Patent Abstract:
A method and apparatus for inspecting and tallying pipe in a well completion system. In one embodiment, at least one sensor determines the length of a pipe and/or at least one thread protector sensor determines whether the thread protectors are removed from both ends of the pipe. The sensors may be located in a mast assembly, a pipe arm, a walkway adjacent said pipe arm used to urge pipe towards the pipe arm, or various other places as desired. A moveable control van with a control system receives signals from the sensors. The control van comprises a system which also keeps a tally of the total amount of pipe currently in the wellbore. In one embodiment, memory chips may be used on the pipe to store a history of the pipe. The sensors then communicate this information back to the control system.

Full Description:
TECHNICAL FIELD 
     One possible embodiment of the present disclosure relates, generally, to the field of producing hydrocarbons from subsurface formations. Further, one possible embodiment of the present disclosure relates, generally, to the field of making a well ready for production or injection. More particularly, one possible embodiment of the present disclosure relates to completion systems and methods adapted for use in wells having long lateral boreholes. 
     BACKGROUND 
     In petroleum production, completion is the process of making a well ready for production or injection. This principally involves preparing the bottom of the hole to the required specifications, running the production tubing and associated down hole tools, as well as perforating and/or stimulating the well as required. Sometimes, the process of running and cementing the casing is also included. 
     Lower completion refers to the portion of the well across the production or injection zone, beneath the production tubing. A well designer has many tools and options available to design the lower completion according to the conditions of the reservoir. Typically, the lower completion is set across the production zone using a liner hanger system, which anchors the lower completion equipment to the production casing string. 
     Upper completion refers to all components positioned above the bottom of the production tubing. Proper design of this “completion string” is essential to ensure the well can flow properly given the reservoir conditions and to permit any operations deemed necessary for enhancing production and safety. 
     In cased hole completions, which are performed in the majority of wells, once the completion string is in place, the final stage includes making a flow path or connection between the wellbore and the formation. The flow path or connection is created by running perforation guns into the casing or liner and actuating the perforation guns to create holes through the casing or liner to access the formation. Modern perforations can be made using shaped explosive charges. 
     Sometimes, further stimulation is necessary to achieve viable productivity after a well is fully completed. There are a number of stimulation techniques which can be employed at such a time. 
     Fracturing is a common stimulation technique that includes creating and extending fractures from the perforation tunnels deeper into the formation, thereby increasing the surface area available for formation fluids to flow into the well and avoiding damage near the wellbore. This may be done by injecting fluids at high pressure (hydraulic fracturing), injecting fluids laced with round granular material (proppant fracturing), or using explosives to generate a high pressure and high speed gas flow (TNT or PETN, and propellant stimulation). 
     Hydraulic fracturing, often called fracking, fracing or hydrofracking, is the process of initiating and subsequently propagating a fracture in a rock layer, by means of a pressurized fluid, in order to release petroleum, natural gas, coal steam gas or other substances for extraction. The fracturing, known colloquially as a frack job or frac job, is performed from a wellbore drilled into reservoir rock formations. The energy from the injection of a highly pressurized fluid, such as water, creates new channels in the rock that can increase the extraction rates and recovery of fossil fuels. 
     The technique of fracturing is used to increase or restore the rate at which fluids, such as oil or water, or natural gas can be produced from subterranean natural reservoirs, including unconventional reservoirs such as shale rock or coal beds. Fracturing enables the production of natural gas and oil from rock formations deep below the earth&#39;s surface, generally 5,000-20,000 feet or 1,500-6,100 meters. At such depths, there may not be sufficient porosity and permeability to allow natural gas and oil to flow from the rock into the wellbore at economic rates. Thus, creating conductive fractures in the rock is essential to extract gas from shale reservoirs due to the extremely low natural permeability of shale. Fractures provide a conductive path connecting a larger area of the reservoir to the well, thereby increasing the area from which natural gas and liquids can be recovered from the targeted formation. 
     Pumping the fracturing fluid into the wellbore, at a rate sufficient to increase pressure downhole, until the pressure exceeds the fracture gradient of the rock and forms a fracture. As the rock cracks, the fracture fluid continues to flow farther into the rock, extending the crack farther. To prevent the fracture(s) from closing after the injection process has stopped, a solid proppant, such as a sieved round sand, can be added to the fluid. The propped fracture remains sufficiently permeable to allow the flow of formation fluids to the well. 
     The location of fracturing along the length of the borehole can be controlled by inserting composite plugs, also known as bridge plugs, above and below the region to be fractured. This allows a borehole to be progressively fractured along the length of the bore while preventing leakage of fluid through previously fractured regions. Fluid and proppant are introduced to the working region through piping in the upper plug. This method is commonly referred to as “plug and perf.” 
     Typically, hydraulic fracturing is performed in cased wellbores, and the zones to be fractured are accessed by perforating the casing at those locations. 
     While hydraulic fracturing can be performed in vertical wells, today it is more often performed in horizontal wells. Horizontal drilling involves wellbores where the terminal borehole is completed as a “lateral” that extends parallel with the rock layer containing the substance to be extracted. For example, laterals extend 1,500 to 5,000 feet in the Barnett Shale basin. In contrast, a vertical well only accesses the thickness of the rock layer, typically 50-300 feet. Horizontal drilling also reduces surface disruptions, as fewer wells are required. Drilling a wellbore produces rock chips and fine rock particles that may enter cracks and pore space at the wellbore wall, reducing the porosity and/or permeability at and near the wellbore. The production of rock chips, fine rock particles and the like reduces flow into the borehole from the surrounding rock formation, and partially seals off the borehole from the surrounding rock. Hydraulic fracturing can be used to restore porosity and/or permeability. 
     Conventional lateral wells are completed by inserting coiled tubing or a similar, generally flexible conduit therein, until the flexible nature of the tubing prevents further insertion. While coil tubing does not require making up and/or breaking out each pipe joint, coiled tubing cannot be rotated, which increases the likelihood of sticking and significantly reduces the ability to extend the pipe laterally. Once a certain depth is reached in a highly angled and/or horizontal well, the pipe essentially acts like soft spaghetti and can no longer be pushed into the hole. Coiled tubing is also more limited in terms of pipe wall thickness to provide flexibility thereby limiting the weight of the string. 
     Conventional completion rigs include a mast, which extends upward and slightly outward typically at approximately a 3 degree angle from a carrier or similar base structure. The angled mast provides that cables and/or other features that support a top drive and/or other equipment can hang downward from the mast, directly over a wellbore, without contacting the mast. For example, most top drives and/or power swivels require a “torque arm” to be attached thereto, the torque arm including a cable that is secured to the ground or another fixed structure to counteract excess torque and/or rotation applied to the top drive/power swivel. Additionally, a blowout preventer stack, having sufficient components and a height that complies with required regulations, must be positioned directly above the wellbore. A mast having a slight angle accommodates for these and other features common to completion rigs. As a result, a rig must often be positioned at least four feet, or more, away from the wellbore depending on the height of the mast. A need exists for systems and methods having a reduced footprint, especially in lucrative regions where closer spacing of wells can significantly affect production and economic gain, and in marginal regions, where closer spacing of wells would be necessary to enable economically viable production. 
     Prior to common use of coiled tubing, completion operations often involved the use of workover/production rigs for insertion of successive joints of pipe, which must be threaded together and torqued, often by hand, creating a significant potential for injury or death of laborers involved in the completion operation, and requiring significant time to engage (e.g., “make up”) each pipe joint Drilling rigs could also be utilized to run production tubing but are more expensive although the individual joints of pipes result in the same types of problems. 
     A significant problem with prior art production/workover rigs or drilling rigs as opposed to coiled tubing units is that individual production tubing pipe connections are often considerably more difficult to make up and/or break out than the drilling pipe connections. Drilling pipe connections are enlarged and are designed for quick make up and break out many times with very little concern about exact alignment of the connectors. Drill pipe is designed to be frequently and quickly made up and broken out without being damaged even if the alignment is not particularly precise. On the other hand, production tubing is normally intended for long term use in the well and requires much more accurate alignment of the connectors to avoid damaging the threads. Production tubing does not typically utilize the expensive enlarged connectors like drill pipe and, in some completions, enlarged connectors simply are not feasible due to clearance problems within the wellbore. Thus, especially for production tubing, prior art workover/production rigs are much slower for inserting and/or removing production tubing pipe into or out of the well than coiled tubing units and are more likely to result in operator injuries and errors during pipe connection make up and break out than coiled tubing. There are also problems with human error in aligning the individual production tubing connectors whereby cross-threading could result in a damaged or leaking connection. 
     Prior art insertion techniques of completion tubing into a lateral well therefore suffers from significant limitations including but not limited to: 1) the longer time required to run tubing into a well; 2) operator safety; and 3) the maximum horizontal distance across which the tubing can be inserted is limited by the nature of the tubing used and/or the force able to be applied from the surface. Generally, once the frictional forces between the lateral portion of the well and the length of tubing therein exceed the downward force applied by the weight of the tubing in the vertical portion of the well, further insertion becomes extremely difficult, if not impossible, thus limiting the maximum length of a lateral. 
     Due to the significant day rates and rental costs when performing oilfield operations, a need exists for systems and methods capable of faster, yet safer insertion of pipe and/or tubing into a well. Additionally, due to the costs associated with the drilling, completion, and production of a well, a need exists for systems and methods capable of extending the maximum length of a lateral, thereby increasing the productivity of the well. 
     Hydraulic fracturing is commonly applied to wells drilled in low permeability reservoir rock. An estimated 90 percent of the natural gas wells in the United States use hydraulic fracturing to produce gas at economic rates. 
     The fluid injected into the rock is typically a slurry of water, proppants, and chemical additives. Additionally, gels, foams, and/or compressed gases, including nitrogen, carbon dioxide and air can be injected. Various types of proppant include silica sand, resin-coated sand, and man-made ceramics. The type of proppant used may vary depending on the type of permeability or grain strength needed. Sand containing naturally radioactive minerals is sometimes used so that the fracture trace along the wellbore can be measured. Chemical additives can be applied to tailor the injected material to the specific geological situation, protect the well, and improve its operation, though the injected fluid is approximately 99 percent water and 1 percent proppant, this composition varying slightly based on the type of well. The composition of injected fluid can be changed during the operation of a well over time. Typically, acid is initially used to increase permeability, then proppants are used with a gradual increase in size and/or density, and finally, the well is flushed with water under pressure. At least a portion of the injected fluid can be recovered and stored in pits or containers; the fluid can be toxic due to the chemical additives and material washed out from the ground. The recovered fluid is sometimes processed so that at least a portion thereof can be reused in fracking operations, released into the environment after treatment, and/or left in the geologic formation. 
     Advances in completion technology have led to the emergence of open hole multi-stage fracturing systems. These systems effectively place fractures in specific places in the wellbore, thus increasing the cumulative production in a shorter time frame. 
     Those of skill in the art will appreciate the present system which addresses the above and other problems. 
    
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
       The accompanying drawings, which are incorporated in and constitute a part of this specification, illustrate an implementation of apparatus consistent with one possible embodiment of the present disclosure and, together with the detailed description, serve to explain advantages and principles consistent with the disclosure. In the drawings, 
         FIG. 1  illustrates an embodiment of a long lateral completion system usable within the scope of one possible embodiment of the present disclosure. 
         FIG. 2  is a perspective view of the mast assembly, pipe arm, pipe tubs, and the carrier of the long lateral completion system of  FIG. 1  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 3  is a plan view of the carrier, mast assembly, pipe arm, and pipe tub of the long lateral completion system of  FIG. 1  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 4  is an illustration of the carrier of the long lateral completion system of  FIG. 1  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 4A-A  is a cross sectional view of the carrier of  FIG. 4  taken along the section line A-A in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 4B-B  is a cross sectional view of the carrier of  FIG. 4  taken along the section line B-B in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 5  is an elevation view of the carrier, the mast assembly, the pipe arm and the pipe tubs of the long lateral completion system of  FIG. 1  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 5A  is an enlarged or detailed view of the section identified in  FIG. 5  as “A” of the rear portion of the carrier engaged with a skid of the depicted long lateral completion system in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 6  illustrates an elevation view of the completion system of  FIG. 1  with the mast assembly extended in a perpendicular relationship with the carrier and the pipe tubs in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 6A  is an enlarged or detailed view of the portion of  FIG. 6  indicated as section “A” illustrating the relationship of the mast assembly, the deck and the base beam in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 7  is an elevation view of the carrier, the mast assembly, the pipe arm, and the pipe tub of  FIG. 1 , with the mast assembly shown in a perpendicular relationship with the carrier, and the pipe arm engaged with the mast in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 7A-A  is a cross sectional view of  FIG. 7  taken along the section line A-A showing the mast assembly and top drive of the depicted long lateral completion system in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 7B  is a perspective view of the portion of the mast assembly and pipe arm illustrated in  FIG. 7A-A  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 8  is an elevation view of the completion system of  FIG. 1  illustrating the mast assembly in a perpendicular relationship with the carrier, including the use of a hydraulic pipe tong in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 8A-A  is a cross sectional view of the system of  FIG. 8  taken along the section line A-A, showing the pipe tong with respect to the mast assembly in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 8B-B  is a cross sectional view of the system of  FIG. 8  taken along the section line B-B, showing the mast assembly and top drive in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 8C  is a perspective view of the portion of the system shown in  FIG. 8B  in accord with one possible embodiment of the completion system of the present disclosure.  FIG. 9  is an illustration of the long lateral completion system of  FIG. 1 , depicting the relationship between the carrier, the mast assembly, the pipe arm, the pipe tubs and a blowout preventer in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 9A-A  is a cross sectional view of the system of  FIG. 9  taken along the section line A-A, illustrating the upper portion of the mast assembly in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 9B-B  is a perspective view of the upper portion of the mast assembly as illustrated in  FIG. 9A-A , showing the top drive and the pipe clamp in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 9C-C  is a cross sectional view of the system of  FIG. 9  taken along the section line C-C, illustrating the relationship of the blowout preventer to the completion system in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 10A  is an illustration of an embodiment of a pipe tong fixture usable in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 10B  is a perspective view of the pipe tong fixture of  FIG. 10A . 
         FIG. 11A ,  FIG. 11B ,  FIG. 11C , and  FIG. 11D  illustrate an embodiment of a compact snubbing unit usable in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 12A  is a schematic view of an embodiment of a control cabin usable in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 12B  is an elevation view of the control cabin of  FIG. 12A  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 12C  is a first end view (e.g., a left side view) of the control cabin of  FIG. 12A  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 12D  is an opposing end view (e.g., a right side view) of the control cabin of  FIG. 12A  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 13  is an illustration of an embodiment of a carrier adapted for use in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 14  is an illustration of an embodiment of a pipe arm usable in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 14A  depicts a detail view of an engagement between the pipe arm of  FIG. 14  and an associated skid in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 15A  is an elevation view of the pipe arm of  FIG. 14  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 15B  is an exploded view of a portion of the pipe arm of  FIG. 15A , indicated as section “B” in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 15C  is an enlarged or detailed view of a portion of the pipe arm of  FIG. 15A , indicated as section “C” in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 15D  is an enlarged or detailed view of a portion of the pipe arm of  FIG. 15A , indicated as section “D” in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 15E  is a plan view of the pipe arm of  FIG. 14  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIGS. 15F and 15G  are end views of the pipe arm of  FIG. 14  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 16A  is an elevation view of the pipe arm of  FIG. 14  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 16B  is a plan view of the pipe arm of  FIG. 14  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 16C  is an enlarged or detailed view of a portion of the pipe arm of  FIG. 16  A, indicated as section “C” in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 16D  is an end view of the pipe arm of  FIG. 14  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 17  is a perspective view of an embodiment of a kickout arm usable in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 17A  is an enlarged or detailed view of an embodiment of a clamp of the kickout arm of  FIG. 17  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 18A  is an elevation view of the kickout arm of  FIG. 17  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 18B  is a bottom view of the kickout arm of  FIG. 17  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 18C  is a top view of the kickout arm of  FIG. 17  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 18B-B  is a sectional view of the end taken along the section line B-B in  FIG. 18B  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 18C-C  is a cross sectional view of the kickout arm of  FIG. 18C  taken along the section line C-C in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 19A  is an elevation view of an embodiment of a top drive fixture usable with the mast assembly of embodiments of the completion system in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 19B  is a side view of the top drive fixture illustrated in  FIG. 19A  in accord with one possible embodiment of the completion system of the present invention. 
