Patent Abstract:
A subsea well safing method and apparatus adapted 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 adapted to connect the marine riser to the BOP stack. 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 is actuated to physically separate the upper safing assembly and connected marine riser from the lower safing assembly that is connected to the BOP stack.

Full Description:
RELATED APPLICATIONS 
     This application claims the benefit of U.S. provisional patent application No. 61/377,851 which was filed on Aug. 27, 2010. 
    
    
     BACKGROUND 
     This section provides background information to facilitate a better understanding of the various aspects of the invention. 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. 
     The invention relates in general to wellbore operations and more particular to safety devices and methods to seal, control and monitor subsea oil and gas wells. 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 (formation kick) emanating from a well reservoir during drilling. 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, rig (the equipment system used to drill a wellbore) 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, due to the failure the wellhead equipment was damaged creating additional obstacles to recovering control of the well. 
     SUMMARY 
     According to one or more aspects of the invention, a subsea well safing package for installing on a blowout preventer stack on a subsea well comprises a safing assembly connector interconnecting a lower assembly and an upper safing assembly, the safing assembly connector operable to a disconnected position, wherein the lower safing assembly is adapted to be connected to a blowout preventer stack on a subsea well and the upper safing assembly is adapted to be connected to a marine riser; the lower assembly comprising lower slips to engage a tubular suspended in a bore formed through the lower and the upper safing assemblies; the upper safing package comprising upper slips operable to engage the tubular; and a shear positioned between the upper slips and the lower slips, the shear operable to shear the tubular. 
     A subsea well safing system according to one or more aspects of the invention comprises a safing assembly comprising a lower safing assembly connected to a blowout preventer stack connected to a subsea well and an upper safing assembly connected to a marine riser; a safing assembly connector interconnecting the lower safing assembly and the upper safing assembly providing a bore therethrough in communication with the marine riser and the well; and an ejector device connected between the upper safing assembly and the lower safing assembly, the ejector device operable to physically separate the upper assembly and connected marine riser from the lower safing assembly. 
     According to one or more aspects of the invention, a subsea well safing sequence comprises utilizing a safing assembly installed between a blowout preventer stack of a subsea well and a marine riser, the safing assembly comprising a lower safing assembly connected to the blowout preventer stack and an upper safing assembly connected to the marine riser forming a bore between the riser and the blowout preventer stack; securing a tubular suspended in the bore at a position in the lower safing assembly; securing the tubular at a position in the upper safing assembly; shearing the tubular in the bore between the position in the lower safing assembly and the position in the upper safing assembly at which the tubular has been secured; and physically separating the upper safing assembly and the connected marine riser from the lower safing assembly connected to the blowout preventer stack. 
     The foregoing has outlined some of the features and technical advantages of the invention in order that the detailed description of the invention that follows may be better understood. Additional features and advantages of the invention will be described hereinafter which form the subject of the claims of the invention. 
    
    
     
       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 invention utilized in a subsea well drilling system. 
         FIG. 2  depicts a subsea safing system according to one or more aspects of the invention, wherein the safing sequence has been initiated and the 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 invention in isolation. 
         FIG. 4A-4B  is a flow chart of a subsea well safing sequence according to one or more embodiments of the subsea well safing system. 
         FIGS. 5-17  are schematic diagrams of safing sequence steps according to one or more embodiments of the subsea well safing system. 
         FIG. 5A  is a sectional view of a vent system according to one or more embodiments of the well safing package shown along the line I-I of  FIG. 5 . 
         FIG. 8A  is a sectional view of an embodiment of a deflector device shown along the line I-I of  FIG. 8 . 
         FIG. 8B  is a sectional, side view of an embodiment of the impingement device of  FIG. 8A  in isolation. 
         FIG. 13A  illustrates the 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. Moreover, the formation of a first feature over or on a second feature in the description that follows may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact. 
