Patent Publication Number: US-9903179-B2

Title: Enhanced hydrocarbon well blowout protection

Description:
RELATED APPLICATIONS 
     The present application is a continuation application of non-provisional patent application Ser. No. 14/740,399 filed on Jun. 16, 2015, which is a continuation of non-provisional patent application Ser. No. 13/151,669 filed on Jun. 2, 2011, which claims the benefit of the following prior filed provisional applications: provisional application No. 61/350,803, filed on Jun. 2, 2010; provisional application No. 61/352,385, filed on Jun. 7, 2010; provisional application No. 61/357,519, filed on Jun. 22, 2010; provisional application No. 61/362,055, filed on Jul. 7, 2010; each of which is hereby incorporated in their entirety by reference. 
    
    
     BACKGROUND 
     High pressure gas and oil deposits underground can explode through an oil well, gushing oil and gas into the environment, causing explosions killing people, and inflicting tremendous damages to the environment and wild life. Such risks to human and environment though not limited to off-shore wells are particularly severe and difficult to manage at deep ocean off-shore sites. Case in point is the Deepwater Horizon drilling rig explosion that occurred Apr. 20, 2010 at the Macondo prospect oil field in the Gulf of Mexico. The explosion resulted in the sinking of the rig, 4.9 million barrels of crude oil spewed into the ocean, 50 billion cubic feet of methane gas spewed into the environ, and 2 million barrels of dispersants injected into the sea. Many estimated that the Deepwater Horizon disaster has caused damages in the order of a hundred billion US Dollars, and inestimable further damages yet to unfold. 
     A conventional blowout preventer (BOP) used in hydrocarbon wells is a costly and massive contraption. The one used at the Macondo Well of the Deepwater Horizon disaster was about 53′ high×16′×16′ wide and weighing 300 tons. It is installed atop a well head with an approximately 36″ flange connection to a well pipe about 20″ in diameter. A blowout preventer is a complex multiple-stage pipe-shearing and ramming device powered by batteries, controlled electrically via electrical wiring and electronic communications circuitry between the blowout preventer and the drilling rig, all of which may fail when encountering hostile conditions such as fire, explosion, blowout, and human error. In the case of the Deepwater Horizon disaster, the blowout preventer&#39;s electrical components failed at the very beginning. Attempts to mechanically activate the pipe-shearing and pipe-ramming devices using deep-sea robots also failed because the drill pipe remaining in the blowout preventer jammed these devices. In addition, the blowout preventer was listing 12 to 16 degrees risking a catastrophic toppling. Postmortem examination of the blowout preventer showed extensive corrosion. There was no access to the well head and the well below the blowout preventer, and no means to remove the damaged blowout preventer before the well was sealed through a five month long conventional “bottom kill” procedure, during which a relief well was drilled to access the bottom of the problem well to plug it. If the casing system of the well is compromised, stemming the blowout hydrocarbon flow at or above blowout preventer would result in high pressure hydrocarbon breaching grounds below the sea floor and escaping through the sea floor. 
     Conventional remedial methods were tried and failed during the many months following the Deepwater Horizon drilling rig explosion. During that time, the oil spilled and the dispersant released into the Gulf of Mexico traveled wide with the gulf current, causing disastrous environmental and commerce damages. The conventional methods tried and failed included the use of coffered domes and top hats which are massive up-side-down funnels with a riser pipe at the top that were lowered over the hydrocarbon spewing broken pipe sections in hope of capturing the spewing hydrocarbon. Unfortunately frozen hydrate formed to block the riser pipe. 
     Another method that was tried and failed was the insertion of a thinner good pipe into the damaged pipe section in an attempt to capture some of the oil and gas flow. Unfortunately, the hydrocarbon pressure enlarged the broken gap at the pipe section near the top of the blowout preventer and spewed out there instead. 
     Another method that was tried and failed was the pumping golf balls, tire shreds, ropes, knots, and other junk and mud into the blowout preventer, hoping to plug the pipe in the blowout preventer to stem the massive hydrocarbon flow. Unfortunately, the high pressure hydrocarbon flow spewed out the junk with it. 
     Another method that was tried and failed was a hat-like contraption, called a lower marine riser package (LMRP), with a wide open bottom and a pipe at the top. This was placed loosely fitting over the cut pipe opening at the top of blowout preventer, hoping to catch some of the spewing hydrocarbon. Unfortunately, more than 75% of the spewing hydrocarbon was reflected off the hat-top of the LMRP and ejected down into the surrounding ocean. 
     SUMMARY 
     Protection at a hydrocarbon well is enhanced by placing a blowout preventer over a well head. An adapter is connected to the blowout preventer. The adapter includes a valve that when turned off prevents non-production flow from the blowout preventer to a riser pipe. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         FIG. 1  shows an anchoring infrastructure for a blowout preventer with piers drilled into bedrock in accordance with an embodiment of the disclosure. 
         FIG. 2  shows an alternate example of anchoring piers with pier-anchoring discs that anchor the piers in case the location has deep sediment or uneven sea floor. 
         FIG. 3  and  FIG. 4  show a flange sealable capping and flow capturing device, sealable hydrocarbon capturing pipe adaptor (SHCPA) with a tubular body and flange connectors, an optional flow control valve, and an optional side branch adaptor in accordance with embodiments of the disclosure. 
         FIG. 5  shows a pipe plugging assembly with a flanged pipe adaptor and a flow-control valve in accordance with an embodiment of the disclosure. 
         FIG. 6  and  FIG. 7  show use of a reaming device to ream a smooth sealable surface in the pipe that mates with the plug shown in  FIG. 5  in accordance with an embodiment of the disclosure. 
         FIG. 8  shows a pipe sleeve lined with sealable elastomeric material used to make a sealed connection between the pipe and the capping device illustrated in  FIG. 3  in accordance with an embodiment of the present disclosure. 
         FIG. 9  shows a well head protection base plate composed of two self-sealing half plates installed at a well head at the sea floor level in accordance with an embodiment of the present disclosure. 
         FIG. 10  shows a hydrocarbon containment and collection chamber in accordance with an embodiment of the present disclosure. 
         FIG. 11 ,  FIG. 12  and  FIG. 13  show several electrically and hydraulically operable pipe squeezers in accordance with an embodiment of the present disclosure. 
         FIG. 14  shows a roaming pipe squeezer in accordance with an embodiment of the present disclosure. 
         FIG. 15 ,  FIG. 16 , and  FIG. 17  show various assemblies that can replace a conventional blowout preventer in accordance with an embodiment of the present disclosure. 
         FIG. 18 ,  FIG. 19  and  FIG. 20  show multi-port branched pipe adaptors (MPBPA) in accordance with an embodiment of the present disclosure. 
         FIG. 21  shows a device driver deploying well monitoring and inspection devices, pipe repairing assembly, and well plugging devices in accordance with an embodiment of the present disclosure. 
         FIG. 22  and  FIG. 23  show a multi-port branched pipe adaptor (MPBPA) mounted above, and below a blowout preventer in accordance with embodiments of the present disclosure. 