         FIG. 19C-C  is a cross sectional view of the top drive fixture of  FIG. 19B  taken along the section line C-C in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 19D  is an enlarged or detailed view of a portion of the top drive fixture of  FIG. 19B  indicated as section “D” in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 19E-E  is a cross sectional view of the top drive fixture of  FIG. 19A  taken along the section line E-E in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 20A  is an illustration of a top drive within the top drive fixture of  FIG. 19A  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 20  A-A is a cross sectional view of the top drive and fixture of  FIG. 20A  taken along section line A-A in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 20B  is a top view of the top drive and fixture of  FIG. 20A  in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 21A  is a perspective view of a pivotal pipe arm having a pipe thereon with pipe clamps retracted to allow a pipe to be received into receptacles of the pipe arm in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 21B  is a perspective view of a pivotal pipe arm having a pipe thereon with pipe clamps engaged with the pipe whereby the pipe arm can be moved to an upright position in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 22A  is an end perspective view of a walkway with pipe moving elements whereby the pipe moving elements are positioned to urge pipe into a pipe arm in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 22B  is an end perspective view of a walkway with pipe moving elements whereby a pipe has been urged into a pipe arm by pipe moving elements in accord with one possible embodiment of the completion system of the present disclosure. 
         FIG. 23A  is an end perspective view of a pipe feeding mechanism whereby a pipe is transferred from a pipe tub into a pipe arm in accord with one possible embodiment of the present disclosure. 
         FIG. 23B  is another end perspective view of a pipe feeding mechanism whereby a pipe is transferred from a pipe tub into a pipe arm in accord with one possible embodiment of the present disclosure. 
         FIG. 23C  is a cross sectional view of a pipe feeding mechanism whereby a pipe is transferred from a pipe tub into a pipe arm in accord with one possible embodiment of the present disclosure. 
         FIG. 23D  is a cross sectional view of a pipe feeding mechanism with the pipes removed in accord with one possible embodiment of the present disclosure. 
         FIG. 23E  is a cross sectional view of a pipe feeding mechanism whereby a pipe is transferred from a pipe tub into a pipe arm in accord with one possible embodiment of the present disclosure. 
         FIG. 24A  is a perspective view of an embodiment of a gripping apparatus engageable with a top drive of one possible embodiment of the present disclosure. 
         FIG. 24B  depicts a diagrammatic side view of the gripping apparatus of  FIG. 24A . 
         FIG. 25A  is an exploded perspective view of a guide apparatus engageable with a top drive in accord with one possible embodiment of the present disclosure. 
         FIG. 25B  is a diagrammatic side view of the guide apparatus of  FIG. 25A . 
         FIG. 26  is a top view of a roller engaged with a guide rail in accord with one possible embodiment of the present disclosure. 
         FIG. 27A  is a top view of a crown block sheave assembly showing an axis of rotation in accord with one possible embodiment of the present disclosure. 
         FIG. 27B  is a top view of a traveling sheave block showing an axis of rotation in accord with one possible embodiment of the present disclosure. 
         FIG. 28A  is a perspective view of a system for conducting a long lateral well completion system of multiple wellheads in close proximity in accord with one possible embodiment of the present invention. 
         FIG. 28B  is another perspective view of a system for conducting a long lateral well completion system of multiple wellheads in close proximity in accord with one possible embodiment of the present invention. 
     
    
    
     The above general description and the following detailed description are merely illustrative of the generic invention, and additional modes, advantages, and particulars of this invention will be readily suggested to those skilled in the art without departing from the spirit and scope of the invention. 
     DESCRIPTION OF EMBODIMENTS 
       FIG. 1  illustrates an embodiment of a long lateral completion system  10  usable in accord with one possible embodiment of the completion system of the present disclosure. In this embodiment, the completion system  10  is shown having a mast assembly  100 , which extends in a generally vertical direction (i.e., perpendicular to the rig carrier  600  and/or the earth&#39;s surface), a pipe handling mechanism  200 , a catwalk-pipe arm assembly  300 , two pipe tubs  400 , a pump pit combination skid  500 , a rig carrier  600  usable to transport the mast assembly  100  and various hydraulic and/or motorized pumps and power sources for raising and lowering the mast assembly  100  and operating other rig components, and a control van  700 , used to control operation of one or more of the components of long lateral completion system  10 . Other embodiments may comprise the desired completion system  10  components otherwise arranged on skids as desired. For example, in another embodiment, separate pump and pit skids might be utilized. In another embodiment, catwalk pipe tubes with tube handling elements might be combined on one skid with pipe arm assembly  300  provided separately. It will be appreciated that many different embodiments may be utilized. Accordingly,  FIG. 1  shows one possible arrangement of various components of the completion system  10  that can be implemented around a well (e.g., an oil, natural gas, or water well). Due to the construction, system  10  can work with wells that are in close proximity to each other, e.g. within ten feet of each other. For example, mast assembly  100  may be located above a first well, as discussed hereinafter, and rig floor  102  (if used) may be elevated above a second capped wellhead (not shown) within ten feet of the first well. Sensors, such as laser sights, guides mounted to the rear of rig carrier  600 , and the like may be utilized, e.g., mounted to and/or guided to the well head, to locate and orient the axis of drilling rig mast  100  precisely with respect to the wellbore, which in one embodiment may be utilized to align a top drive mounted on guide rails with the wellbore, as discussed hereinafter. 
     Control van  700  and automated features of system  10  can allow a single operator in the van to view and operate the truck mounted production rig by himself, including raising the derrick, picking up pipe, torqueing to the desired torque levels for tubing, going in the hole, coming out of the hole, performing workover functions, drilling out plugs, and/or other steps completing the well, which in the prior art required a rig crew, some problems of which were discussed above. In other embodiments, the control van  700  and/or other features can be configured for use and operation by multiple operators. Control van  700  may comprise a window arrangement with windows at the top, front, sides and rear (See e.g.,  FIG. 12B ), so that once positioned in a desired position on the well site, all operations to the top of mast  100  are readily visible. 
     For example, embodiments of the system  10  can be positioned for real time operation, e.g., by a single individual operating the control van  700  and/or a similar control system, and further embodiments can be used to perform various functions automatically, e.g., after calibrating the system  10  for certain movements of the pipe arm assembly  300 , the top drive or a similar type of drive unit along the mast assembly  100 , etc. After providing the system  10  in association with a wellbore, e.g., by erecting the mast assembly  100  vertically thereabove, a tubular segment can be transferred from one or more pipe tubs and/or similar vessels to the pipe arm assembly  300 , and the control van  700  and/or a similar system can be used to engage the tubular segment with a pipe moving arm thereof. For example, as described hereinafter, hydraulic members of the pipe tubs and/or similar vessels can be used to urge a tubular member over a stop into a position for engagement with a pipe moving arm, while hydraulic grippers thereof can be actuated to grip the tubular member. The control system can then be used to raise the pipe moving arm and align the tubular segment with the mast assembly, which can include extension of a kick-out arm from the pipe moving arm, further described below. Alignment of the tubular segment with the mast assembly could further include engagement of the tubular segment by grippers (e.g., hydraulic clamps and/or jaws) positioned along the mast. The control system is further usable to move the top drive along the mast assembly to engage the tubular segment (e.g., through rotation thereof), to disengage the pipe moving arm from the tubular, and to further move the top drive to engage the tubular segment with a tubular string associated with the wellbore. While the system is depicted having a pipe moving arm used to raise gripped segments of pipe into association and/or alignment with the mast, in other embodiments, a catwalk-type pipe handling system in which the front end of each pipe segment is pulled and/or lifted into a desired position, while the remainder of the pipe segment travels along a catwalk, can be used. 
     In an embodiment, any of the aforementioned operations can be automated. For example, the control system can be used to calibrate movement of the drive unit along the mast assembly, e.g., by determining a suitable vertical distance to travel to engage a top drive with a tubular segment positioned by the pipe moving arm, and a suitable vertical distance to travel to engage a tubular segment engaged by the top drive with a tubular string below, such that movement of a top drive between positions for engagement with tubular members and engagement of tubular members with a tubular string can be performed automatically thereafter. The control system can also be used to calibrate movement of the pipe moving arm between raised and lowered positions, depending on the position of the mast assembly  100  relative to the pipe arm assembly  300  after positioning the system  10  relative to the wellbore. Then, future movements of the pipe moving arm, and the kick-out arm, if used, can be automated. In a similar manner, grippers on the mast assembly  100 , if used, annular blowout preventers and/or ram/snubbing assemblies, and other components of the system  10  can be operated using the control system, and in an embodiment, in an automated fashion. After assembly of a completion string, further operations, such as fracturing, production, and/or other operations that include injection of substances into or removal of substances from the wellbore can be controlled using the control system, and in an embodiment, can be automated. In embodiments where a catwalk-type pipe handling system is used, operations of the catwalk-type pipe handling system can also be highly automated, including engagement of the front end of a pipe segment, lifting and/or otherwise moving the front end of the pipe segment, and the like. 
       FIG. 2  is a perspective view of the mast assembly  100 , catwalk-pipe arm assembly  300 , pipe tubs  400 , and the carrier  600  of the long lateral completion system  10  in accord with one possible embodiment of the completion system of the present invention. The carrier  600  has the mast assembly  100  extending from the rear portion of the carrier  600 . In one embodiment, the mast assembly  100  is essentially perpendicular to the carrier  600 . In another embodiment, mast assembly  100  is aligned either coaxially, within less than three inches, or two inches, or one inch to an axis of the bore through the wellhead, BOPs, or the like when the top drive is positioned at a lower portion of the mast and/or is parallel to the axis of the borehole adjacent the surface of the well and/or the bore of the wellhead pressure equipment within less than five degrees, or less than three degrees, or less than one degree in another embodiment. For example, in one embodiment, mast rails  104 , which guide top drive  150 , may be aligned to be essentially parallel to the axis of the bore, within less than five degrees in one embodiment, or less than three degrees, or less than one degree in another embodiment, whereby top drive  150  moves coaxially or concentric to the well bore within a desired tolerance. As used herein a well completion system may be essentially synonymous with a workover system or drilling system or rig or drilling rig or the like. The system of the present invention may be utilized for completions, workovers, drilling, general operations, and the like and the term workover rig, completing rig, drilling rig, completion system, intervention system, operating system, and the like are used herein substantially interchangeably for the herein described system. Pipe as used herein may refer interchangeably to a pipe string, a single pipe, a single pipe that is connected to or removed from a pipe string, a stand of pipe for connection or removal from a pipe string, or a pipe utilized to build a pipe string, tubular, tubulars, tubular string, oil country tubulars, or the like. 
     The carrier  600  is illustrated with a power plant  650  and a winch or drawworks assembly  620 . Winch or drawworks  620  can be utilized for lifting and lowering the top drive  150  in mast  100  utilizing pulley arrangements in crown  190  and blocks associated with top drive  150 . The mast positioning hydraulic actuators  630  provide for lifting the mast assembly  100  into a desired essentially vertical position, with respect to the axis of the borehole at the surface of the well, within a desired accuracy alignment angle. In one embodiment, a laser sight may be mounted to the wellbore with a target positioned at an upper portion of the mast to provide the desired accuracy of alignment. In this embodiment, crown laser alignment target  192  is provided adjacent crown  190 . The mast assembly  100  is affixed to the rear portion of the carrier  600 . Also the mast assembly  100  is illustrated with a top drive  150  and a crown  190 . The top drive allows rotation of the tubing, which results in significant improvement when inserting pipe into high angled and/or horizontal well portions. Further associated with the mast assembly  100  and the carrier  600  is a mast support base beam  120  for providing stability to the carrier  600  and the mast assembly  100 , e.g., by increasing the surface area that contacts the ground. 
     In one possible embodiment, a catwalk-pipe arm assembly  300  may be located proximate to the mast assembly  100 , which, in one possible embodiment, may be utilized to automatically insert and/or remove pipe from the wellbore. In one embodiment, the pipe is not stacked in the rig but instead is stored in one or more moveable pipe tubs  400 . Catwalk-pipe arm assembly  300  may be configured so that components are provided in different skids, as discussed hereinbefore, and as discussed hereinafter to some extent. In this example, catwalk-pipe arm assembly  300  has associated on either side thereof a pipe tub  400 . However, pipe tubes  400  may be used on only one side, two on one side, or any configuration may be utilized that fits with the well site. While more than two pipe tubes can be utilized, usually not more than four pipe tubs are utilized. However, pipe racks or other means to hold and/or feed pipe may be utilized. It can be appreciated that multiple pipe tubs  400  are provided for supplying multiple pipes to the catwalk-pipe arm assembly  300 . Pipe tubs  400  may or may not comprise feed elements, which guide each pipe as needed to roll across catwalk  302  to pivotal pipe arm  320 . Conceivably, means (not shown) may be provided which allow torqueing two or more pipes from associated pipe tubes for simultaneously handling stands of pipes utilizing pivotal pipe arm  300  for faster insertion into the well bore. However, in the presently shown embodiment, only one pipe at a time is typically handled by pipe arm  300 . When handling stands of pipe, then the correspondingly lengthened mast  100  may be carried in multiple carrier trucks  600 . 
     The pipe tubs are preferably capable of holding multiple joints of pipe for delivery to the pipe arm. The pipe tubs are further preferably capable of continuously lifting and feeding a section of pipe to the pipe arm. The pipe tubs in some embodiments can be positioned in an orientation substantially parallel to the pipe arm, so that the sections of pipe are in a length-wise orientation parallel to the pipe arm. A pipe tub may further comprise a hydraulic lifting system for raising the floor or bottom shelf of the pipe tub in an upwards direction away from the ground and additionally may be used to tilt the pipe tub, so as to lift and roll one or more sections of pipe into a position to be received by the pipe arm. The pipe tubs could additionally include a series of pins along the edge of the pipe tub closest to the pipe arm, which feeds the sections of pipe to the pipe arm. However, preferably the series of pins are disposed on the pipe arm skid at a location proximate to the adjacent edge of the pipe tubs. These pins serve the purpose of stopping or preventing a joint of pipe from rolling onto the pipe arm or pipe arm skid prematurely. Each pipe tub used in the pipe handling system can further incorporate one or more flipper arms, which are hydraulically actuated arms or plates to push or bump a section of pipe over the above mentioned pins when the pipe handling skid and pipe arm are in a position to receive the said section of pipe. Preferably, the pipe arm skid includes one or more flipper arms which pivotally rotate in an upward direction and which engage the joints of pipe to lift the joints of pipe over the pins retaining the joint(s) of pipe, whether the pins are disposed along the edge of the pipe arm skid or on the edge of the pipe tub. It can be appreciated that as an alternative to the pipe tubs  400 , pipe ramps, saw horses, or tables can be used. The selection of the apparatus (e.g. pipe tubs, ramps, saw horses, or tables) for delivery of pipe joints to the pipe arm depends on the physical layout of the surrounding area and if there are any obstructions or hazards that need to be avoided or overcome. 
