Patent Publication Number: US-11047199-B2

Title: Hydraulic workover unit for live well workover

Description:
TECHNICAL FIELD OF THE INVENTION 
     The disclosure relates, in general, to hydrocarbon production, and more particularly, to electrical submersible pump (ESP) completions utilized in the production of hydrocarbons. Most particularly, the disclosure relates to a hydraulic workover unit for performing a live well workover involving ESP completions. 
     BACKGROUND OF THE INVENTION 
     Oil wells are commonly overbalanced, wherein wellbore pressure exceeds formation fluid pressure preventing the well from flowing. In many instances, overbalanced wells require artificial lift to produce. One common type of artificial lift uses an electrical submersible pump (ESP), which is lowered into the well on a production tubing string. Power is supplied to the ESP by an electrical cable that is clamped or banded to the outer diameter of the tubing string. Because the wells are overbalanced, when workover on the well is required, traditional kill weight fluids, such as water, cannot be used because the kill weight fluid could damage the already overbalanced well. 
     Where wells cannot be killed, the only option is a live well (snubbing) workover, whereby the well remains under pressure during the workover. In such snubbing operations, equipment is run into the well on a pipe string using a hydraulic workover rig. Unlike wireline or coiled tubing, the pipe sections that make up the pipe string are not spooled off a drum, but made up and broken up while running in and pulling out, much like conventional drill pipe. However, even in wells that are overbalanced such that formation fluids are not flowing to the surface, there may be gas, such as hydrogen sulfide (H 2 S) existing in the well between the formation fluid column in the well and the surface. This gas must be taken into consideration and contained during live well workovers. Thus, blow out preventer are positioned between the wellhead and the hydraulic jack utilized in the snubbing workover to trip tubing string in and out of the well. Where the tubing string is annular in cross-section, the BOP may be a conventional annular BOP with a dynamic seal that retains the seal as the tubing string is passed through the BOP. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       For a detailed description of exemplary embodiments, reference will now be made to the accompanying drawings in which: 
         FIG. 1  is a front elevation view of a hydraulic workover unit in accordance with the teachings herein; 
         FIG. 2  is a close-up front elevation view of a wellhead attached at a lower end of the hydraulic workover unit of  FIG. 1 ; 
         FIG. 3  is a close-up front elevation view of an upper portion of the hydraulic workover unit of  FIG. 1 ; 
         FIG. 4  is a close-up front elevation view of a middle portion of the hydraulic workover unit of  FIG. 1 ; 
         FIG. 5  is a close-up front elevation view of a lower portion of the hydraulic workover unit of  FIG. 1 ; 
         FIG. 6  is a flowchart outlining a first method of using a hydraulic workover unit in accordance with the teachings herein; and 
         FIG. 7  is a flowchart outlining a second method of using a hydraulic workover unit in accordance with the teachings herein. 
     
    
    
     DETAILED DESCRIPTION 
     The embodiments described herein include a hydraulic workover system configured for performing live well workover during electrical submersible pump (ESP) completion operations, thereby permitting the ability to insert jointed pipe production string with an ESP cable attached thereto into an underground wellbore without killing the well. Generally, the hydraulic workover system includes a hydraulic jack having a first portion reciprocally movable relative to a second portion, with a first static annular blow out preventer mounted on one portion and a second dynamic blowout preventer mounted on the other portion. The first static blow out preventer has a tubular riser attached thereto, which tubular riser extends through and is sealingly engaged by the second dynamic blow out preventer. The hydraulic jack can be actuated to axially move the tubular riser through the second dynamic blow out preventer. In one or more embodiments, a first end of a tubular spool is attached to the second blow out preventer and a third static annular blow out preventer is attached to a second end of the spool so that the second and third blowout preventers are fixed relative to one another. A cross-over valve may be provided between the second blowout preventer and the third blowout preventer. The first and third blowout preventers each include one or more deformable elastomeric sealing elements, while the second blow out preventer includes one or more rigid elastomeric sealing elements. In operation, as the hydraulic jack is utilized to raise or lower an irregularly shaped tubing string, only one of the first or third blowout preventers is utilized at any given time to seal around the tubing string, such that either the first and second blow out preventers are providing sealing during actuation of the jack, or the second and third blow out preventers are providing sealing during actuation of the jack. 
       FIG. 1  is a front elevation view of a hydraulic workover unit. Specifically, shown is a well site  100  that includes an underground wellbore  102  extending from a surface  104 . A wellhead  106  may be disposed at surface  104  above wellbore  102 . In the illustrated embodiment, wellhead  106  includes one or more BOPs  108 . In one embodiment, BOPs  108  may be ram-type BOPs. However, in other embodiments wellhead  106  may include, without limitation, various other annular BOPs, housings, valves, and flanges. In any event, a workover system  110  is attached to wellhead  106  above the BOPs  108 . It will be appreciated that hydraulic workover system  110  may be utilized with any wellhead  106  and the above description of wellhead  106  is for illustrative purposes only. In one or more embodiments, a portion of wellhead  106  may be provided as part of hydraulic workover system  110 . 
     As shown, workover system  110  may be disposed above wellhead  106  which may structurally support workover system  110 . In one or more embodiments, workover system  110  may be supported externally by a crane or other structure (not shown) or supported by both a crane and wellhead  106 . Workover system  110  may include a first or lower flange  111 . In one or more embodiments, first flange  111  is disposed for attachment to wellhead  106 . In the illustrated embodiment, first flange  111  of workover system  110  is bolted to second flange  107  of wellhead  106 . The flanged connection provides a structural and pressure-containing interface between wellhead  106  and workover system  110 . 
       FIG. 2  is a close-up front elevation view of a wellhead attached at a lower end of the hydraulic workover unit of  FIG. 1 , and in particular, illustrates wellhead  106  in more detail. Wellhead  106  may include one or more BOPs  108 . A bore  112  is formed through wellhead  106  generally about longitudinal axis  114 . Workover system  110  is generally axially aligned with longitudinal axis  114  so that various components of workover system  110  can be in fluid communication with bore  112 . Bore  112  includes an inner surface  112   a  having an inner diameter D 1 . Wellhead  106  is configured to provide a structure for suspending a casing string  102   a  used to line wellbore  102 . Furthermore, wellhead  106  is configured to provide pressure containment between wellbore  102  and surface  104 . Wellhead  106  may include a first, lower, or hanger flange  106   a  and a second or upper flange  107 . In one or more embodiments, first flange  106   a  is disposed for attachment to a casing string  102   a  and second flange  107  is disposed for attachment to workover system  110 . A production string  116  may be disposed in bore  112  along longitudinal axis  114 . Production string  116  includes an outer surface  116   a  having an outer diameter D 2 . Outer diameter D 2  may be smaller than inner diameter D 1  of bore  112  to enable production string  116  to pass freely through bore  112 . It will be appreciated that when workover system  110  is connected to wellhead  106  as described herein, wellbore  102 , wellhead  106 , and bore  112  substantially align so that production string  116  may extend from within wellbore  102 , through wellhead  106 , through bore  112 , and above workover system  110  (see  FIG. 1 ). Production string  116  may include a cable  118  attached to outer surface  116   a . Cable  118  may be secured to outer surface  116   a  of production string  116  using fasteners  128 , such as clamps. 