     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 being the top point and the total depth of the well being 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 of the invention, the subsea well safing system provides a mechanism to separate the riser from the blowout preventer stack and the well in a manner intended to limit the physical damage to the well drilling system and to enhance the potential for successfully reconnecting to the well, for example via 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  also 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  comprises safing package, or assembly, referred to herein as a catastrophic safing package (“CSP”)  28  that is landed on BOP system  14  and operationally connects a riser  30  extending from platform  31  (e.g., vessel, rig, ship, etc.) to BOP stack  14  and thus well  18 . CSP  28  comprises an upper CSP  32  and a lower CSP  34  that are adapted to separate from one another in response to initiation of a safing sequence thereby disconnecting 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. According to one or more embodiments of the invention, subsea well safing system  10  may automatically initiate the safing sequence in response to the correspondence of monitored parameters to selected safing triggers. According to one or more embodiments of the invention CSP  28  may include an accumulator  29 , see  FIGS. 3 and 7 , hydraulically connected to wellhead  16  to operate the wellhead connector lock as further described below. In the embodiment of depicted 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 consist of 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  24 . 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  commonly comprises a riser adapter for connecting the lowest end  30   a  of riser  30  (e.g., bolts, welding, hydraulic connector) and 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 on along the length of riser  30 . Riser connector  36  may further comprise one or more ports for connecting fluid (i.e., hydraulic) and electrical conductors, i.e., communication umbilical, which may extend along (exterior or interior) 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 . 
     Riser  30  is a tubular string that extends from the drilling platform  31  down to well  18 . The riser is in effect an extension of the wellbore extending through the water column to drilling vessel  31 . The 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 riser  30 . Drilling mud and drill cuttings can be returned to surface  5  through riser  30 . Communication umbilical (e.g., hydraulic, electric, optic, etc.) can be deployed exterior to or through 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  according to one or more aspects of the invention in isolation. CSP  28  depicted in  FIG. 3  is further described with reference to  FIGS. 1 and 2 . In the depicted embodiment, CSP  28  comprises upper CSP  32  and lower CSP  34 . Upper CSP  32  comprises 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 . CSP  28  comprises 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  44   a ,  46   a . In some embodiments, riser connector  42  may also comprise a flex joint. 
     CSP  28  comprises an internal longitudinal 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 diameter of bore  40 . 
     Upper CSP  32  further comprises a slips  48  (i.e., safety slips) adapted to close on tubular  38 . Slips  48  are actuated in the depicted embodiment by hydraulic pressure from an accumulator  50 . In the depicted embodiment, CSP  28  comprises 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. In the depicted embodiment, 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 . In one or more embodiments of the invention, the pressure in accumulators  50  are monitored and accumulators  50  may be actuated in sequence and as needed to ensure that adequate hydraulic pressure is available and provided for actuation of CSP devices such as slips  48 . 
     Lower CSP  34  comprises a connector  54  to connect to BOP stack  14 , for example, via riser connector  36 , 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). Vent system  64  comprises one or more valves  66 . In this embodiment, vent system  64  comprise 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 . 
     In the depicted embodiment, lower CSP  34  further comprises a deflector device  70  (e.g., impingement device, shutter ram) 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 , in particular lower CSP  34 , may include methanol, or other chemical, source  76  operationally connected for injecting into lower CSP  34 , for example to prevent hydrate formation. 
     Upper CSP  32  and lower CSP  34  are detachably connected to one another by a connector  72 . CSP connector  72  is depicted in the illustrated embodiments as a collet connector, comprising a first connector portion  72   a  and a second mandrel connector portion  72   b  which are illustrated for example in  FIG. 13A . 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 riser  30  from lower CSP  34  and BOP stack  14  after connector  72  has been actuated to the unlocked position. 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. 
     According to one or more embodiments of the invention, CSP  28  comprises 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 comprise one or more controllers which are located at different locations. For example, in at least one embodiment, control system  78  comprise 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 the embodiments depicted in  FIGS. 3 to 17 , control system  78  includes upper controller  80  and a lower controller  82 . Each of upper and lower controllers  80 ,  82  may comprise 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 comprise control valves. 
     According to at least one embodiment, one of the controllers, for example lower controller  82 , serves as the primary controller and provides command and control sequencing to various subsystems of safing package  28  and/or communicates 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 embodiments of subsea well safing system  10  is disclosed. In sequence step  88 , the safing sequence is initiated in response to monitoring the limit state sensor  84  package by upper controller  80 . In sequence step  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 step  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 step  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 step  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 device  70  to a closed position. In sequence step  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 step  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 step  102 , tubular  38  is sheared in lower CSP  34  by activating shears  58 , see, e.g.,  FIGS. 1 ,  3  and  11 . In sequence step  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 step  106 , riser  30  and upper CSP  32  are 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 step  108 , (see, e.g.,  FIGS. 1-3  and  14 ) blind rams  56  are closed to shut-off fluid flow from BOP stack  14  through bore  40  (see  FIG. 3 ) and escaping to the environment. In sequence step  110 , treating hydrate formation in lower CSP  34  by injecting methanol, see, e.g.,  FIGS. 1-3  and  15 . In sequence step  112 , closing the vents  66   a  opened in vent system  64  in sequence step  90 , see, e.g.,  FIGS. 1-3  and  16 . In sequence step  114 , performing a formation stability test, see, e.g.,  FIGS. 1-3  and  17 . 