     Various types of scanners such as laser scanners for bar codes, RFIDs, and the like may be utilized to monitor each pipe whereby the amount of usage, the length, torque history and other applied stresses, testing history of wall thickness, wear, and the like may be recorded, retrieved, and viewed. If desired, the pipe tub and/or catwalk may comprise sensors to automatically measure the length of each pipe. Thus, the operator in the van can automatically keep a pipe tally to determine accurate depths/lengths of the pipe string in the well bore. Torque sensors may be utilized and recorded so that the torque record shows that each connection was accurately aligned and properly torqued, and/or immediately detect/warn of any incorrectly made up connection. 
       FIG. 3  is a plan view of one possible embodiment of carrier  600 , mast assembly  100 , catwalk-pipe arm assembly  300  and pipe tub  400  of the long lateral completion system  10  pursuant to one possible embodiment of the present invention The carrier  600  is illustrated with the power plant  650  and the winch or drawworks assembly  620  The mast assembly  100  is disposed at a rear extremity of the carrier  600  and adjacent to the winch or drawworks assembly  620  In this embodiment, base beam  120  is disposed beneath and/or adjacent to the mast assembly  100  for providing security/stability for the mast assembly  100  Base beam  120  may comprise wide flat mats  122 , (also shown in  FIG. 2 ), which are pushed downwardly by base beam hydraulic actuators  612  (shown in  FIG. 2  and better shown in  FIG. 8A-A ). In one possible embodiment, wide flat mats  122  may be  50  percent to  200  percent as wide as mast  100  Wide flat mats  122  may fold upon each other and/or extend telescopingly or slidingly outwardly from carrier  600  and/or hydraulically Wide flat mats  122  may be slidingly supported on beam runner  124  and may be transported on carrier  600  or provided separately with other trucks 
     In this embodiment, catwalk-pipe arm assembly  300  is affixed to mast assembly  100  and carrier  600  by rig to arm connectors  305  (also shown in  FIG. 2 ) In this embodiment, catwalk-pipe arm assembly  300  is shown with a pipe tub  400  on both sides of the catwalk-pipe arm assembly  300  The pipe tubs  400  are shown with the side supports  402 , the end support  404  and a cavity  420  A plurality of pipes (not illustrated) is placed in the pipe tubs  400  Pipes are displaced on to the catwalk-pipe arm assembly  300  and lifted up to the mast assembly  100 . Catwalk  302  may be somewhat V-shaped or channeled to urge pipes to roll into the center for receipt and clamping, utilizing catwalk-pipe arm assembly  300  Catwalk  302  provides a walkway surface for workers and the like Additional pipe tubs  400  can be slid into place to provide for a continuum of pipe lengths for use by the completion system  10  Acoustic and/or laser and/or sensors or RFID transceivers  408  and  410  may be positioned on ends  404  and sides  402  of pipe tubs  400 , or elsewhere as desired, to measure and/or detect the lengths of the pipes, and to detect RFIDs, bar codes, and/or other indicators which may be mounted to the pipes Alternatively, pipe length sensors  412 ,  414  may each comprise one or more sensors, which may be mounted to pipe arm  320 . In one embodiment, sensors  412 ,  414  may comprise acoustic, electromagnetic, or light sensors which may be utilized to detect features such as length of the pipe. Pipe connection cleaning/grease injectors  416 ,  418  may be provided for wire brushing, grease injecting, thread protector removal and other automated functions, if desired. 
     In one embodiment, sensors  412 ,  414  may comprise thread protector sensors provided to ensure that the thread protectors have been removed from both ends of a pipe. Thread protectors are generally plastic or steel and used during transportation to prevent any damage to the threading of pipe. Damage as a result of faulty or damaged threads could jeopardize a well site and the safety of the workers therein. However, failing to remove a thread protector can cause the same potential dangers if not found before inserted into the pipe string. The pipe will not mate properly with the threads of the pipe string, compromising the integrity of the entire pipe string and well site. The thread protector sensors  412 ,  414  may be acoustic sensors or lasers used to determine whether the thread protectors have been removed and communicate this data with the control system. If the thread protectors are present, an acoustic or light signal transmitted by sensor  412  may be reflected rather than received at sensor  414 . Alternatively, sensors  412  and  414  may be transceivers that will not receive a signal unless the thread protector is present. In another embodiment, a light detector will detect a different profile. In another embodiment, sensors  412  and  414  may comprise a camera in addition to other thread protector sensors. If the thread protectors have not been removed, an operator will be informed before attempting to make up the pipe connection so that the problem can be fixed. 
     In one possible embodiment, inner portion adjacent catwalk  302  and/or catwalk edges  301  and  307  may comprise gated feed compartments whereby pipes are fed into a compartment or funnel large enough for only single pipes or stands of pipes, and then gated to allow individual pipes or stands of pipes to be automatically rolled onto either side of catwalk  302 . 
       FIG. 4  is an illustration of the carrier  600  of the long lateral completion system  10  in accord with one possible embodiment of the completion system of the present disclosure. The carrier  600  is illustrated with the power plant  650  and the winch or drawworks assembly  620 . Also, the mast assembly  100  is illustrated in a lowered or horizontal position, which is essentially parallel relationship with the carrier  600 . Mast  100  is clamped into the generally horizontal position with carrier front clamp/support  633  above cab  605 . Mast  100  is hinged at mast to carrier pivot  634  so that the mast is secured from any forward/reverse/side-to-side movement with respect to carrier  600  during transport after being clamped at the front and/or elsewhere. In this embodiment, mast positioning hydraulic actuators  630  are pivotally mounted with respect to carrier walkway  602  so that when extended, the hydraulic actuators  630  are angled toward the rear instead of toward the front of carrier  600  as in  FIG. 4  (See for example  FIG. 2 ). In one embodiment, mast positioning hydraulic actuators  630  may comprise multiple telescopingly connected sections as shown in  FIG. 6A . The horizontally disposed mast assembly  100  is illustrated for moving on the highway and for arrangement in the proximate location with respect to a wellbore. It will be noted that hydraulic pipe tongs  170  are mounted to mast  100  so that when the mast  100  is lowered pipe tongs  170  are in a position generally perpendicular to the operational position. Movements and actuation of the pipe tongs can be fully automated, for forming and/or breaking both shoulder connections and collared connections. The mast assembly  100  has the crown  690  extending in front of the carrier  600 . In one embodiment, rig carrier is less than  20  feet high, or less than  15  feet high, while still allowing the rig to work with well head equipment having a height of about  20  feet. This is due to the construction of the mast with the Y-frame connection as discussed herein. The rig floor can be adjusted to a convenient height and is not necessarily fixed in height. In an embodiment, the rig floor could be connected to snubbing jacks. 
       FIG. 4A-A  is a top view taken along the line A-A in  FIG. 4  of the mast assembly  100  of the long lateral completion system pursuant to one possible embodiment of the present invention.  FIG. 4A-A  illustrates a downward view of the mast assembly  100 . The mast assembly  100  shows the top drive assembly or fixture  150  (also shown in  FIG. 4 ) affixed to the portion of the mast assembly  100  over the winch or drawworks assembly  620  over the carrier  600 . The top drive assembly or fixture  150  is provided at the location associated with the carrier  600  for distributing the load associated with the carrier  600  for easy transportation on the highway. Top drive or fixture  150  may be clamped or pinned into position with clamps or pins  162  or the like that are inserted into holes within mast  100  at the desired axial position along the length of mast  100 . Angled struts  134  (also shown in  FIG. 4 ) on Y-section  132 , which may be utilized in one possible embodiment of mast  100 , are illustrated in the plan view. Top drive  150  is shown with end  163 , which may comprise a threaded connector and/or tubular guide member and/or pipe clamping elements and/or torque sensors and/or alignment sensors. 
       FIG. 4B-B  is an end elevational view taken along the line B-B in  FIG. 4  of the carrier  600  and the mast assembly  100  of the long lateral completion system  10  of in accord with one possible embodiment of the completion system of the present disclosure.  FIG. 4B-B  illustrates the carrier  600 , the winch or drawworks assembly  620  and the top drive  150 . In this view, vertical top drive guide rails  104  are shown, upon which top drive  150  is guided, as discussed hereinafter. In this embodiment, it will also be noted that top drive threaded connector and/or guide member and/or clamp portion  163  is positioned in the plane defined between vertical top drive guide rails  104 . In this embodiment, the view also shows one or more angled struts  134 , which may comprise Y section  132  of one possible embodiment of mast  100 , which is discussed in more detail with respect to  FIG. 6A . 
       FIG. 5  is an elevation view of the carrier  600 , the mast assembly  100 , and the catwalk-pipe arm assembly  300  of the long lateral completion system  10  with respect to one possible embodiment of the present invention. The carrier  600  is illustrated with the power plant  650  and the winch or drawworks assembly  620 . The cable from drawworks  620  to crown  190  is not shown but may remain connected during transportation and raising of mast  100 . The drawworks cable may be pulled from drawworks  620  as mast  100  is raised. The mast assembly is illustrated engaged at the rear extremity of the carrier  600 . The mast assembly  100  is in a vertical arrangement such that it is at an essentially perpendicular relationship with the carrier  600 . The mast assembly  100  is illustrated with the top drive  150  in an upper position near the crown  190 . The pivotal pipe arm  320  is shown in an angled disposition slightly above catwalk  302  for clarity of view. Pivotal pipe arm  320  is shown with pipe  321  clamped thereto. The catwalk-pipe arm assembly  300  is engaged or connected via rig to arm assembly connectors  305  with the carrier  600  and the mast assembly  100 . Rig to arm assembly connectors  305  provide that the spacing arrangement between pivotal pipe arm  320  and mast  100  and/or carrier  600  is affixed so the spacing does not change during operation. Rig to arm assembly connectors  305  may comprise hydraulic operators for precise positioning of the spacing between mast  100  and pivotal pipe arm  320 , if desired. 
       FIG. 5A  is an enlarged or detailed view of a section shown in  FIG. 5  as the rear portion of the carrier  600  engaged with a skid or mast support base beam  120  of the long lateral completion system  10  with respect to one possible embodiment of the present invention. Mast positioning hydraulic actuators  630  are provided for lowering and raising the mast assembly  100  with respect to the carrier  600 , about mast to carrier pivot connection  634 . Brace  632  for Y-base or support section  130  provides additional support for mast  100 . 
       FIG. 6  illustrates the completion system  10  in a side elevational view with the mast assembly  100  extended in a perpendicular relationship with the carrier  600  and the pipe tubs  400  of the long lateral completion system  10  with respect to one possible embodiment of the present invention. The pivotal pipe arm  320  is angularly disposed with respect to the catwalk  302 . The mast assembly  100  is illustrated with the top drive  150  slightly below the crown  190 . Alternately, and not required in practicing the present disclosure, guy wires  101  can be engaged between the crown  190  of the mast assembly  100  and the carrier  600  on one extreme and the remote portion of a pipe tube  400  on the other extreme. However, one or more guy wires could be anchored to the ground and/or may not be utilized. One or more guy wires can also be secured to the ends of base beam  120 . It can be appreciated that the rigidity of the mast assembly  100  with respect to the carrier  600  and the base beam  120  does not require guy wires  101 . However, it may be appropriate in a particular situation or in severe weather conditions to adapt the present disclosure for use with such guy wires  101 . The carrier is illustrated with the power plant  650  and the winch or drawworks assembly  620  on the carrier deck  602 . 
       FIG. 6A  is an enlarged or detailed view of the portion of  FIG. 6  illustrating the relationship of the mast assembly  100 , the deck  602  and the base beam  120  of the long lateral completion system  10  with respect to one possible embodiment of the present invention.  FIG. 6A  shows the relationship of the mast assembly  100 , the deck  602  of the carrier  600  and the base beam  120 . It will be noted that base beam widening sections  121  may extend or slide outwardly from base beam  120  and be pinned into position with pin  123 . Also illustrated is what may comprise multiple segments of mast positioning hydraulic actuators  630  for angularly disposing the mast assembly  100  in a proximately perpendicular relationship with the carrier  600 , and aligned with respect to the well bore, as discussed hereinbefore. Above the deck  602  of the carrier and affixed with the mast assembly  100  is a hydraulic pipe tong  170 . The hydraulic pipe tong  170  is usable for handling the pipe as it is placed into a well, e.g., by receiving joints of pipe from the pipe arm and/or the top drive. The lower extremity of the mast assembly  100  includes a y-base  130 , which defines a recessed region above the wellbore at the base of the mast assembly  100 , for accommodating a blowout preventer stack, snubbing equipment, and/or other wellhead components. The recessed region enables the generally vertical mast assembly  100  to be positioned directly over a wellbore without causing undesirable contact between blowout preventers and/or other wellhead components and the mast assembly  100 . 
     The lower extremity of the mast assembly  100  is defined by the y-base  130 . The y-base  130  provides a disposed arrangement for making and inserting pipe using the completion system  10  in accord with one possible embodiment of the completion system of the present invention. Y-base  130  supports Y section  132 , which extends angularly with angled strut  134  out to support one side of mast  100 . This construction provides an opening or space  136  for the BOP assembly, such as BOP (see  FIG. 9 ), snubbing unit (see  FIG. 11A ), Christmas tree, well head, and/or other pressure control equipment. Mast  100  is supported by carrier to mast pivot connection  634  and at the carrier  600  rearmost position by mast support plate  636  (also shown in  FIG. 4 ). Mast support plate  636  may be shimmed, if desired. In another embodiment, mast support plate may be mounted to be slightly moveable upwardly or downwardly with hydraulic controls to support the desired angle of mast  100 , which as discussed above may be oriented to a desired angle (e.g. less than five degrees or in another embodiment less than one degree) with respect to the axis of the bore of the well bore and/or bore of BOP  900 , shown in  FIG. 9 . In this embodiment, mast support plate  636  does not extend horizontally and rearwardly from carrier  600 , as far as the other mast  100  horizontal supports, e.g., horizontal mast supports or struts  140 . This construction allows the opening or space  136  for the BOP (see  FIG. 9 ), snubbing unit (see  FIG. 11A ), Christmas tree, well head, and/or other pressure control equipment. However, the mast construction is not intended to be limited to this arrangement. 
     In other words, Y-base  130  back most rail  138  is horizontally offset closer to carrier  600  than back most vertical mast supports  105  with respect to carrier  600 . Y-base  130  is sufficiently tall to allow BOP stacks to fit within opening or space  136 . However, Y-base  130  is replaceable and may be replaced with a higher or shorter Y-base as desired. to accommodate the desired height of any pressure control and/or well head equipment. In this example, the bottoms of Y-base  130  may be replaceably inserted/removed from Y-base receptacles  142  to allow for easy removal/replacement of Y-base  130  from carrier  600 . 
     As discussed hereinafter, vertical mast supports  105  support vertical top drive guide rails  104  (see  FIG. 4  B-B and  FIG. 8  B-B), which guide top drive  150 . An optional raiseable/lowerable rig floor, such as rig floor  102  (See  FIG. 1 ) is not shown for viewing convenience. 
       FIG. 7  is a side elevational view of the carrier  600 , the mast assembly  100 , the catwalk-pipe arm assembly  300 , and the pipe tub  400  with the mast assembly  100  (e.g., transporting a joint of pipe to the mast assembly  100  for engagement by the top drive) in a perpendicular relationship with the carrier  600 , and an arm to mast engagement element  325  of the pivotal pipe arm  320  engaged with optional upper mast fixture  135  on mast assembly  100  of the long lateral completion system  10  with respect to one possible embodiment of the present disclosure. The engagement of elements  325  and  135  may be utilized to provide an initial alignment of the pivotal connection of kick out arm  360  to pivotal pipe arm  320 . Kick out arm  360  is shown pivotally rotated to a vertical position so that pipe  321  is aligned for connection with top drive  150 , as discussed hereinafter. The carrier  600  is illustrated with the winch assembly  620  on the deck  602 . The depicted hydraulic actuator  630  has raised the mast assembly  100  into its vertical position, as discussed hereinbefore. The mast assembly  100  is illustrated with the top drive  150  near the crown  190 . The kickout arm  360  of the catwalk-pipe arm assembly  300  may be more accurately vertically placed in the extended position adjacent to the mast assembly  100 , having a kickout arm  360  in association therewith. As such, when the pipe arm  320  pivots into the position shown in  FIG. 7  (e.g., using the hydraulic cylinder  304 ), the pipe arm  320  is not parallel with the mast assembly  100 , thus a joint of pipe engaged with the pipe arm  320  would not be positioned suitably for engagement with the top drive  150 . The kickout arm  360  is extendable from the pipe arm  320  into a position that is generally parallel with the mast assembly  100 , e.g., by use of a hydraulic actuator  362 . Using the kickout arm  360 , the pipe  321  is placed in the position which is essentially parallel with the mast assembly  100 , and in this embodiment is positioned in the plane defined by mast rails  104  (See  FIG. 4B-B ), which guide top drive  150 , by use of the hydraulic actuator  362 . The movement of the pivotal pipe arm  320  is provided by the hydraulic actuator  304 . 