     Turning back to  FIG. 1 , workover system  110  includes an upper portion  110   a , a middle portion  110   b  and a lower portion  110   c . Lower portion  110   c  engages wellhead  106  via first flange  111  and generally includes a lower annular BOP  200  with a tubular  190 , such as an extension spool, extending up from lower annular BOP  200  along axis  114 . Lower annular BOP  200  is a statically sealing BOP. In one or more embodiments, an upper flow cross assembly  192  and a lower flow cross assembly  210  may be provided to direct flow around lower annular BOP  200  as described below. Middle portion  110   b  of workover system  110  generally includes a stationary assembly  120  and a traveling assembly  220  which reciprocates along axis  114  relative to stationary assembly  120  for stripping production string  116  to which cable  118  is attached. In this regard, middle portion  110   b  functions as the feed point for joining cable  118  to production string  116  using fasteners  128 . This is typically performed adjacent a lower work platform such as first work platform  130  within a traveling window  230 . In any event, middle portion  110   b  includes a frame  122  which supports an actuation mechanism  170 , such as a reciprocating jack  170 , to move traveling assembly  220  relative to stationary assembly  120 . Stationary assembly  120  includes a stationary or fixed BOP  180  to which the extension spool or tubular  190  of lower portion  110   c  attached, thereby fixing stationary BOP  180  and lower annular BOP  200  relative to one another. Stationary BOP  180  is a dynamically sealing BOP. Traveling assembly  220  includes a traveling annular BOP  270  which is reciprocated by jack  170  relative to stationary BOP  180 . Traveling annular BOP  270  is a statically sealing BOP. Traveling assembly  220  may also include a first set of traveling slips  260  generally adjacent second set of traveling slips  250 . Upper portion  110   a  generally incudes a first set of upper slips  150 , such as heavy slips, and a second set of upper slips  160 , such as snub slips, utilized to attach and detach pipe sections from production string  116  from an upper work platform such as second platform  132 . As stated above, various components of workover system  110  generally axially aligned along longitudinal axis  114  such that traveling annular BOP  270 , dynamic BOP  180  and stationary annular BOP  200  are all generally axially aligned. 
     As described herein, dynamic BOPs typically refer to BOPs that include one or more solid elastomeric seal elements that are actuated with a piston, plungers, rams, linkage or similar mechanical structure to urge the elastomeric seal element(s) into engagement with a tubing string. In this regard, dynamic BOP may be an annular BOP or a ram BOP. Where an irregular shaped tubing string is being tripped in or out of the wellbore, such as would be the case where an ESP is deployed on the tubing string and an electrical cable clamped to the outer diameter of the tubing string, conventional dynamic BOPs with seal elements as described above cannot be utilized because such BOPs, and in particular, their seal elements, will not seal around irregular shaped or non-round tubing strings. However, there is a class of annular BOPs that employ soft elastomeric seal elements that can adapt to irregular shaped tubing string to form a seal around the tubing string. Typically, such seal elements are typically inflatable, with a pressure cavity formed within the seal element and disposed for receipt of a pressurized activation fluid in order to expand the seal element around an irregular shape. It will be appreciated that such BOPs do not require any moving parts such as pistons to activate, but simply function as pressure to close; vent to open type devices. However, because the seal element inflates to seal around a pipe string, such “soft” seal element BOPs are static in nature, and are referred to herein as static annular BOPs. Static annular BOPs cannot satisfy the dynamic needs required for snubbing workovers where ESP production tubing is involved. 
     With respect to production string  116  and cable  118 , fasteners  128  may be spaced apart from one another by a distance HE The distance H 1  may correspond to a stroke length L 1  of workover system  110 . However, it will be appreciated that any spacing may be used. As used herein, production string  116  may generally refer to any type of tubing, including without limitation jointed pipe or coiled tubing and may or may not include cable  118  disposed on outer surface  116   a . When production string  116  includes cable  118 , production string  116  may have a non-circular or other irregularly-shaped outer surface  116   a . However, even when production string  116  does not include cable  118 , production string  116  may include components having a non-circular or other irregularly shaped outer surface  116   a , including without limitation some types of pipe or tubing, downhole tools, a gas lift side-pocket mandrel, or any other irregularly shaped wellbore implements known in the art. As used herein, cable  118  may generally refer to any type of cable or tubing attached to outer surface  116   a  of production string  116 , including without limitation an ESP cable, a subsurface safety valve (SSSV) control line tubing, an external capillary string, an electrical or hydraulic tubing, an external tubing on a gas lift mandrel, or any other control line cable or tubing known in the art. As used herein, fastener  128  is not limited to a particular type of fastener. In one or more embodiments, fastener  128  may be conventional tubing clamps having a low profile as is known in the industry. It will be appreciated that when production string  116  includes cable  118  and clamps  128 , then outer diameter D 2  may correspond to a major diameter of production string  116 , cable  118 , and clamps  128  and outer diameter D 2  may exceed a diameter of outer surface  116   a.    
     As described above, workover system  110  includes a stationary assembly  120  and a traveling assembly  220 , which may move relative to stationary assembly  120  along longitudinal axis  114 . Stationary assembly  120  may include a frame  122  for structurally supporting a first or lower work platform  130  and a second or upper work platform  132 . Frame  122  supports first work platform  130  below second work platform  132 . In one or more embodiments, to be described later, first work platform  130  may alternatively be attached to traveling assembly  220  instead of being attached to stationary assembly  120 , thus making first work platform  130  movable relative to stationary assembly  120 . 
       FIG. 3  is a close-up front elevation view of an upper portion of the hydraulic workover unit of  FIG. 1 , and in particular, illustrates upper portion  110   a  of workover system  110  in more detail. Frame  122  includes a first or upper end  122   a  disposed for attachment to second work platform  132 . Frame  122  further supports a gin pole  140  having a cable  142  suspended therefrom. Cable  142  includes a first end attached to a winch  144  and a second end attached to an elevator (not shown). Gin pole  140  may use the elevator to lift and/or lower a section of production pipe between surface  104  and second work platform  132 . In one or more embodiments, gin pole  140  may be sized to suspend an upper end of the joint of production pipe by as much as 32 feet above second work platform  132  while maintaining tension using winch  144 . Second work platform  132  may include a pipe tong  146  for making-up or breaking-out a connection between the production pipe section and production string  116 . Pipe tong  146  may be disposed on second work platform  132 . In one or more embodiments, pipe tong  146  may be suspended from a tong arm (not shown) attached to second work platform  132 . In one or more embodiments, pipe tong  146  may be suspended from a tong arm (not shown) attached to gin pole  140 . In one or more embodiments, pipe tong  146  may rotated into and out of alignment with longitudinal axis  114  in order to make-up or break-out the connection. When the connection is made-up, production string  116  may extend from the elevator down through workover system  110  and into wellbore  102 . In one or more embodiments, during operation, as production string  116  is run into wellbore  102 , cable  142  and winch  144  maintain tension on production string  116  while a second winch (not shown) lowers a second cable (not shown) to surface  104  to simultaneously lift a next joint of production pipe to second work platform  132 . In one or more embodiments, workover system  110  may include one or more control consoles, including without limitation a BOP operator console, a winch console, and a jack operator console (not shown). In one or more embodiments, various functions of the one or more control consoles may be combined into a single console and/or controlled remotely. 