         FIG. 24 ,  FIG. 25  and  FIG. 26  show pipe assemblies using a one-way check valve to prevent up-flow as well as various configurations of such one-way check valves in accordance with embodiments of the present disclosure. 
     
    
    
     DESCRIPTION OF THE EMBODIMENTS 
     This description herein incorporates by reference all the subject matter disclosed in provisional application No. 61/350,803, filed on Jun. 2, 2010; provisional application No. 61/352,385, filed on Jun. 7, 2010; provisional application No. 61/357,519, filed on Jun. 22, 2010; provisional application No. 61/362,055, filed on Jul. 7, 2010. 
     Hydrocarbon well safety is enhanced by protecting a blowout preventer, and its connection to a riser pipe and a well head. In various embodiments, infrastructure is anchored to protect well components and to deploy assembly and operations. A flange sealable capping and hydrocarbon capturing pipe adaptor is used to cap an oil and gas spewing BOP and capture the hydrocarbon flow, a sealing plug with a sealable pipe adaptor is used to seal a broken pipe sits atop the BOP and to capture the spewing blowout hydrocarbon flow. A base-plate is mounted on the sea floor to protect the well head and anchor the BOP. A containment and protection chamber with a venue for hydrocarbon extraction is mounted on the base plate. A safer and more effective blowout preventer is presented that replaces a conventional blowout preventer. A multi-port branched pipe-adapter (MPBPA) can be mounted above and below a blowout preventer to improve well access and safety, and to capture hydrocarbon flow in case of a blowout event. A MPBPA enables full collection of the blowout hydrocarbons while conducting well monitoring, inspection, repair, plugging, or “bottom killing” the well from the well through the MPBPA after a blowout event. 
     Pre-event fabrication and installation of devices and apparatus described in this disclosure will enhance well safety, help prevent blowout events, enable quick and effective remedial responses, and minimize risks and damages from a blowout event. Additional benefits include prevention of accidental damages or unauthorized access to the blowout preventer, well head, and wellbore, securing wellbore access regardless of the blowout preventer condition, the ability to remove and replace a problematic blowout preventer, and the ability to separately capture and collect methane gas from oil. 
     The concepts illustrated herein are extendable by those skilled in the arts to a multitude of variations, combinations and applications in the oil and gas industry including exploration, production, and service and maintenance operations not specifically discussed in this application. 
     Disclosed embodiments are applicable to all phases of a well creation and operations. Even though the embodiments are illustrated with a vertically drilled off-shore well, many disclosed elements are also suited for non-vertically drilled wells and on shore wells. 
       FIG. 1  shows an anchoring infrastructure for a blowout preventer  306 . To form an anchoring infrastructure  100 , anchoring piers  101  are driven into the sea floor  90  through a sediment layer  91  into bedrock  92  at a suitable distance from a well. Mounting and positioning devices  102  mount a platform  103  onto anchoring piers  101  to support and protect well components or to deploy various assemblies or well operations. Anchoring infrastructure  100  also serves to position and align the assembly that includes blowout preventer  306 , platform  103 , pipes, various apparatus and components in anchoring infrastructure  100 . 
     For pre-event installation, platform  103  incorporates a via for connecting BOP  306  to a riser pipe  104 . A BOP to riser pipe flange and clamp  105  is mounted above a blowout preventer  306  and platform  103 . A flange mounted flexible pipe section  210  can be mounted below riser pipe  104  and on top a sealable hydrocarbon capturing pipe adaptor (SHCPA)  200  as described in  FIG. 3  or a MPBPA  500  as described in  FIG. 18 , which is mounted to the top flange of BOP on top platform  103 . Platform  103  anchors well components above it, and protects well components below it including blowout preventer  306 , and well head  303 . 
     If riser pipe  104  falls with a sinking rig, as occurred during the Deepwater Horizon disaster, riser pipe  104  may break anywhere between the rig (not shown) and the flexible pipe section, or at worst at the component immediately above platform  103 . The flexible pipe section cushions the drag from the fallen riser pipe and protects SHCPA  200  or MPBPA  500 . Platform  103  and everything below, including blowout preventer  306  are protected and most likely will remain intact. Alternately, platform  103  can be located immediately below the top flange of SHCPA  200  or MPBPA  500  connecting to the top of BOP  306 , with only the flexible pipe and riser pipe above platform  103 . If either flexible pipe  210  or riser pipe  104 , or both are damaged, they can be easily removed and replaced. 
     A well head protection base plate  300  is shown mounted at the sea floor level. A containment and protection chamber can be mounted on base plate  300 , as illustrated in  FIG. 10  where containment and protection chamber  310  is mounted on base plate  300 . Containment and protection chamber  310  also serves to protect the well and to capture hydrocarbon flow leaking from the well in case of a blowout or an accident. 
     A blowout preventer support framework can be mounted to anchor on base plate  300  and positioned immediately below blowout preventer  306  so that the weight of blowout preventer  306  sits on the framework. Alternately, the framework can be anchored to anchoring piers  101 . This is illustrated in  FIG. 22  where is shown a blowout preventer support and isolation framework  760  upon which a blowout preventer  306  sits. 
     As shown in  FIG. 1 , for example, platform  103  can be made with an apparatus mounting hole  110  used for mounting various devices and apparatus. This allows platform  103  to function as a general purpose operation launching counter-pressure platform as needed for deploying and mounting devices or apparatus used in response to a high pressure blowout hydrocarbon flow. For example, operations utilizing platform  103  might include an operation to cap and capture the blowout hydrocarbon flow, an operation to squeeze shut or cut off damaged riser pipe, an operation to mount an encapsulation or containment and protection chamber to enclose the well and contain and capture leaking hydrocarbon flow, an operation to remove pipes stuck in the blowout preventer, and an operation to mount an assembly driving string for launching sensors, plugs, and repair assembly into the well. 
       FIG. 2  shows additional detail of pier anchoring discs  106  located at sea floor  90  where piers  101  penetrate sea floor. Pier anchoring discs  106  have through-holes through which piers  101  are driven into the sea floor  90 . Pier anchoring discs  106  help anchor piers  101 , reducing the depth into which piers  101  need to be driven into the sea floor  90 . These pier anchoring discs are especially helpful when the sediment layer is deep, or when the geography around the well head is not flat over an adequately large area. 
       FIG. 3  shows a sealable hydrocarbon capturing pipe adaptor (SHCPA)  200  that can be used for capping a problem well leaking from above the blowout preventer, and to collect and harvest the hydrocarbon flow to a collection facility. Sealable hydrocarbon capturing pipe adaptor SHCPA  200  has a flange  201  for connecting to blowout preventer  306 . A flange  203  allows connection to a hydrocarbon collection pipe  204  or a riser pipe containing a hydrocarbon collection pipe. An optional flow control valve  202  can be included to provide additional operational flexibility. At least one branch can be added to SHCPA  200 . The top of SHCPA  200  can be capped, as shown in  FIG. 4 , which also shows  2  side branches. More than 2 branches can be added. 