     In one possible embodiment, the upright position of pivotal pipe arm  320  is controlled by angular sensors  325  and/or shaft position sensors  326  (see  FIG. 16A ) to account for any variations in hydraulic operator  304  operation. 
     Alternatively, or in addition, upper mast fixture  135  may comprise a receptacle and guide structure. In this embodiment, which may be provided to guide the top of pivotal pipe arm  320  into contact with mast  100 , whereby the same vertical/side-to-side positioning of kick out arm  360  is assured in the horizontal and vertical directions. The guide elements may, if desired, comprise a funnel structure that guides arm to mast engagement element  325  into a relatively close fitting arrangement. If desired, a clamp and/or moveable pin element (with mating hole in pivotal pipe arm) may be utilized to pin and/or clamp pivotal pipe arm  320  into the same position for each operation. In another embodiment upper mast fixture may comprise a hydraulically operated clamp with moveable elements that clamp the pipe in a desired position for aligned engagement with top drive threaded connector and/or guide member and/or clamp portion  163 . As shown in  FIG. 7A-A , upper fixture  135  may also comprise one or more pipe alignment guide members/clamps/supports as indicated at  139  to position pipe  321  and/or kickout arm  360  to thereby align pipe  321  and pipe connector  323  with respect to top drive threaded connector and/or guide member and/or clamp portion  163 . Element  139  may comprise a moveable hydraulic clamp or guide to affix and align the pipe in a particular position. Element  139  may instead comprise a fixed groove or slot or guide and may be hydraulically moveable to a laser aligned position. 
     As a result, top connector  323  on tubing pipe  321  is aligned to top drive threaded connector and/or guide member and/or clamp portion  163 , as discussed in more detail hereinafter, by consistent positioning of kick out arm  360 . It will be appreciated that rig to arm connectors  305  further aid alignment by insuring that the distance between catwalk-pipe arm assembly  300  and mast  100  remains constant. 
       FIG. 7A-A  is a rear elevational view of  FIG. 7  showing the mast assembly  100  and top drive  150  of the long lateral completion system  10  with respect to one possible embodiment of the present disclosure.  FIG. 7A-A  illustrates the portion of the mast assembly  100 , which includes the top drive  150 , and the upper portion of the pivotal pipe arm  320 . Also illustrated are the lattice structural support elements  112  of the mast assembly  100 . The top drive  150  is shown secured within a top drive fixture/carrier  151 , which can be moved vertically along the mast assembly  100 , e.g., via a rail/track-in-channel engagement using rollers, bearings, etc. Due to the generally vertical orientation of the mast assembly  100 , and the positioning of the mast assembly  100  directly over the wellbore, the top drive  150  can be directly engaged with the mast assembly  100 , via the top drive fixture  151 , as shown, rather than requiring use of conventional cables, traveling blocks, and other features required when an angled mast is used. Engagement between the top drive  150  and the mast assembly  100  via the top drive fixture  151  eliminates the need for a conventional cable-based torque arm. Contact between the top drive  150  and the fixture  151  prevents undesired rotation and/or torqueing of the top drive  150  entirely, using the structure of the mast assembly  100  to resist the torque forces normally imparted to the top drive  150  during operation. 
       FIG. 7B  is a perspective view of the portion of the mast assembly  100  and pivotal pipe arm  320  with clamps  370 B engaged with upper fixture  135  as illustrated in  FIG. 7A-A  of the long lateral completion system  10  with respect to one possible embodiment of the present invention. The mast assembly  100  is illustrated with the top drive  150  positioned a selected distance the pipe arm  300 . 
       FIG. 8  is a side elevational view of the completion system  10  in accord with another embodiment of the present disclosure illustrating the mast assembly  100  in a perpendicular relationship with the carrier  600  and/or aligned with an axis of the upper portion of the wellbore. The carrier  600  is shown with the deck  602  and the mast positioning hydraulic actuators  630  providing movement for the mast assembly  100  mast to carrier pivot connection  634 . The mast assembly  100  has the top drive  150  disposed proximate to the crown  190 . As discussed hereinafter, crown  190  may comprise multiple pulleys that are utilized to raise and lower the blocks associated with top drive  150  utilizing drawworks  620 . The pipe arm  320  is extended in an upward position using the pipe arm hydraulic actuator  304 . Further, the kickout arm  360  is disposed in a parallel relationship with the mast assembly  100  using the kick out arm hydraulic alignment actuator  362  to align pipe  321  appropriately with respect to the mast assembly  100 , e.g., in one embodiment the pipe is positioned in the plane defined between mast top drive rails  104 . Mast top drive rails  104  (shown in  FIG. 8B-B ) are secured to an inner portion of the two rear most (with respect to carrier  600 ) vertical supports  105  of mast  100 . 
       FIG. 8A-A  shows another view of Y section  132 , which comprises one or more angled struts  134  on each side of mast  100  utilized to support vertical mast supports  105 . Pipe tong  170  is aligned within the plane between guide rails  104  to thereby be aligned with top drive threaded connector and/or guide member and/or clamp portion  163  (see  FIG. 8B-B  and  FIG. 4B-B ) of top drive  150   
       FIG. 8B-B  is a rear elevational view of the mast assembly  100  and top drive  150  of the long lateral completion system  10  (shown in  FIG. 8 ) with respect to one possible embodiment of the present invention.  FIG. 8B-B  illustrates the relationship of pivotal pipe arm  320 , the top drive  150  and the mast assembly  100 . Further, the lattice support structure  112  is illustrated for providing superior rigidity to and for the mast assembly  100 . 
       FIG. 8C  is a perspective view of  FIG. 8B-B  of the relationship between the pivotal pipe arm  320  and the top drive  150  relative to the mast assembly  100  of the long lateral completion system with respect to one possible embodiment of the present invention. Also illustrated is the pipe clamp  370  associated with the pivotal pipe arm  300  for holding a joint of pipe. In an embodiment, a joint of pipe raised by the pipe arm  300  then extended using the kickout arm  360  may require additional stabilization prior to threading the pipe joint to the top drive. Additional pipe clamps along the mast assembly  100  can be used to receive and engage the joint of pipe while the pipe clamp  370  of the pipe arm  300  is released, and to maintain the pipe directly beneath the top drive  150  for engagement therewith. 
     Returning again to  FIG. 8A-A , the figure depicts a sectional view of FIG. showing the pipe tong  170  with respect to the mast assembly  100  of the long lateral completion system with respect to one possible embodiment of the present invention.  FIG. 8A-A  illustrates the relationship of the hydraulic pipe tong  170  with respect to the mast assembly  100  and the base beam  120 . The mast assembly  100  is supported by braces  112 . The braces  112  can be at various locations about the system  10  as one skilled in the art would appreciate. 
       FIG. 9  is an illustration of the long lateral completion system  10  of the present enclosure that depicts an embodied relationship of the carrier  600 , the mast assembly  100 , catwalk-pipe arm assembly  300 , the catwalk  302  and a blowout preventer and snubbing stack  900  of the long lateral completion system  10  with respect to one possible embodiment of the present disclosure. As described previously, the mast assembly  100  is disposed in a generally vertical orientation (e.g., perpendicular to the earth&#39;s surface and/or the deck  602 ), such that the mast assembly  100  is directly above the blowout prevent and snubbing stack  900  with the wellbore therebelow. The recessed region at the base of the mast assembly  100  accommodates the blowout preventer and snubbing stack  900 , while the top drive  150  disposed near the crown  190  of the mast assembly  100  can move vertically along the mast assembly  100  while remaining directly over the well. 
     The mast assembly  100  can be moved and maintained in position by the hydraulic actuators  630  and/or other supports. The pipe arm  300  can be moved and maintained in the depicted raised position via extension of the hydraulic actuator  304 . The kickout arm  360  pivots from the top of pivotal pipe arm using the hydraulic system  362  for aligning a joint of pipe in alignment with the well and BOP and snubbing stack  900 , which may utilize sensors  902 ,  904 ,  906 ,  908 , for example, laser alignment sensors  902  mounted on BOP and snubbing stack  900 ,  904  on kickout arm  360 , and/or laser alignment sensors  906  on top drive  150 . It should be appreciated that the kick-out arm can be extended or retracted through the use of hydraulic system  362  and may be connected through manual actuation of hydraulic/pneumatics or through an electronic control system, which maybe be operated through a control van or remotely through an Internet connection. This particular embodiment implements the use of a kick-out arm  360  to provide a substantially vertical joint of pipe for reception by the mast assembly  100 , which may include a top drive of some configuration. It is important that the joint of pipe be substantially vertical so that the threads on each joint are not cross-threaded when the connection to the top drive is made. Cross-threading can lead to catastrophic failure of the connected joints of pipe or damage the threads of the joint of pipe and render the joint of pipe unusable without extensive and costly repair. As mentioned above, the pipe arm  300  can further include a centering guide, which is capable of mating with a centering receiver located on the mast assembly  100 . This centering guide and centering receiver, when used provides an additional point of contact between the pipe arm  300  and the mast assembly  100  providing additional stability to the system and more precise placement and orientation of the pipe arm and joints of pipe. 
       FIG. 9A-A  is a sectional view of  FIG. 9  illustrating the upper portion of the mast assembly  100  of the long lateral completion system  10  with respect to one possible embodiment of the present invention. One possible embodiment of the relationship of the pipe arm  300  and the clamp  370  is shown. Also, the lattice support  112  for providing rigidity for the mast assembly  100  is illustrated. The top drive  150  is retained by the fixture  151 , which is moveably disposed along the mast assembly  100 . 
       FIG. 9B  is a perspective view of the upper portion of the mast assembly  100  as illustrated in  FIG. 9A-A , showing the top drive  150  and the upper mast fixture  135  of the long lateral completion system with respect to one possible embodiment of the present invention. The pipe arm  300  is shown below the top drive  150 . The pipe clamp  370  enables removable engagement between pipe arm  300 , and a joint of pipe, which said joint of pipe is engaged by the top drive  150 , and alternately one or more clamps or similar means of engagement along the mast assembly  100 , or other engagement systems associated with the mast assembly  100  and/or the top drive  150 , can be used to assist with the transfer of the joint of pipe from the pipe arm  300  to the top drive  150 . 
       FIG. 9C-C  is a sectional view of  FIG. 9  illustrating the relationship of the blowout preventer and snubbing stack  900  with respect to the completion system  10  of one possible embodiment of the present invention. The blowout preventer and snubbing stack  900  is shown directly underneath the mast assembly  100 , and thus directly adjacent to the rig carrier, such that the hydraulic pipe tong  170  can be operatively associated with joints of pipe added to or removed from a string within the wellbore. The mast assembly  100  can be secured using the adjustable braces  612  attached to the base plate  120 . As another example, mast top drive guide rails  104 , which guide top drive  150  may be aligned to be essentially parallel to the axis of the bore of BOP, within less than five degrees in one embodiment, or less than three degrees, or less than one degree in another embodiment. Accordingly, top drive threaded connector and/or guide member and/or clamp portion  163  (See  FIG. 4B-B ) is also aligned to move up and down mast  100  essentially parallel or coaxial to the axis of the bore of BOP, within less than five degrees in one embodiment, or less than three degrees, or less than one degree in another embodiment. The blowout preventer and/or other pressure equipment may comprise pipe clamps and seals to clamp and/or seal around pipe as is well known in the art. As discussed hereinafter, a snubbing jack may comprise additional clamps and hydraulic arms for moving pipe into and out of a well under pressure, which is especially important when the pipe string in the hole weighs less than the force of the well pressure acting on the pipe, which would otherwise cause the pipe to be blown out of the well. 
     Specifically, the blowout preventer of the BOP and snubbing stack  900  is shown having a first set of rams  1012  positioned beneath a second set of rams  1014 , the rams  1012 ,  1014  usable to shear and/or close about a tubular string, and/or to close the wellbore below, such as during emergent situations (e.g., blowouts or other instances of increased pressure in the wellbore). Above the first and second set of rams  1012 ,  1014 , a snubbing assembly can be positioned, which is shown including a lower ram assembly  1016  positioned above the rams  1014 , a spool  1018  positioned above the lower ram assembly  1014 , an upper ram assembly  1020  positioned above the spool  1018 , and an annular blowout preventer  1022  positioned above the upper ram assembly  1018 . In an embodiment, the upper and lower ram assemblies  1020 ,  1016  and/or the annular blowout preventer  1022  can be actuated using hydraulic power from the mobile rig, while the first and second set of rams  1012 ,  1014  of the blowout preventer can be actuated via a separate hydraulic power source. In further embodiments, multiple controllers for actuating any of the rams  1012 ,  1014 ,  1016 ,  1018  and/or the annular blowout preventer  1022  can be provided, such as a first controller disposed on the blowout preventer and/or snubbing assembly and a second controller disposed at a remote location (e.g., elsewhere on the mobile rig and/or in a control cabin). During snubbing operations, the upper and lower ram assemblies  1020 ,  1016  and/or the annular blowout preventer  1022  can be used to prevent upward movement of tubular strings and joints, while during non-snubbing operations, the upper and lower ram assemblies  1020 ,  1016  and annular blowout preventer  1022  can permit unimpeded upward and downward movement of tubular strings and joints. Typically, the annular blowout preventer  1022  can be used to limit or eliminate upward movement of tubular strings and/or joints caused by pressure in the wellbore, though if the annular blowout preventer  1022  fails or becomes damaged, or under non-ideal or extremely volatile circumstances, the upper and lower ram assemblies  1020 ,  1016  can be used, e.g., in alternating fashion, to prevent upward movement of tubulars. As such, the depicted snubbing assembly (the ram assemblies  1020 ,  1018  and annular blowout preventer  1022 ) can remain in place, above the blowout preventer, such that snubbing operations can be performed at any time, as immediately as necessary, without requiring rental and installation of third party snubbing equipment, which can be limited by equipment availability, cost, etc. In an embodiment, the upper and lower ram assemblies  1020 ,  1018  can be used as stripping blowout preventers during snubbing operations. Additionally, while the figures depict a single ram-type blowout preventer in the BOP and snubbing stack  900  having two sets of rams  1012 ,  1014 , in various embodiments, additional blowout preventers could be used as safety blowout preventers, which can include pipe blowout preventers, blind blowout preventers, or combinations thereof. 
     Due to the clearance provided in the recessed region defined by the Y-base  132  and support section  130 , the snubbing assembly can remain in place continuously, beneath the vertical mast, without interfering with operations and/or undesirably contacting the top drive or other portions of the mobile rig. Further, the clearance provided in the recessed region can enable a compact snubbing unit (e.g., snubbing jacks and/or jaws) to be positioned above the annular blowout preventer  1022 , such as the embodiment of the compact snubbing unit  800 , described below, and depicted in  FIGS. 11A through 11D . 