     Stationary assembly  120  (see  FIG. 1 ) further includes a first set of upper stationary slips  150  and a second set of upper stationary slips  160  located in a fixed position at about a height of second work platform  132 . First set of upper stationary slips  150  may be heavy slips while second set of upper stationary slips  160  may be snub slips. Stationary heavy slips  150  are configured to grip and hold production string  116  stationary in a pipe heavy condition, wherein a balance of forces on production string  116  is downward. Stationary snub slips  160  are configured to grip and hold production string  116  stationary in a pipe light condition, wherein a balance of forces on production string  116  is upward. In one or more embodiments, stationary slips  150 ,  160  may have a weight capacity that ranges from about 150,000 pounds to about 600,000 pounds. More particularly, the weight capacity may range from about 150,000 pounds to about 460,000 pounds. In one non-limiting example, stationary slips  150 ,  160  may have a weight capacity of 340,000 pounds. In one or more embodiments, stationary slips  150 ,  160  may have inner diameter D 1  greater than outer diameter D 2  of production string  116 . 
       FIG. 4  is a close-up front elevation view of a middle portion of the hydraulic workover unit of  FIG. 1 , and in particular, illustrates middle portion  110   b  of workover system  110  in more detail. Stationary assembly  120  has a base plate  124  to which a second or lower end  122   b  of frame  122  attaches. Reciprocating jack  170  is disposed adjacent second end  122   b  of frame  122 . In one or more embodiments, jack  170  may be disposed on base plate  124 . In one or more embodiments, jack  170  may be hydraulically or electrically actuated using hydraulic cylinders or electric linear actuators, respectively. In one or more embodiments, the hydraulic cylinders and electric linear actuators may be omitted, and jack  170  may be actuated using overhead cables. In one or more embodiments, jack  170  may include two or more piston cylinders, such as piston cylinders  172   a ,  172   b . In one or more embodiments, jack  170  may include two sets of piston cylinders  172   a ,  172   b , arranged in a square-shaped footprint surrounding longitudinal axis  114  of workover system  110 . In any event, each of piston cylinders  172   a ,  172   b  includes a respective housing  174   a ,  174   b  and a respective piston rod  176   a ,  176   b . Jack  170  may raise and lower traveling assembly  220  of workover system  110  by stroke length L 1 , wherein stroke length L 1  of traveling assembly  220  corresponds to a stroke length of jack  170  effected by piston cylinders  172   a ,  172   b . It will be appreciated that jack  170  may include any size and number of piston cylinders  172   a ,  172   b  necessary to provide stable and level operation and to accommodate design stroke length L 1  of traveling assembly  220 . In one or more embodiments, jack  170  may be rated to handle a weight twice an expected working load of workover system  110 . For example, if a working load of 170,000 pounds is expected for an operation, jack  170  could be rated for 340,000 pounds. In one or more embodiments, stationary slips  150 ,  160  may be sized in accordance with the weight capacity of jack  170 . For instance, if jack  170  is rated for 340,000 pounds, then stationary slips  150 ,  160  may be rated to handle 340,000 pounds. If greater clearance is needed to accommodate outer diameter D 2  of production string  116 , then stationary slips  150 ,  160  may have a greater weight capacity compared to jack  170  to accommodate the greater clearance. In one non-limiting example, in order to create adequate clearance for 9⅝ inch tubing, stationary slips  150 ,  160  may be rated for 600,000 pounds, whereas stationary slips  150 ,  160  creating adequate clearance for 7⅝ inch tubing may be rated for a lower weight capacity such as 340,000 pounds or 460,000 pounds. It will be appreciated that reference has been made herein to slips having standard sizes and weight capacities. However, slips having non-standard sizes and weight capacities may be used. 
     Stationary assembly  120  may further include a stationary BOP  180 . In one or more embodiments, BOP  180  may be of a conventional type. Stationary BOP  180  is a dynamic BOP. In one or more embodiments, dynamic BOP  180  may be attached to base plate  124 . In one or more embodiments, dynamic BOP  180  may be located below jack frame  122  and base plate  124  in cases where jack frame  122  does not support well pressure integrity through base plate  124 . In such cases, base plate  124  may not include top and bottom ring grooves that would provide necessary pressure sealing. In one or more embodiments, dynamic BOP  180  may include one or more sealing elements  182  for dynamic sealing. Sealing elements  182  may be standard elastomeric sealing elements known in the industry. The one or more dynamic sealing elements  182  are positioned within a bowl section (not shown) of a housing  184  of dynamic BOP  180 . Housing  184  may include a first or lower flange  184   a  disposed for attachment to base plate  124 . Housing  184  may enclose an actuation element (not shown) that may be hydraulically or electrically powered. In one or more embodiments, the actuation element is a hydraulically powered annular piston that pushes the one or more elements  182  against a cam surface (not shown) forcing the one or more elements  182  inward and into sealing engagement with a reciprocating riser  280  of traveling assembly  220 . As used herein, dynamic sealing element refers to a sealing element through which a tubular, such as completion string  116 , can dynamically slide while maintaining a seal between the tubular and the sealing element. Likewise, a dynamic annular BOP refers to a BOP through which a tubular, such as completion string  116 , can slide while maintaining a seal around the tubular as it dynamically slides through the BOP. 
     Traveling assembly  220  of workover system  110  is operatively connected to stationary assembly  120  via jack  170 . Upper ends of piston rods  176   a ,  176   b  may connect to a traveling assembly base plate  222 . A traveling window  230  may be disposed on an upper surface of base plate  222 . In one or more embodiments, traveling window  230  includes a roller guide arch  232  attached thereto for accommodating an off-axis approach of cable  118  toward production string  116  disposed along longitudinal axis  114 . In one or more embodiments, cable  118  may be stored at ground level surface  104  on a reel (not shown). In one or more embodiments, cable  118  may run over the top of roller guide arch  232  directly or may be fed thereto by a large diameter guide wheel (not shown). In one or more embodiments, roller guide arch  232  moves with traveling assembly  220 . In one or more other embodiments, roller guide arch  232  may be stationary and suspended from a crane or supported by workover system  110 . During operation, cable  118  is brought adjacent and clamped to production string  116  using clamps  128  within traveling window  230 . 
     In one or more embodiments, first work platform  130  moves vertically up and down with traveling window  230  providing personnel working on first work platform  130  access to production string  116  throughout an entire stroke length L 1  of traveling window  230 , allowing clamps  128  to be attached at any location along production string  116 . In other embodiments, first work platform  130  is kept stationary providing personnel working on first work platform  130  with limited access to traveling window  230  such that each clamp  128  can only be installed when traveling window  230  has approached a bottom of a stroke. In one or more embodiments, safety may be improved by keeping first work platform  130  stationary such that personnel are not moving with traveling assembly  220 . 
     Traveling assembly  220  may further include a first set of traveling slips  250  and a second set of traveling slips  260  disposed at an upper end of traveling window  230 . In one embodiment, first set of traveling slips are heavy slips and second set of traveling slips are snub slips. Traveling heavy slips  250  can grip and hold production string  116  stationary relative to traveling assembly  220  in a pipe heavy condition, wherein a balance of forces on production string  116  is downward. Traveling snub slips  260  can grip and hold production string  116  stationary relative to traveling assembly  220  in a pipe light condition, wherein a balance of forces on production string  116  is upward. In one or more embodiments, traveling slips  250 ,  260  may have a weight capacity that ranges from about 150,000 pounds to about 600,000 pounds. More particularly, the weight capacity may range from about 150,000 pounds to about 460,000 pounds. In one non-limiting example, traveling slips  250 ,  260  may have a weight capacity of 340,000 pounds. In one or more embodiments, traveling slips  250 ,  260  may be sized in accordance with the weight capacity of jack  170  as described earlier for stationary slips  150 ,  160 . In one or more embodiments, traveling slips  250 ,  260  may have inner diameter D 1  greater than outer diameter D 2  of production string  116 . In one or more embodiments, in operation, there is a risk that pipe buckling may occur in an unsupported area of production string  116  between traveling snub slips  260  and stationary snub slips  160  or between traveling heavy slips  250  and stationary heavy slips  150 . In one or more embodiments, a telescoping snubbing pipe guide may be positioned in the unsupported area to mitigate the risk of pipe buckling. 
