30 . Riser connector  36  may include one or more ports for connecting fluid (i.e., hydraulic) and electrical conductors, i.e., communication umbilical, which may extend along (exterior or interior) marine riser  30  from the drilling platform located at surface  5  to subsea drilling system  12 . For example, it is common for a hydraulic choke line  44  and a hydraulic kill line  46  to extend from the surface for connection to BOP stack  14 . 
     Marine riser  30  is a tubular string that extends from the drilling platform  31  down to well  18 . The marine riser is in effect an extension of the wellbore extending through the water column to drilling vessel  31 . The marine riser diameter is large enough to allow for drillpipe, casing strings, logging tools and the like to pass through. For example, in  FIGS. 1 and 2 , a tubular  38  (e.g., drillpipe) is illustrated deployed from drilling platform  31  into marine riser  30 . Drilling mud and drill cuttings can be returned to surface  5  through marine riser  30 , for example through the annulus between drillpipe and the riser. Communication umbilicals (e.g., hydraulic, electric, optic, etc.) can be deployed exterior to or through marine riser  30  to CSP  28  and BOP stack  14 . A remote operated vehicle (“ROV”)  124  is depicted in  FIG. 2  and may be utilized for various tasks. 
     Refer now to  FIG. 3  which illustrates a subsea well safing package  28  in accordance to an aspect of one or more embodiments. CSP  28  depicted in  FIG. 3  is further described with reference to  FIGS. 1 and 2 . The illustrated CSP  28  has an upper CSP  32  and a lower CSP  34 . Upper CSP  32  includes a riser connector  42  which may include a riser flange connection  42   a , and a riser adapter  42   b  which may provide for connection of communication umbilicals and extension of the communication umbilicals to various CSP  28  devices and/or BOP stack  14  devices. For example, a choke line  44  and a kill line  46  are depicted extending from the surface with riser  30  and extending through riser adapter  42   b  for connection to the choke and kill lines of BOP stack  14 . The illustrated CSP  28  includes a choke stab  44   a  and a kill line stab  46   a  for interconnecting the upper portion of choke line  44  and kill line  46  with the lower portion of choke line  44  and kill line  46 . As will be further described below with reference to safing sequence  86 , stabs  44   a ,  46   a  also provide for disconnecting from the stab and kill lines during a safing operations and during subsequent recovery and reentry operations reconnecting to the choke and kill lines via stabs. The riser connector  42  may include a flex joint. 
     CSP  28  has an internal longitudinal extending bore  40 , depicted in  FIG. 3  by the dashed line through lower CSP  34 , for passing tubular  38 . Annulus  41  is formed between the outside diameter of tubular  38  and the inside diameter of bore  40 . 
     Upper CSP  32  includes slips  48  (i.e., safety slips) to close on tubular  38  and secure tubular  38  in the upper assembly. Slips  48  are actuated in the illustrated system by hydraulic pressure from an accumulator  50 . Depicted CSP  28  includes a plurality of hydraulic accumulators  50  which may be interconnected in pods, such as upper accumulator pod  52 . As will be understood by those skilled in the art with benefit of the present disclosure, accumulators  50  may be provided in various configurations. The depicted accumulators  50  are hydraulically charged and do not require connection to a hydraulic source at the surface. It will also be recognized by those skilled in the art that hydraulic pressure may be provided from the surface. In this embodiment, accumulators  50  located in the upper accumulator pod  52  are at least hydraulic connected to slips  48 . The pressure in accumulators  50  can be monitored and accumulators  50  may be actuated in sequence as needed to ensure that adequate hydraulic pressure is available to actuate CSP devices such as slips  48 . 
     Lower CSP  34  includes a connector  54  to connect to the subsea well, rams  56  (e.g., blind rams), high energy shears  58 , lower slips  60  (e.g., bi-directional slips), and a vent system  64  (e.g., valve manifold). In  FIGS. 1 and 2  CSP  28  is illustrated connected to the subsea well and wellhead through BOP stack  14 , for example, via riser connector  36  of the LMRP  22 . Vent system  64  may include one or more valves  66 . Vent system  64  is depicted with vent valves (e.g., ball valves)  66   a , choke valves  66   b , and one or more connection mandrels  68 . Valves  66   b  can be utilized to control fluid flow through connection mandrels  68 . For example, a recovery riser  126  is depicted connected to one of mandrels  68  for flowing effluent from the well and/or circulating a kill fluid (e.g., drilling mud) into the well as further described below. Vent system  64  is further described below with reference to  FIGS. 5 and 5A . 