       FIG. 9C-C  also shows a first hydraulic jack  1024 A positioned at the lower end of the Y-base  132 , on a first side of the rig, and a second hydraulic jack  1024 B positioned at the lower end of the Y-base  132 , on a second side of the rig. The hydraulic jacks  1024 A,  1024 B are usable to raise and/or lower a respective side of the rig to provide the rig with a generally horizontal orientation. For example, while  FIG. 1  depicts an embodiment the long lateral completion system  10  having a mast assembly  100  and a pipe handling system (e.g., skid  200 , system  300 , and tubs  400 ) positioned at ground level, each component having a lower surface contacting the upper surface of the well (e.g., the earth&#39;s surface), the hydraulic jacks  1024 A,  1024 B can be used to maintain a ground level rig in an operable, horizontal orientation, independent of the grade of the surface upon which the rig is operated. 
       FIG. 10A  and  FIG. 10B  provide an illustration of one possible embodiment for mounting pipe tong  170  utilizing the pipe tong fixture  172  to support pipe tong  170  at a desired vertical distance in mast  100  from BOPs, such as the blowout preventer  900  shown in  FIG. 9C-C , and with respect to a co-axial orientation with respect to the bore of the BOPs. Pipe tongs  170  may be moved in/out and up/down. The pipe tong fixture comprises one or more pipe tong vertical support rails  176 , two pipe tong horizontal movement hydraulic actuators  178  in association with a horizontal pipe support  174  for displacing the pipe tong  170 . It will be appreciated that fewer or more than two pipe tong horizontal movement hydraulic actuators  178  could be utilized. In this embodiment, horizontal support  174  may comprise telescoping and/or sliding portions, which engagingly slide with respect to each other, namely square outer tubular component  175  and square inner tubular component  177 , which move slidingly and/or telescopingly with respect to each other. In this embodiment, components  175  and  177  are concentrically mounted with respect to each other for strength but this does not have to be the case. Accordingly, pipe tong  170  is moved slidingly or telescopically horizontally back and forth as shown by comparison of  FIGS. 10A and 10B . In  FIG. 10A , pipe tong  170  is shown in a first horizontal position moved laterally away from pipe tong vertical support rails  176 . In  FIG. 10B , pipe tong  170  is shown in a second horizontal position moved laterally or horizontally toward pipe tong vertical support rails  176 . In this way, pipe tong  170  can be moved in the desired direction to position pipe tong  170  concentrically around the pipe from the bore through BOP  900 . It will be noted that here as elsewhere in this specification, terms such as horizontal, vertical, and the like are relevant only in the sense that they are shown this way in the drawings and that for other purposes, e.g. transportation purposes as shown in  FIG. 4  with the rig collapsed and hydraulic tongs oriented vertically as compared to their normal horizontal operation, hydraulic actuators  178  would then move pipe tong  170  vertically. It will also be understood that multiple tongs may be utilized on such mountings, if desired, in other embodiments of the invention, e.g. where a rotary drilling rig were utilized with the pipe tong mounting on a moveable carrier. If desired, additional centering means may be utilized to move pipe tong horizontally between vertical supports  176  to provide positioning in three dimensions 
       FIG. 10B  is a perspective view of the pipe tong fixture  172  as illustrated in  FIG. 10A  of the blowout preventer with respect to the completion system of one possible embodiment of the present invention whereby pipe tong  170  is moved vertically downwardly along pipe tong vertical support rails  176 . Vertical sliding supports  179  permit pipe tong frame  181 , which comprise various struts and the like, to be moved upwardly and downwardly. Extensions  183  may be utilized in mounting support rails  176  to mast  100  and/or may be utilized with clamps associated with vertical sliding supports  179  for affixing pipe tong frame  181  to a particular vertical position. Pipe tong frame  181  may be lifted utilizing lifting lines within mast  100  and/or by connection with the blocks and/or top drive  150  and/or by hydraulic actuators (not shown). 
       FIG. 11A ,  FIG. 11B ,  FIG. 11C , and  FIG. 11D  illustrate one possible embodiment for a compact snubbing unit  800 , usable with the completion system  10  of the present disclosure, e.g., by securing the snubbing unit  800  above the blowout preventer and snubbing stack  900  (shown in  FIG. 9 ). However, snubbing unit  800  is simply shown as an example of a snubbing jack and other types of snubbing jacks may be utilized in accord with the present invention. Generally, a snubbing jack will have a movable gripper, which may be mounted on a plate that is movable with respect to a stationary gripper. At least one gripper will hold the pipe at all times. The grippers are alternately released and engaged to move pipe into and out of the wellbore under pressure. If not for this type of arrangement, when the string is lighter than the force applied by the well, the string would shoot uncontrollably out of the well. When the string is lighter than the force applied by the well, this example of snubbing jack  800  can be utilized to move pipe into or out of the well in a highly controlled manner, as is known by those of skill in the art. In another embodiment, an additional set of pulleys (not shown) might be utilized to pull top drive downwardly (while the existing cables remain in tension but slip at the desired tension to prevent the cables from swarming). Once the pipe is heavier than the force of the well, then the normal operation of top drive may be utilized for insertion and removal of pipe so long as the pipe string is preferably significantly heavier than the force acting on the pipe string. In this example, the grippers of snubbing jack  800  also provide a back up in case of a sudden increase in pressure in the well. The compact (but extendable) snubbing unit  800  can be sized to fit within the recessed region of the mast assembly  100 , to prevent undesired contact with the mast assembly  100  even when the snubbing jack is in an extended position. In this example, the depicted snubbing unit  800  includes a first horizontally disposed plate member  802 , which is a vertically moveable plate, and a second horizontally disposed plate member  804 , which is a fixed plate with respect to the wellhead, displaced by vertical columns or stanchions  806  and  808 . The lower and/or possibly upper portion of columns or stanchions  806  and  808  may comprise hydraulic jacks members which can be utilized for hydraulically moving plate member  802  upwardly and downwardly with respect to plate member  804  and may be referred to herein as hydraulic jacks  806  and  808 . Also, in this example, between the first member  802  and the second member  804  is an intermediate member  803 . In this example, between the first member  802  and the intermediate member  803  is a first engaging mechanism  820  for engaging and/or clamping and/or advancing or withdrawing pipe. Between the intermediate member  803  and the second member  804  is a second engaging mechanism  830  for engaging and advancing, or withdrawing pipe. In one embodiment, both plates  802  and  803  are vertically moveable with respect to plate  804  whereby both clamps (i.e., engaging mechanisms)  820  and  830  are used at the same time. Accordingly, in one embodiment, both plates  802  and  803  move together. In another embodiment, grippers (i.e., engaging mechanisms)  820  and  830  may be moveable with respect to each other. In one possible mode of operation, the clamping mechanisms  820 ,  830  can be used to grip a joint of pipe and exert a downhole force or upward force thereto, counteracting a force applied to the string due to pressure in the wellbore. Because the force of the snubbing jack unit  800  is selected to exceed the pressure from the wellbore, joints can be added or removed from a completion string even under adverse, high pressure conditions. The BOPs or other control equipment, positioned below the snubbing jack  800 , can seal around the pipe as it is moved into and out of the wellbore by snubbing jack  800 . Thus, grippers  820  and  830  may be engaged and hydraulic jacks within stanchions  806  and  808  may be expanded to remove pipe from the well or force pipe into the well. The hydraulic jacks may be contracted to move pipe into the well or pull pipe out of the well in a controlled manner. Other grippers within the BOPs may be utilized to hold the pipe, when grippers  820  and  830  are released and moveable plates  802  and/or  803  are moved to a new position for grasping the pipe to move the pipe into or out of the borehole as is known to those of skill in the art. In one embodiment of the present invention, the computer control of the control van is utilized to control the grippers  820 ,  830 , and the hydraulic jacks  806  and  808 , and other grippers and seals in the BOPs to provide automated movement of the pipe into or out of the wellbore. This movement may be coordinated with that of the top drive and tongs for adding pipe or removing pipe. Thus, the entire process or portions of the process of going into the hole with snubbing units may be automated. However, it will be understood that at least two separate grippers or sets of grippers are required for a snubbing unit. If the top drive is connected to be able to apply a downward force then another stationary set of grippers is required. In addition, multiple sealing mechanisms such as rams, inflatable seals, grease injectors, and the like, may be utilized to open and close around sections of pipes so that larger joints and the like may be moved past the sealing mechanisms in a manner where at least one seal or set of seals is always sealed around the pipe string in a manner than allows sliding movement of the pipe string. The control system of the present invention is programmed to operate the entire system in a coordinated manner. In addition to or in lieu of the snubbing unit  800  and/or the snubbing assembly depicted and described above, various embodiments of the present system can include a full-sized snubbing unit, e.g., similar to a rig assist unit. 
       FIG. 12A  depicts a schematic view of an embodiment of a control cabin  702  of the long lateral completion system  10  with respect to the present disclosure. The control cabin  702  comprises a command station  710 . The command station  710  comprises a seat  712 , control  714 , monitor  716  and related control devices. Further, the control cabin  702  provides for a second seat  715  in association with a monitor, and, optionally, a structure for supporting other related monitoring and/or control activities  722 ,  724 , and a third seat  718  in association with yet another monitor. The control cabin  702  has doors for exiting the cabin area and accessing a walkway  720  disposed around the perimeter of the control cabin  702 . 
     In one embodiment, command station  710  is positioned so that once control van  700  is oriented or positioned with respect to mast  100  (See  FIG. 1 ), carrier  600 , catwalk and pipe handling assembly  300 , and/or pump/pit  500 , then all mast operations can be observed through command station front windows  730  as well as command station top windows  732 . Front windows  730 , for example, allow a close view of rig operations at the rig floor. Top windows  732  allow a view all the way to the top of mast  100 . In one embodiment, additional command station side and rear windows  740 , side windows  742  (depicted in  FIG. 12C ),  744  (depicted in  FIG. 12D ) will allow easy observation of other actions around mast  100 . If desired, control van  700  may be positioned as shown in  FIG. 1  and/or adjacent pump/pit combination skid  500 . If desired, additional cameras may be positioned around the rig to allow direct observation of other components of the rig, e.g., pump/pit return line flow or the like. 
     The control van  700  may include a scissor lift mechanism to lift and adjust the yaw of command station  710 . A scissor lift mechanism is a device used to extend or position a platform by mechanical means. The term “scissor” is derived from the mechanism used, which is configured with linked, folding supports in a crisscrossed “X” pattern. An extension motion or displacement motion is achieved by applying a force to one of the supports resulting in an elongation of the crossing pattern supports. Typically, the force applied to extend the scissor mechanism is hydraulic, pneumatic or mechanical. The force can be applied by various mechanisms such as by way of example and without limitation a lead screw, a rack and pinion system, etc. 
     For example with loading applied at the bottom, it is readily determined that the force required to lift a scissor mechanism is equal to the sum of the weights of the payload, its support, and the scissor arms themselves divided by twice the tangent of the angle between the scissor arms and the horizontal. This relationship applies to a scissor lift mechanism that has straight, equal-length arms, i.e., the distance from an actuator point to the scissors-joint is the same as the distance from that scissor-joint to the top load platform attachment. The actuator point can be, by way of examples, a horizontal-jack-screw attachment point, a horizontal hydraulic-ram attachment point or the like. For loading applied at the bottom, the equation would be F=(W+Wa)/2 Tan Φ. The terms are F=the force provided by the hydraulic ram or jack-screw, W=the combined weights of the payload and the load platform, Wa=the combined weight of the two scissor arms themselves, and is the angle between the scissor arm and the horizontal. 
     And for loading applied at the center pin of the crisscross pattern, the equation would be F=W+(Wa/2)/Tan Φ. The terms are F=the force provided by the hydraulic ram or jack-screw, W=the combined weights of the payload and the load platform, Wa=the combined weight of the two scissor arms themselves, and is the angle between the scissor arm and the horizontal. 
       FIG. 12B  is an elevation view of the control cabin  702  of the completion system  10  of one possible embodiment of the present invention. The command station  710  the walkway  720  and exterior controls  726 . 
       FIG. 12C  is an end view of the control cabin  702  of the completion system  10  of one possible embodiment of the present invention.  FIG. 12C  illustrates the command station  710  in association with the control cabin  702 . The walkway  720  is also illustrated. 
       FIG. 12D  is an end view of the control cabin  702  taken from the alternate perspective as that of  FIG. 12C  of the completion system of one possible embodiment of the present invention. The outer controls  726  are illustrated. 
       FIG. 13  is an illustration of the carrier  600  adapted for use with the completion system  10  of one possible embodiment of the present invention. The carrier comprises a cabin  605 , a power plant  650 , and a deck  610 . Foldable walkway  602  folds up for transportation and then when unfolded extends the walkway space laterally to the side of carrier  600 . Winch assembly  620  can be mounted along slot  622  at a desired axial position at any desired axial position along the length of carrier  600 . Winch or drawworks assembly  620  may or may not be mounted to a mounting such as mounting  624 , which is securable to slot  620 . Mounting  624  may be utilized for mounting an electrical power generator or other desired equipment. Recess  626  may be utilized to support mast positioning hydraulic actuators  630 , which are not shown in  FIG. 13 . One or more stanchions  614  (e.g., a Y-base) are illustrated for engaging the mast assembly  100  with the carrier  600 , wherein the mast can be supported by carrier to mast pivot connection  634  and at the carrier  600  rearmost position by mast support plate  363  (also shown in  FIG. 4  as  636 ). 
       FIG. 14  is an illustration of the catwalk-pipe arm assembly  300  of the completion system  10  of one possible embodiment of the present invention. The catwalk-pipe arm assembly  300  is illustrated with a ground skid  310 , pipe arm hydraulic actuators  304  for lifting the pivotal pipe arm  320  and the kickout arm  360  attached thereto. The kickout arm  360  can subsequently be extended the central pipe arm  320  using additional hydraulic cylinders disposed therebetween. 
     In yet another embodiment, a pivotal clamp could be utilized at  312  in place of the entire kick arm  360  whereby orientation of the pipe for connection with top drive  150  may utilize upper mast fixture  135  and/or mast mounted grippers and/or guide elements. 
     In one embodiment, catwalk  302  may be provided in two elongate catwalk sections  309  and  311  on either side of pivotal pipe arm  320  for guiding pipe to and/or away from pivotal pipe arm  320 . However, only one elongate section  309  or  311  might be utilized. Catwalk  302  provides a walkway and a catwalk is often part of a rig, along with a V-door, for lifting pipes using a cat line. To the extent desired, catwalk  302  may continue provide this typical function although in one possible embodiment of the present invention, pivotal pipe arm  320  is now preferably utilized, perhaps or perhaps not exclusively, for the insertion and removal of tubing from the wellbore. 
     In one possible embodiment of catwalk  302 , each catwalk section  309  and  311  may comprise multiple catwalk pipe moving elements  314  which move the pipes toward or away from pivotal pipe arm  320  and otherwise are in a stowed position, resulting in a relatively smooth catwalk walkway. Referring to  FIG. 15F  and F 15 G,  FIG. 21A , and  FIG. 21B , catwalk pipe moving hydraulic controls  333  may be utilized to independently tilt catwalk pipe moving elements  314  upwardly or downwardly, as indicated. On the left of  FIG. 15F , catwalk pipe moving element  314  is in the stowed position flat with catwalk  309 . On the right of  FIG. 15F , catwalk pipe moving element  314  is tilted inwardly to urge pipes toward pivotal pipe arm  320 . In  FIG. 15G , catwalk pipe moving elements are both tilted away from pipe moving element  314  to urge pipes away from pivotal pipe arm  320 . However, each group of catwalk pipe moving elements  314  on each of catwalks  309  and  311  operate independently. In one embodiment, by tilting pipe moving elements  314  away from pivotal pipe arm  320 , the pipe moving elements  314  operate in synchronized fashion with pipe ejector direction control which directs pipe away from pipe arm  320  in a desired direction as indicated by arrows  377 A and  377 B (see  FIG. 17 ), as discussed hereinafter. 