       FIG. 5  is a schematic diagram of sequence step  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  is activated to provide hydraulic power to the valve actuators  116  of controller  82 . Lower controller  82  continuously monitors the accumulator pod  62  pressure 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 step are 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 step  92 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 and 3 . In sequence step  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 step  94 , according to one or more embodiments 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 steps, e.g., when deflector device  70  is closed, slips  48 ,  60  are closed; and due to the loss of hydraulic pressure to wellhead connector lock  120  when riser  30  is disconnected from BOP stack  14  disconnecting any hydraulic sources extending along riser  30  to CSP  28 . 
       FIG. 8  is a schematic diagram of sequence step  96 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 ,  3 ,  8 A and  8 B. In sequence step  96 , controller  82  actuates deflector device  70 , described in the embodiments of  FIG. 8 ,  8 A and  8 B as shutter ram  70 , to a closed position (see  FIG. 8A ) in response to applying hydraulic pressure in the embodiment of  FIG. 8  from a hydraulic accumulator  50  of lower accumulator pod  62 . In the closed position, deflector device  70  diverts fluid flow from passing through annulus  41  of CSP  28  to vent system  64  and open vent valves  66   a . The closed shutter ram  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 . Shutter ram  70  may be provided in various manners and configurations. Referring to  FIG. 8A , tubular  38  is depicted substantially centered within bore  40  of shutter ram  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 as 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 step  98 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 and 3 . In sequence step  98 , controller  82  actuates lower slips  60  (e.g., bi-directional slips) securing tubular  38  within lower CSP  34  in preparation for sequence step  102 . In some embodiments, lower slips  60  may comprise deflector armor to divert fluid flow toward vent system  64  instead of, or in addition to, shutter ram  70  described and disclosed with reference to sequence step  96  and  FIGS. 8 ,  8 A, and  8 B. 
       FIG. 10  is a schematic diagram of sequence step  100 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 and 3 . In sequence step  100 , upper slips  48  are actuated to engage tubular  38  within upper CSP  32 . In this embodiment, sequence step  100  is actuated by upper controller  80 . As with other sequence steps, 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 step device (i.e., slips  48  in sequence step  100 ). 
       FIG. 11  is a schematic diagram of sequence step  102 , according to one or more embodiments 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 step  104 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 ,  2 ,  3  and  13 A. In sequence step  104 , CSP connector  72  is actuated to the open, or disconnected, position permitting separation of upper CSP  32  from lower CSP  34  in sequence step  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 riser, for re-entry into well  18 . 
       FIG. 13  is a schematic diagram of sequence step  106 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1-3  and  13 A. In sequence step  106 , ejector devices  74  (i.e., ejector bollards) are actuated to physically separate upper CSP  32  and 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 the embodiment of  FIG. 13 , actuation of ejector devices  74  is provided by upper controller  80  and accumulator(s)  50  located in upper accumulator pod  52 . 
     Typically, riser  30  will be in tension which will assist in pulling the disconnected upper CSP  32  vertically away from lower CSP  34 . In addition, the water currents and deflection in riser  30  (e.g., offset from platform  31 ) will assist in moving riser  30  and 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 means for reconnection to surface sources during recovery operations. 
     In the depicted embodiments, 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  shown generally in  FIG. 13 . 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 the invention. 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 step  108 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 ,  2  and  3 . In sequence step  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 . In the depicted embodiment, actuation of blind rams  56  is provided by lower controller  82  and accumulator(s)  50  located in lower accumulator pod(s)  62 . 
       FIG. 15  is a schematic diagram of sequence step  110 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 ,  2  and  3 . In sequence step  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 . In the depicted embodiment, the injection of methanol  76  is provided 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 step  112 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1 ,  2  and  3 . In sequence step  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 step  114 , according to one or more embodiments of subsea well safing system  10  which is described with further reference to  FIGS. 1-3 . Subsequent to closing vent valves  66   a  in sequence step  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 riser  126  and to the surface; and the open vent valves  66   a  are operated to the closed position, thus providing a means to limit environmental damage until control of well  18  can be recovered. 
