Patent Publication Number: US-10787900-B2

Title: Differential pressure indicator for downhole isolation valve

Description:
BACKGROUND OF THE DISCLOSURE 
     1. Field of the Disclosure 
     The present disclosure generally relates to a differential pressure indicator for a downhole isolation valve. 
     2. Description of the Related Art 
     A wellbore is formed to access hydrocarbon bearing formations, e.g. crude oil and/or natural gas, by the use of drilling. Drilling is accomplished by utilizing a drill bit that is mounted on the end of a drill string. To drill the wellbore, the drill string is rotated by a top drive or rotary table on a surface platform or rig, and/or by a downhole motor mounted towards the lower end of the drill string. After drilling a first segment of the wellbore, the drill string and drill bit are removed and a section of casing is lowered into the wellbore. An annulus is thus formed between the string of casing and the formation. The casing string is cemented into the wellbore by circulating cement into the annulus defined between the outer wall of the casing and the borehole. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons. 
     An isolation valve assembled as part of the casing string may be used to temporarily isolate a formation pressure below the isolation valve such that a drill string, work string, completions string, or wireline may be quickly and safely inserted into or removed from a portion of the wellbore above the isolation valve that is temporarily relieved to atmospheric pressure. Since the pressure above the isolation valve is relieved, the drill/work string can be tripped into the wellbore without wellbore pressure acting to push the string out and tripped out of the wellbore without concern for swabbing the exposed formation. 
     Before reopening the valve, pressure above the valve is equalized with pressure below the valve in order to avoid damage thereto. The differential pressure across the valve is determined using available known parameters. However, this results in only an estimate of the differential pressure. 
     SUMMARY OF THE DISCLOSURE 
     The present disclosure generally relates to a differential pressure indicator for a downhole isolation valve. In one embodiment, a differential pressure indicator (DPI) for use with a downhole isolation valve includes a tubular mandrel for assembly as part of a casing string and for receiving a tubular string. The mandrel has a stop shoulder and a piston shoulder. The DPI further includes a tubular housing for assembly as part of the casing string and for receiving the tubular string. The housing is movable relative to the mandrel between an extended position and a retracted position and has a stop shoulder and a piston shoulder. The DPI further includes a hydraulic chamber formed between the piston shoulders and a coupling in communication with the hydraulic chamber and for connection to a sensing line. The housing is movable relative to the mandrel and to the extended position in response to tension exerted on the DPI. 
     In another embodiment, a method of constructing a wellbore includes deploying a tubular string into the wellbore through a casing string disposed in the wellbore. The casing string has an isolation valve in a closed position and a hydraulic sensing line extending along the casing string. The method further includes: equalizing pressure across the isolation valve using the sensing line to determine differential pressure across the isolation valve; opening the isolation valve; and lowering the tubular string through the open valve. 
     In another embodiment, an isolation valve for use in drilling a wellbore includes: a tubular housing for assembly as part of a casing string and for receiving a drill string; a seat disposed in the housing and longitudinally movable relative to the housing; a flapper pivotally connected to the seat between an open position and a closed position; a flow tube longitudinally movable relative to the housing for opening the flapper; a hydraulic chamber formed between the flow tube and the housing and receiving a piston of the flow tube; a hydraulic passage in fluid communication with the chamber and a hydraulic coupling; and a differential pressure indicator (DPI) linked to the seat for responding to force exerted on the seat by the flapper in the closed position. 
     In another embodiment, an isolation valve for use in drilling a wellbore includes a tubular housing: for assembly as part of a casing string, for receiving a drill string, and having a shoulder formed in an inner surface thereof for receiving the seat. The isolation valve further includes: a seat disposed in the housing and longitudinally movable relative to the housing; a flapper pivotally connected to the seat between an open position and a closed position; a flow tube longitudinally movable relative to the housing for opening the flapper; a hydraulic chamber formed between the flow tube and the housing and receiving a piston of the flow tube; a hydraulic passage in fluid communication with the chamber and a hydraulic coupling; and a differential pressure indicator (DPI) for measuring force exerted on the isolation valve when the flapper is in the closed position. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       So that the manner in which the above recited features of the present disclosure can be understood in detail, a more particular description of the disclosure, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended drawings illustrate only typical embodiments of this disclosure and are therefore not to be considered limiting of its scope, for the disclosure may admit to other equally effective embodiments. 
         FIGS. 1A-1C  illustrate a terrestrial drilling system in a drilling mode, according to one embodiment of the present disclosure. 
         FIGS. 2A and 2B  illustrate a differential pressure indicator (DPI) of the drilling system. 
         FIGS. 3A-3C  illustrate operation of the DPI. 
         FIGS. 4A-4D  illustrate isolation valves having integrated DPIs, according to other embodiments of the present disclosure. 
         FIGS. 5A-5C  illustrate further isolation valves having integrated DPIs, according to other embodiments of the present disclosure. 
     
    
    
     DETAILED DESCRIPTION 
       FIGS. 1A-1C  illustrate a terrestrial drilling system  1  in a drilling mode, according to one embodiment of the present disclosure. The drilling system  1  may include a drilling rig  1   r , a fluid handling system  1   f , a pressure control assembly (PCA)  1   p , and a drill string  5 . The drilling rig  1   r  may include a derrick  2  having a rig floor  3  at its lower end. The rig floor  3  may have an opening through which the drill string  5  extends downwardly into the PCA  1   p . The drill string  5  may include a bottomhole assembly (BHA)  33  and a conveyor string. The conveyor string may include joints of drill pipe  5   p  connected together, such as by threaded couplings. The BHA  33  may be connected to the conveyor string, such as by threaded couplings, and include a drill bit  33   b  and one or more drill collars  33   c  connected thereto, such as by threaded couplings. The drill bit  33   b  may be rotated  4   r  by a top drive  13  via the conveyor string and/or the BHA  33  may further include a drilling motor (not shown) for rotating the drill bit. The BHA  33  may further include an instrumentation sub (not shown), such as a measurement while drilling (MWD) and/or a logging while drilling (LWD) sub. 