     In another embodiment, each entire elongate catwalk section  309  and  311  could be pivotally mounted on skid edges  301  and  307 . Accordingly, due to the pivotal mounting discussed previously or in accord with this alternate embodiment, catwalk sections  309  may be selectively utilized to urge pipes toward or away from pivotal pipe arm  320 . However, in yet another embodiment the catwalks may also be fixed structures so as to either slope towards or away from pivotal arm  320  or may simply be relatively flat. 
     In yet another embodiment, at least one side of catwalk  302  (catwalk sections  309  and/or  311 ) may be slightly sloped inwardly or downwardly toward pivotal pipe arm  320  to urge pipe toward guide pipe for engagement with pivotal pipe arm  320 . In one embodiment, pipe tubs  400  and/or one or both sides of catwalk  302  (and/or catwalk pipe moving elements  314 ) include means for automatically feeding pipes onto catwalk  302  for insertion into the wellbore, which operation may be synchronized for feeding pipe to or ejecting pipe from pivotal pipe arm  320 . In another embodiment, at least one side of catwalk  302  and/or catwalk pipe moving elements  314 , may also be slightly sloped slightly downwardly towards at least one of pipe tubs  400  to urge pipes toward the respective pipe tub when pipe is removed from the well. In one embodiment, one pipe tub may be utilized for receiving pipe while another is used for feeding pipe. In another embodiment, catwalk  302  may simply provide a surface with elements (not shown) built thereon for urging the pipe to or from the desired pipe tub  400 . 
     In yet another embodiment, catwalk  302 , which may or may not be pivotally mounted and/or comprise catwalk pipe moving elements  314 , may be provided as part of the pipe tub and may not be integral or built onto the same skid as pivotal pipe arm  320 . In yet another embodiment, the pipes may be manually fed to and from the pipe tubs or pipe racks to pivotal pipe arm  320  via catwalk  302 . 
       FIG. 14A  is a blowup view of the lower pipe arm pivot connection  313  upon which the pivotal pipe arm  320  is lifted for the catwalk-pipe arm assembly  300 . The lower pipe arm pivot connection  313  comprises a bearing  306  and a shaft or pin  308  which provides a pivot point for the pivotal pipe arm  320  with respect to the pipe arm ground skid  310 . 
       FIG. 15A  is an elevation view of the catwalk-pipe arm assembly  300  of the completion system  10  of one possible embodiment of the present invention. The catwalk-pipe arm assembly  300  comprises the central arm  320 , a kickout arm  360  and one or more clamps  370 A,  370 B,  370 C for engaging a pipe “P.” The catwalk-pipe arm assembly  300  is rotationally moved or pivoted with respect to lower pipe arm pivot connection  313  using the hydraulic actuators  304 . In this embodiment, pivotal pipe arm  320  comprises a grid comprising plurality of pipe arm struts  364 . 
       FIG. 15B  is an enlarged or detailed view of the section “B” of pivot connection  313  as illustrated in  FIG. 15A  of the completion system of one possible embodiment of the present invention. The pivotal pipe arm  320  is pivotally moved using a bearing  306  in association with a shaft or pin  308 . Control arm  315 , to which pivot arm struts  317  (See also  FIG. 15A ) are affixed, pivots about lower pipe arm pivot connection  313 . 
       FIG. 15C  is an enlarged or detailed view of section “C” illustrated in  FIG. 15A  of the completion system of one possible embodiment of the present invention, which shows control arm to hydraulic arm pivot connection  319 . Piston  323  of the hydraulic cylinder of hydraulic actuator  304  is pivotally engaged with control arm  315  using the pin  327 . 
       FIG. 15D  is an enlarged or detailed view of the section indicated by “D” in  FIG. 15A  of the completion system of one possible embodiment of the present invention, which shows the hydraulic cylinder of hydraulic actuator  304  pivotal connection  329 .  FIG. 15D  shows the engagement of the hydraulic cylinder with the skid using the pin  331 . 
       FIG. 15E  is a plan view of the catwalk-pipe arm assembly  300  of the completion system  10  of one possible embodiment of the present invention. The catwalk-pipe arm assembly  300  comprises the pivotal pipe arm  320  in association with the skid  310 . The arm has engaged with it a kickout arm  360  which is pivotally moved with the hydraulic actuator  362 . The pivotal pipe arm  320  is pivotally moved with the hydraulic actuator  304 . The kickout arm has clamps  370 A,  370 B for engaging a piece of pipe “P.” 
       FIG. 16A  is an elevation view of the pivotal pipe arm  320  of the completion system  10  of one possible embodiment of the present invention, without the catwalk  302  for easier viewing. Pivotal pipe arm  320  comprises an elongate lower pipe arm section  322  which is pivoted using the hydraulic actuators  304 . Lower pipe arm section  322  is secured to y-joint connector  324 , which in turn connects to pivot arm Y arm strut components  326 A and  326 B (depicted in  FIG. 16B ). The Y arm strut components  326 A and  326 B are connected to control arms  315 , which are in moveable engagement with the hydraulic actuators  304 . An extension (not shown) may be utilized to engage upper mast fixture  135 , if desired, to provide a preset starting position from which kickout arm  360  pivots outwardly to align with the top drive  150 . 
     The elongate kickout arm  360  secures a piece of pipe “P” using a plurality of pipe clamps  370 , which are labeled  370 A and  370 B at the bottom and top (when upright) of kickout arm  360 . Pipe ejector direction control  371  acts to eject the pipe from pivotal arm  320  in a desired direction when the pipe is laid down adjacent catwalk  302 , as discussed hereinafter. 
       FIG. 16B  is a plan view of the pivotal pipe arm  320 , as illustrated in  FIG. 16A  for the completion system  10  of one possible embodiment of the present invention, showing only the pipe arm components for convenience. In one possible embodiment, upper pipe arm section  340  may also incorporate kickout arm  360 . In this embodiment, kickout arm  360  remains generally parallel to pivotal pipe arm  320  except when pivotal pipe arm  320  is moved into the upright position shown in  FIG. 7 ,  FIG. 8 , and  FIG. 9 . Upon reaching the upright position, kickout arm  360  is pivoted using the hydraulic actuators  362 , which cause kickout arm  360  to pivot away from pipe arm  360  about kickout arm pivot connection  312  ( FIG. 16C ) at the top of pivotal pipe arm  320 . The kickout arm  360  is shown with the clamps  370 A and  370 B at the bottom and top (when vertically raised) of kickout arm  360  as well as pipe ejector direction control  371 , which may be positioned more centrally, if desired. 
       FIG. 16C  is an enlarged or detailed view of the section “C” as illustrated in  FIG. 16A  for the completion system  10  of one possible embodiment of the present invention, which shows kick arm pivot connection  312  ( FIG. 16C ) at the top of pivotal pipe arm  360 .  FIG. 16C  shows the pivotal pipe arm  320  in association with an upper portion of kickout arm  360  (when vertically raised) and the clamp  370 B. 
       FIG. 16D  is an end view of the pivotal pipe arm  320  and kickout arm  360  of the completion system  10  of one possible embodiment of the present invention for the completion system  10 , which shows an end view kickout arm pivot connection  312  ( FIG. 16C ) at the top of pivotal pipe arm  360   320  and clamp  370 B. Pivot beam  366  connects pipe kickout arm  360  to the top of pivotal pipe arm  320 . Kickout arm base  375  may comprise a rectangular cross-section in this embodiment. The pipe is received into pipe reception groove  378 . 
       FIG. 17  is a perspective view of a portion of the kickout arm  360  of the completion system  10  of in accord with one possible embodiment of the present invention. The kickout arm  360  is illustrated with the components attached to a kick out arm base  375 , which in this embodiment may have a relatively rectangular or square profile. The kick out arm base  375  is used for supporting one possible embodiment of the pipe clamps  370 A and  370 B (See also  FIG. 18A ) and pipe ejector directional control  371 . Torsional arms  372 , which are also referred to as torsional arms  372 A and  372 B, are utilized to selectively activate eject arms  374 A and  374 B. The eject arms  374 A connect to torsional arms  372 A. The eject arms  374 B connect to torsional arms  372 B, respectively. When torsional arms  372 A are rotated utilizing hydraulic actuator  382 A, which rotates plates  384 A, (see  FIG. 17A  and  FIG. 18  C-C), then eject arms  374 A will lift the pipe to eject the pipe from kickout arm  360  in the direction shown by pipe ejection direction arrow  377 A to the pipe tub or the like. Similarly, when torsional arms  372 B are rotated, then eject arms  374 B eject the pipe in the direction indicated by pipe ejection direction arrow  377 B to the other side. Prior to ejection or clamping, the pipe will align with the pipe reception grooves  378  in the clamps  370  and ejector mechanism  380 . Plates  375  comprise a relatively square receptacle  385  (see  FIG. 17A ) that mates to kick out arm base  375  for secure mounting to resist torsional forces created during pipe ejection and/or pipe clamping. 
       FIG. 17A  and  FIG. 18C-C  provide an enlarged or detailed view of the pipe ejector direction control  371  illustrated in  FIG. 17  for the completion system of one possible embodiment of the present invention. The pipe ejector direction control  371  is illustrated using the plates  376 , which may be connected by a bracket  386 , in association with the torsional ejection rods  372 A and  372 B. The ejection mechanisms  380 A and  380 B (see  FIG. 18  C-C) are between the plates  376  and provides for rotational movement of the torsional ejection rods  372 A and  372 B. Ejection mechanism  380 A operates to eject pipe as indicated by pipe ejection direction arrow  377 A (see  FIG. 17 ). Ejection mechanism  380 B operates to eject pipe in the direction indicated by arrow  377 B. The pipe reception groove  378  is for accepting the joint of pipe during clamping or prior to ejection. In this embodiment, ejector hydraulic actuators  382 A and  382 B are pivotally connected to pivotal plates  384 A and  384 B, respectively, which are fastened to respective torsional ejection rods  372 A and  372 B for selectively ejecting the pipe from kickout arm  360  in the desired direction as indicated by pipe ejection arrows  377 A and  377 B. As shown in  FIG. 17 , torsional ejection rods  372 A and  372 B are rotationally mounted to plates on clamps  370 A and  370 B for support at the ends thereof. 
     Referring to  FIG. 17 ,  FIG. 18C ,  FIG. 21A , and  FIG. 21B , clamps  370 A and  370 B are similar and in this embodiment each comprises two sets of clamping members, lower clamp set  387 A,B and upper clamp set  389  A,B. Each clamp set is activated by respective pairs of clamp hydraulic actuators, such as  392 A and  392 B, perhaps best shown in  FIG. 18A . In this embodiment, after the pipe is rolled into the pipe reception grooves, then the clamp sets  387 A,  389 A and  387 B,  389 B are pivotally mounted on clamp arms  394 A and  394 B to rotate upwardly around pivot connections to clamp the pipes. When not in use clamp sets  387 A,  389 A and  387 B,  389 B are rotated downwardly to be out of the way (as shown in  FIGS. 17 and 21A ) as the pipes are rolled into the pipe reception grooves  378 . 
     It will be appreciated that other types of clamps, arms, ejection mechanisms and the like may be hydraulically operated to clamp and/or eject the pipe onto or away from kickout arm  360 . 
       FIG. 18A  is an elevation view of the kickout arm  360  of the completion system  10  in accord with one possible embodiment of the present invention. The kickout arm  360  is shown with the lower and upper pipe clamps  370 A and  370 B, pipe ejector direction control  371 , base  375  with torsional ejection rod  372 A (depicted in  FIG. 18B ), ejector hydraulic actuator  382 A, and pipe clamp hydraulic actuators  392 A. 
       FIG. 18B  is a bottom view of the kickout arm  360  as illustrated in  FIG. 18A  for the completion system of one possible embodiment of the present invention.  FIG. 18B  illustrates the base  375  in association with the torsional ejection rods  372 A and  372 B, which in this embodiment are rotationally secured to each of clamps  370 A and  370 B as well as to pipe ejector direction control  371 . The clamps  370 A and  370 B are dispersed at the remote ends of the kickout arm  360 . There may be fewer or more clamps, as desired. 
       FIG. 18C  is a top view of the kickout arm  360  of the completion system  10  of the present invention. The kickout arm  360  is illustrated with the clamps  370 A and  370 B secured with the base  375  and operatively associated with the torsional ejection rods  372 A and  372 B. 
       FIG. 18B-B  is a sectional view  FIG. 18B  for the completion system of one possible embodiment of the present invention. The end  390  is illustrated is with kick arm pivot connection  312  at the top (when pivotal pipe arm is upright) of pivotal pipe arm  320 . 
       FIG. 18C-C  is a cross section of  FIG. 18C  illustrating pipe ejector direction control  371 . The ejector mechanism  380 A and  380 B comprise ejector hydraulic actuators  382 A,  382 B and pivotally mounted ejection control arms  384 A and  384 B, which rotate torsional ejection rods  372 A, and  372 B in one possible embodiment of the present invention. 
       FIG. 19A  is an elevation view of the top drive fixture  151 , without the top drive mechanism  160 , used in conjunction with the mast assembly  100  of the completion system  10  of one possible embodiment of the present invention. The top drive fixture  151  is shown with the guide frame  152 , separated designated as  152 A,  152 B. Guide frames  152 A,  152 B are connected at top drive fixture flanges  141 A,  141 B to extensions  143 A,  143 B downwardly projecting from side plates  156 A,  156 B of a traveling block frame  154 . Traveling block fixture  154  is part of a traveling block assembly  153  comprising frame  154  and a cluster of sheaves  155 A,  155 B,  155 C,  155 D supported in such frame. Guide frames  152 A,  152 B slidingly engage mast top drive guide rails  104 , as discussed hereinbefore. 
       FIG. 19B  is a side view of the top drive fixture  151  and frame  154  of the traveling block assembly  153  illustrated in  FIG. 19A .  FIG. 19B  illustrates the guide frame  152 B in relation to the traveling block frame  154 B using the block side plate  156 B. 
       FIG. 19C-C  is a cross sectional view taken along the section line C-C in  FIG. 19B  illustrating the mechanism associated with the top drive fixture  151  of the completion system of one possible embodiment of the present invention. The mechanism provides for the slide supports  152  having at its extremities a first and second rollers  158 A,  158 B on a respective roller axles  159 A,  159 B of guide frame  152 B, which may be utilized to provide a rolling interaction with mast top drive guide rails  104  maintaining the top drive in a relatively fixed vertical position.  FIG. 19C-C  also depicts flange  141 B connected to extension  143 B. 
       FIG. 19D  is an enlarged or detailed view of the roller  158 A as illustrated in  FIG. 19B . 
       FIG. 19E-E  is a cross sectional view taken along the section line E-E in  FIG. 19A .  19 E-E is in the same orientation as  FIG. 19B , but is sectional. Referring to  FIGS. 19A, 19B and 19E -E, traveling block frame  154  further comprises a front plate  144 A, a rear plate  144 B (depicted in  FIG. 19B ), and side plates  156 A,  156 B including the downwardly projecting extensions  143 A,  143 B. A frame cross member spans side plates  156 A,  156 B above traveling block sheaves  155 A,  155 B,  155 C,  155 D sufficiently within parallel planes tangent to peripheries of flanges of such sheaves that a drilling line reeved around the sheaves as described below does not contact cross member. Cross member mounts inferiorly a plurality of rigid spaced apart parallel hangers  146 A,  146 B,  146 C,  146 D and  146 E (depicted in  FIG. 19A ), each in a plane perpendicular to an axis of front sheaves of a crown block assembly described below. Hangers  146 A,  146 B support between them an axle  147 A for traveling block sheave  155 A; hangers  146 B,  146 C support between them an axle  147 B for traveling block sheave  155 B; hangers  146 C,  146 D support between them an axle  147 C for traveling block sheave  155 C; and hangers  146 D,  146 E support between them an axle  147 D for traveling block sheave  155 D. Each sheave axle  147 A,  147 B,  147 C and  147 D is parallel to the plane of the axis of the front sheaves of the crown block assembly. Traveling block sheaves  155 A,  155 B,  155 C,  155 D rotate in traveling block frame respectively on axles  147 A,  147 B,  147 C and  147 D. 