     In a normal operation of an oil well there should never be hydrocarbon presence in the well space outside of a production pipe. Hydrocarbon presence there is a rogue hydrocarbon presence and indicates trouble. The legitimate fluids in this space are drilling fluids (also called drilling mud), sea water and occasionally cement slurry. This space includes the casing pipe string below the well head, the BOP core, and the riser pipe outside of the production pipe within. Before the production pipe is installed, there should be no hydrocarbon presence in the well all the way from the low end of the casing pipe through the BOP and riser pipe up to the rig. When sensing a hydrocarbon up flow from the bottom of the well—which pushes drilling fluid up at the top end, more drilling mud must be pumped down to increase counter pressure to expel the rogue hydrocarbon back down to the reservoir. During drilling phase, a relatively small diameter drill pipe string (passing through the center of a riser pipe, the BOP tubular core, and the casing pipe) pumps down drilling fluid into the well bore to cool the drill head attached to the drill pipe through a collar at the bottom end of the drill pipe and circulate the formation debris such as rocks, sand and soil up with the drilling fluid through the well bore, the casing pipe, the BOP tubular core and the riser pipe, to the drilling rig. The debris is filtered out, and the drilling fluid re-circulated down to the well bore. During the drilling process, the well bore size is progressively reduced and progressively smaller diameter casing pipe strings are installed into the well bore to line the well and isolate the earth formation from the well. Typically, the last two layers of casing pipe strings reach the reservoir. The annular space between the layers and the core space of the inner most casing pipe are filled with drilling fluid. The bottom end of the annular space is sealed from the reservoir with cement. The bottom of the casing pipe is sealed from the reservoir with a “cement shoe.” Heavy drilling fluid column inside the wellbore counter balances the hydrocarbon pressure in the reservoir. Above a safe level of drilling fluid column, sea water is used to fill the space. The production pipe is installed inside the inner most casing pipe during a “completion” process sometime after the drilling process is completed. The production pipe assembly goes from the rig, pass through the riser pipe, BOP core, through the center of the casing pipe down to the reservoir. During a production mode, the usually hot hydrocarbons are manipulated to flow up the production pipe to the rig at a controlled rate, which is production flow. Every other flow that happens in these pipes is a non-production flow. The annular space in the riser pipe, the BOP core, and the casing pipe outside the production pipe is filled with drilling fluid or sea water, and sometimes injected nitrogen gas to balance pressure and keep the well bore at an appropriate temperature range. 
     If sealable hydrocarbon capturing pipe adaptor SHCPA  200  is not installed pre-event, it can be mounted to blowout preventer  306  using an undersea robot such as a Remotely Operated Undersea Vehicle (ROV). Hydrocarbon collection pipe  204  can then be attached to flange  203 . Flow control valve  202  is kept open through the process to minimize resistive pressure from the blowout flow. 
     Alternatively, sealable hydrocarbon capturing pipe adaptor SHCPA  200  can be attached to a riser pipe at sea level, and lowered with the riser pipe to blowout preventer  306  to make a flange-to-flange connection to blowout preventer  306  at flange  201  using an ROV. Flow control valve  202  can be kept open when attaching flange  201  to the blowout preventer flange to minimize resistive pressure from the blowout flow. The valve can be closed to stop the hydrocarbon flow when desirable—for example, when threat of storm mandates a connected rig or an oil storage ship to leave for safe harboring, or when an oil storage ship is full and ready to disengage. 
     An optional branch  205  with control valve  206  and collection pipe flange  207  can be added as an additional collection channel or as a diverting channel when desirable. For example, after sealable hydrocarbon capturing pipe adaptor SHCPA  200  is attached to blowout preventer  306 , diverting the flow to side branch  205  helps clear the visibility and resistive pressure for attaching hydrocarbon collection pipe  204  to the assembly at flange  203 . Another example is when a storage ship is to disengage and another ship engaged, the side branch can be used to divert the hydrocarbon flow to the new ship before valve  202  is shut off to disengage the first ship. Side branch adaptor  205  includes pipe connecting flange  207  and control valve  206 . Multiple side branches are incorporated for operational needs and flexibility. 
     When SHCPA  200  is to be used for pre-event installation, a pressure or hydrocarbon sensor (or both), sensor assembly  208  is added to close control valve  202  when hydrocarbon presence is detected. The closing of control valve  202  will divert the rogue hydrocarbons to branch  205 , which is further piped to a storage unit at seafloor while remedial action is sought, or to wait for a suitable time to transport to a collection facility at sea surface. A collection facility is any combination of the following: a ship, a tanker, a rig, a processing facility, a storage unit or a storage tank, or anything that collects. And it can be located at or near the sea surface (hence forth as at sea surface) or at or near sea floor (hence forth as at seafloor). A storage unit is any combination of the following: a storage tank (or multiple storage tanks), a storage tank without outlet, or a storage tank with an inlet and an outlet. The storage unit can be further equipped with a manifold as shown in  FIG. 17  to fill a storage tank (or multiple storage tanks) of a size convenient for transport from seafloor to a collection facility at sea surface. Additional optional branches can be added to  205  to provide more functions. A flexible pipe section with top and bottom flange connectors can be added to SHCPA  200  as desired, for example, for the purpose of shock absorption or drag isolation. 
     If after a blowout event a damaged riser pipe is cut at above the blowout preventer and cannot be easily or safely removed from the blowout preventer, a plugging device, such as a pipe plug  235  shown in  FIG. 5 , can be used to plug the cut pipe, at least until the cut pipe is removed from blowout preventer  306 . 
     As shown in  FIG. 5 , pipe plug  235  incorporates a flange  226  for connecting to a hydrocarbon collection pipe  239 . Plug  235  can be used to plug a cut pipe  238 , and capture hydrocarbon flow through hydrocarbon collection pipe  239  connected to flange  226 . Pipe plug  235  can be used in conjunction with an optional assembly handling and counter pressure application accessory  210  to increase the area for handling pipe plug  235  and where force can be applied to help drive pipe plug  235  into the opening of cut pipe  238 . When needed, the assembly handling accessory  210  can be mounted on the general purpose counter pressure platform  103  anchored to anchoring infrastructure  100  shown in  FIG. 1 . A flow control valve  225  controls the hydrocarbon flow, and hydrocarbon collection pipe  239  connected to flange  226  harvests hydrocarbon flow to a storage ship, a storage terminal, or a temporary storage unit at seafloor. When and if the ship has to disengage, flow control valve  225  can be closed off if so desired. Flow control valve  225  also enables controlled pressure relief during and after the plugging process. 
     A pliable pipe sleeve lined with pliable sealing material can be used to make a sealed joint between sealable hydrocarbon capturing pipe adaptor SHCPA  200  shown in  FIG. 3  and cut pipe  238 . A reamer  241  can be used to generate a smooth sealable plug-mating surface at the opening of cut pipe  238 , as illustrated in  FIG. 6  and  FIG. 7 .  FIG. 6  shows a side cross sectional view and  FIG. 7  shows a top cross-sectional view of reamer  241  having a rotating cone  236  and an abrasive surface  237 . 