     An upper end of the drill string  5  may be connected to a quill of the top drive  13 . The top drive  13  may include a motor for rotating  4   r  the drill string  5 . The top drive motor may be electric or hydraulic. A frame of the top drive  13  may be coupled to a rail (not shown) of the derrick  2  for preventing rotation thereof during rotation of the drill string  5  and allowing for vertical movement of the top drive with a traveling block  14 . The frame of the top drive  13  may be suspended from the derrick  2  by the traveling block  14 . The traveling block  14  may be supported by wire rope  15  connected at its upper end to a crown block  16 . The wire rope  15  may be woven through sheaves of the blocks  14 ,  16  and extend to drawworks  17  for reeling thereof, thereby raising or lowering  4   a  the traveling block  14  relative to the derrick  2 . 
     The PCA  1   p  may include, one or more blow out preventers (BOPs)  18   u,b , a flow cross  19 , a variable choke valve  20 , a control station  21 , one or more shutoff valves  27   c,r , one or more pressure gauges  28   d,r , a hydraulic power unit (HPU)  35 , a hydraulic manifold  36 , an auxiliary valve  31 , one or more control lines  37   o,c , a sensing line  37   s , a choke spool  39 , a differential pressure indicator (DPI)  40 , and an isolation valve  50 . A housing of each BOP  18   u,b  and the flow cross  19  may each be interconnected and/or connected to a wellhead  6 , such as by a flanged connection. 
     The wellhead  6  may be mounted on an outer casing string  7  which has been deployed into a wellbore  8  drilled from a surface  9  of the earth and cemented  10  into the wellbore. An inner casing string  11  has been deployed into the wellbore  8 , hung from the wellhead  6 , and a portion  11   c  thereof cemented  12  into place. The inner casing string  11  may extend to a depth adjacent a bottom of an upper formation  22   u . The upper formation  22   u  may be non-productive and a lower formation  22   b  may be a hydrocarbon-bearing reservoir. The inner casing string  11  may include a casing hanger  11   h , a plurality of casing joints connected together, such as by threaded couplings, the DPI  40 , the isolation valve  50 , and a guide shoe  23 . The inner casing string may have a free portion  11   f  including the hanger  11   h , a plurality of casing joints, the DPI  40 , and the isolation valve  50 , and the cemented portion  11   c  including the guide shoe  23  and a plurality of casing joints. A casing annulus  34   c  may be formed between the inner casing string  11  and the outer casing string  7  and between the inner casing string  11  and a portion of the wellbore  8  traversing the upper formation  22   u . A free portion of the casing annulus  34   c  (adjacent to the respective free portion  11   f ) may be open (free from cement  12 ). 
     The sensing line  37   s  may extend from the HPU  35 , through the wellhead  6 , along an outer surface of the inner casing string  11 , and to the DPI  40 . The control lines  37   o,c  may extend from the manifold  36 , through the wellhead  6 , along an outer surface of the inner casing string  11 , and to the isolation valve  50 . The control lines  37   o,c  and sensing line  37   s  may be fastened to the inner casing string  11  at regular intervals. The control lines  37   o,c  may be bundled together as part of an umbilical. 
     Alternatively, the sensing line  37   s  may also be bundled with the control lines  37   o,c  as part of the umbilical. Alternatively, instead of the inner casing string, the well may include a liner string hung from a bottom of the outer casing string and cemented into the wellbore and a tie-back casing string hung from the wellhead and having a lower end stabbed into a polished bore receptacle of the liner string and the DPI  40  and isolation valve  50  may be assembled as part of the tie-back casing string. Alternatively, the lower formation  22   b  may be non-productive (e.g., a depleted zone), environmentally sensitive, such as an aquifer, or unstable. Alternatively, the wellbore may be subsea having a wellhead located adjacent to the waterline and the drilling rig may be a located on a platform adjacent the wellhead. Alternatively, a Kelly and rotary table (not shown) may be used instead of the top drive. 
     The isolation valve  50  may include a tubular housing  51 , an opener, such as a flow tube  52 , a closure member, such as a flapper  53 , a seat  54 , and a receiver  55 . To facilitate manufacturing and assembly, the housing  51  may include one or more sections (only one section shown) each connected together, such by threaded couplings and/or fasteners. Interfaces between the housing sections may be isolated, such as by seals. The housing sections may include an upper adapter (not shown) and a lower adapter (not shown), each having a threaded coupling for connection to other members of the inner casing string  11 . The isolation valve  50  may have a longitudinal bore therethrough for passage of the drill string  5 . Although shown as part of the housing  51 , the seat  54  may be a separate member connected to the housing, such as by threaded couplings and/or fasteners. The receiver  55  may be connected to the housing  51 , such as by threaded couplings and/or fasteners. 
     The flow tube  52  may be disposed within the housing  51  and be longitudinally movable relative thereto between a lower position (shown) and an upper position (not shown). The flow tube  52  may have one or more portions, such as an upper sleeve, a lower sleeve, and a piston connecting the upper and lower sleeves. The flow tube piston may carry a seal for sealing an interface formed between an outer surface thereof and an inner surface of the housing  51 . Alternatively, the flow tube portions  52  may be separate members interconnected, such as by threaded couplings and/or fasteners. 
     A hydraulic chamber  56  may be formed in an inner surface of the housing  51 . The housing  51  may have shoulders formed in an inner surface thereof adjacent to the chamber  56 . The housing  51  may carry an upper seal located adjacent to an upper shoulder and a lower seal and wiper located adjacent to the lower shoulder for sealing the chamber  56  from the bore of the isolation valve  50 . The hydraulic chamber  56  may be defined radially between the flow tube  52  and the housing  51  and longitudinally between the upper and lower shoulders. Hydraulic fluid  61  may be disposed in the chamber  56 . The hydraulic fluid  61  may be an incompressible liquid, such as a water based mixture with glycol or a refined or synthetic oil. An upper end of the hydraulic chamber  56  may be in fluid communication with an opener hydraulic coupling  57   o  via an opener hydraulic passage  58   o  formed in and along a wall of the housing  51 . A lower end of the hydraulic chamber  56  may be in fluid communication with a closer hydraulic coupling  57   c  via a closer hydraulic passage  58   c  formed in and along a wall of the housing  51 . 