     With continued reference to  FIG. 4 , traveling assembly  220  further includes traveling annular BOP  270 . Traveling annular BOP  270  is a static annular BOP. In one or more embodiments, traveling annular BOP  270  is attached to base plate  222 . Traveling annular BOP  270  may include one or more elastomeric, static sealing elements  272 . The one or more elastomeric static sealing elements  272  may be configured to seal around any type of pipe or tubing known in the art including pipe or tubing having a circular or non-circular outer surface or any other irregular shape. The one or more elastomeric static sealing elements  272  may be softer or more deformable than conventional elements, such as the dynamic sealing element  182  described above, to enable conforming and sealing around irregular shapes. The one or more elastomeric static sealing elements  272  may be positioned within a bowl section (not shown) of a housing  274 . Housing  274  may have upper and lower flanges for connecting traveling annular BOP  270  to adjoining flanges. Housing  274  may enclose an actuation element (not shown) that may be hydraulically or electrically powered. In one or more embodiments, the actuation element is a hydraulically powered annular piston that pushes the one or more elastomeric static sealing elements  272  against a cam surface (not shown) forcing the one or more elastomeric static sealing elements  272  inward and into sealing engagement with production string  116 . In one non-limiting example, traveling annular BOP  270  may be a Regan Torus or Regan Type K annular BOP for sealing an annulus around production string  116  including cable  118  attached to an outside thereof. In one or more embodiments, traveling annular BOP  270  may be limited to static sealing only. In one or more embodiments, traveling annular BOP  270  may have a pressure rating from about 1000 psi to about 2000 psi. In one or more embodiments, traveling annular BOP  270  may have inner diameter D 1  greater than outer diameter D 2  of production string  116 . In one non-limiting example, production string  116  may consist of 4½ inch tubing, and traveling annular BOP  270  may be a 7 1/16 inch annular. It will be appreciated that in various embodiments, an annular having a different size may be used. However, in this example, the 7 1/16 inch annular may represent the smallest standard size annular that could accommodate the 4½ inch tubing along with cable  118  and clamps  128  attached thereto. Of course, if production string  116  had a different size or cable  118  and clamps  128  had a lower or higher profile, then a smaller or larger standard size traveling annular BOP  270  could be used. As used herein, a static sealing element refers to a sealing element formed of elastomeric or similarly deformable, non-rigid material that can be deform or shaped to statically seal around irregularly shaped objects, such as completion string  116  with cable  118  attached thereto. Notably such sealing elements are not generally disposed to allow a tubular to slide relative to the sealing element and maintain a seal. The static seal is generally only maintained when the tubular is fixed relative to the static sealing element. Likewise, a static annular BOP refers to a BOP which seals most effectively around non-moving, static tubulars. 
     In one or more embodiments, traveling assembly  220  may include a purge gas flow cross assembly  216 . In one or more embodiments, purge gas flow cross assembly  216  may be disposed above dynamic BOP  180  and below traveling annular BOP  270  in fluid communication with annulus  290 . In one or more embodiments, purge gas flow cross assembly  216  may connect to traveling annular BOP  270  and move with traveling assembly  220 . Purge gas flow cross assembly  216  may include a first or inlet port  216   a  and a second or inlet/outlet port  216   b . To control fluid communication through first port  216   a  and second port  216   b , purge gas flow cross assembly  216  may further include first and second valves (not shown), which may be operated using a control system. 
     Traveling assembly  220  further includes a reciprocating riser  280  extending below and in fluid communication with traveling annular BOP  270 . In one or more embodiments, purge gas flow cross assembly  216  may be connected between reciprocating riser  280  and traveling annular BOP  270 . In any event, reciprocating riser  280  and traveling BOP  270  are fixed relative to one another and reciprocate in unison as described herein. Reciprocating riser  280  includes an inner surface  280   a  having inner diameter D 3  and an outer surface  280   b  having outer diameter D 4 . Production string  116  and cable  118  may be disposed within reciprocating riser  280 . Inner diameter D 3  of reciprocating riser  280  may be greater than outer diameter D 2  of production string  116 . Reciprocating riser  280  may be disposed inside dynamic BOP  180  forming a dynamic seal between the one or more elements  182  of dynamic BOP  180  and outer surface  280   b  of reciprocating riser  280 , thereby permitting a seal to be maintained as reciprocating riser  280  is moved axially through dynamic BOP  180 . It will be appreciated that in various embodiments, outer surface  280   b  may be machined smooth and/or polished to improve sealing. In one or more embodiments, outer surface  280   b  may be lubricated to reduce friction on the reciprocating seal. Dynamic BOP  180  may be sized to have inner diameter D 1  greater than outer diameter D 4  of reciprocating riser  280  to accommodate displacement of reciprocating riser  280  therein. Dynamic BOP  180  may have a larger clearance than a lower annular BOP  200  (to be described later) and traveling annular BOP  270  to accommodate reciprocating riser  280  having a larger outer diameter D 4  compared to outer diameter D 2  of production string  116 . In one or more embodiments, dynamic BOP  180  may have a pressure rating from about 1000 psi to about 2000 psi. In one or more embodiments, a variable hydraulic control or pressure regulator may be used to limit an actuation pressure of dynamic BOP  180  to maintain the one or more elements  182  in sealing contact with reciprocating riser  280  without over pressurizing the reciprocating seal. For example, if only 600 psi is needed to maintain the reciprocating seal, then applying greater than 600 psi, or more particularly, applying around about 1500 psi to about 2000 psi would wear out the one or more elements  182  at a much faster rate. In one non-limiting example, production string  116  may consist of 4½ inch tubing, and traveling annular BOP  270  may be a 7 1/16 inch annular. In that case, reciprocating riser  280  may have a 7 1/16 inch inner diameter D 3  and an outer diameter D 4  around about 8+ inches depending on pipe specifications. Then it will be appreciated that to accommodate reciprocating riser  280 , dynamic BOP  180  may be a next standard size 11 inch annular, one size larger than lower annular BOP  200  and traveling annular BOP  270 . Of course, if traveling annular BOP  270  were smaller or larger, then a smaller (7 1/16 inch) or larger (13⅝ or 18 inch) standard size dynamic BOP  180  could be used. 
     Thus, the one or more elements  182  of dynamic BOP  180  may form a dynamic seal with outside surface  280   b  of reciprocating riser  280 . Reciprocating riser  280  and dynamic BOP  180  may move vertically or rotate relative to each other while outer surface  280   b  of reciprocating riser  280  remains in sealing engagement with the one or more elements  182 . In one or more embodiments, polishing and/or lubricating outer surface  280   b  of reciprocating riser  280  may improve sealing with and may increase the lifespan of the one or more elements  182 . The dynamic seal may provide well pressure integrity inside reciprocating riser  280  between dynamic BOP  180  and traveling annular BOP  270 . Traveling annular BOP  270  and reciprocating riser  280  may travel vertically up and down with traveling assembly  220  including piston rods  176   a ,  176   b , base plate  222 , traveling window  230 , traveling heavy slips  250 , and traveling snub slips  260 . In this way, traveling annular BOP  270 , reciprocating riser  280 , and dynamic BOP  180  form a sealed telescoping assembly effectively functioning as a wellhead moving with traveling assembly  220 . In one or more embodiments, traveling assembly  220  may reciprocate below a level of second work platform  132 , wherein traveling heavy slips  250  and traveling snub slips  260  are disposed below stationary heavy slips  150  and stationary snub slips  160 . This arrangement may represent an opposite orientation compared to a traditional hydraulic workover or snubbing unit. 