     Lower CSP  34  is depicted in  FIG. 3  with a deflector or shutter device  70  (e.g., impingement device) disposed above vent system  64  and below lower slips  60 , shears  58  and blind rams  56 . Lower CSP  34  includes a plurality of hydraulic accumulators  50  that are arranged and connected in one or more lower hydraulic pods  62  for operations of various devices of CSP  28 . As will be further described below, CSP  28  may be operationally connected to a chemical source  76 , e.g. methanol, to mitigate hydrate formation. For example, a chemical such as methanol may be injected in lower CSP  34  to prevent hydrate formation for example when vents  66  are opened. 
     Upper CSP  32  and lower CSP  34  are detachably connected to one another by a connector  72 . CSP connector  72  includes a first connector portion  72   a  and a second mandrel connector portion  72   b  which are illustrated for example in  FIG. 13A , for example a collet connector. An ejector device  74  (e.g., ejector bollards) is operationally connected between upper CSP  32  and lower CSP  34  to separate upper CSP  32  and marine riser  30  from lower CSP  34  and BOP stack  14  after connector  72  has been actuated to the unlocked position. The depicted CSP  28  also includes a plurality of sensors  84  which can sense various parameters, such as and without limitation, temperature, pressure, strain (tensile, compression, torque), vibration, and fluid flow rate. Sensors  84  further includes, without limitation, erosion sensors, position sensors, and accelerometers and the like. Sensors  84  can be in communication with one or more control and monitoring systems, for example as further described below, forming a limit state sensor package. 
     CSP  28  includes a control system  78 , which may be located subsea for example at CSP  28 , or at a remote location such as at the surface. Control system  78  may include one or more controllers that may be located at different locations. For example, a depicted control system  78  includes an upper controller  80  (e.g., upper command and control data bus) and a lower controller  82  (e.g., lower command and controller bus). Control system  78  may be connected via conductors (e.g., wire, cable, optic fibers, hydraulic lines) and/or wirelessly (e.g., acoustic transmission) to various subsea devices and to surface (i.e., drilling platform  31 ) control systems. 
     With reference to  FIGS. 3 to 17 , depicted control system  78  includes upper controller  80  and lower controller  82 . Each of upper and lower controllers  80 ,  82  may have a collection of real-time computer circuitry, field programmable gate arrays (FPGA), I/O modules, power circuitry, power storage circuitry, software, and communications circuitry. One or both of upper and lower controller  80 ,  82  may include control valves. 
     One of the controllers, for example lower controller  82 , may serve as the primary controller and provide command and control sequencing to various subsystems of safing package  28  and/or communicate commands from a regulatory authority for example located at the surface. The primary controller, e.g., lower controller  82 , contains communications functions, and health and status parameters (e.g., riser strain, riser pressure, riser temperature, wellhead pressure, wellhead temperature, etc.). One or more of the controllers may have black-box capability (e.g., a continuous-write storage device that does not require power for data recovery). 
     Upper controller  80  is described herein as operationally connected with a plurality of sensors  84  positioned throughout CSP  28  and may include sensors connected to other portions of the drilling system, including along riser  30 , at wellhead  16 , and in well  18 . Upper controller  80 , using data communicated from sensors  84 , continuously monitors limit state conditions of drilling system  12 . According to one or more embodiments, upper controller  80 , may be programmed and reprogrammed to adapt to the personality of the well system based on data sensed during operations. If a defined limit state is exceeded an activation signal (e.g., alarm) can be transmitted to the surface and/or lower controller  82 . A safing sequence may be initiated automatically by control system  78  and/or manually in response to the activation signal. 