     The isolation valve  50  may further include a hinge  59 . The flapper  53  may be pivotally connected to the seat  54  by the hinge  59 . The flapper  53  may pivot about the hinge  59  between an open position (shown) and a closed position (not shown). The flapper  53  may be positioned below the seat  54  such that the flapper may open downwardly. The flapper  53  may have an undercut formed in at least a portion of an outer face thereof. The flapper undercut may facilitate engagement of an outer surface of the flapper  53  with a kickoff spring (not shown) connected to the housing  51 , such as by a fastener. An inner periphery of the flapper  53  may engage a respective seating profile formed in an adjacent end of the seat  54  in the closed position, thereby sealing an upper portion of the valve bore from a lower portion of the valve bore. The interface between the flapper  53  and the seat  54  may be a metal to metal seal. 
     The hinge  59  may include a leaf, a knuckle of the flapper  53 , one or more flapper springs, and a fastener, such as hinge pin, extending through holes of the flapper knuckle and a hole of each of one or more knuckles of the leaf. The seat  54  may have a recess formed in an outer surface thereof at an end adjacent to the flapper  53  for receiving the leaf. The leaf may be connected to the seat  54 , such as by one or more fasteners. 
     The flapper  53  may be biased toward the closed position by the flapper springs, such as one or more inner and outer tension springs. Each tension spring may include a respective main portion and an extension. The seat  54  may have slots formed therethrough for receiving the flapper springs. An upper end of the main portions may be connected to the seat  54  at an end of the slots. The seat  54  may also have a guide path formed in an outer surface thereof for passage of the flapper springs to the flapper  53 . Ends of the extensions may be connected to an inner face of the flapper  53 . The kickoff spring may assist the tension springs in closing the flapper  53  due to the reduced lever arm of the spring tension when the flapper is in the open position. 
     Alternatively, the hinge may include a torsion spring instead of the tension springs and the kickoff spring. Alternatively, the leaf of the hinge  59  may be free to slide relative to the respective seat by a limited amount and a polymer seal ring may be disposed in a groove formed in the seating profile of the seat  54  such that the interface between the flapper inner periphery and the seating profile is a hybrid polymer and metal to metal seal. Alternatively, the seal ring may be disposed in the flapper inner periphery. 
     The flapper  53  may be opened and closed by interaction with the flow tube  52 . Downward movement of the flow tube  52  may engage the lower sleeve  52   b  thereof with the flapper  53 , thereby pushing and pivoting the flapper to the open position against the tension springs due to engagement of a bottom of the lower sleeve with an inner surface of the flapper. Upward movement of the flow tube  52  may disengage the lower sleeve thereof with the flapper  53 , thereby allowing the tension springs to pull and pivot the flapper to the closed position due to disengagement of the lower sleeve bottom from the inner surface of the flapper. 
     When the flow tube  52  is in the lower position, a flapper chamber  60  may be formed radially between the housing  51  and the flow tube and the (open) flapper  53  may be stowed in the flapper chamber. The flapper chamber  60  may be formed longitudinally between the seat  54  and the receiver  55 . The flow tube bottom may be positioned adjacent to an upper end of the receiver  55 , thereby closing the flapper chamber  60 . The flapper chamber  60  may protect the flapper  53  from abrasion by the drill string  5  and from being eroded and/or fouled by cuttings in drilling returns  31   f . The flapper  53  may have a curved shape to conform to the annular shape of the flapper chamber  60  and the seating profile of the flapper seat  54  may have a curved shape complementary to the flapper curvature. 
     The control station  21  may include a console  21   c , a microcontroller (MCU)  21   m , and a display, such as a gauge  21   g , in communication with the microcontroller  21   m . The console  21   c  may be in communication with the manifold  36  via an operation line and be in fluid communication with the control lines  37   o,c  via respective pressure taps. The console  21   c  may have controls for operation of the manifold  36  by the technician and have gauges for displaying pressures in the respective control lines  37   o,c  for monitoring by the technician. The control station  21  may further include a pressure sensor (not shown) in fluid communication with the DPI sensing line  37   s  via a pressure tap and the MCU  21   m  may be in communication with the pressure sensor to receive a pressure signal therefrom. The auxiliary valve  31  may be assembled as part of the sensing line  37   s  and may be a shutoff valve for selectively providing fluid communication between the sensing line and the HPU accumulator. 
     Alternatively, the auxiliary valve  31  may be incorporated into the manifold  36  and an upper end of the sensing line  37   s  may connect to the manifold. 
     The fluid system if may include a mud pump  24 , a drilling fluid reservoir, such as a pit  25  or tank, a solids separator, such as a shale shaker  26 , a return line  29 , a feed line, a supply line  30 , a mud-gas separator (MGS)  38   s , and a flare  38   f  ( FIG. 3A ). A first end of the return line  29  may be connected to a branch of the flow cross  19  and a second end of the return line may be connected to an inlet of the shaker  26 . The returns pressure gauge  28   r  and returns shutoff valve  27   r  may be assembled as part of the return line  29 . A first end of the choke spool  39  may be connected to the return line  29  between the returns pressure gauge  28   r  and the returns shutoff valve  27   r  and a second end of the choke spool may be connected to the shaker inlet. The choke shutoff valve  27   c , choke valve  20 , and MGS  38   s  may be assembled as part of the choke spool  39 . The MGS  38   s  may include an inlet and a liquid outlet assembled as part of the choke spool  39  and a gas outlet connected to the flare  38   f  or a gas storage vessel (not shown). 
     A lower end of the supply line  30  may be connected to an outlet of the mud pump  24  and an upper end of the supply line may be connected to an inlet of the top drive  13 . The supply pressure gauge  28   d  may be assembled as part of the supply line  30   p,h . A lower end of the feed line may be connected to an outlet of the pit  25  and an upper end of the feed line may be connected to an inlet of the mud pump  24 . The returns pressure gauge  28   r  may be operable to monitor wellhead pressure. The supply pressure gauge  28   d  may be operable to monitor standpipe pressure. 
     The drilling fluid  32   d  may include a base liquid. The base liquid may be refined or synthetic oil, water, brine, or a water/oil emulsion. The drilling fluid  32   d  may further include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite, and/or asphalt, thereby forming a mud. 