       FIG. 5  is a close-up front elevation view of a lower portion of the hydraulic workover unit of  FIG. 1 , and in particular, illustrates lower portion  110   c  of workover system  110  in more detail. Below base plate  124 , stationary assembly  120  may further include an API spool extension  190  to accommodate internal displacement of reciprocating riser  280  of traveling assembly  220 , to be described later. In one or more embodiments, API spool extension  190  may have inner diameter D 1  greater than outer diameter D 2  of production string  116 . An upper flow cross assembly  192  may be located below API spool extension  190 . In one or more embodiments, upper flow cross assembly  192  may have inner diameter D 1  greater than outer diameter D 2  of production string  116 . Upper flow cross assembly  192  includes an equalization port  192   a  and a bleed off port  192   b . To control fluid communication through equalization port  192   a  and bleed off port  192   b , upper flow cross assembly  192  may further include an equalization valve  194   a  and a bleed off valve  194   b , respectively. Upper flow cross assembly  192  enables equalization to or bleed off of wellbore pressure in an annulus  290  above a lower annular BOP  200 . Equalization valve  194   a  and bleed off valve  194   b  may be operated using a control system to facilitate movement of production string  116  into and out of wellbore  102  under pressure. 
     Lower annular BOP  200  may be positioned below upper flow cross assembly  192 . Lower annular BOP  200  is a static BOP and may include one or more elastomeric static sealing elements  202 . The one or more elastomeric static sealing elements  202  may be configured to seal around any type of pipe or tubing known in the art including pipe or tubing having a circular or non-circular outer surface or any other irregular shape. The one or more embodiments, elastomeric static sealing elements  202  may be softer than conventional elements to enable conforming and sealing around irregular shapes. The one or more elastomeric elements  202  may be positioned within a bowl section (not shown) of a housing  204 . Housing  204  may have upper and lower flanges for connecting lower annular BOP  200  to adjoining flanges. Housing  204  may enclose an actuation element (not shown) that may be hydraulically or electrically powered. In one or more embodiments, the actuation element is a single acting, hydraulically powered, annular piston that receives a hydraulic pressure through an inlet port, moves upward, and compresses the one or more elastomeric elements  202  against a cam surface (not shown) forcing the one or more elastomeric elements  202  inward and into sealing engagement with production string  116 . The actuation element may be reversed and the one or more elastomeric elements  202  opened by venting the hydraulic pressure. A cycle open time may vary due to ambient temperature. In one or more embodiments, a dual acting design, providing power open and power close, may be used to positively retract the annular piston. In one non-limiting example, lower annular BOP  200  may be a Regan Torus or Regan Type K annular BOP for sealing an annulus around production string  116 . In one or more embodiments, lower annular BOP  200  may be limited to static sealing only. In one or more embodiments, lower annular BOP  200  may have a pressure rating from about 1000 psi to about 2000 psi. In one non-limiting example, production string  116  may consist of 4½ inch tubing, and lower annular BOP  200  may be a 7 1/16 inch annular. It will be appreciated that in various embodiments, an annular having a different size may be used. However, in this example, the 7 1/16 inch annular represents the smallest standard size annular that could accommodate the 4½ inch tubing. Of course, if production string  116  had a different size, then a smaller or larger standard size lower annular BOP  200  could be used. In one or more embodiments, lower annular BOP  200  may have inner diameter D 1  greater than outer diameter D 2  of production string  116 . 
     In one or more embodiments, during operation, an equalization step may be required because lower annular BOP  200  may not open with a pressure differential across lower annular BOP  200  caused by higher wellbore pressure below lower annular BOP  200  than in annulus  290  above lower annular BOP  200 . In one or more embodiments, an equalization gas or liquid having a pressure high enough to counteract wellbore pressure below lower annular BOP  200  may be fed to equalization port  192   a . In one or more embodiments, injecting gas for this purpose may be preferred since introducing non-gaseous fluids into wellbore  102  may be undesirable. In one or more embodiments, the equalization gas may include, without limitation well fluid or nitrogen (N2). In the case of well fluid, a lower flow cross assembly  210  may be installed below lower annular BOP  200 . Lower flow cross assembly  210  may include a first or inlet port  210   a  and a second or outlet port  210   b . To control fluid communication through first port  210   a  and second port  210   b , lower flow cross assembly  210  further includes a first or inlet valve  212   a  and a second or outlet valve  212   b , respectively. First valve  212   a  and second valve  212   b  may be remotely operated using a control system to facilitate the equalization step. In one or more embodiments, second valve  212   b  may be opened to route well fluid to equalization port  192   a  via a flow loop  214 . In one or more embodiments, N2 may be injected into annulus  290  via equalization port  192   a  using external piping, separate from lower flow cross assembly  210  or flow loop  214 , connected directly to equalization port  192   a  or first valve  194   a . In one or more embodiments, N2 may be injected using an additional T-junction on flow loop  214 . 
     In one or more embodiments, first flange  111  of workover system  110  disposed below lower flow cross assembly  210  may be connected to one or more annular and ram-type BOPs, choke/kill lines, choke/kill flow crosses, and other valve and fittings (not shown) located adjacent to or generally disposed above wellhead  106  to provide secondary and tertiary safety and shear functions and annulus access for kill fluid circulation if so required based on contingency planning. 
     In one or more embodiments, during operation, gas, such as natural gas or sweet gas, may be disposed in annulus  290  above lower annular BOP  200 . In this case, the gas may be vented to the atmosphere. In one or more embodiments, the gas may include hydrogen sulfide (H 2 S), which can be purged with N2 by equalizing and bleeding off with N2, thus limiting the presence of H 2 S above lower annular BOP  200 . Additional valving and piping may connect bleed off port  192   b  to a flare pit for gas or a liquid pit in the case of liquid and gas (not shown). In operation, according to one or more embodiments, a purge gas, such as N2, may be flowed into purge gas flow cross assembly  216  through either first port  216   a  or second port  216   b , down through the annulus  290 , and out through bleed off port  192   b  in order to expel H 2 S from within annulus  290 . 
     In one or more embodiments, annulus  290  may be defined at a top end by the one or more elastomeric elements  272  of traveling annular BOP  270 ; at a bottom end by the one or more elastomeric elements  202  of lower annular BOP  200 ; on an outside surface by housing  274  of traveling annular BOP  270 , purge gas flow cross assembly  216 , reciprocating riser  280 , the one or more elements  182  and housing  184  of dynamic BOP  180 , extension spool  190 , upper flow cross assembly  192 , and housing  204  of lower annular BOP  200 ; and on an inside surface by production string  116 . 
