This section is intended to introduce selected aspects of the art, which may be associated with various embodiments of the present disclosure.  This discussion is believed to assist in providing a framework to facilitate a better understanding of particular aspects of the present disclosure.  Accordingly, it should be understood that this section should be read in this light, and not necessarily as admissions of prior art. 
Field of the Invention
The present disclosure relates to the field of well completion.  More specifically, the present disclosure relates to fluid control valves for a completion tree used for hydraulic fracturing.  The present disclosure further relates to an automatic lubrication unit configured for use with a hydraulic fracturing tree. 
Discussion of Technology
In the drilling of an oil and gas well, a near-vertical wellbore is formed through the earth using a drill bit urged downwardly at a lower end of a drill string.  The drill bit is rotated in order to form the wellbore, while drilling fluid is pumped through the drill string and back up to the surface on the back side of the pipe.  The drilling fluid serves to cool the bit and flush drill cuttings during rotation. 
After drilling to a predetermined vertical depth, the wellbore may be deviated.  The deviation may be at a “kick-off” angle of, for example, 45 degrees or 60 degrees.  Alternatively, the deviation may be about 90 degrees.  In this instance, a wellbore having a substantially horizontal leg is formed. 
Within the last two decades, advances in drilling technology have enabled oil and gas operators to economically “kick-off” and steer wellbore trajectories from a generally vertical orientation to a generally horizontal orientation.  The horizontal “leg” of each of these wellbores now often exceeds a length of one mile.  This significantly multiplies the wellbore exposure to a target hydrocarbon-bearing formation (or “pay zone”).  For example, for a given target pay zone having a (vertical) thickness of 100 feet, a one-mile horizontal leg exposes 52.8 times as much pay zone to a horizontal wellbore as compared to the 100-foot exposure of a conventional vertical wellbore. 
During the drilling process, the drill string and bit are periodically removed and the wellbore is lined with a string of casing.  An annular area is formed between the string of casing and the formation penetrated by the wellbore.  A cementing operation is then conducted in order to fill or “squeeze” the annular volume with cement along the length of the wellbore casing.  The combination of cement and casing strengthens the wellbore and facilitates the zonal isolation, and subsequent completion, of certain sections of potentially hydrocarbon-producing pay zones behind the casing. 
During wellbore formation, it is common to place several strings of casing having progressively smaller outer diameters into the wellbore.  A first string may be referred to as surface casing.  The surface casing serves to isolate and protect the shallower, fresh water-bearing aquifers from contamination by any other wellbore fluids.  Accordingly, this casing string is almost always cemented entirely back to the surface.  The process of drilling and then cementing progressively smaller strings of casing is repeated several times below the surface casing until the well has reached total depth.  In some instances, the final string of casing is a liner, that is, a string of casing that is not tied back to the surface but is hung from the lowest intermediate string of casing. 
FIG.  1 provides a cross-sectional view of a wellbore 100 having been completed in a horizontal orientation.  It can be seen that a wellbore 100 has been formed from the earth surface 101, through numerous earth strata 20a, 20b, . . .  20h and down to a hydrocarbon-producing formation 150.  The subsurface formation 150 represents a “pay zone” for the oil and gas operator.  The wellbore 100 includes a vertical section 105 above the pay zone 150, and a horizontal section 107.  The horizontal section 107 defines a heel 115 and a toe 117, along with an elongated leg there between that extends along the pay zone 150. 
In connection with the completion of the wellbore 100, several strings of casing having progressively smaller outer diameters have been cemented into the wellbore 100.  These include a string of surface casing 120, and may include one or more strings of intermediate casing 130, and finally, a production casing 140.  The final string of casing 140, referred to as a production casing, is typically cemented 143 into place.  In some completions, the production casing 140 has external casing packers (“ECP's), swell packers, or some combination thereof spaced across the productive interval.  This creates compartments between the swell packers for isolation of zones and specific stimulation treatments. 
In FIG.  1, a column of cement 127 is placed into an annular space residing between the surface casing 120 and the surrounding formation 20a, 20b.  A so-called cement shoe 128 is provided at the lower end of the surface casing 120.  Similarly, a column of cement 137 is optionally placed in an annular space residing between the intermediate casing string 130 and the surrounding formation 20d, 20e.  A cement shoe 138 is again provided at the lower end of the casing string 130. 
As part of the completion process and before the production tubing string is installed, the production casing 140 is perforated at a desired level 107.  This means that lateral holes (or “perforations” 145) are shot through the casing 140 and the cement column 143 surrounding the casing 140.  The perforations 145 allow reservoir fluids to flow into the wellbore 100.  Where swell (or other) packers are provided, the perforating gun penetrates the casing 140, allowing reservoir fluids to flow from the rock formation 20h into the horizontal leg 107 of the wellbore 100 and into selected zones. 
After perforating, the formation 20h is typically fractured at the corresponding zone.  Hydraulic fracturing consists of injecting water with friction reducers or viscous fluids (usually shear thinning, non-Newtonian gels or emulsions) into a formation at such high pressures and rates that the reservoir rock parts and forms a network of fractures 146.  The fracturing fluid is typically mixed with a proppant material such as sand, ceramic beads or other granular materials.  The proppant serves to hold the fractures 146 open after the hydraulic pressures are released.  In the case of so-called “tight” or unconventional formations, the combination of fractures and injected proppant substantially increases the flow capacity, or permeability, of the treated reservoir. 