     Once the inner casing string  11  has been deployed into the wellbore  8  and cemented  12  into place, the drill string  5  may then be deployed into the wellbore until the drill bit  33   b  is adjacent to the guide shoe  23 . The drilling fluid  32   d  may then be circulated into the wellbore to displace chaser fluid (not shown) from a drilling annulus  34   d  formed between the drill string  5  and the inner casing string  11  and between the drill string  5  and a portion of the wellbore  8  being drilled through the lower formation  22   b . Once the drilling fluid  32   d  has filled the annulus  34   d , circulation may be halted such that only hydrostatic pressure of the drilling fluid  32  is exerted on an inner surface of the upper sleeve  52   u  and hydrostatic pressure of the hydraulic fluid  61  is exerted on an outer surface of the upper sleeve  52   u . If the isolation valve  50  is not already open, the technician may operate the control station  21  to place the opener control line  37   o  in fluid communication with a reservoir of the HPU  35  via the manifold  36 . The technician may then operate the control station  21  to shut-in the opener line  37   o , thereby hydraulically locking the piston  52   p  in place. The technician may then operate the control station  21  to place the closer line  37   c  in communication with the accumulator of the HPU  35  via the manifold  36  and then to shut in the closer line with an initial pressure. 
     Alternatively, the closer line  37   c  may be shut-in with no pressure or left open in fluid communication with the HPU reservoir. Alternatively, the opener line  37   o  may be shut in at surface before deployment of the inner casing string  11 . 
     To extend the wellbore  8  from the casing shoe  23  into the lower formation  22   b , the mud pump  24  may pump the drilling fluid  32  from the pit  25 , through a standpipe and Kelly hose of the supply line  30  to the top drive  13 . The drilling fluid  32   d  may flow from the supply line  30  and into the drill string  5  via the top drive  13 . The drilling fluid  32   d  may be pumped down through the drill string  5  and exit the drill bit  33   b , where the fluid may circulate the cuttings away from the bit and return the cuttings up the drilling annulus  34   d . The returns  32   r  (drilling fluid plus cuttings) may flow up the drilling annulus  34   d  to the wellhead  6  and exit the wellhead at the flow cross  19 . The returns  32   r  may continue through the return line  29  and into the shale shaker  26  and be processed thereby to remove the cuttings, thereby completing a cycle. As the drilling fluid  32   d  and returns  32   r  circulate, the drill string  5  may be rotated  4   r  by the top drive  13  and lowered  4   a  by the traveling block  14 , thereby extending the wellbore  8  into the lower formation  22   b.    
       FIGS. 2A and 2B  illustrate the DPI  40 . The DPI  40  may include a tubular mandrel  41   m  and a tubular housing  41   h . The mandrel  41   m  and the housing  41   h  may be longitudinally movable relative to each other between an extended position ( FIG. 2A ) and a retracted position ( FIG. 2B ). The DPI  40  may have a longitudinal bore therethrough for passage of the drill string  5 . The mandrel  41   m  may include two or more sections, such as an adapter  42  and a piston  43 , each connected together, such by threaded couplings (shown) and/or fasteners (not shown). The housing  41   h  may include two or more sections, such as a piston  44  and an adapter  45 , each connected together, such by threaded couplings (shown) and/or fasteners (not shown). 
     The mandrel adapter  42  may also have a threaded coupling (not shown) formed at an upper end thereof for connection to another member of the inner casing string  11 . The housing adapter  45  may also have a threaded coupling formed at a lower end thereof for connection to an upper end of the isolation valve  50 . The housing adapter  45  may also carry a seal  47   e  for sealing an interface between the DPI  40  and the isolation valve  50 . The mandrel adapter  42  may carry a seal  47   a  for sealing an upper interface formed between mandrel  41   m  and the housing  41   h  and the mandrel piston  43  may carry a seal  47   d  for sealing a lower interface formed between mandrel and the housing, thereby sealing a bore of the DPI  40  from the casing annulus  34   c . The mandrel  41   m  and housing  41   h  may be made from a metal or alloy, such as steel, stainless steel, or a nickel based alloy, having strength sufficient to support the isolation valve  50 , any casing joints of the free portion  11   f  below the isolation valve, and the cemented portion  11   c.    
     The mandrel piston  43  may have an upper portion  43   u , a mid portion  43   m  having an enlarged outer diameter relative to the upper portion, and a lower portion  43   b  having an enlarged outer diameter relative to the mid portion. The upper portion  43   u  may have the threaded coupling formed in an outer surface thereof and connecting the mandrel piston  43  to the mandrel adapter  42 . A piston shoulder  43   p  may be formed between the upper  43   u  and mid  43   m  portions in an outer surface of the mandrel piston  43 . A torsional coupling, such as spline teeth  43   s  and spline grooves, may be formed between the mid and lower  43   b  portions in the outer surface of the mandrel piston  43 . An outer diameter of the mandrel adapter  42  may be greater than an outer diameter of the mandrel piston upper portion  43   u  such that a lower end of the mandrel adapter may serve as a stop shoulder  42   h . The threaded coupling connecting the mandrel piston  43  to the mandrel adapter  42  may be formed in an inner surface of the mandrel adapter  42  adjacent to the lower end thereof. 
     The housing piston  44  may receive a lower portion of the mandrel adapter  42  and the upper  43   u  and mid  43   m  portions of the mandrel piston  43 . The housing piston  44  may have an upper portion  44   u , a mid portion  44   m  having a reduced inner diameter relative to the upper portion, and a lower portion  44   b  having an enlarged inner diameter relative to the mid portion. A stop shoulder  44   h  may be formed between the upper  44   u  and mid  44   m  portions in an inner surface of the housing piston  44 . A piston shoulder  44   p  may be formed between the mid  44   m  and lower  44   b  portions in the inner surface of the housing piston  44 . The mid  44   m  and lower  44   b  portions may have the threaded coupling connecting the housing piston  44  to the housing adapter  45  formed in an outer surface thereof. A torsional coupling, such as spline teeth  44   s  and spline grooves, may be formed in a lower end of the housing piston  44 . The housing adapter  45  may receive part of the mid portion  44   m  and the lower portion  44   b  of the housing piston  44  and the lower portion  43   b  of the mandrel piston  43 . The housing adapter  45  may have an upper portion  45   u , a lower portion  45   b  having a reduced inner diameter relative to the upper portion, and a shoulder  45   h  joining the upper and lower portions. The upper portion  45   u  may have the threaded coupling connecting the housing piston  44  to the housing adapter  45  formed in an inner surface thereof. 
     Alternatively, each torsional coupling may include a keyway formed in the respective housing  41   h  and mandrel  41   m  and the torsional connection completed by a key inserted therein. 