     With reference to  FIGS. 4A and 4B , a safing sequence  86  according to one or more aspects of subsea well safing system  10  is illustrated. In sequence block  88 , the safing sequence is initiated in response to monitoring the limit state sensor  84  package for example by upper controller  80 . In sequence block  90 , pressure is vented from CSP  28  by opening a valve  66   a  in vent system  64 , see, e.g.,  FIGS. 1 ,  3 ,  5  and  5 A. In sequence block  92 , the choke and kill lines are closed to prevent combustibles from flowing up from the well and to the surface through the kill and choke lines, see, e.g.,  FIGS. 1 ,  3  and  6 . In sequence block  94 , the wellhead  16  connector lock is pressurized to prevent accidental ejection of BOP stack  14  from wellhead  16 , see, e.g.,  FIGS. 3 and 7 . In sequence block  96 , fluid flowing up from the well is diverted, e.g., partially diverted, to the open vents to prevent erosion of CSP elements such as the slips  48 ,  60 , see, e.g.,  FIGS. 1 ,  3 ,  8 ,  8 A and  8 B. For example, fluid flow may be diverted by operating a deflector or shutter device  70  to a closed position. The rams of device  70  may act to center the tubular in the bore of the safing assembly prior to securing the tubular with the slips and/or prior to shearing the tubular. In sequence block  98 , tubular  38  is secured in lower CSP  34  by closing lower slips  60  (e.g., bi-directional slips), see, e.g.,  FIGS. 1 ,  3  and  9 . In sequence block  100 , tubular  38  is secured in upper CSP  32  by closing upper slips  48  (e.g., safety slips), see, e.g.,  FIGS. 1 ,  3  and  10 . In sequence block  102 , tubular  38  is sheared in lower CSP  34  by activating shears  58 , see, e.g.,  FIGS. 1 ,  3  and  11 . In sequence block  104 , upper CSP  32  and lower CSP  34  are disconnected from one another by operating CSP connector  72  to a disconnected position, see, e.g.,  FIGS. 1 ,  3 ,  12  and  13 A. In sequence block  106 , marine riser  30  and upper CSP  32  are physically separated (e.g., ejected) from lower CSP  34  and BOP stack  14  by activating ejector device  74  (i.e., ejector bollards), see, e.g.,  FIGS. 1-3 ,  13 , and  13 A. In sequence block  108 , (see, e.g.,  FIGS. 1-3  and  14 ) blind rams  56  are closed to seal bore  40  (see, e.g.  FIG. 3 ) and shut-off the fluid flow from the subsea well into the environment. In sequence block  110 , hydrate formation in lower CSP  34  is treated by injecting methanol, see, e.g.,  FIGS. 1-3  and  15 . In sequence block  112 , the open valves  66   a  in vent system  64  are closed, see e.g.,  FIGS. 1-3  and  16 . In sequence block  114 , a formation stability test is performed, see, e.g.,  FIGS. 1-3  and  17 . 
       FIG. 5  is a schematic diagram of sequence block  90 , according to one or more embodiments of subsea well safing system  10 , which is described with further reference to  FIGS. 1 and 3 . In response to initiating safing sequence  86 , one or more vent valves  66   a  of vent system  64  are opened. Valves  66   a  are opened to reduce the flow of fluid through the annulus  41  between tubular  38  and the CSP  28  walls forming bore  40  through CSP  28  (see  FIG. 3 , the dashed lines in lower CSP  34 ) and lowering the backpressure on lower slips  60 . The open and closed position of vent valves  66   a  can be verified by a control signal from each valve position sensor  84 . An accumulator  50  located in the assigned accumulator pod  62  can be activated to provide hydraulic power to the valve actuators  116  of controller  82 . Lower controller  82  continuously monitors the pressure at accumulator pod  62  and activates additional accumulators  50  as may be required to maintain working pressure. With reference to  FIGS. 5-17 , the active device (e.g., accumulators, valves, slips, shears) of the depicted sequence block is emphasized by hatching. 
       FIG. 5A  is a sectional view of an embodiment of vent system  64  shown along the line I-I of  FIG. 5 .  FIG. 5A  depicts two vent valves  66   a  on each side of vent system  64 , which are depicted in the closed position. Valves  66   b  are positioned to control flow through connection mandrels  68 . In the depicted embodiment, the sensor  84  located proximate to the connection mandrel  84  is an accelerometer. 