       FIG. 6  is a flowchart outlining a first method of using a hydraulic workover unit. Specifically, shown is a method  300  of using workover system  110  illustrated with reference to  FIGS. 1-5 . More particularly, method  300  describes tripping out production string  116  under pressure in a pipe light condition starting from an initial position, such as illustrated in  FIG. 1 , of workover system  110 . In this initial position for tripping out, workover system  110  is shown extended, such as at the top or end of an upstroke of production string  116 , where movement of traveling assembly  220  has only just stopped. In the initial position or “extended” position, hydraulic cylinders  172   a ,  172   b  are extended bringing traveling assembly  220  to the top of upward stroke, where traveling annular BOP  270  is still in a sealingly closed configuration around the production string, while fixed annular BOP  200  remains in an open configuration about the production string to allow the production string to move upward therethrough. Traveling snub slips  260  may be in a closed configuration to grip production string  116 . Finally, equalization valve  194   a  and bleed off valve  194   b  may be closed. 
     Continuing from the initial position, at step  302 , with traveling annular BOP  270  remaining in a closed configuration, lower annular BOP  200  is now activated to a closed configuration to sealingly engage production string  116  so as to contain wellbore pressure within wellbore  102  below lower annular BOP  200 . Stationary snub slips  160  may be set in order to support production string  116  during this stage of the operation. In one or more embodiments, stationary snub slips  160  may be set before activating lower annular BOP  200  so as to prevent relative movement between production string  116  and lower annular BOP  200 . At optional step  304 , because gas may be trapped in annulus  290  between lower annular BOP  200  and traveling annular BOP  270 , bleed off valve  194   b  may be opened to lower the pressure within annulus  290 . 
     In any event, since lower BOP  200  is now in a closed configuration, in step  306 , traveling annular BOP  270  may be activated to an opened configuration before progressing farther. In this open configuration, traveling BOP  270  is sealingly disengaged from the production string to allow the traveling BOP  270  to be moved downward relative to the production string, which is temporarily suspended by stationary snub slips  160 . Thus, at this point, production string  116  is suspended by stationary snub slips  160  while traveling snub slips  260  and traveling annular BOP  270  are both in an open configuration. In one or more embodiments, traveling snub slips  260  may be opened after activating traveling annular BOP  270  so as to prevent relative movement between production string  116  and traveling annular BOP  270 . 
     At step  308 , jack  170  is actuated to urge it from the initial extended position to a retracted position, bringing traveling assembly  220  to the bottom of a downward stroke. In one or more embodiments, the bottom of a downward stroke may be about one foot above a retraction stop. At this stage, workover system  110  is in a retracted position, traveling assembly  220  having moved axially downward by stroke length L 1 . As jack  170  is moved to its retracted position, reciprocating riser  280  slides downward through dynamic BOP  180 . In this regard, in some embodiments, when jack  170  is in the extended position, a bottom end  280   c  of reciprocating riser  280  may be disposed in housing  184  of dynamic BOP  180 . After jack  170  has moved to the retracted position, reciprocating riser  280  may extend further downward through spool extension  190  and into flow cross assembly  192 . In the retracted position, bottom end  280   c  of reciprocating riser  280  may be disposed in flow cross assembly  192 . It should be noted that in one or more embodiments, throughout any stroke of jack  170 , reciprocating riser  280  remains in dynamic sealing engagement with dynamic BOP  180  to ensure annulus  290  is always contained. Spool extension  190  and flow cross assembly  192  may be sized wherein inner diameter D 1  of each is greater than outer diameter D 4  of reciprocating riser  280  to accommodate displacement of reciprocating riser  280  therein. 
     At step  310 , with jack  170  at the bottom of its stroke, traveling annular BOP  270  may now be actuated to a closed configuration to sealingly engage the production string. In one or more embodiments, traveling snub slips  260  may also be actuated to a closed configuration around the production string so as to engage the production string for supporting the weight of the production string. In one or more embodiments, traveling snub slips  260  may be set before activating traveling annular BOP  270  so as to prevent relative movement between production string  116  and traveling annular BOP  270 . 
     At optional step  312 , with both traveling annular BOP  270  and lower annular BOP  200  in closed configurations and sealingly engaging the production string, equalization valve  194   a  is opened to raise a pressure in annulus  290  to about wellbore pressure below lower annular BOP  200 . In one or more embodiments, step  312  may further include opening second valve  212   b  of lower flow cross assembly  210  and routing fluid from wellbore  102  to equalization valve  194   a  via flow loop  214 . In one or more other embodiments, step  312  may further include injecting N2 into annulus  290  via equalization port  192   a , as described above. 
     At step  314 , with wellbore pressure contained below traveling BOP  270  by virtue of BOP  270  being in a closed configuration around the production string, lower annular BOP  200  is actuated to an opened configuration so as to sealingly disengage lower BOP  200  from the production string, leaving only traveling BOP  270  sealingly engaged with the production string. In one or more embodiments, stationary snub slips  160  may also be released so that only traveling snub slips  260  are supporting the production string. In one or more embodiments, jack  170  may be retracted several inches to allow stationary snub slips  160  to open. In one or more embodiments, stationary snub slips  160  may be opened after activating lower annular BOP  200  so as to prevent relative movement between production string  116  and lower annular BOP  200 . 
     At step  316 , jack  170  is activated to extended jack  170  through an upward stroke, moving traveling assembly  220  upward and completing an upward stroke of production string  116 , thereby lifting production string  116  out of wellbore  102 . In one or more embodiments, the upward stroke may be about one foot below an extension stop. At this stage, workover system  110  has returned to the original beginning or “extended” position having traveled upward by stroke length L 1 . To continue tripping out, method  300  is repeated by returning to step  302  and progressing again through the steps described above. 
     Turning to  FIG. 7 , a method  400  of using workover system  110  is illustrated with reference to  FIGS. 1-5 . More particularly, method  400  describes tripping in a production string under pressure in a pipe light condition. The following lists the changes needed to adapt method  300  to method  400 . At step  308 , jack  170  is moved to the extended position bringing traveling assembly  220  to a desired upward stroke position, and at step  316 , jack  170  is retracted in a downward stroke, moving traveling assembly  220  downward and completing a downward stroke of production string  116 . Otherwise, the steps of method  300  are taken in the same sequence as before, and to continue tripping in the method is repeated by returning to step  302  as before. 
       FIG. 7  is a flowchart outlining a second method of using a hydraulic workover unit. Specifically, shown is method  400  of tripping in a production string under pressure in a pipe light condition starting from the retracted position of workover system  110 , wherein a downstroke of production string  116  has just been completed and movement of traveling assembly  220  has only just stopped. Thus, in an initial position for tripping in, hydraulic cylinders  172   a ,  172   b  are in a “retracted” position such that traveling assembly  220  is at the bottom of a downward stroke. At this point, traveling annular BOP  270  is in a closed configuration, sealingly engaging the production string while lower annular BOP  200  is in an open configuration so as to be sealingly disengaged from the production string. Moreover, at this initial position, traveling snub slips  260  are in a closed configuration, thereby gripping and supporting production string  116 . In one or more embodiments, equalization valve  194   a  and bleed off valve  194   b  may be closed. 
     Continuing from the initial trip in position described above, at step  402 , lower annular BOP  200  is actuated from an open to a closed position, thereby sealingly engaging production string  116 . In one or more embodiments, stationary snub slips  160  may likewise be actuated to a closed position so as to grip production string  116 . In one or more embodiments, stationary snub slips  160  may be set before activating lower annular BOP  200  so as to prevent relative movement between production string  116  and lower annular BOP  200 . 
     At optional step  404 , with both traveling annular BOP  270  and lower annular BOP  200  in a closed configuration, bleed off valve  194   b  may be opened to lower the pressure in annulus  290  adjacent dynamic BOP  180  to the pressure that is annulus  290  above traveling annular BOP  270 . 