     The piston shoulders  43   p ,  44   p  may be engaged when the DPI  40  is in the extended position and the stop shoulders  42   h ,  44   h  may be engaged when the DPI  40  is in the retracted position. A hydraulic chamber  46   c  may be formed longitudinally between the piston shoulders  43   p ,  44   p  when the DPI  40  is in the retraced position. The hydraulic chamber  46   c  may be formed radially between an inner surface of the mandrel piston upper portion  43   b  and an outer surface of the housing piston lower portion  44   b . The housing piston  44  may carry a seal  47   b  in an inner surface of the mid portion  44   m  located adjacent to the piston shoulder  44   p  and the mandrel piston  43  may carry a seal  47   c  in an outer surface of the mid portion  43   m  located adjacent to the piston shoulder  43   p  for sealing the hydraulic chamber  46   c  from the DPI bore. The hydraulic fluid  61  may be disposed in the chamber  46   c . The hydraulic chamber  46   c  may be in fluid communication with a hydraulic coupling  46   f  via a hydraulic passage  46   p  formed in a wall of and along the housing piston  44 . 
     The DPI  40  may be biased toward the extended position by tension  62  exerted on the DPI mandrel  41   m  by the free portion  11   f  being hung from the wellhead  6  and weight of the DPI housing  41   h , the isolation valve  50 , any casing joints of the free portion  11   f  below the isolation valve, and the cemented portion  11   c . Injection of the hydraulic fluid  61  into the chamber  46   c  may overcome the bias and retract the DPI  40  by exerting upward pressure on the housing piston shoulder  44   p  and downward pressure on the mandrel piston shoulder  43   p . A stroke length of the DPI  40  may be infinitesimal relative to a length of the DPI  40 , such as less than one tenth, one twentieth, one fiftieth, or one hundredth. The infinitesimal stroke length may avoid the need for slip joints in the control lines  37   o,c  and the sensing line  37   s . Torsional connection between the housing  41   h  and the mandrel  41   m  may be maintained in and between the retracted and the extended positions by the engaged spline couplings  43   s ,  44   s.    
       FIGS. 3A-3C  illustrate operation of the DPI  40 . Referring specifically to  FIG. 3A , during deployment of the inner casing string  11 , deployment of the drill string  5 , and drilling of the lower formation  22   b , the isolation valve  50  may be open and the DPI  40  idle in the extended position. 
     Referring specifically to  FIG. 3B , after drilling of the lower formation  22   b  to total depth, the drill string  5  may be raised to such that the drill bit  33   b  is above the flapper  53 . The technician may then open the auxiliary valve  31  to supply pressurized hydraulic fluid  61  from the HPU accumulator to the DPI chamber  46   c  via the sensing line  37   s , the coupling  46   f , and the passage  46   p . The DPI  40  may stroke to the retracted position at a threshold pressure  63   t  generating a retraction force (not shown) sufficient to overcome the tension  62  in the inner casing string  11  and to stretch the inner casing string  11  by amount corresponding to the stroke length of the DPI  40  (may be negligible due to infinitesimal stroke length). The HPU accumulator may have a level indicator for monitoring a volume expended therefrom to retract the DPI  40 . Once the threshold pressure  63   t  has been reached, the technician may then close the auxiliary valve  31 , thereby shutting in the DPI chamber  46   c , and instruct the MCU  21   m  to record the threshold pressure. 
     If the tie-back alternative, discussed above, is employed, the retraction force generated by the threshold pressure may only need to overcome the tension in the tieback casing string. Alternatively, pressure may be monitored within the system while tension is pulled on its parent casing to correlate observed pressure fluctuations with the initial tension set on the casing string. 
     Referring specifically to  FIG. 3C , the technician may then close the isolation valve  50  by operating the control station  21  to supply pressurized hydraulic fluid  61  from the HPU accumulator to the closer passage  58   c  and to relieve hydraulic fluid from the opener passage  58   o  to the HPU reservoir. The pressurized hydraulic fluid  61  may flow from the manifold  36  through the wellhead  6  and into the wellbore via closer line  37   c . The pressurized hydraulic fluid  61  may flow down the closer line  37   c  and into the closer passage  58   c  via the hydraulic coupling  57   c . The hydraulic fluid  61  may exit the passage  58   c  into the hydraulic chamber lower portion and exert pressure on a lower face of the flow tube piston, thereby driving the piston upwardly relative to the housing  51 . 
     Alternatively, the drill string  5  may need to be removed for other reasons before reaching total depth, such as for replacement of the drill bit  33   b.    
     As the piston  52   p  begins to travel, hydraulic fluid  61  displaced from the hydraulic chamber upper portion may flow through the opener passage  58   o  and into the opener line  37   o  via the hydraulic coupling  570 . The displaced hydraulic fluid  61  may flow up the opener line  37   o , through the wellhead  6 , and exit the opener line into the hydraulic manifold  36 . As the piston  52   p  travels and the lower sleeve  52   b  clears the flapper  53 , the tension springs may close the flapper. Movement of the piston  52   p  may be halted by abutment of an upper face thereof with the upper housing shoulder. Once the flapper  53  has closed, the technician may then operate the control station  21  to shut-in the closer line  37   c  or both of the control lines  37   o,c , thereby hydraulically locking the piston  52   p  in place. Drilling fluid  32  may be circulated (or continue to be circulated) in an upper portion of the wellbore  8  (above the lower flapper) to wash an upper portion of the isolation valve  50 . The drill string  5  may then be retrieved to the rig  1   r.    
     Once circulation has been halted and/or the drill string  5  has been retrieved to the rig  1   r , pressure  64   u  in the inner casing string  11  acting on an upper face of the flapper  53  may be reduced relative to pressure  64   b  in the inner casing string acting on a lower face of the flapper, thereby creating a net upward force  65  on the flapper which is transferred to the DPI housing  41   h  via the isolation valve housing  51 . Since the net upward force  65  generated by the pressure differential  63   u,b  across the flapper  53  also tends to retract the DPI  40 , the pressure in the DPI chamber  46   c  is reduced to an indication pressure  63   i.    
     The indication pressure  63   i  may be detected by the MCU  21   m  and used thereby to calculate a delta pressure between the indication and threshold  63   t  pressures. The MCU  21   m  may be programmed with a correlation between the calculated delta pressure and the pressure differential  64   u,b  across the flapper  53 . The MCU  21   m  may then convert the delta pressure to a pressure differential across the flapper  53  using the correlation. The MCU  21   m  may then output the converted pressure differential to the gauge  21   g  for monitoring by the technician. 