       FIG. 6  is a schematic diagram of sequence block  92 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 and 3 . In sequence block  92 , valves  118  positioned in each of choke line  44  and kill line  46  are actuated from the open to the closed position to prevent combustibles from flowing up the choke line  44  and the kill line  46 . 
       FIG. 7  is a schematic diagram of sequence block  94  according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 and 3 . Controller  82  initiates the pressurization of wellhead connector lock  120  to prevent the accidental ejection of BOP stack  14  from wellhead  16  due to the high back pressure encountered in subsequent sequence blocks, e.g., when device  70  is closed, slips  48 ,  60  are closed, and due to the loss of hydraulic pressure to wellhead connector lock  120  when marine riser  30  is disconnected from BOP stack  14  disconnecting any hydraulic sources extending along marine riser  30  to CSP  28 . 
       FIG. 8  is a schematic diagram of sequence block  96 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 ,  3 ,  8 A and  8 B. In sequence block  96 , controller  82  actuates device  70  to a closed position (see  FIG. 8A ) in response to applying hydraulic pressure for example from a hydraulic accumulator  50  of lower accumulator pod  62 . In the closed position, device  70  can divert fluid flowing from the well to vent system  64  and to open vent valves  66   a  and away from passing through annulus  41  of safing package  28 . The closed device  70  depicted in  FIG. 8A , protects CSP  28  from the high flow rates and entrained solids that are encountered thereby limiting erosion of devices of CSP  28 , such as upper safety slips  48  and lower slips  60 . Deflector device  70  may be provided in various manners and configurations. Referring to  FIG. 8A , tubular  38  is depicted substantially centered within bore  40  by device  70 , which is coaxial with bore  40  of CSP  28 , by rams  70 A,  70 B, and  70 C. According to at least one embodiment, closure of rams  70 A,  70 B,  70 C does not seal annulus  41 . In the embodiment depicted in  FIG. 8B , each of rams  70 A,  70 B and  70 C comprises stacked and spaced apart plates  71  which interleave portions of the plates  71  of the adjacent rams. 
       FIG. 9  is a schematic diagram of sequence block  98 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 and 3 . In sequence block  98 , controller  82  actuates lower slips  60  (e.g., bi-directional slips) securing tubular  38  within lower CSP  34  in preparation for sequence block  102 . In some embodiments, lower slips  60  may include deflector armor to divert fluid flow toward vent system  64  instead of, or in addition to, the use of device  70  described for example with reference to sequence block  96  and  FIGS. 8 ,  8 A, and  8 B. 
       FIG. 10  is a schematic diagram of sequence block  100 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 and 3 . In sequence block  100 , upper slips  48  are actuated to engage tubular  38  within upper CSP  32 . In this embodiment, sequence block  100  is actuated by upper controller  80 . As with other sequence blocks, the controller monitors the pressure status of accumulators  50  and if a low pressure is detected, a subsequent accumulator in a pod is activated to actuate the sequence block device (i.e., slips  48  in sequence block  100 ). 
       FIG. 11  is a schematic diagram of sequence block  102 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 and 3 . After tubular  38  is engaged and secured respectively in upper CSP  32  (i.e., by slips  48 ) and lower CSP  34  (i.e., slips  60 ), lower controller  82  actuates shears  58  thereby shearing tubular  38  between upper slips  48  and lower slips  60 . 
       FIG. 12  is a schematic diagram of sequence block  104 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 ,  2 ,  3  and  13 A. In sequence block  104 , CSP connector  72  is actuated to the open or disconnected position permitting separation of upper CSP  32  from lower CSP  34  in sequence block  106 . In this embodiment, CSP connector  72  is actuated via upper controller  80  and hydraulic accumulators  50  located in upper accumulator pod  52 . In the depicted embodiment, CSP connector  72  is a collet comprising a first connector portion  72   a  and a second connector portion  72   b , depicted for example in  FIG. 13A . Second connector portion  72   b  is disposed with lower CSP  34  and comprises a mandrel, identified individually by the numeral  72   c  (see,  FIGS. 13A ,  14 - 17 ). The mandrel  72   c  provides a mechanism for reconnecting, for example with a marine riser  30 , for re-entry into well  18 . 