     At step  406 , with the wellbore pressure contained below lower annular BOP  200 , traveling annular BOP  270  actuated to an open configuration so as to disengage the production string  116 , leaving only lower annular BOP  200  sealingly engaged with the production sting  116 . In one or more embodiments, stationary snub slips  160  are also actuated to a closed configuration so as to grip production string  116 . In one or more embodiments, traveling snub slips  260  may be released from gripping engagement with production string  116 . In one or more embodiments, jack  170  may be extended several inches to allow traveling snub slips  260  to be actuated to an open configuration. In one or more embodiments, traveling snub slips  260  may be opened after activating traveling annular BOP  270  so as to prevent relative movement between production string  116  and traveling annular BOP  270 . 
     At step  408 , jack  170  is activated to extended jack  170  through an upward stroke, moving traveling assembly  220  upward and completing an upward stroke. The upward stroke may top out about one foot below the extension stop. At this stage, workover system  110  is in the extended position having traveled upward by stroke length L 1 . It will be appreciated that at this point, stationary snub slips  160  are supporting production string  116  while lower annular BOP  200  is sealingly engaging production string  116 . Moreover, because traveling annular BOP  270  is disengaged from production string  116  (as are traveling snub slips  260 ), then traveling assembly  220  can be moved upward relative to production string  116  through the upward stroke of jack  170 . As such, traveling annular BOP  270  moves axially relative to production string  116 . 
     At step  410 , with traveling assembly  220  extended to the top of the upward stroke of jack  170 , traveling BOP  270  is actuated to a closed configuration so as to sealingly engage production string  116 . In one or more embodiments, traveling snub slips  260  may likewise be actuated to a closed configuration in order to grip production string  116 . In one or more embodiments, traveling snub slips  260  may be set before activating traveling annular BOP  270  so as to prevent relative movement between production string  116  and traveling annular BOP  270 . 
     It will be appreciated at this point that both traveling BOP  270  and lower BOP  200  are sealingly engaged with production string  116 . Thus, at optional step  412 , equalization valve  194   a  may be opened to raise the pressure in the annulus  290  adjacent dynamic BOP  170  to a pressure that is approximately the same as the wellbore pressure below lower annular BOP  200 . 
     At step  414 , with wellbore pressure contained below traveling annular BOP  270 , lower annular BOP  200  may be actuated to an open configuration, thereby sealingly disengaging lower annular BOP  200  from the production string  116 . In one or more embodiments, stationary snub slips  160  may also be actuated to an open configuration, thereby releasing them from gripping engagement with production string  116  leaving only traveling snub slips  260  to support the weight of production string  116 . In one or more embodiments, stationary snub slips  160  may be opened after activating lower annular BOP  200  so as to prevent relative movement between production string  116  and lower annular BOP  200 . 
     At step  416 , with traveling BOP  270  sealingly engaging production string  116  and traveling snub slips  260  supporting production string  116 , traveling assembly  220  may be lowered towards wellhead  106  by actuating jack  170  through a downward stroke, moving traveling assembly  220  downward and thus lowering production string  116  into wellbore  102 . The downward stroke may be about one foot above the extension stop. At this stage, workover system  110  has returned to the retracted position having traveled downward by stroke length L 1 . To continue tripping in, method  400  is repeated by returning to step  402 . 
     In one or more embodiments, method  400  may be used for snubbing production string  116  having a packer (not shown) and tailpipe (not shown) disposed thereon rather than having cable  118  attached thereto. The tailpipe may be disposed below the packer. In one non-limiting example, the packer may be a retrievable hydraulic-set packer having a bidirectional slip system and a packing element, and the tailpipe may include a temporary plugging device. Once the packer is positioned in wellbore  102 , a pressure differential is created by pressuring up against a temporary plugging device (not shown) until a shear release pressure is reached generating enough force to set the slips and expand the packing element to seal off an annulus in wellbore  102 . Using method  400  in conjunction with workover system  110  may eliminate compression loading on the packer during snubbing into wellbore  102 . In this case, production string  116  may have a substantially circular outer surface  116   a  instead of the non-circular or other irregularly shaped outer surface  116   a  of production string  116  having cable  118  attached thereto. Therefore, the one or more elastomeric elements  202 ,  272  configured for sealing the non-circular or other irregularly shaped outer surface  116   a  may be unnecessary and surface pressures may exceed 2000 psi. 
     To adapt methods  300 ,  400  to a pipe heavy condition, stationary heavy slips  150  and traveling heavy slips  250  are substituted for stationary snub slips  160  and traveling snub slips  260  in each instance. A change in slip utilization is needed because conventional slips only grip production string  116  in a single direction, i.e., heavy slips resist downward force and snub slips resist upward force, as described earlier. In one or more embodiments, rather than using conventional slips, a slip bowl load transfer system may be used to engage both heavy and snub slips on production string  116  simultaneously. Using workover system  110 , snub loads based on a total cross-sectional area of reciprocating riser  280  may exceed snub loads experienced by a conventional workover unit based on a net cross-sectional area of production string  116  and cable  118 . Higher snub loads may greatly increase potential loading on reciprocating jack  170  relative to conventional snubbing operations. Given a relatively large total cross-sectional area of reciprocating riser  280 , a weight of production string  116  may cycle between heavy and light load directions. A pipe heavy load may reverse to pipe light when reciprocating riser  280  is equalized (pressured up) at steps  312 ,  412 . Conversely, a pipe light load may reverse to pipe heavy when reciprocating riser  280  is bled off (depressurized) at steps  304 ,  404 . Various load transfer technology may resist loading from production string  116  automatically in both directions, eliminating risk of operator error and enhancing safety. 
     In operation of workover system  110 , it may be important that production string  116  does not move relative to lower annular BOP  200  or traveling annular BOP  270  when either annular is closed. Relative movement may occur if jack  170  begins to move production string  116  before the respective BOP is opened. Sliding production string  116  including cable  118  and clamps  128  through one or more engaged elastomeric elements  202 ,  272  of lower annular BOP  200  and traveling annular BOP  270 , respectively, may damage cable  118  and clamps  128 . To prevent inadvertent movement of jack  170  and production string  116  an interlock system may be used to assure correct logic between open/close of slips  150 ,  160 ,  250 ,  260 , open/close of lower annular BOP  200  and traveling annular BOP  270 , and control of jack  170 . 
     In one non-limiting example, referring to steps  306  and  308  of method  300 , the interlock system may prevent jack  170  from being retracted at step  308  until receiving a signal that traveling annular BOP  270  has opened at step  306 . In the same way, the interlock system may prevent jack  170  from being extended at step  316  until receiving a signal that lower annular BOP  200  has opened at step  314 . It will be appreciated that the interlock system may be any hydraulic, pneumatic, or electrical interlock system known in the art. 
     In one or more embodiments, method  300  may be modified by separating each of steps  310 ,  314  into two separate steps, wherein each separate step is independently linked to the interlock system. Likewise, method  400  may be modified by separating each of steps  410 ,  414  into two separate steps, wherein each separate step is independently linked to the interlock system. 