     The correlation may be determined theoretically using parameters, such as geometry of the flapper  53 , isolation valve housing  51 , DPI housing  41   h , and DPI mandrel  41   m , and material properties thereof, to construct a computer model, such as a finite element and/or finite difference model, of the DPI  40  and isolation valve  50  and then a simulation may be performed using the model to derive a formula. The model may or may not be empirically adjusted. 
     The control station  21  may further include an alarm (not shown) operable by the MCU  21   m  for alerting the technician, such as a visual and/or audible alarm. The technician may enter one or more alarm set points into the control station  21  and the MCU  21   m  may alert the technician should the converted annulus pressure violate one of the set points. A maximum set point may be a design pressure of the flapper  53 . Weight of the DPI housing  41   h , the isolation valve  50 , any casing joints of the free portion  11   f  below the isolation valve, and the cemented portion  11   c  may be sufficient such that the tension  62  is greater than or equal to the net upward force  65  generated by a pressure differential  64   u,b  equal to the design pressure of the flapper  65 , thereby ensuring that a measurement range of the DPI  40  is broad enough to include the flapper design pressure. 
     If total depth has not been reached, the drill bit  33   b  may be replaced and the drill string  5  may be redeployed into the wellbore  8 . The DPI  40  may also be used to monitor differential pressure while tripping into the hole to gauge surge and swab effects. 
     Pressure in the upper portion of the wellbore  8  may then be equalized with pressure in the lower portion of the wellbore  8  using the converted pressure differential displayed by the gauge  21   g  to ensure proper equalization. The technician may then operate the control station  21  to supply pressurized hydraulic fluid to the opener line  37   o  while relieving the closer line  37   c , thereby opening the flapper  53 . Once the flapper  53  has been opened, the technician may then operate the control station  21  to shut-in the opener line  37   c  or both of the control lines  37   o,c , thereby hydraulically locking the flow tube piston in place. Drilling may then resume. In this manner, the lower formation  22   b  may remain live during tripping due to isolation from the upper portion of the wellbore  8  by the closed isolation valve  50 , thereby obviating the need to kill the lower formation  22   b.    
     Once drilling has reached total depth, the drill string  5  may be retrieved to the drilling rig  1   r , as discussed above. A liner string (not shown) may then be deployed into the wellbore  8  using a work string (not shown). The liner string and workstring may be deployed into the live wellbore  8  using the isolation valve  50 , as discussed above for the drill string  5 . Once deployed, the liner string may be set in the wellbore  8  using the work string. The work string may then be retrieved from the wellbore  8  using the isolation valve  50  as discussed above for the drill string  5 . The PCA  1   p  may then be removed from the wellhead  6 . A production tubing string (not shown) may be deployed into the wellbore  8  and a production tree (not shown) may then be installed on the wellhead  6 . Hydrocarbons (not shown) produced from the lower formation  22   b  may enter a bore of the liner, travel through the liner bore, and enter a bore of the production tubing for transport to the surface  9 . 
     Alternatively, each piston shoulder  43   p ,  44   p  may be transposed with the respective stop shoulder  42   h ,  44   h , the passage  46   p  formed in a wall of and along the mandrel  41   m  instead of the housing  41   h , thereby causing the indication pressure  63   i  to increase with increasing differential pressure  63   u,b  across the flapper  53 . In a further variant of this alternative, the DPI may have a pressure sensor in fluid communication with the DPI chamber and the sensing line may be an electric or optical cable for transmission of a signal from the sensor to the control station. 
       FIGS. 4A-4D  illustrate isolation valves  70 ,  80 ,  90 ,  100  having integrated DPIs, according to other embodiments of the present disclosure. Referring specifically to  FIG. 4A , the isolation valve  70  may include a tubular housing  71 , an opener, such as the flow tube  52 , a closure member, such as the flapper  53 , the opener coupling  57   o , the closer coupling  57   c , the hinge  59 , a seat  74 , a seat receiver  75 , and a flow tube receiver (not shown). 
     To facilitate manufacturing and assembly, the housing  71  may include one or more sections (only one section shown) each connected together, such by threaded couplings and/or fasteners. Interfaces between the housing sections may be isolated, such as by seals. The housing sections may include an upper adapter and a lower adapter, each having a threaded coupling for connection to other members of the inner casing string  11 . The isolation valve  70  may have a longitudinal bore therethrough for passage of the drill string  5 . The housing  71  may have the hydraulic chamber  56  (not shown) and the passages  58   o,c  (not shown) for operation of the flow tube  52 . Each of the flow tube receiver and seat receiver  75  may be connected to the housing  71 . The housing may also have a piston shoulder  71   s  formed in an inner surface thereof. 
     The flapper  53  may be pivotally connected to the seat  74  by the hinge  59 . An inner periphery of the flapper  53  may engage a respective seating profile formed in an adjacent end of the seat  74  in the closed position, thereby sealing an upper portion of the valve bore from a lower portion of the valve bore. The interface between the flapper  53  and the seat  74  may be a metal to metal seal. 
     The seat  74  may be longitudinally movable relative to the housing  71  between an upper position (not shown) and a lower position (shown). The seat  74  may be stopped in the lower position by the seat receiver  75 . The seat  74  may have a piston shoulder  74   s  formed in an inner surface thereof. The isolation valve  70  may further include a DPI chamber  76  formed longitudinally formed between the housing shoulder and the seat shoulder  74   s . The housing  71  may carry a seal located adjacent to the shoulder  71   s  and the seat  74  may carry a seal located adjacent to the shoulder  74   s  for sealing the DPI chamber  76  from the bore of the isolation valve  70 . The DPI chamber  76  may be defined radially between the seat  74  and the housing  71 . Hydraulic fluid  61  may be disposed in the DPI chamber  76 . The DPI chamber  76  may be in fluid communication with the sensing coupling  46   f  via a hydraulic passage  78  formed in and along a wall of the housing  71 . The sensing line  37   s  (not shown) may connect the coupling  46   f  to the control station  21  and the HPU  35 . 