       FIG. 13  is a schematic diagram of sequence block  106 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1-3  and  13 A. In sequence block  106 , depicted ejector devices  74  (i.e., ejector bollards) are actuated to physically separate upper CSP  32  and marine riser  30  from lower CSP  34  as depicted in  FIGS. 2 and 13A . For example, ejector devices  74  may include piston rods  74   a  which extend to push the upper CSP  32  away from lower CSP  34  in the depicted embodiment.  FIGS. 2 ,  13 A, and  14 - 17  illustrate piston rod  74   a  in an extended position. In  FIG. 13 , actuation of ejector devices  74  is provided by upper controller  80  and accumulator(s)  50  located in upper accumulator pod  52 . 
     Typically, marine riser  30  will be in tension which will assist in pulling the disconnected upper CSP  32  vertically away from lower CSP  34  which is connected to BOP stack  14 . In addition, the water currents and deflection in marine riser  30  (e.g., offset from platform  31 ) will assist in moving marine riser  30  and the separated upper CSP  32  laterally away from lower CSP  34  and the well. Choke line  44  and kill line  46  are disconnected respectively at choke stab  44   a  and kill stab  46   a  ( FIG. 3 ). Stabs  44   a  and  46   b  provide a mechanism for reconnection to surface sources during recovery operations. 
     In  FIG. 13 , ejector device  74  is attached to lower CSP  34  and piston rods  74   a  push against a portion of upper CSP  32 , for example a portion of the frame  122  of upper CSP  32 . It will be understood by those skilled in the art with benefit of this disclosure that ejector device  74  may be arranged in different configurations without departing from the scope of this disclosure. For example, ejector device  74  may be reversed so as to be attached with upper CSP  32  wherein piston rod  74   a  acts against lower CSP  34 . 
       FIG. 14  is a schematic diagram of sequence block  108 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 ,  2  and  3 . In sequence block  108 , blind rams  56  are actuated to the closed position sealing bore  40  (see  FIGS. 3 and 8A ,  8 B) to block any fluid that may be flowing up from well  18  through BOP stack  14 . The actuation of blind rams  56  may be provided by lower controller  82  and accumulator(s)  50  located in lower accumulator pod(s)  62 . 
       FIG. 15  is a schematic diagram of sequence block  110 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 ,  2  and  3 . In sequence block  110 , methanol  76  may be injected into lower CSP  34  to prevent hydrate formation CSP  28 , in particular in the vents (e.g., vent valves  66   a ) of vent system  64 . The injection of methanol  76  may be provided for example by lower controller  82  and may be powered by accumulator(s)  50  located in lower accumulator pod(s)  62 . 
       FIG. 16  is a schematic diagram of sequence block  112 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 ,  2  and  3 . In sequence block  112 , lower controller  82  actuates hydraulic power (e.g., accumulator  50 ) to actuate the open vent valves  66   a  from the open to the closed position. 
       FIG. 17  is a schematic diagram of sequence block  114 , according to one or more aspects of subsea well safing system  10 , which is described with further reference to  FIGS. 1 ,  2 , and  3 . Subsequent to closing vent valves  66   a  in sequence block  112 , lower controller  82  can initiate and perform a formation stability test for example by monitoring wellhead temperature and pressure via one or more sensors  84 . 
     If stable formation conditions are indicated, safing system  10  may be placed in a standby condition until recovery operations can be initiated and completed. If unstable formation conditions are indicated, vent valves  66   a  may be opened to relieve pressure in an effort to prevent a subsurface blowout of well  18 , which will result in loss of the well and require more difficult and time consuming processes to plug well  18 . With effluent venting to the environment, a recovery riser  126  extending, for example from a vessel at surface  5 , may be connected to connection mandrel  68  of vent system  64  as depicted in  FIG. 3 . ROV  124  ( FIG. 2 ) may be utilized to connect flexible riser  126 . A valve, such as valve  68   b , may be operated to the open position permitting flow of effluent through mandrel  68  of vent system  64  into recovery riser  126  and to the surface; and the open vent valves  66   a  are operated to the closed position, thus providing a means to mitigate environmental damage until control of well  18  can be recovered. 