     In one or more embodiments, the interlock system may also function as a grip interlock to prevent inadvertent release of production string  116 . In one non-limiting example, referring to steps  302  and  306  of method  300 , the grip interlock may prevent traveling snub slips  260  from being opened at step  306  until receiving a signal that stationary snub slips  160  have closed at step  302  and are supporting production string  116 . In the same way, the grip interlock may prevent stationary snub slips  160  from being opened at step  314  until receiving a signal that traveling snub slips  260  have closed at step  310  and are supporting production string  116 . A signal indicating closed slips may be a hydraulic, pneumatic, or electrical signal. In one or more embodiments, slips  150 ,  160 ,  250 ,  260  may be hydraulically actuated using one or more hydraulic cylinders. An increase in hydraulic pressure or fluid flow in a grip direction of the one or more hydraulic cylinders may indicate gripping. Likewise, an increase in hydraulic pressure or fluid flow in a release direction of the one or more hydraulic cylinders may indicate non-gripping. In one or more embodiments, the position of the slips may be monitored using one or more proximity or position sensors to detect actuation to a gripping or non-gripping position. 
     In one or more embodiments, a direct indication of slips  150 ,  160 ,  250 ,  260  supporting production string  116  may be provided by a load cell positioned on slips  150 ,  160 ,  250 ,  260 . An increase in load above a threshold value may indicate supporting production string  116  and a decrease in load below the threshold value may indicate non-support of production string  116 . 
     Various advantages of keeping the well alive throughout the ESP completion operation include maintaining the current production rate of the well; preventing skin damage to the producing formation; reducing the cost of ESP workover by eliminating a need to transport, store, and pump kill fluids into the wellbore for well control; and reducing a chance of formation damage. Particularly, embodiments of the hydraulic workover unit include a stationary assembly including a dynamic annular and a traveling assembly including a reciprocating riser, wherein the reciprocating riser moves in sealing engagement with the dynamic annular for sealing a pressure in the wellbore as the traveling assembly moves the production string. In one or more embodiments, the hydraulic workover unit enables dynamic movement and pressure control during snubbing at well surface pressures up to about 2,000 psi; provides dynamic sealing during insertion and/or removal of the production string from the wellbore; provides load control in both pipe heavy and pipe light conditions; and enables safe operation while performing a live well workover. 
     Thus, a workover unit for moving a production string through a wellbore has been described. In one or more embodiments, the workover unit may include a stationary assembly having a dynamic BOP; and a traveling assembly movable relative to the stationary assembly between a first extended position and a second retracted position, the traveling assembly having a reciprocating riser with a riser diameter, wherein the reciprocating riser extends through the dynamic BOP so as to be sealingly engaged therewith in each of the fully extended and fully retracted positions of the traveling assembly. In other embodiments, the workover unit may include a dynamic BOP supported on a workover frame having an upper end and a lower end; a first static annular BOP axially aligned with the dynamic BOP and positioned between dynamic BOP and the upper end of the workover frame; and a second static annular BOP axially aligned with the dynamic BOP and positioned below the dynamic BOP. 
     For any of the foregoing embodiments, the workover unit may include any one of the following elements, alone or in combination with each other:
         Dynamic BOP is an annular BOP.   Dynamic BOP is a ram BOP.   The dynamic BOP comprises a solid elastomeric element.   The static annular BOP comprises an inflatable seal element.   The static annular BOP comprises an expandable seal element.   The stationary assembly further comprises a lower annular BOP.   The traveling assembly further comprises a traveling annular BOP from which the reciprocating riser extends.   The traveling assembly further comprises one or more traveling slips.   An actuation mechanism for reciprocating traveling assembly relative to stationary assembly.   The stationary assembly further comprises one or more stationary slips.   The traveling assembly further comprises a traveling annular BOP from which the reciprocating riser extends and wherein the stationary assembly further comprises a lower annular BOP, the traveling annular BOP and lower annular BOP being static BOPs.   A tubular extending between the dynamic BOP and the lower annular BOP, wherein the tubular has a tubular diameter that is larger than the riser diameter of the reciprocating riser.   The traveling annular BOP is a static annular BOP and includes one or more expandable elastomeric seal elements.   A workover unit for moving a production string through a wellbore comprising:   The lower end of the workover frame comprises a stationary assembly to which the dynamic BOP is attached and the upper end of the workover frame comprises a traveling assembly to which the first static annular BOP is attached, wherein the traveling assembly is axially movable relative to the stationary assembly.   The traveling assembly further comprises traveling slips supported on the workover frame between the first static annular BOP and the upper end of the workover frame.   The stationary assembly further comprises a lower annular configured to seal around the production string when the traveling assembly is moved relative to the production string.   The traveling assembly further comprises traveling slips configured to grip the production string during the lowering.   A cross-over assembly adjacent the lower static annular BOP.   Relatedly, a method of snubbing a production string using a workover unit has been described. Embodiments of the snubbing method may include forming a first seal between the production string and a traveling assembly; forming a second seal between a reciprocating riser of the traveling assembly and a dynamic annular of a stationary assembly; and lowering the traveling assembly relative to the stationary assembly to snub the production string into the wellbore, wherein the first and second seals are formed prior to lowering the traveling assembly. In other embodiments, the snubbing method includes positioning a production string in a riser; activating a first static annular BOP adjacent the production string; activating a second static annular BOP adjacent the production string; and moving the pipe string and riser in conjunction with one another by passing the riser through a dynamic BOP.       

     For the foregoing embodiments, the method may include any one of the following steps, alone or in combination with each other:
         Forming the first seal comprises closing a traveling annular on the production string.   Forming the second seal comprises closing the dynamic annular on the reciprocating riser.   Lowering the traveling assembly relative to the stationary assembly comprises retracting a reciprocating jack.   Closing traveling snub slips on the production string to grip the production string prior to lowering the traveling assembly relative to the stationary assembly.   Opening stationary snub slips after the traveling snub slips are closed.   Opening a lower annular after the traveling annular is closed.   Opening an equalization port prior to opening the lower annular.   Supporting the production string at a location above the first static annular BOP; activating a first static annular BOP adjacent the production string comprises engaging the production string with the first static annular BOP; activating a second static annular BOP adjacent the production string comprises disengaging the second static annular BOP from the production string; and further comprising lowering the production string into a wellbore.   Supporting the production string at a location above the first static annular BOP; activating a second static annular BOP adjacent the production string comprises engaging the production string with the second static annular BOP; activating a first static annular BOP adjacent the production string comprises disengaging the first static annular BOP from the production string; and further comprising raising the production string from a wellbore.   Raising the production string from a wellbore comprises extending a reciprocating jack and moving the riser upward through the dynamic annular riser.   Lowering the production string into a wellbore comprises retracing a reciprocating jack and moving the riser downward through the dynamic annular riser   Engaging the production string with the first static annular BOP comprises inflating a first static sealing element; and wherein disengaging the second static annular BOP from the production string comprises deflating a second static sealing element.   Disengaging the first static annular BOP from the production string comprises deflating a first static sealing element; and wherein engaging the second static annular BOP with the production string comprises deflating a second static sealing element.   Opening an equalization port prior to disengaging the second static annular BOP.   Engaging the production string with the static annular BOP comprises inflating a static sealing element.   Disengaging the production string with the static annular BOP comprises deflating a static sealing element.   Supporting the production string at a location above the first static annular BOP   Activating a first static annular BOP adjacent the production string comprises engaging the production string with the first static annular BOP.   Activating a first static annular BOP adjacent the production string comprises disengaging the first static annular BOP from the production string.   Activating a second static annular BOP adjacent the production string comprises engaging the production string with the second static annular BOP.   Activating a second static annular BOP adjacent the production string comprises disengaging the second static annular BOP from the production string.       

     While various embodiments have been illustrated in detail, the disclosure is not limited to the embodiments shown. Modifications and adaptations of the above embodiments may occur to those skilled in the art. Such modifications and adaptations are in the spirit and scope of the disclosure.