       FIG. 8  shows a pipe sleeve  256  lined with pliable material  252 . For example, pliable material  252  is an elastomeric material reinforced with para-aramid synthetic fiber or some other pliable material with suitable chemical and physical characteristics. Pipe sleeve  256  is further equipped at the top with a flange connector  255  to form a sealed connection with the bottom flange  201  of sealable hydrocarbon collection pipe adaptor SHCPA  200 . A pipe fastener  254  is used for tightening pipe sleeve  256  to cover and seal an imperfect pipe  246 . A slightly angled cone surface  253  facilitates a tight seal. 
     As shown in  FIG. 9 , whole base plate  300  is formed, for example, from half plates  301  and  302  tongue-in-grooved to form an oil sealed connection with each other. Base plate  300  is installed on the sea floor to surround and protect well head  303 . Base plate  300 , with its large horizontal surface resting on the seafloor is self anchoring. Additionally, through-holes can be added to the base plate to accommodate anchoring piers to drive through these holes into the sea floor to help anchoring the piers. As shown in  FIG. 1 , base plate  300  and anchoring piers  101  which are driven through holes in  300  into the base rock mutually anchoring one another&#39;s stability. Alternately, base plate  300  can be an independent anchoring apparatus. A sealing groove  304  supports a full enclosure containment and protection chamber. A two-piece well head brace  305  forms an oil tight seal with base plate  300  around well head  303 . Well head brace  305  is inserted into a center well-head through-hole of base plate  300  to brace well head  303 . Well head brace  305  can be removed for well head inspection. In a conventional well, blowout preventer  306  is mounted directly on top of well head  303  without benefit of a support structure. Base plate  300  can anchor and support a frame work upon which blowout preventer  306  sits. Independent of anchoring infrastructure, SHCPA  200  described in  FIG. 3  can be inserted between BOP  306  and riser pipe  204  as shown in  250 , which in itself substantially enhance well safety. 
     If base plate  300  is installed before blowout preventer  306  is mounted, base plate  300  can be installed as a whole plate with a center through-hole for well head  303  and well head brace  305 . 
       FIG. 10  shows a containment and protection chamber  310  deployed over blowout preventer  306 . For deploying after a blow out event to contain, capture, and harvest the blowout hydrocarbon flow, containment and protection chamber includes a flanged pipe adaptor  314  and a control valve  312 . Containment and protection chamber  310  is placed over the blowout preventer  306  on base plate  300  and with a damaged riser pipe  317  already cut away from it. 
     A hydrocarbon collection pipe can be mounted on pipe adaptor  314  to pipe the captured hydrocarbon flow from containment and protection chamber  310  to a storage ship, a collection terminal, or a temporary storage unit at sea floor near the well. Since base plate  300  and containment and protection chamber  310  must be larger than blowout preventer  306  in order to adequately surround blowout preventer  306 , and both are to be made of heavy and durable material, it is anticipated that anchoring piers  101  (shown in  FIG. 1 ) and a chamber-top counter pressure platform  103  may not be needed and are optional in this embodiment. A via at the center of the top of chamber  310  is not needed for post-event emergency installation, and chamber  310  needs to be taller than the blowout preventer. 
     For pre-event installation to enhance safety, containment and protection chamber  310  is additionally equipped with a via  315 , through which the blowout preventer top pipe feeds through to the top of containment and protection chamber  310  with a blowout preventer top flange  316  sits on top of containment and protection chamber  310 , and a riser pipe  317  is connected to flange  316  for conducting normal operation. An optional back up cut-and-seal slider assembly  318  as illustrated in  FIG. 11  can be mounted on top of containment and protection chamber  310  to cut and seal a damaged riser pipe in case of an event and a blowout preventer failure. A pipe squeezing assembly can also be added on top of chamber  310  for redundancy. An optional door  335  permits ROV access to blowout preventer  306  and well head  303 . Alternately a flexible pipe (flex pipe) can be inserted between the top flange of the blowout preventer (BOP)  306  to feed through via  315  with the top flange of the flex-pipe anchored and sit on top chamber  310 , and connected to riser pipe  317 . The advantage of this arrangement is that the containment and protection chamber of the same height can be used for both pre- and post-event installation. The flex-pipe extends the BOP pipe to adapt to the taller chamber  310 , while further insulates BOP  306  from mechanical shocks coming from outside of chamber  310 . Additional safety benefit of a containment and protection chamber  310  is that it isolates blowout preventer  306  and well head  303  from undesired open access prone to accidental marine life collision or sabotage. Ideally, a sealed hydrocarbon collection pipe adaptor SHCPA  200  or a MPBPA  500  is added between containment and protection chamber  310  and riser pipe  317  to further enhance operational flexibility and safety. 
       FIG. 11  shows views of pipe slicer assembly  318  and block pipe squeezer assembly  340  to be mounted on and anchored to the top of containment and protection chamber  310  or a general purpose assembly mounting and anchoring platform such as platform  103  shown in  FIG. 1 . Pipe slicer assembly  318  is a cut and seal slider, where assembly tracks  319  mounted on both sides of a target object  321  guide blade  320  to cut target object  321 . When blade  320  completes the cut and traverse along tracks  319  pass target object  321 , seal cap  322  located behind blade  320  drops down to seal the cut pipe. The drop is facilitated by levers  324 . Pipe squeezer assembly  340  includes an anchor block  341  and rails  342  and  343 . A ramming block  344  presses toward anchor block  341  and squeezes a target object such as an oil pipe  345  flat and shut. 
       FIG. 12  shows a top sectional view of a block and piston squeezer, where both blocks  351  and  352  are mounted and anchored to the top of containment and protection chamber  310  or a general purpose assembly mounting and anchoring platform such as platform  103  shown in  FIG. 1 . A piston  353  is tightened to squeeze oil pipe  355  flat and shut. 
       FIG. 13  is a conceptual drawing of a multi-stage pipe squeezer which reduces mechanical stress on a squeezed pipe  365 . A squeeze stage comprised of squeezers  361  and  371  and a squeeze stage comprised of squeezers  362  and  372  squeeze pipe  365  partially and progressively shut, until a squeeze stage composed of squeezer  363  squeezes pipe  365  fully shut. Any number of stages can be constructed to optimize the shut-off speed and minimize potential for pipe breakage. 
     A pipe slicer or a pipe squeezer such as any of the ones shown in  FIG. 11 ,  FIG. 12  and  FIG. 13  can be incorporated with containment and protection chamber  310  in multiple stage stacks, or stack mounted on a general purpose assembly mounting and anchoring platform  103  as described in  FIG. 1 , to replace or back up the functions of a blowout preventer. 