     In operation, the seat  74  may be maintained in the lower position by a threshold pressure in the DPI chamber  76  and the DPI chamber being shut in by the valve  31  whether the isolation valve  70  is closed or open. When the isolation valve  70  is closed, the MCU  21   m  may monitor pressure in the sensing line  37   s , calculate a delta pressure, and use a correlation to calculate differential pressure across the flapper  53 . As compared to the DPI  40 , a net upward force on the flapper  53  will increase pressure in the DPI chamber  76  instead of reducing pressure and the isolation valve  70  may be located in either the free portion  11   f  or the cemented portion  11   c.    
     Alternatively, the DPI chamber  76  may be in fluid communication with either the opener passage or the closer passage and the sensing coupling  46   f  and sensing line  37   s  may be omitted. 
     Referring specifically to  FIG. 4B , the isolation valve  80  may include a tubular housing  81 , an opener, such as the flow tube  52 , a closure member, such as the flapper  53 , the opener coupling  57   o , the closer coupling  57   c , the hinge  59 , a seat  74 , a seat receiver (not shown), and a flow tube receiver (not shown). The valve  80  may be similar to the valve  70  except that a biasing member, such as compression spring  82  may be disposed in the DPI chamber  76 . An upper end of the compression spring  82  may bear against the housing shoulder  71   s  and a lower end of the compression spring may bear against the seat shoulder  74   s , thereby biasing the seat  74  toward the lower position. A stiffness and stroke of the spring  82  may be selected such that the spring may bottom out at the flapper design pressure. Further, the control station  21  may include an accumulator  83  for operation of the isolation valve  80  having a level sensor  84  in communication with the MCU  21   m  and the shutoff valve  31  and connection to the HPU  35  by the sensing line may be omitted. 
     In operation, the DPI chamber  76  may be in communication with the accumulator  83  whether the isolation valve  80  is open or closed. When the isolation valve  80  is closed, a net upward force on the flapper  53  may drive the seat  74  upward against the spring  82 , thereby expelling hydraulic fluid  61  from the DPI chamber  76  into the accumulator  83 . The MCU  21   m  may monitor a fluid level in the accumulator  83  using the level sensor  84  to determine a volume of the hydraulic fluid  61  expelled from the DPI chamber  76  and calculate a change in length of the spring  82  using an area of the DPI chamber  76 . Once the MCU  21   m  has calculated the spring length, the MCU  21   m  may then determine the differential pressure across the flapper  53  using a stiffness of the spring  82  and geometry of the flapper  53 . 
     Referring specifically to  FIG. 4C , the isolation valve  90  may include a tubular housing  91 , an opener, such as the flow tube  52 , a closure member, such as the flapper  53 , the opener coupling  570 , the closer coupling  57   c , the hinge  59 , a seat  94 , a biasing member, such as the compression spring  82 , a DPI chamber  96 , a seat receiver (not shown), and a flow tube receiver (not shown). The valve  90  may be similar to the valve  80  except that the hydraulic fluid  61  may be omitted from the DPI chamber  96  and a proximity sensor  92   s  and target  92   t  disposed at respective ends of the DPI chamber  96 . The housing  91  may have a sealed conduit  98  for receiving leads  97  extending from the proximity sensor  92   s  to an electrical coupling (not shown, replaces hydraulic coupling  46   f ). A sensing cable (not shown) may extend from the isolation valve  90  to the control station  21  instead of the sensing line  37   s . The sensing cable may extend to the control station  21  independently of the control lines  37   o,c  or be bundled therewith in the umbilical. 
     The target  92   t  may be a ring made from a magnetic material or permanent magnet and may be mounted to the seat shoulder  94   s  by being bonded or press fit into a groove formed in the shoulder face. The sensor  92   s  may be mounted to the housing  91  adjacent to the shoulder  91   s . Each of the housing  91  and the seat  94  may be made from a diamagnetic or paramagnetic material. The proximity sensor  92   s  may or may not include a biasing magnet depending on whether the target  92   t  is a permanent magnet. The proximity sensor  92   s  may include a semiconductor and may be in electrical communication with the leads  97  for receiving a regulated current. The proximity sensor  92   s  and/or target  92   t  may be oriented so that the magnetic field generated by the biasing magnet/permanent magnet target is perpendicular to the current. The proximity sensor  92   s  may further include an amplifier for amplifying the Hall voltage output by the semiconductor when the target  92   t  is in proximity to the sensor. 
     Alternatively, the proximity sensor may include, but is not limited to inductive, capacitive, optical, or utilization of wireless identification tags. Alternatively, the sensor  92   s  and target  92   t  may each be connected to a respective end of the spring  82 . 
     In operation, when the isolation valve  90  is closed, a net upward force on the flapper  53  may drive the seat  94  upward against the spring  82 , thereby moving the target  92   t  toward the sensor  92   s . The MCU  21   m  may monitor the sensor  92   s  and determine a length of the spring  82 . The MCU  21   m  may then determine the differential pressure across the flapper  53  using a stiffness of the spring  82  and geometry of the flapper  53 . 
     Referring specifically to  FIG. 4D , the isolation valve  100  may include a tubular housing  101 , an opener, such as the flow tube  52 , a closure member, such as the flapper  53 , the opener coupling  57   o , the closer coupling  57   c , the hinge  59 , the seat  94 , a biasing member, such as the compression spring  82 , a DPI chamber  96 , a seat receiver (not shown), and a flow tube receiver (not shown). The valve  100  may be similar to the valve  90  except for having a position sensor  102   i,o  instead of the proximity sensor  92   s  and target  92   t.    
     The position sensor  102   i,o  may be a linear variable differential transformer (LVDT) having an outer tube  102   o  and an inner ferromagnetic core  102   i . The outer tube  102   o  may be disposed in the sealed conduit  108  and mounted to the housing  101 . The outer tube  102   o  may be in electrical communication with the electrical coupling via leads (not shown). The inner core  102   i  may extend from the outer tube  102   o , through the DPI chamber  96  and have a lower end connected to the seat shoulder  94   s . The outer tube  102   i  may have a central primary coil (not shown) and a pair of secondary coils (not shown) straddling the primary coil. The primary coil may be driven by an AC signal and the secondary coils monitored for response signals which may vary in response to position of the core  102   i  relative to the outer tube  102   o.    