     According to at least one embodiment, a method of recovery of well  18  comprises closing in well  18  via lower CSP  34  and/or venting effluent from well  18  through vent system  64  and a recovery riser  126  to the surface. A marine riser  30  and choke line  44  and/or kill line  46  hydraulics are extended from the surface to lower CSP  34 . Choke and kill lines  44 ,  46  can be connected to BOP stack  14  and well  18  via choke stab  44   a  and kill stab  46   a  which are located on lower CSP  34  which is still connected to well  18 . Marine riser  30  in some circumstances may be connected to connector mandrel  72   b  of CSP connector  72  to reestablish hydraulic communication with well  18  through BOP stack  14 . Depending on the status of BOP stack  14  and formation stability, drilling mud may be circulated down one of marine riser  30 , kill line  46 , choke line  44 , and/or flexible riser  126  to kill well  18 . 
     According to one or more aspects, a subsea well safing package for installing on a subsea well includes a safing assembly connector interconnecting a lower safing assembly and an upper safing assembly, the safing assembly connector operable to a disconnected position. The lower safing assembly is configured to connect to the subsea well, for example via a blowout preventer stack and the upper safing assembly is configured to be connected to a marine riser. The lower safing assembly may include lower slips to engage a tubular suspended in a bore formed through the lower and the upper safing assemblies and the upper safing assembly may include upper slips operable to engage the tubular. A shear positioned between the upper slips and the lower slips is operable to shear the tubular. 
     According to one or more aspects a subsea well safing package is provided for installing on a subsea well having a safing assembly connector interconnecting a lower safing assembly and an upper safing assembly. The lower safing assembly including lower slips to engage and secure a tubular suspended in a bore formed through the lower and the upper safing assemblies and the upper safing assembly having upper slips operable to engage the tubular. A shear may be positioned between the upper slips and the lower slips to shear the tubular. The safing package may include an ejector device connected between lower safing assembly and the upper safing assembly that is operable to physically separate the upper safing assembly from the lower safing assembly. The ejector device may include an extendable piston rod. 
     The well safing package may include a vent operable between an open and a closed position. For example, the vent may be carried by the lower safing assembly and positioned below the lower slips when connected to the well. 
     A well safing package may include for example a vent carried by the lower safing assembly and positioned below the lower slips well and a deflector device positioned between the lower slips and the vent. The vent may be opened and the shutter device operated to a closed position to divert fluid flow toward the vent. In some embodiments the deflector device does not seal against the tubular suspended in the lower safing assembly. 
     A subsea well safing system according to one or more aspects includes a lower safing assembly connected to a subsea well and an upper safing assembly connected to a marine riser. A safing assembly connector interconnects the lower safing assembly and the upper safing assembly providing a bore therethrough in communication with the marine riser and the subsea well. An ejector device may be connected between the upper safing assembly and the lower safing assembly to physically separate the upper assembly and the connected marine riser from the lower safing assembly and the well. 
     The safing assembly may include, for example, lower slips operable to engage and secure a tubular suspended in the bore of the lower safing assembly and upper slips operable to engage and secure the tubular suspend in the bore of the upper safing assembly and a shear located between the lower slips and the upper slips operable to shear the tubular. A vent may be in communication with the bore and operable between a closed position and an open position. The safing system may include a deflector device located in the lower safing assembly between the lower slips and the vent that is operable to a closed position to divert fluid flow for example toward the vent. 
     A subsea well safing sequence includes utilizing a safing assembly installed between a subsea well and a marine riser. The safing assembly includes a lower safing assembly connected to the subsea well and an upper safing assembly connected to the marine riser, the safing assembly forming a bore between the marine riser and the subsea well. When the well safing sequence is initiated, securing a tubular that is suspended in the bore at a position in the lower safing assembly and securing the tubular at a position in the upper safing assembly. The tubular is sheared in the bore between the positions in the lower and the upper safing assemblies at which the tubular has been secured and physically separating the upper safing assembly and the connected marine riser from the lower safing assembly and the subsea well. 
     The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure. Those skilled in the art should appreciate that they may readily use the disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the disclosure. The scope of the invention should be determined only by the language of the claims that follow. The term “comprising” within the claims is intended to mean “including at least” such that the recited listing of elements in a claim are an open group. The terms “a,” “an” and other singular terms are intended to include the plural forms thereof unless specifically excluded.

Technology Classification (CPC): 4