FIG.  1 demonstrates a series of fracture half-planes 146 along the horizontal section 107 of the wellbore 100.  The fracture half-planes 146 represent the orientation of fractures that will form in connection with a perforating/fracturing operation.  According to principles of geo-mechanics, fracture planes will generally form in a direction that is perpendicular to the plane of least principal stress in a rock matrix.  Stated more simply, in most wellbores, the rock matrix will part along vertical lines when the horizontal section of a wellbore resides below 3,000 feet, and sometimes as shallow as 1,500 feet, below the surface.  In this instance, hydraulic fractures will tend to propagate from the wellbore' s perforations 145 in a vertical, elliptical plane perpendicular to the plane of least principal stress.  If the orientation of the least principal stress plane is known, the longitudinal axis of the leg 107 of a horizontal wellbore 100 is ideally oriented parallel to it such that the multiple fracture planes 146 will intersect the wellbore at-or-near orthogonal to the horizontal leg 107 of the wellbore, as depicted in FIG.  1. 
In support of the formation fracturing process, a so-called hydraulic “frac” tree 50 is installed at the surface 101.  An illustrative tree is seen at 200 in FIG.  2.  The tree 5 serves to connect fluid hoses and pumps, and to direct hydraulic fracturing fluid into the wellbore.  Those of ordinary skill in the art understand that formation fracturing fluid is pump through the hoses, through control valves associated with the fracturing tree, and down the wellbore 4 until it exits exposed perforations.  This pumping process is frequently done in horizontal stages, enabling specific zones to be sequentially isolated along the horizontal section 4c.  
The ability to replicate multiple vertical completions along a single horizontal wellbore is what has made the pursuit of hydrocarbon reserves from unconventional reservoirs, and particularly shales, economically viable within relatively recent times.  This revolutionary technology has had such a profound impact that Baker Hughes Rig Count information for the United States indicates only about one-fourth (26%) of wells being drilled in the U.S. are classified as “Vertical”, whereas the other three-fourths are classified as either “Horizontal” or “Directional” (62% and 12%, respectively).  That is, horizontal wells currently comprise approximately two out of every three wells being drilled in the United States. 
A complication associated with the formation fracturing process is the wear upon the surface equipment used during the fracturing process.  In this respect, the proppant placed within the fracturing fluid is highly abrasive, particularly when pumped through control valves at high flow rates.  The control valves include a body in which is placed a movable gate which functions to controllably allow or prevent the flow of fluids through the control valve.  The internal gate loosely abuts a pair of seats positioned on either side of the gate. 
Oftentimes, the control valves are arranged in series, forming a so-called hydraulic fracturing tree or “valve tree.”  During the fracturing process, the fracturing fluid passes through internal components of the valves along the valve tree.  The passage of the fracturing fluid, and especially the abrasive proppant which constitutes a part of the fracturing fluid, causes scarring, pitting or other damage to the internal components of the valves, such as the gates, seats, stem and body.  Once the valve becomes scarred or damaged, the valves and, possibly, the entire tree, must be repaired or replaced to ensure the safe operation of the well.  Such repairs are both costly and time consuming to the operator of the completion equipment. 
Some operators have attempted to cure this problem by lubricating the gate of the valves.  This is currently done by applying a viscous lubrication fluid to the valves, cycling the gate of each of the valves, lubricating the valves again, and then moving the gate again.  However, when moving the gate from a closed position to an open position, pressure in the body of the tree is released.  This, in turn, creates a pressure differential from the bore of the fracturing tree to the body of the valves when the fracturing operation begins. 
Upon pressurization, the pressure in the bore is typically 6,500 to 8,500 psi but only 0 psi in the gate cavity and seats.  Thus, there is a 6,500 to 8,500 psi differential.  When the gate is moved to its open position, the pressure differential allows the abrasive fracturing fluid and proppant to be forced between the gate and seat in the opened valve until the body cavity equalizes with the pumping pressure applied to the valve bore and well.  Thus, once again the fracturing fluid and proppant is potentially damaging the internal valve components, creating scarring and pits therein.  The build-up of such damage may result in gates no longer being capable of moving between open and closed positions.  In a worst-case scenario, well control may be compromise since the tree cannot be fully shut in. 
Accordingly, it is desirable provide a portable lubrication unit that may be carried to a well site, and then fluidically connected to the control valves of a fracturing tree.  In this way, the gate cavity may be pre-pressurized in such a manner as to restrict the abrasive fluids associated with the perforating process from entering the cavity and damaging the internal components of the valves.  Further, a need exists for a frac tree fitted with a lubricant pump that enables lubricating fluid to be pumped into the gate cavity at very high pressure before fracturing fluid is pumped downhole.  Still further, a need exists for a process of pre-pressurizing control valves along an injection tree or injection manifold before a hydraulic fracturing fluid is injected into a wellbore for formation fracturing.