       FIG. 20A  is an illustration of the top drive  150  in the top drive fixture  151  of the completion system of one possible embodiment of the present invention. The top drive comprises the top drive fixture  151  in conjunction with the drive mechanism  160 . The drive mechanism  160  is moveably engaged with the guide frames  152 A,  152 B and moves in a vertical direction using traveling block assembly  153 . A top drive shaft  165  provides rotational movement of the pipe using the drive mechanism  160 . Top drive shaft  165  connects to item  163 , which may comprise a top drive threaded connector and/or pipe connection guide member. Item  163  may also be adapted to hold the pipe. A torque sensor may also be included therein. 
       FIG. 20B  is an upper view of traveling block assembly  153  and top drive  150  as illustrated in  FIG. 20A .  FIG. 20B  illustrates the guide frames  152 A,  152 B with the frame  154  there between. 
     Referring to  FIGS. 19A, 19B, 19E -E,  20 A and  20 B, traveling block sheaves  155  are seen to be horizontally canted in frame  154 . The purpose and angle of this canting and the operation of the traveling block assembly to raise and lower top drive  150  is now explained. 
     Referring now to  FIGS. 4, 7B, 9, 27A, and 27B , carrier  600  pivotally mounts mast  100  on the carrier for rotation upward to an erect drilling position, as has been described. Mast  100  comprises front and rear vertical support members  105 , and a mast top or crown  190  supported atop front and rear vertical support members  105 . Drawworks  620  is mounted on carrier  600  to the rear of an erect mast  100 . Drawworks  620  has a drum  621  with a drum rotation axis perpendicular to the drilling axis for winding and unwinding a drilling line on drum  621 . A crown block assembly  191  is mounted in mast top or crown  190  for engaging the drilling line. The crown block assembly comprises a cluster  193  of front sheaves mounted at the front of mast top  190  facing the drilling axis. This cluster  193  comprises first and second outermost sheaves and at least one inboard sheave, all aligned on an axis in a plane perpendicular to the drilling axis and having a predetermined distance between grooves of adjacent front sheaves. A fast line sheave  194  is mounted on the drawworks side of the mast top behind the first outermost front sheave of cluster  193  and on an axis substantially parallel to the axis of the front sheaves of cluster  193 , for reeving the drilling line to the first outermost front sheave of cluster  193 . A deadline sheave  195  (blocked from view by the front sheaves of cluster  193 ) is mounted on the drawworks side of mast top  190  behind a second laterally outermost front sheave (blocked from view by fast line sheave  194 ) and on an axis substantially parallel to the axis of the front sheaves of cluster  193 , for reeving the drilling line from the second outermost front sheave to an anchorage. 
     Traveling block assembly  153  hangs by the drilling line from the front sheaves of the crown block assembly, and comprising, as has been described, fixture  154  and the cluster of sheaves  155  supported in the fixture. The cluster is one less in number than the number of front sheaves in the crown block assembly and includes at least first and second outermost traveling block sheaves  155 A,  155 D (in the illustrated embodiment there are two traveling block sheaves,  155 B,  155 C inboard of outermost traveling block sheaves  155 A,  155 D. Traveling block sheaves  155 A,  155 B,  155 C,  155 D have a predetermined distance between grooves of adjacent traveling sheaves and rotate on a common horizontal axis in a plane perpendicular to the drilling axis. The axis of the traveling sheaves  155 A,  155 B,  155 C,  155 D is angled in the latter plane relative to the axis of the front sheaves of the crown block assembly such that the drilling line reeves downwardly from the groove in a first front sheave parallel to the drilling axis to engage the groove in a first traveling block sheave and reeves upwardly from the groove in a first traveling block sheave toward the second front sheave next adjacent such first front sheave at an up-going drilling line angle to the drilling axis effective according to the distance between the grooves of the first and second front sheaves to move the drilling line laterally relative to the front sheave axis and engage the groove of the second front sheave, each the traveling block sheaves receiving the drilling line parallel to the drilling axis and reeving the drilling line to each following front sheave at an up-going angle. 
     Accordingly, first outermost traveling block sheave  155 A receives the drilling line reeved downward from the first laterally outermost front sheave of the crown block assembly parallel to the drilling axis and reeves the drilling line at an up-going angle to a next adjacent inboard front sheave. The latter inboard front sheave reeves the drilling line downward to traveling block sheave  155 B next adjacent first laterally outermost traveling block sheave  155 A parallel to the drilling axis. The latter traveling block sheave  155 B reeves the drilling line at an up-going angle to a front sheave next adjacent the front sheave next adjacent the first laterally outermost front sheave, and so forth, for each successive traveling block sheave (respectively sheaves  155 C,  155 D in the illustrated embodiment of  FIGS. 19A, 19B, 19E -E,  20 A and  20 B), until the second outmost traveling block sheave ( 155 D in the illustrated embodiment) reeves the drilling line at an the up-going angle to the second outmost front sheave. The second outmost front sheave reeves the drilling line to the deadline sheave, and the deadline sheave reeves the line to the anchorage. 
     In an embodiment, an up-going angle from a traveling block sheave to a crown block front sheave is not more than about 15 degrees. In an embodiment, an up-going angle from a traveling block sheave to a crown block front sheave is about 12 degrees. 
     In an embodiment, the predetermined distances between grooves of the front sheaves are equal from sheave to sheave. In an embodiment in which the front sheaves comprise a plurality of inboard sheaves, the predetermined distance between at least one pair of inboard front sheaves may be the same or different than the distance separating an outermost front sheave from a next adjacent inboard front sheave. 
       FIG. 20A-A  is a cross sectional view taken along the section line A-A in  FIG. 20A  illustrating the relationship of the drive mechanism  160  in the top drive frame  151 . The guide frames  152  provide structural support for the drive mechanism  160 . 
       FIG. 21A  is a perspective view of the pipe arm assembly with the pipe clamps recessed allowing the pipe arm to receive pipe, as also previously discussed with respect to  FIG. 17 , and  FIG. 18C . In this embodiment, pipe ejector direction control  371  is omitted for clarity of the other elements in the figure. However, in another possible embodiment, the pipe ejector mechanism may not be utilized or may be replaced by other pipe ejector means. Kickout arm  360  is secured to pivotal pipe arm  320  at kickout arm pivot connection  312  located at the top of pivotal pipe arm  320 . Kickout arm hydraulic actuators  362  provide pivotal movement when pipe arm  320  is in an upright position. In this embodiment, pipe clamps  370 A and  370 B are mounted to kickout arm  360 , although in other embodiments pipe clamps  370 A and  370 B can be mounted directly to pivotal pipe arm  320 . Catwalk segments  309  and  311  contain one possible embodiment of catwalk pipe moving elements  314  to urge pipe onto pipe arm  320  which are guided or rolled into pipe reception grooves  378  along pipe guides  379  (See  FIG. 16D ). Pipe clamp sets  387 A,  389 A and  387 B,  389 B are recessed below an outer surface of pipe guides  379  within pipe clamp mechanisms  370 A and  370 B to allow pipe P to be accepted in pipe reception grooves  378 , such as pipe P which is shown in position in the pipe reception grooves. Pipe clamp sets  387 A,  389 A and  387 B,  389 B are mounted to pivotal pipe clamp arms  394 A and  394 B. 
       FIG. 21B  is a perspective view of the pipe arm assembly with the pipe clamps engaged around the pipe, which allows the pipe arm to move the pipe P to an upright position in mast  100 . In this embodiment, pipe clamp  370 A is located at a lower point on kickout arm  360 , while pipe clamp  370 B is located on an upper part of kickout arm  360 . In another embodiment, pipe clamps  370 A and  370 B could be mounted to pipe arm  320 . As discussed hereinbefore, pipe clamp sets  387 A,  389 A and  387 B,  389 B are mounted to pivotal pipe clamp arms  394 A and  394 B. In this embodiment, once pipe P is urged into pipe receptacle grooves  378  by catwalk moving elements  314  on either catwalk section  309  or  311 , pipe clamp hydraulic actuators  392 A and  392 B (See  FIG. 18C ) urge pipe clamp sets  387 A,  389 A and  387 B,  389 B around clamp pivots  391 A and  391 B to engage pipe P. 
       FIG. 22A  is a perspective end view of one possible embodiment of walkway  309  and  311  with one possible example moving elements, illustrating how pipe is moved from the walkway to the pipe arm. In  FIG. 22A , catwalk segment  311  contains catwalk pipe moving elements  314  in a sloped position for urging pipe P into pipe clamp mechanisms  370 A and  370 B utilizing pipe reception grooves  378 . In another embodiment, catwalk pipe moving elements  314  can move into a second sloped position for moving pipe away from kickout arm  360  towards a pipe tub. In this embodiment, corresponding pipe moving element hydraulic controls  333  can be utilized for selectively operating pipe moving elements  314  on catwalk segments  309  and  311 (See  FIG. 15F ). For example, the moving elements can be retracted below the surface of walkway  311  or raised to provide a gradual slope that urges the pipes into pipe reception grooves  378 . 
     In one possible embodiment, pipe barrier posts  316  may be utilized to prevent additional pipes from entering catwalk segment  311  while pipe is being moved with pipe moving elements  314  towards pipe clamp mechanisms  370 A and  370 B located on kickout arm  360 . Pipe barrier posts  316  may keep the pipe outside of the catwalk segment  311  after pipe moving elements  314  are lowered, whereby an operator may walk along the catwalk without impediments and/or utilize the catwalk for other purposes such as making up tools or the like. Catwalk segment  309  illustrates pipe moving elements  314  in a flat position flush with the surface of catwalk segment  309 . In one possible embodiment, pipe barrier posts  316  may be hydraulically raised and lowered. In another embodiment pipe barrier posts  316  may mechanically inserted, removed, or replaced (such as with sockets in the catwalk). In another embodiment, pipe barrier posts may not be utilized. In another embodiment, other means for separating the pipe may be utilized to urge a single pipe on pipe moving elements whereupon catwalk moving elements  314  are raised to gently urge one or more pipes into pipe reception grooves  378 . Catwalk pipe moving elements may be larger or wider if desired. In another embodiment, catwalk pipe moving elements may comprise a groove that holds the next pipe until raised whereupon the pipes are urged toward pipe guides  379  and pipe reception grooves  379 . 
       FIG. 22B  is a perspective end view of the walkway with movable elements in accord with one possible embodiment of the invention. Catwalk segment  309  contains pipe moving elements  314  in a recessed position with pipe barrier posts  316  to prevent pipe from entering catwalk segment  309  while pipe P is engaged with pivotal pipe arm  320 . In this embodiment, catwalk segment  311  illustrates pipe moving elements  314  in a raised position that work with pipe barrier posts  316  to prevent pipe from entering catwalk segment  311 . In other embodiments, pipe barrier posts  316  may be hydraulically actuated or manually removable. In another embodiment, pipe barrier posts may be omitted and pipe moving elements  314  may contain a groove for holding back pipe from pipe tub  400 . Kickout arm  360  is secured to pivotal pipe arm  320  at kickout arm pivot connection  312  located at the top of pivotal pipe arm  320 . Pipe P has rolled into pipe reception grooves  378  located in pipe clamp mechanisms  370 A and  370 B where pipe clamp sets  387 A,  389 A and  387 B,  389 B will pivot about pivotal pipe clamp arms  394 A and  394 B to engage pipe P. 
       FIG. 23A  is an end perspective view of a pipe feeding mechanism in accord with one possible embodiment of the invention. In this embodiment, pipe tub  400  comprises a rack or support, at least a portion of which is sloped downward towards catwalk segment  311  which urges pipe towards pipe feed receptacle  424 . Pipe feed receptacle  424  is movably mounted to support arms  434  for transporting pipe between pipe tub  400  and catwalk segment  311 . Accordingly, in one embodiment, pipe receptacle  424  lifts pipe one at a time out of pipe tub  400  onto catwalk  311  and/or catwalk moving elements  314 . As used herein pipe tube  400  may comprise a volume in which multiple layers of pipe may be conveniently carried or may simply be a pipe rack with a single layer of pipe. 
       FIG. 23B  is another end perspective view of a pipe feeding mechanism  422  in accord with one possible embodiment of the present invention. Pipe feed mechanism  422  comprises support arms  434  which, if desired, may be fastened to catwalk segment  311 . In one possible embodiment, pipe feed receptacle may comprise a wall, rods, brace  425  at edge  427  of pipe feed receptacle adjacent the incoming pipe that contains the remaining pipe on the rack when pipe feed receptacle  424  moves, in this embodiment, upwardly. Thus, the wall or rods act as a gate. Once pipe receptacle  424  is lowered, then another pipe drops into pipe receptacle  424 . In this embodiment, pipe feed receptacle  424  is slidingly mounted to support arms  434  for movement between pipe tub  400  and catwalk segment  311 . Once pipe P is moved towards catwalk segment  311 , catwalk moving elements  314  urge pipe P towards pipe arm  320  with kickout arm  360 . Pipe feed receptacle  424  could also be pivotally mounted to urge pipe out of pipe tub  400 . In another embodiment, the tub or rack of pipes may be higher than the surface of catwalk  311  and the catwalk moving elements act as the pipe feed to control the flow of pipe from the pipe tub or rack  400  of pipe. Accordingly, the pipe feed may or may not be mounted within pipe tube  400 . 
     In yet another embodiment, as shown in  FIG. 23C  pipe tub  400  may comprise means for moving pipe from the bottom to the top of the pipe tub  400 , such as a hydraulic floor or a spring loaded floor. In one embodiment, pipe tub  400  may also contain pipe gate  426  at an upper edge of pipe tub  400  for efficiently moving pipe from pipe tub  400  to pipe feed receptacle  424 . 
       FIG. 23C  is a cross sectional view of another possible embodiment of a pipe feeding mechanism  422  with the pipes present. The embodiment of pipe tub  400  shown in  FIG. 23C  may also be utilized for receiving pipe as the pipe is removed from the well in conjunction with pipe ejection mechanisms and/or catwalk pipe moving elements discussed hereinbefore. As discussed hereinbefore, pipe tub  400  contains sloped bottom  428  and optional pipe rungs  432  for controlling movement of pipes towards pipe gate  426 . The downward sloped angle of pipe rungs  432  and their placement inside pipe tub cavity  420  continually move pipe as pipe gate  426  opens to allow pipe P to be received by pipe feed receptacle  424 . Pipe feed receptacle  424  lifts pipe P to an upper position adjacent a surface of catwalk segment  311  for movement unto kickout arm  360 . Various types of lifting mechanisms may be utilized for pipe feed receptacle including hydraulic, electric, or the like. Pipe gate  426  controls movement of pipe onto pipe feed receptacle  424  which is supported by vertical support member  430  and support base  440  to prevent movement during operation. 
       FIG. 23D  is a cross sectional view of a pipe feeding mechanism  422  with the pipes removed in accord with one possible embodiment of the present invention. Pipe feed mechanism  422  is positioned between pipe tub  400  and catwalk segment  311 . Pipe tub  400  contains pipe gate  426  at a lower end of pipe tub  400  facing catwalk segment  311 . Pipe rungs  432  may be utilized in connection with sloped bottom  428  within pipe tub  400  for controlling the movement of pipe P towards pipe gate  426 . As discussed hereinbefore, pipe feed receptacle  424  is stabilized by vertical support member  430  and support base  440  while in this position. Pivotal rungs may be removable or pivotal to open for filling the pipe tub more quickly. 