       FIG. 14  shows a mating pair of a roaming pipe squeezer that can be deployed with an ROV to squeeze shut any pipe section  385 . Blocks  381  and  382  (with or without a piston) are deployed to the opposite sides of a pipe section and assembled together. Blocks  381  and  382  and a piston are hydraulically operated to come together to squeeze shut pipe section  385 . Rods  383  and  384  are mounted on blocks  381  and  382 , as shown in  FIG. 14 . Rod  383  is inserted through a hole in block  382 . Rod  384  is inserted through a hole in block  381 , as shown. Tightening disks  386  and  387  parked on blocks  381  and  382  are then mounted onto rods  383  and  384 , and hydraulically operated to tighten blocks  381  and  382  against pipe  385 . Optional piston  388  further assists the pipe squeezing. 
     Conventional hydrocarbon kick detection is conducted on board a drilling or production rig by analyzing measurement of indirect indicators such as drilling mud pit volume change, fluid out-flow of the well compared to fluid pumped into the well through the drilling pipe, or drill pipe fluid pressure measured at the pump which is difficult to interpret because so many different factors can affect that pressure. These indicators unfortunately can be masked by operational activities. Furthermore, the indicators are then displayed for human interpretation. These difficulties compounded by the time lag between a dangerous hydrocarbon kick occurrence at the well bore and the detection of indirect indicators make timely issuance of a command to activate a conventional BOP difficult to achieve. When and if a conventional BOP is activated, its annular seals can seal the tubal core chamber of the BOP, but can not seal a pipe present in the BOP core chamber. Its blind shearing ram can shear a pipe present in BOP, but can not shear pipe joints, and can not shear an off-centered pipe. The rubberized material used in the rams and the annular seals in the conventional BOP, as well as the movable rams that join with the tubal members to form the tubular core chamber of BOP are not designed for extended hydrocarbon exposure and prone to corrosion and leak. Embodiments described below provide solutions to these problems. 
     A direct hydrocarbon-kick detection and automated kick management system using a full featured SHCPA  200  shown in  FIG. 3  can be retro-fitted between conventional blowout preventer  306  and riser pipe  204  as shown in  250  of  FIG. 9 . Similarly, such system can be incorporated into a new blowout preventer  399  as described in  FIG. 15, 440 ; or, alternately installed between well head  303  and a conventional blowout preventer  306  using MPBPA  500 , as illustrated in system  710  in  FIG. 22 . Furthermore, with a pressure sensor installed in a sensor assembly  208 , the diversion branch in SHCPA and MPBPA can be used to relieve over pressured drilling fluid present in an annular space between the inner-most casing pipe (also called the production casing pipe) and the production pipe to manage and regulate the difficult annular pressure buildup problem during hydrocarbon production mode. The branch can be further fitted with a bladder to store the over-pressured over-flow fluid, and to push back the fluid when the annular pressure drops. One example of such a bladder is a balloon bladder. Similarly, the annular pressure between two casing pipes can be regulated through a branch pipe as well. This can be accomplished by equipping a branch with a pressure sensor, and connecting the branch to the annular space and a fluid overflow bladder. The assembly regulates pressure in the annular space by conducting over pressured drilling fluid out of the annular space into the overflow bladder. When the pressure reduces in the annular space, the fluid returns back to the annular space. 
       FIG. 15  shows a blowout preventer  399  with a simpler, sturdier, and more effective design than conventional blowout preventer  306 . Blowout preventer  399  includes a two level protection and support chamber  400  mounted on well head protection base plate  300 . A lower pipe section  403  is made of stronger and thicker walls of hydrocarbon compatible material than an ordinary well pipe. A flange  404  at the bottom of blowout preventer  399  mounts to well head  303  at the flange  420 . Pipe section  403  extends through an upper level floor  402  of chamber  400  terminating at a flange  405  resting on upper level floor  402  of chamber  400 . An upper well pipe section  406  is made of material that can be reliably squeezed shut or cleanly cut and sealed. A flange  407  mounts to flange  405  at the top of lower pipe section  403 . 
     A multi-stage pipe squeezing stack  410  is composed of devices similar to, for example, any of those shown in  FIGS. 11, 12 and 13 . An off-setting multi-stage cutting and sealing stack  412  is mounted 90 degrees from multi-stage pipe squeezing stack  410 . Both stacks are mounted on upper level supporting floor  402  of protective chamber  400  for support and anchoring. Upper level pipe  406  extends through the ceiling of protective chamber  400  with a connecting flange  414  sitting at the top of the protective chamber  400 , to be connected to a riser pipe  415  through a flange  416 . Alternately, a SHCPA  200  or a MPBPA  500  can be installed between BOP flange  414  and riser pipe flange  416 . Doors  430  can be installed on select sides of protective chamber  400  at both levels for access, maintenance and inspection. 
     Hydrocarbon kick detection and management system  440  can be incorporated with lower pipe section  403  as an additional safety feature not available in conventional blowout preventer  306 . Hydrocarbon kick detection and management system  440  includes a control valve  434 , a sensor assembly  431 , a hydrocarbon diversion pipe  436  for conducting hydrocarbon kick flow to a safe distance for collection or storage, and a control valve  435  for pipe  436 . Control valve  434  can be set to a normally open position to allow drilling mud and drill pipe to pass through, and closes when detecting hydrocarbon presence to divert hydrocarbon to diversion pipe  436 . Control valve  435  is normally closed to prevent drilling mud from entering diversion pipe  436 , and opens when sensor  431  detects presence of hydrocarbon to divert the flow to a storage unit  439  in  FIG. 16 . A separate pipe outside of the blowout preventer can be used for accommodating drilling mud up-flow. Control valve  434  can then be a one-way valve set at a normally closed position, preventing any up-flow and allowing only down flow of drilling mud. Progressively more advanced kick management capability can be attained by progressively adding the following components: an optional bleed valve  432  to control the rate of hydrocarbon release to diversion pipe  436 ; an optional oil and methane separator  438  equipped with oil pipe  441  which can be extended with a flange connector  443  to lead to an oil storage unit at seafloor or a collection facility at sea surface. A methane pipe  442  which can be extended with a flange connector  445  to lead to a methane storage unit or a collection facility. Oil and gas separator  438  can be constructed using a sufficiently strong filter that allows gaseous methane to pass to methane outlet pipe  442 , and filters out oil to pass to oil outlet pipe  441 . Alternately, separator  438  can be accomplished by using a storage tank  439  and gravity separation, by locating a gas outlet pipe  442  at a top location of the storage tank and an oil outlet pipe  441  at a bottom location of the storage tank, as illustrated in  FIG. 16 . Separating methane storage from oil at sea floor level allows each to be separately piped to separate storage units. A hydrocarbon manifold  450  shown in  FIG. 17  can be used to fill multiple storage tanks  452  of a size suitable for handling and transport, each having a valve which closes when the tank is filled. Manifold  450  contains a battery pack, sensors, a control circuit, pipes and valves. The manifold  450  controls and conducts orderly filling of tanks  452  and orderly open and closing of valves. A docking unit  455  facilitates removal and replacement of tanks  452 . Valve  453  closes when tank  452  is filled to a desired level. Valve  454  expels pre-existing pressure balancing liquid (e.g. sea water) in tank  452  as it is filled with hydrocarbon. The filled tanks can be removed and lifted to sea surface at a suitable time to transport to long term storage or processing facility. Methane gas can be filled at seafloor level to a desired compression level, and further compressed or liquefied at a processing plant. Filled tanks are removed and replaced aided by an ROV. Oil outlet pipe  441  can be piped to an oil tanker at sea surface at a safe location, or piped to a temporary oil storage unit at the sea floor, or to manifold  450  to fill multiple storage tanks to be transported to the sea surface at a suitable time. The hydrocarbons from pipe  436  can also be piped to a storage unit at seafloor, or a collection facility at sea surface. 