     According to 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 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 . 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 riser  30 , kill line  46 , choke line  44 , and/or flexible riser  126  to kill well  18 . 
     According to one or more aspects of the invention, a subsea well safing package for installing on a blowout preventer stack on a subsea well comprises a safing assembly connector interconnecting a lower safing assembly and an upper safing assembly, the safing assembly connector operable to a disconnected position, wherein the lower safing assembly is adapted to be connected to a blowout preventer stack on a subsea well and the upper safing assembly is adapted to be connected to a marine riser; the lower assembly comprising lower slips to engage a tubular suspended in a bore formed through the lower and the upper safing assemblies; the upper safing assembly comprising upper slips operable to engage the tubular; and a shear positioned between the upper slips and the lower slips, the shear operable to shear the tubular. 
     According to one or more aspects of the invention a subsea well safing package is provided for installing on a blowout preventer stack on a subsea well comprises a safing assembly connector interconnecting a lower safing assembly and an upper safing assembly, the safing assembly connector operable to a disconnected position, wherein the lower safing assembly is adapted to be connected to a blowout preventer stack on a subsea well and the upper safing assembly is adapted to be connected to a marine riser; the lower assembly comprising lower slips to engage a tubular suspended in a bore formed through the lower and the upper safing assemblies; the upper safing assembly comprising upper slips operable to engage the tubular; a shear positioned between the upper slips and the lower slips, the shear operable to shear the tubular; and an ejector device connected between lower safing assembly and the upper safing assembly, the ejector device operable to physically separate the upper safing assembly from the lower safing assembly. 
     The package may include a vent carried by the lower safing assembly, the vent operable between an open and a closed position. In at least one embodiment the package further includes a vent carried by the lower safing assembly and positioned below the lower slip when connected to the well, wherein the vent is operable between an open and a closed position. 
     According to one or more embodiments of the invention, the ejector device includes an extendable piston rod. The piston rod may be extendable in response to the application of hydraulic pressure. 
     According to one or more embodiments of the invention, the safing package comprises a hydraulic accumulator disposed with the safing assembly and in hydraulic communication with the lower slips. In some embodiments, a plurality of hydraulic accumulators are arranged in an upper accumulator pod, wherein the upper accumulator pod is in hydraulic communication with the upper slips. According to at least one embodiment the shear is in hydraulic communication with at least one of a lower hydraulic accumulator pod and an upper hydraulic accumulator pod. Similarly, the ejector device is in hydraulic communication with at least one of a lower hydraulic accumulator pod and an upper hydraulic accumulator pod in some embodiments. 
     According to one or more embodiments, a vent is carried by the lower safing assembly and positioned below the lower slip when connected to the well, wherein the vent is operable between an open and a closed position; and a deflector device is positioned between the lower slips and the vent, wherein the deflector device is operable 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 when in the closed position. 
     A subsea well safing system according to one or more aspects of the invention comprises a safing assembly comprising a lower safing assembly connected to a blowout preventer stack connected to a subsea well and an upper safing assembly connected to a marine riser; a safing assembly connector interconnecting the lower safing assembly and the upper safing assembly providing a bore therethrough in communication with the marine riser and the well; and an ejector device connected between the upper safing assembly and the lower safing assembly, the ejector device operable to physically separate the upper assembly and connected marine riser from the lower safing assembly. 
     The safing assembly can further comprise, for example, lower slips operable to engage a tubular suspended in the bore of the lower safing assembly; upper slips operable to engage the tubular suspend in the bore of the upper safing assembly; a shear located between the lower slips and the upper slips operable to shear the tubular; and a vent in communication with the bore, the vent operable between a closed position and an open position. In some embodiments, the safing system further comprises a deflector device located in the lower safing assembly between the lower slips and the vent, the deflector device operable to a closed position to divert fluid flow toward the vent. 
     According to one or more aspects of the invention, a subsea well safing sequence comprises utilizing a safing assembly installed between a blowout preventer stack of a subsea well and a marine riser, the safing assembly comprising a lower safing assembly connected to the blowout preventer stack and an upper safing assembly connected to the marine riser forming a bore between the riser and the blowout preventer stack; securing a tubular suspended in the bore at a position in the lower safing assembly; securing the tubular at a position in the upper safing assembly; shearing the tubular in the bore between the position in the lower safing assembly and the position in the upper safing assembly at which the tubular has been secured; and physically separating the upper safing assembly and the connected marine riser from the lower safing assembly connected to the blowout preventer stack. 
     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