       FIG. 23E  is a cross sectional view of a pipe feeding mechanism  422  in accord with one possible embodiment of the present invention. In this embodiment, pipe rungs  432  are omitted so that pipe tub cavity  420  only contains sloped bottom  428  and pipe gate  426 . This arrangement allows a higher volume of pipe to be stored in pipe tub  400  for drilling operations. Sloped bottom  428  will urge pipe towards pipe gate  426  which remotely opens and closes to allow pipe P to be received by pipe feed receptacle  424 . After pipe P has cleared pipe gate  426 , it will be hoisted along vertical support member  430  via pipe feed receptacle  424  until it reaches catwalk segment  311 . Once at catwalk segment  311 , pipe P will be further urged to pipe arm  320  by catwalk moving elements  314  (See  FIG. 23B ). In one embodiment, the pipe feeding mechanism of  FIG. 23E  may be utilized with the pipe tub  400  of  FIG. 23C . When removing pipe from the well, the pipe may be positioned onto the rungs by catwalk moving elements and/or pipe ejection elements discussed hereinbefore. 
     During operation for insertion of pipes into the wellbore, pipes are moved from pipe tubs  400  to the catwalk (if desired by automatic operation) and in one embodiment catwalk pipe moving elements  314  are activated to urge the pipes into pipe grooves  378  past retracted pipe clamps  387 A,  389 A and/or  387 B,  389 B. Once the pipe is in the grooves, then the pipe clamps are pivoted upwardly  387 A,  389 A and/or  387 A,  389 A to clamp the pipes. During this time, the length and other factors of the pipe is sensed or read by RFID tags. Pivotal pipe arm  320  is then rotated upwardly to the desired position (which may be determined by sensors and/or an upper mast fixture  315 . Kickout arm  360  pivots outwardly to orient the pipe vertically. 
     Top drive  150  is lowered using drawworks  620  to lower traveling block assembly  153 , and top drive shaft  165  is rotated to threadably connect with the upper pipe connector. The pipe is then lowered utilizing traveling block assembly  153  and top drive  150  so that the lower connection of the pipe is connected to the uppermost connection of the pipe string already in the wellbore and the pipe may be rotated to partially make up the connection. The pipe tongs  170  are moved around the pipe connection to torque the pipe with the desired torque and the torque sensor measures the make-up torque curve to verify the connection is made correctly. The pipe tongs are moved out of the way. The slips are disengaged and the pipe string is lowered so that the pipe upper connection is adjacent the rig floor and the slips are applied again to hold the pipe string. The pipe tongs may be brought back in for breaking the connection of this pipe and may utilize reverse rotation of the top drive to undo the connection. Using drawworks  620  to raise traveling block assembly  153 , top drive  150  is moved back toward the mast top in readiness for the next pipe. 
     To remove pipe from the well bore, the top drive is raised so that the lower connection of the pipe for removal is available to be broken by pipe tongs. Once broken, the top drive may be used to undo the connection the remainder of the way. The pipe is then raised, kickout arm  360  is pivoted outwardly, and clamps  370 A and  370 B clamp the pipe. The connection to the top drive is then broken by rotation of the top drive shaft  165 , whereupon the top drive is moved out of the way. Kickout arm  360  is then pivoted back to be adjacent pivotal pipe arm  320 . Pivotal pipe arm  320  is lowered. Clamps  370 A and  370 B are released and retracted. Either the eject arms  374 A or  374 B are activated depending on which side the pipe tube is located. Accordingly, a single operator can run pipe into the well, perform services, and remove pipe from the well. Other personnel at the well site may be utilized for other functions such as cleaning pipe threads, removing thread protectors, moving pipe onto pipe tubs, which may also simply comprise racks, checking mud measurements, checking engines, and the like as is well known. 
     For alignment purposes of the present application, a wellhead, BOP, snubber stack, pressure control equipment or other equipment with the well bore going through is considered equivalent because this equipment is aligned with the path of the top drive. 
       FIG. 24A  depicts a perspective view of an embodiment of a gripping apparatus  1000  engageable with a top drive, such that pipe segments can be gripped by the apparatus  1000  to eliminate the need to thread each individual segment to the top drive itself.  FIG. 24B  depicts a diagrammatic side view of the apparatus  1000 . 
     The apparatus  1000  is shown having an upper connector  1002  (e.g., a threaded connection) usable for engagement with the top drive, though other means of engagement can also be used (e.g., bolts or other fasteners, welding, a force or interference fit). Alternatively, the gripping apparatus  1000  could be formed integrally or otherwise fixedly attached to a top drive or similar drive mechanism. 
     The apparatus  1000  is shown having an upper member  1004  engaged to the connector  1002 , and a lower member  1006 , engaged to the upper member  1004  via a plurality of spacing members  1008 . While  FIGS. 24A and 24B  depict the upper and lower members  1004 ,  1006  as generally circular, disc-shaped members, separated by generally elongate spacing members  1008 , it should be understood that the depicted configuration of the body of the apparatus  1000  is an exemplary embodiment, and that any shape and/or dimensions of the described parts can be used. The lower member  1006  is shown having a bore  1010  therein, through which pipe segments can pass. 
     During operation, the apparatus  1000  can be threaded and/or otherwise engaged with the top drive, then after positioning of a pipe segment beneath the top drive and apparatus  1000 , e.g., using a pipe handling system, the apparatus  1000  can be lowered by lowering the top drive. And end of the pipe segment thereby passes through the bore  1010 , such that slips or similar gripping members disposed on the lower member  1006  can be actuated (e.g., through use of hydraulic cylinders or similar means) to grip and engage the pipe segment. Continued vertical movement of the top drive along the mast thereby moves the apparatus  1000 , and the pipe segment, due to the engagement of the gripping members thereto. Likewise, rotational movement of the top drive (e.g., to make or unmake a threaded connection in a pipe string) causes rotation of the apparatus  1000 , and thus, rotation of the gripped pipe segment. The apparatus  1000  is thereby usable as an extension of the top drive, such that pipe segments need not be threaded to the top drive itself, but can instead be efficiently gripped and manipulated using the apparatus  1000 . 
     Other types of attachments for engagement with a top drive or other drive system, and/or for engaging and/or guiding a tubular joint are also usable. For example,  FIG. 25A  depicts an exploded perspective view of an embodiment of a guide apparatus  1100  engageable with a top drive such that tubular joints brought into contact with the guide apparatus  1100  can be moved toward a position suitable for engagement with the top drive (e.g., in axial alignment therewith).  FIG. 25B  depicts a diagrammatic side view of the guide apparatus  1100 . 
     Specifically, the guide apparatus  1100  is shown having an upper member  1102  that includes a connector (e.g., interior threads) configured to engage a top drive and/or other type of drive mechanism, though other means of engagement can also be used (e.g., bolts or other fasteners, welding, a force or interference fit). Alternatively, the guide apparatus  1100  could be formed integrally or otherwise fixedly attached to a top drive or similar drive mechanism. 
     The upper member  1102  is shown engaged to the remainder of the guide apparatus  1100  via insertion through a central body  1106  having an internal bore, such that a threaded lower portion  1104  of the upper member  1102  protrudes beyond the lower end of the central body  1106 . A collar-type engagement, shown having two pieces  1108 A,  1108 B, connected via bolts  1110 , nuts  1111 , and washers  1113 , can be used to secure the upper member  1102  to the remainder of the apparatus  1100 , though it should be understood that the depicted configuration is exemplary, and that any manner of removable or non-removable engagement can be used, or that the upper member  1102  could be formed as an integral portion of the guide apparatus  1100 . 
     A lower member  1112  is shown below the upper member  1102 , the lower member  1112  having a generally frustroconical shape with a bore  1114  extending therethrough. The shape of the lower member  1112  defines a sloped and/or angled interior surface  1116 . A plurality of spacing members  1118  are shown extending between the lower member  1112  and the central body  1106 , thus providing a distance between the lower member  1112  and the upper member  1102  and/or a top drive connected thereto. While  FIGS. 25A and 25B  depict the upper member  1102  and central body  1106  as generally tubular and/or cylindrical structures, it should be understood that any shape and/or configuration could be used. Similarly, while the lower member  1112  is shown as a generally frustroconical member, other shapes (e.g., pyramid, partially spherical, and/or curved shapes) could be used to present an angled and/or curved surface in the direction of a tubular. 
     During operation, the guide apparatus  1100  can be threaded and/or otherwise engaged with the top drive, then after positioning of a tubular joint beneath the top drive and the guide apparatus  1100  (e.g., using a pipe handling system), the guide apparatus  1100  can be lowered by lowering the top drive. After the end of the tubular joint passes through the lower end of the bore  1114 , the end of the tubular joint contacts the angled interior surface  1116 . Continued movement of the guide apparatus  1100  causes the tubular to move along the angled interior surface  1116  until the end of the tubular exits the upper end of the bore  1114 , where contact between the tubular and the upper portion off the lower member  1112 , and/or between the tubular and the spacing members  1118  prevents further lateral movement of the tubular relative to the guide apparatus  1100 . 
     The end of the tubular joint can then be connected (e.g., threaded) to the lower portion  1104  of the upper member  1102 . Continued vertical movement of the top drive along the mast thereby moves the guide apparatus  1100 , and the tubular joint, due to the engagement between the joint and the guide apparatus  1100 . Likewise, rotational movement of the top drive (e.g., to make or unmake a threaded connection in a pipe string) causes rotation of the guide apparatus  1100 , and thus, rotation of the engaged tubular joint. The guide apparatus  1100  is thereby usable as an extension of the top drive, such that tubular joints need not be threaded to the top drive itself, where misalignment can occur, but can instead be presented in a misaligned position, contacted against the angled interior surface  1116 , and moved into alignment for engagement with the apparatus  1100 . In alternate embodiments, the upper member  1102  and lower portion  1104  thereof could be omitted, and a tubular joint could be engaged with a portion of the top drive directly. 
       FIG. 26  is a top view of a roller and a support rail in accord with one possible embodiment of the present invention. Roller  158  is one of several rollers connected to both guide frames  152 A and  152 B (See  FIGS. 19, 19B, and 19C -C). Roller  158  is connected to guide frame  152  at roller axle  159  allowing roller  158  to spin freely around roller axle  159 . Support rail  176  is sized to mate with groove  173  of roller  178  to facilitate movement of top drive  150  along support rail  176 . In another embodiment, support rail  176  could contain groove  173  whereby roller  158  is sized to engage groove  173  to facilitate movement of top drive  150 . In this way, rollers  158  may be utilized to prevent rotation of the top drive and to reduce back and forth movement as may occur in prior art systems. 
     It will be understood that grooves could be provided in the guide frame whereby the rollers fit in the groove of the guide frame rather than the groove being formed in the rollers. The grooves may be of any type including straight line grooves where the grove sides may be angled or perpendicular with respect to the axis of rotation of the rollers. As well, the grooves may be curved. The grooves may also have combination of angled and perpendicular lines or any variation thereof. Mating surfaces in the opposing component, either the guides or the rollers are utilized. There may be some variation in size to reduce friction, e.g., the groove may have a bottom width of two inches and the inserted member may have a maximum width of 1 and three-quarters inches and so forth. As discussed above, the grooves may be V-shaped or partially V-shaped. 
     Turning to  FIGS. 27A and 27B , a top view of a crown block assembly  193  in accord with one possible embodiment of the present invention. Crown block assembly  193  has cluster of sheaves located on top of mast assembly  100 . Sheaves  193 A,  193 B,  193 C,  193 D have an axis of rotation X upon which the sheave cluster  193 A,  193 B,  193 C,  193 D rotates. Traveling sheave block assembly  153  has sheaves  146 A,  146 B,  146 C,  146 D which are fastened to said guide frame  152  of top drive fixture  150  (see  FIG. 19 ). Traveling sheave block assembly  153  has axis of rotation Y, which is offset in relation to axis of rotation X upon which sheave cluster  193 A,  193 B,  193 C,  193 D rotates. In one embodiment, the offset is less than ninety degrees. In another embodiment, the offset is less than forty five degrees. In another embodiment, the offset is less than twenty five degrees. It will be understood that these ranges would also apply if any multiple of ninety degrees were added to these ranges, e.g., between ninety and one-hundred eighty degrees. This orientation improves the ability of sheave cluster  193 A,  193 B,  193 C,  193 D and traveling sheave block assembly  153  to reeve a drilling line. When the traveling sheaves move closely to the crown sheaves, the offset aids in providing a smoother transition from one set of sheaves to the other in that sharp bends of the drilling line are avoided. 
     Generally, sheave wheels have a minimum diameter with respect to the type of drilling line to limit the amount of bending of the drilling line. Generally, the minimum sheave diameter will be between fifteen times and thirty time the diameter of the drilling line. However, this range may vary. Accordingly, in some embodiments, the ratio of sheave wheel diameter to drilling line diameter may be less than twenty. 
     Turning to  FIGS. 28A and 28B , one possible embodiment of long lateral completion system  10  is depicted. A well site with first wellhead  12  and second wellhead  14  is shown. As discussed hereinbefore, long lateral completion system  10  can work well with wellheads in close proximity with each other on a well site, which can be less than a 10 foot distance between first wellhead  12  and second wellhead  14 . Pipe arm assembly  300  occupies a rear portion of skid  16  while rig floor  102  is positioned at a front end of skid  16  closest to second wellhead  14 . In another embodiment, rig floor  102  and pipe arm assembly  300  are operable without skid  16 . Skid  16  is positioned so that rig platform  102  is directly above second wellhead  14 . Rig floor  102  may or may not be part of skid  16 . 
       FIG. 28B  depicts long lateral completion system  10  in accord with one possible embodiment of the present invention. Rig carrier  600  is shown with mast assembly  100  in an upright position. Mast assembly  100  extends past a rear portion of rig carrier  600  so that top drive unit mounted within mast assembly  100  is positioned directly above first wellhead  12  for drilling operations, as discussed hereinbefore. In other embodiments, sensors such as laser sights or guides mounted to the rear of rig carrier  600 , and the like may be utilized, e.g., mounted to and/or guided to the well head, to locate and orient the axis of mast assembly  100  precisely with respect to the wellbore of first wellhead  12 . 
     Rig floor  102  is shown positioned above second wellhead  14  providing operators access to mast assembly  100  when conducting drilling operations on first wellhead  12 . System  10  is configured so that pivotal pipe arm  320  of pipe handling system  300  can move pipe to and away from mast assembly  100  without contacting rig floor  102  during operation. Pivotal pipe arm  320  uses control arm  315  to pivot about pipe arm pivotal connection  313  creating an angle which avoids rig floor  102 . 
     In another embodiment of the present invention, pivotal pipe arm  320  may contain kickout arm  360 . In this embodiment, kickout arm  360  remains generally parallel to pivotal pipe arm  30  except when pivotal pipe arm  360  is moved into the upright position shown in  FIG. 7 ,  FIG. 8 , and  FIG. 9 . Upon reaching the upright position, kickout arm  360  is pivoted using the hydraulic actuators  362 , which cause kickout arm  360  to pivot away from pipe arm  320  about kickout arm pivot connection  312  (See  FIG. 16B ). This preferred configuration of long lateral completion system  10  allows drilling operations on multiple wells in close proximity, which can be less than 10 feet apart in certain embodiments. 
     While certain exemplary embodiments have been described in details and shown in the accompanying drawings, it is to be understood that such embodiments are merely illustrative of and not devised without departing from the basic scope thereof, which is determined by the claims that follow. Moreover, it will be appreciated that numerous inventions are disclosed herein which are taught in various embodiments herein and that the inventions may also be utilized within other types of equipment, systems, methods, and machines so that the invention is not intended to be limited to the specifically disclosed embodiments.

Technology Classification (CPC): 4