     To accommodate presence of production or drill pipe inside Valves  434  and  432 , these valves are constructed in a self centering “iris shutter” style to close inward toward the center such that  434  seals around the pipe inside, and closes completely if no pipe is present. Optional bleed valve  432  is set to partially close to allow controlled pass through of the high pressure hydrocarbon flow to diversion pipe  436 . Details of an iris shutter valve are described later in  FIG. 26 . The casing pipes, the production pipe and the drill pipe can all be fitted with their own safety valves at a low portion of the pipes to defend against threatening hydrocarbon kicks from surging further up the pipes. 
       FIG. 18  shows a multi-port branched pipe adaptor (MPBPA)  500  having main branch  520  with a port  510  for well access or hydrocarbon capture, and at least one other branch  550  with port  551  for hydrocarbon capture or diversion of over pressured well fluids. The top of port  510  is equipped with a seal flange  503 , which can seal mount to a riser pipe  530 , secure a drill pipe or an assembly driver string  540 , or a riser pipe containing a drill pipe or driver string, or a hydrocarbon collection pipe. During normal operation, port  510  can serve as a hydrocarbon collection port. Optional valve  505  allows port  510  to open for various operations including for assembly driver string  540  to pass through, or to close to divert a blowout flow for improved visibility when desired or needed before and during mounting of an apparatus or a pipe during a blowout flow. A hydrocarbon capture port  550  is equipped with a flange  553  to secure, and seal mount to a hydrocarbon collection pipe assembly  560 , to further connect to a hydrocarbon collection facility such as a storage unit at the sea floor, or an oil tanker at the sea level to collect and store the captured hydrocarbons. A flexible pipe section with top and bottom flange connectors can be added to MPBPA  500  as desired. The storage unit at seafloor may be further equipped with a manifold as shown in manifold  450  in  FIG. 17  to fill multiple storage tanks of a size suitable for handling and transport to a collection facility at sea level. A tank docking station facilitates removal and replacement of tanks. 
     An optional valve  555  allows shutting the hydrocarbon flow when needed. Sonar, ultrasonic or electromagnetic wave generation/inspection devices can be mounted and run with assembly driver string  540 . A BOP mounting port at the bottom of the main branch  520  of MPBPA  500  is equipped with a suitable flange  573  to form a sealed direct connection with a blowout preventer top flange  575 . A pipe sleeve  256  as shown in  FIG. 8 ,  FIG. 19 , and  FIG. 20  having a flange  255  can be used for making a sealed connection between MPBPA  500  and a damaged pipe  246  that can not be easily removed from blowout preventer  306 . Padded sealer pipe sleeve  256  includes elastomeric material reinforced with para-aramid synthetic fiber or some other pliable material with suitable chemical and physical characteristics covers damaged pipe  246  and fastened with fastener  254  to provide a seal. The diameters of the ports of MPBPA  500  are close to the diameter of the pipe that is spewing the hydrocarbon flow, so that deflection and reflection of the hydrocarbon flow is minimized. MPBPA  500  can be modified to have two symmetrical hydrocarbon collection ports to weight balance the assembly, and to increase the rate and flexibility in hydrocarbon collection. This is illustrated in  FIG. 19 . Many more side branches can be added. 
     Methane gas volume expands rapidly to become more explosive and dangerous as it rises from the sea floor level toward the rig. It is desirable to separate methane gas from oil, and pipe it away from the well at a level closer to the sea floor to a storage tank, or to gradually raise the pipe in a controlled manner to a methane gas collection facility.  FIG. 20  shows a MPBPA  599  equipped with a pressure sensor and/or hydrocarbon detector, sensor assembly  592  installed at the lower end of the main trunk of MPBPA  599 . When a high pressure hydrocarbon surge is detected, valve  593  automatically closes to divert hydrocarbons to branch pipe  550  which can be further piped to a storage tank at sea floor level. The storage tank can additionally serve as oil and gas separator as described in  FIG. 16 . Separator  596  allows methane to pass to gas pipe  597 , and oil filtered out to oil pipe  595 , each is extended separately to a separate storage at seafloor or a collection facility at sea surface. Hydrocarbon or pressure sensor  592  can be additionally fitted with a bleed valve  594 , when sensor  592  detects hydrocarbon, it closes valve  593 , and partially shuts the optional bleed valve  594 . Bleed valve  594  allows controlled hydrocarbon release into branch pipe  550 . Alternately, hydrocarbon kick detection and management system can be installed in a blowout preventer as described in  FIG. 15 . 
     A multi-port branched pipe adaptor should be incorporated in all well systems at above a blowout preventer, below a blowout preventer, or ideally both above and below a blowout preventer, or located inside a new blow out preventer as standard safety features. 
       FIG. 21  shows a device driving string  640  mounted through MPBPA  600 . Device driving string  640  is used for running and setting devices for well inspection, repair, and plugging from above or below blowout preventer  306 . If a drill pipe or a device driver is broken off and remains in blowout preventer  306  and the well below, it should be removed through port  670  before a new driving string is mounted. If the pipes are stuck in an unsuccessfully activated blowout preventer  306 , the pipes and blowout preventer  306  need to be removed. An MPBPA pre-installed below blowout preventer  306  enables the safe removal of a damaged or malfunctioning blowout preventer as further described below. 
     After the damaged blowout preventer is removed, a new BOP can be installed while the MPBPA below the BOP continues to collect the hydrocarbon flow through side branch  550 . A device driver string  540  can be mounted through the MPBPA above BOP  306 . If a damaged BOP is removed, the MPBPA pre-installed between the well head and the BOP, can be used to mount device driving string  540  from its main port  510  through the well head while hydrocarbon flow is conducted through branch pipe  551 . 