     In operation, when the isolation valve  100  is closed, a net upward force on the flapper  53  may drive the seat  94  upward against the spring  82 , thereby contracting the position sensor  102   i,o . The MCU  21   m  may monitor the sensor  102   i,o  and determine a length of the spring  82 . The MCU  21   m  may then determine the differential pressure across the flapper  53  using a stiffness of the spring  82  and geometry of the flapper  53 . 
     Alternatively, each end of the position sensor  102   i,o  may be connected to a respective end of the spring  82 . 
       FIGS. 5A-5C  illustrate further isolation valves  110 ,  120 ,  130  having integrated DPIs, according to other embodiments of the present disclosure. Referring specifically to  FIG. 5A , the isolation valve  110  may include a tubular housing  111 , an opener, such as the flow tube  52 , a closure member, such as the flapper  53 , the opener coupling  57   o , the closer coupling  57   c , the hinge  59 , a seat  114 , an electrical coupling  116 , and a flow tube receiver (not shown). 
     To facilitate manufacturing and assembly, the housing  111  may include one or more sections (only one section shown) each connected together, such by threaded couplings and/or fasteners. Interfaces between the housing sections may be isolated, such as by seals. The housing sections may include an upper adapter and a lower adapter, each having a threaded coupling for connection to other members of the inner casing string  11 . The isolation valve  110  may have a longitudinal bore therethrough for passage of the drill string  5 . The housing  110  may have the hydraulic chamber  56  (not shown) and the passages  58   o,c  (not shown) for operation of the flow tube  52 . Each of the flow tube receiver and seat receiver  75  may be connected to the housing  111 . The housing may also have a shoulder  111   s  formed in an inner surface thereof. 
     The upper adapter section may have one or more strain gages  112   a,b  mounted on an outer surface thereof. Leads  117  may extend from each strain gage  112   a,b  to the electrical coupling  116 . A sensing cable (not shown) may extend from the isolation valve  110  to the control station  21 . The sensing cable may extend to the control station  21  independently of the control lines  37   o,c  or be bundled therewith in the umbilical. Each strain gage  112   a,b  may be foil, semiconductor, piezoelectric, or magnetostrictive. Each strain gage  112   a,b  may be oriented (i.e., parallel or diagonal) relative to a longitudinal axis of the housing  111  to measure longitudinal strain of the upper adapter section due to force exerted thereon by the closed flapper  53 . Additional strain gages may be disposed on the upper adapter section to account for temperature and/or increase sensitivity. 
     The flapper  53  may be pivotally connected to the seat  114  by the hinge  59 . An inner periphery of the flapper  53  may engage a respective seating profile formed in an adjacent end of the seat  114  in the closed position, thereby sealing an upper portion of the valve bore from a lower portion of the valve bore. The interface between the flapper  53  and the seat  114  may be a metal to metal seal. The seat  114  may be linked to the housing, such as by a fastener  115  and slot  114   t  joint to allow limited longitudinal movement of the seat  114  relative to the housing  111  between an upper position (shown) and a lower position (not shown). The seat  114  may have a shoulder  114   s  formed in an inner surface thereof. The seat  114  may be stopped in the upper position by engagement of the shoulders  114   s ,  111   s.    
     In operation, when the isolation valve  110  is closed, a net upward force on the flapper  53  may push the seat  94  upward toward the housing  111  until the shoulders  114   s ,  111   s  engage, thereby relieving tension on the upper adapter section. The MCU  21   m  may monitor the strain gages  112   a,b  and determine the force exerted on the housing  111  by the closed flapper  53 . The MCU  21   m  may then determine the differential pressure across the flapper  53  using geometry of the flapper  53 . 
     Referring specifically to  FIG. 5B , the isolation valve  120  may include a tubular housing  121 , an opener, such as the flow tube  52 , a closure member, such as the flapper  53 , the opener coupling  57   o , the closer coupling  57   c , the hinge  59 , a seat  124 , the slip joint  114   t ,  115 , the electrical coupling  116 , and a flow tube receiver (not shown). The valve  120  may be similar to the valve  110  except for having a load cell  122  instead of the strain gages  112   a,b.    
     A sensing cable (not shown) may extend from the isolation valve  120  to the control station  21 . The load cell  122  may be disposed in a sealed conduit  128  adjacent to a shoulder  121   s  formed in an inner surface of the housing  121  and mounted to the housing. Leads  127  may extend from the load cell  122  to the electrical coupling  116 . The load cell  122  may be hydraulic, pneumatic, or mechanical (strain gage). An upper end of the seat  124  may serve as a shoulder  124   s  for engaging the load cell  122 . 
     In operation, when the isolation valve  120  is closed, a net upward force on the flapper  53  may push the seat  124  upward toward the housing  121  until the shoulder  124   s  engages the load cell  122 . The MCU  21   m  may monitor the load cell  122  and determine the force exerted thereon by the closed flapper  53 . The MCU  21   m  may then determine the differential pressure across the flapper  53  using geometry of the flapper  53 . 
     Referring specifically to  FIG. 5C , the isolation valve  130  may include a tubular housing  131 , an opener, such as the flow tube  52 , a closure member, such as the flapper  53 , the opener coupling  57   o , the closer coupling  57   c , the hinge  59 , a seat  124 , the slip joint  114   t ,  115 , the electrical coupling  116 , and a flow tube receiver (not shown). The valve  130  may be similar to the valve  110  except for having a strain gage  112   c  mounted to the outer face of the flapper  53 . The strain gage  112   c  may be similar to the strain gages  112   a,b . Leads  137  may extend from the strain gage  112   c  to the electrical coupling  116  via a sealed conduit  138 . A sensing cable (not shown) may extend from the isolation valve  130  to the control station  21 . 
     In operation, when the isolation valve  130  is closed, a net upward force on the flapper  53  may push the flapper against the profile of the seat  124  and the seat upward toward the housing  131  until the seat engages the housing. The MCU  21   m  may monitor the strain gage  112   c  and determine the differential pressure across the flapper  53 . 
     Alternatively, the strain gage  112   c  may be mounted on the flapper hinge  59 . 
     Alternatively, the drilling system  1  may be a closed loop drilling system including a rotating control device, a supply flow meter, a returns flow meter, an automated choke, and/or a gas chromatograph. The closed loop drilling system may be operated to perform a mass balance during drilling and exert variable backpressure on the returns. 
     While the foregoing is directed to embodiments of the present disclosure, other and further embodiments of the disclosure may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.