     A device running example is illustrated in  FIG. 21 . Well plugging assembly  620  is mounted at the bottom of assembly driver string  640 . A retractable rotary cutting device  680  is mounted with the plug to mill through possible debris. A monitoring and inspection device  630  is mounted above a plugging device  620 . If pipe repair is required, expandable casing/pipe repair assembly  650  is mounted next up above monitoring and inspection device  630 . Assembly driver string  640  is launched through the MPBPA  600 , and driven into a BOP tubular core chamber  690  through the assembly driver string port  610 , BOP port  670 , into the well. Devices are grapple mounted, and released and set at locations. A tubing hanger  660  is located at sea floor  90 . Sonic, ultrasonic, or electromagnetic emitters, transducers, or sensors can be deployed to select strategic locations to study the condition of the well casing, pipes, valves, seals and other well components. Device driving string  640  is mounted with repair components or assemblies to location, released, set, and inspected. The assembly device driving string  640  is then driven through the adaptor  200  down to an appropriate well plugging location, one example being at the bottom of the well at reservoir level as in a “bottom kill,” and the plugging assembly released and set. As stated above, alternatively, a drill pipe loaded with cement and mounted through MPBPA  600  below blowout preventer  306  can be lowered down to the bottom of the well and used to pump cement to the bottom of the well to “bottom kill” the well. When there is a damaged pipe stuck inside the BOP core chamber  690 , assembly device driver string  640  can be used to cut away obstruction, and remove the damaged pipe out of BOP core chamber  690  and well bore casing pipe  665 . 
     In case where a bore hole to casing or production tubing annulus seal is broken, a retractable tube cutting device can be used to cut the production tube at the reservoir ceiling level in order to reach and re-seal the wellbore, reservoir, and production tube interface. Alternately, the Production-Can holes can be opened, and an assembly drill pipe string passing through the adaptor is used to pump cement through the Production-Can holes to close the well and seal the well bore to well pipe annulus. 
       FIG. 22  shows installation of MPBPA  500  above blowout preventer  306 . Outside of a blowout event, there should be no hydrocarbon flow or presence in the casing tube, in the BOP core chamber, nor in the MPBPA chamber outside of a production pipe. The presence of MPBPA  500  enables complete blowout hydrocarbon collection from above blowout preventer  306 , inspection and repair of blowout preventer  306 , as well as access to the wellbore through blowout preventer  306 . An optional anchoring infrastructure and support and protection platform  103  installed above blowout preventer  306  anchors and protects blowout preventer  306 , blowout preventer  306  to MPBPA  500  connection  505 , and operations launched through the upper MPBPA  500 . Platform  103  can also be mounted on top of MPBPA  500  with a top flange  503  that sits atop platform  103  to also protect MPBPA  500 . 
     Blowout preventer as one used at Macondo Well is more than 5 times wider and 10 times taller than well head  303 , and weights more than 300 tons. In conventional hydrocarbon well installations, there is no structural support for the blowout preventer and its connections to the riser pipe and the well head. An explosion, an earthquake, a whale, or a fallen riser pipe can upset the vertical stack, causing the blowout preventer to lean and leak with no access to the well to close off the hydrocarbon flow and remove the endangered blowout preventer. Potentially the blowout preventer can fall after leaning for a prolonged period, breaking its connection to the well pipe and well head, or even taking out part of well head  303  and the well casing with it. The set up shown in  FIG. 22  remedies these serious shortcomings. 
       FIG. 22  shows MPBPA  500  having optional hydrocarbon and pressure detection and diversion system  710  installed between blowout preventer  306  and well head  303 . An optional structural support framework  760  is mounted across the bottom of blowout preventer  306  and anchored to anchoring piers  101  to further support and stabilize blowout preventer  306  from below blowout preventer  306 . A base plate  300  and well head brace  305  supports and protects well head  303  and its connection to system  710 . Details of base plate  300  and well head brace  305  are shown in  FIG. 9 . Base plate  300 , with its large horizontal surface resting on the seafloor is self anchoring. It can also be used to anchor BOP, as well as help anchoring piers  101 . 
     Particularly large and highly compressed methane gas bubbles mixed in with oil rising from a methane rich reservoir into a well bore will quickly expand in volume and accelerate the rise to the rig causing explosion and destroy equipment. It is also a precious resource that is burned off and wasted in conventional oil well operations. The problems of conventional kick detection method and the reliability of the conventional BOP are discussed previously. In addition, even if a BOP successfully rams and shears pipes within it and shuts off a high pressure blowout flow, the well and the earth formation beneath could be at risk. It is also extremely difficult and costly and maybe impossible to unwind an activated BOP to recover the well. The embodiments below provide solutions to these problems. 
     Installing Multi-Port Branched Pipe Adaptor (MPBPA)  500  between well head  303  and blowout preventer  306  provides access to the well and control to the hydrocarbon flow from below blowout preventer  306 . This capability is vital when blowout preventer  306  is malfunctioning, jammed, leaking or leaning. Closing valve  505  in MPBAP  500  enables safe removal of a damaged or leaning blowout preventer. A MPBPA assembly installed below blowout preventer  306  further enables inclusion of a hydrocarbon detection and management system  710  similar to system  440  described in  FIG. 15 . System  710  is fitted with a pressure and/or hydrocarbon chemical sensor assembly  713  to directly detect and divert threatening hydrocarbon kick to a distance away from the well for safe release and storage, or to a separator  596  to separate oil and gas for separate diversion and storage. Iris shutter valve  505  closes when sensor  713  detects an unexpected high up-flow pressure or hydrocarbon presence. Diversion pipe  550  conducts the hydrocarbon kick flow to a storage unit  720  at a practical and safe distance as shown in  FIG. 23 . Storage unit  720  may be located on seafloor to accommodate temporary storage during storage ship absence. Optional pipe support  730  is not needed if flexible piping is used. Branch pipe control valve  555  can be used to control the hydrocarbon release rate into diversion pipe  550 . Alternately, hydrocarbon (and/or pressure) sensor assembly  713  can be combined with a bleed valve  714  to control hydrocarbon release into diversion pipe  550 . Separator  596  separates gas collection from oil collection. Separator  596  can be constructed with a sufficiently strong filter that allows gaseous methane to pass, and filters out oil. Alternately, separator  596  can be incorporated into storage unit  720 . Gravity separates the lighter gaseous methane to the upper part of storage unit toward its top, and oil sinks to the lower part of storage unit  720 . Pipe  721  conducts methane away to a methane collection facility and pipe  722  conducts oil to an oil collection facility. Valves  505  and  714  are centrally closing annular valves. They can be constructed using iris shutter valves described later in  FIG. 26  to accommodate pipe presence inside valves  505  and  714 . The details of construct and operation of system  710  are similar to that described in system  440 . During production mode hydrocarbons flow upward through a production pipe mounted through the center of MPBPA main branch  520  and the tubular core of BOP  306 . There should be no legitimate hydrocarbon presence in the annular space outside of the production pipe. System  710  is as essential before and during production. 
     In  FIG. 24  is shown a first line defense at the bottom of the wellbore against a high pressure hydrocarbon kick from surging upward into a well system. An inner-most casing pipe  810  of the well system is fitted with a check valve  811  preventing up-flow as shown in an assembly  800 . Casing pipes that reach the proximity of a hydrocarbon reservoir can each be fitted with a centrally closing check valve to prevent rogue hydrocarbons from entering it or annular space between the pipes. Similarly, in another assembly  802 , a check valve  831  is fitted to the bottom of a drill pipe  830  to prevent hydrocarbons from entering upward into drill pipe  830 . An assembly  804  shows a pipe  840  fitted with a sensor controlled gate valve  841 . These check valves close when encountering an upward pressure preventing upward fluid flow, open proportionally when encountering downward pressure to allow downward insertion of fluid or objects. Check-valves  811  and  831  are constructed in a shutter plate manner. In response to an up flow pressure, a shutter closing plate  812  for valve  811  and a shutter closing plate  832  for valve  831  hung from hinges  814  and  834  respectively rise to close tight against a closing seat  816  for valve  811  and a closing seat  836  for valve  831 , preventing a high pressure hydrocarbon kick from surging upward into pipes  810  and  830  above valve  811  and valve  831 . Closing plates  812  and  832 , or hinges  814  and  834  can be spring loaded such that closing plates  812  and  832  are normally at closed positions. Assembly  804  shows a threshold pressure sensor or a hydrocarbon chemical sensor  843  in combination with a sensor controlled gate valve  841  mounted to a pipe  840  that also prevents hydrocarbon up-flow into pipe  840 . When sensor  843  detects a threshold pressure or hydrocarbons, sensor  843  produces an output that drives gates  842  hung on hinges  844  to shut close, and shut out the rogue hydrocarbon kick flow. Gates  842  and hinges  844  can also be set at a normally closed position by spring loading. All three types of check valve illustrated in  FIG. 24  can be used for all pipes or tubal members of an apparatus. 
     While all three valves in  FIG. 24  can be used on any pipe, it is preferable that the inner-most casing pipe of a well be fitted with a tubal shutter check valve having the same outer diameter as shown in  811 . The passage way of check valve  811  should be close to the inner diameter of casing pipe  810  and larger than the outer diameter of a production pipe (not shown), which is inserted inside casing pipe during well completion process for production. The geometry of the closing plate  812  and its seat  816  are shaped to fit this requirement. The smaller drilling pipe  830  (at 5.5″ OD and 3.5″ ID) places less restriction to the shape and size on check valve  831 . A simple shutter check valve  831  as show in assembly  802  has a square cross section (or any other usable geometric shape, for example a hexagon), a flat closing plate  832  and closing seat  836  slightly larger than, and covering the inner diameter of drill pipe  830 . Valve  831  needs to fit well within the inner most casing pipe  810 , or fit within the production pipe if it is to be used inside the production pipe. 
       FIG. 25  illustrates various inner views of the workings of tubal shutter check valve  811  in assembly  800  shown in  FIG. 24 . A properly shaped closing plate  812  hangs from hinge  814  mounted on a tubal wall location can be spring loaded at the hinge or from the tubal wall below the hinge to maintain a normally closed safety position against shaped ridge seat  816  along the inner tubal wall of valve  811 . When encountering a large enough net downward pressure, the closing plate  812  opens downward. Upward pressure of a hydrocarbon kick pushes the closing plate even tighter against closing seat  816 , securely shut off upward passage to the casing pipe  810  above. Downward pressure from the insertion of a production pipe, a packer, a drill pipe, or other apparatus pushes down closing plate  812  to open valve  811 . At the fully open position, shaped closing plate  812  hangs down and conforms to the tubal wall as shown in top view  850  and side view  851 . Side view  852  shows the fully open position of closing plate  812  at a 90 degree angle from side view  851 . Views  853  and  854  are side views 90 degrees from each other of closing plate  812  at closed position. View  855  shows the closing ridge seat  816  along the inner tubal wall and closing plate  812  closing against ridge seat  816 , viewed at a 45 degree angle from views  853  and  854 . 
       FIG. 26  shows a center closing iris shutter check valve  861 . Properly shaped closing blades  862  hang downward at a suitable angle from spring loaded hinges  864  mounted in a circular ring around an inner parameter of iris shutter check valve  861 . When encountering an upward hydrocarbon surge, the blades rise to close tight toward the center of valve  861 , closing off its flow path upward. When there is no pipe present inside valve  861 , the shutter blades close completely. Shutter blades  862  and hinges  864  can be spring loaded to a normally closed position. Valve  861  can also be configured and controlled to be normally open to allow pipes and legitimate fluids such as drilling mud and seawater to pass through, and only closes to prevent unwanted flow, for example hydrocarbons. 
     Another way of constructing a centrally closing iris shutter valve is Horizontal blade iris shutter valve  865 . Horizontally mounted closing blades  867  move toward the center to close, and retract into a blade chamber  869  surrounding the central passage to open. The horizontal iris shutter can be configured to be a two-way valve, or a one-way valve of either direction. The blades of a horizontal shutter valve can be set at a normally closed position or normally open as needed in different applications. Views  871 ,  873 ,  875  and  877  show top cross sectional views of a centrally closing valve at various degrees of closing (opening) positions. If a pipe is present inside shutter valve  861  or  865 , the shutter blades close around the pipe. 
     When pre-installed in a well system as a part of a rogue hydrocarbon detection, management, and diversion system, control valves  202 ,  434 ,  505 , (and if present bleed valves  432  and  714 ) shown in  FIGS. 3, 15 and 22  are set to normally open, closing at detection of rogue hydrocarbon presence. These are annular valves which close toward the center of the adaptor around an inside pipe if present. Horizontal or vertical blade iris shutter valve as described in  FIG. 26  can be used to construct these valves. Side branch valves  206 ,  435 , and  555  are normally closed, opening at detection of rogue hydrocarbon presence. Side branch valves  206 ,  435  and  555  are normally closed to prevent legitimate fluids from being diverted and opened when sensors detecting rogue hydrocarbon presence. Bleed valves  432 ,  594  and  714  if present, are partially closed to allow controlled hydrocarbon release to a diversion branch. A production pipe can also be equipped with a threshold pressure or flow rate activated valve to protect against a hydrocarbon up flow exceeding a safety threshold pressure or flow rate. During production mode, a side branch in adaptor  200  and  500  can be used to relieve annular pressure build up between production casing pipe and production pipe, if a pressure sensor is installed in the sensor assembly in the main branch. 
     Additional devices can be installed and used to provide information to analysts and decision makers to enable timely and informed decisions. For example, embedded micro sensors, transducers, emitters such as pressure and temperature sensors, chemical sensors, sonic, ultra-sonic, or electromagnetic emitters and transducers can be mixed into an adhesive coating material and painted on well tube surfaces before the tubes are installed into the well. Such devices when installed detect well status and transmit signals to monitoring stations or wireless receivers on an ROV. Alternatively, wired or wireless sensors, emitter, and transducers can be strategically mounted on select well tube locations. These devices mounted in the well can provide information to analysts and decision makers to enable timely and informed decisions. 
     The foregoing discussion discloses and describes merely exemplary methods and embodiments. As will be understood by those familiar with the art, the disclosed subject matter may be embodied in other specific forms without departing from the spirit or characteristics thereof. Accordingly, the present disclosure is intended to be illustrative, but not limiting, of the scope of the invention, which is set forth in the following claims.