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GDEP is the original creator of the drilling pump and continues to set the standard for durable, high-quality drilling pumps that can withstand the world’s toughest drilling environments. Starting with our PZ7 and rounding out with the market"s most popular pump, the PZ1600, our PZ Series of pumps are the perfect choice for today"s high-pressure drilling applications.

This invention relates to a system and a method to enable widespread adoption of geothermal energy and more particularly this invention relates to a system and a method for facilitating energy transfer from a geothermal field to an existing HVAC system of a building with minimal retrofit, thereby enhancing or retro fitting existing conventional HVAC systems with minimal interference of daily activity within the building.

Geothermal energy is an alternative energy source existing under ground. The goal for geothermal energy use is to utilize the typical midrange constant temperatures of 52 to 54° F. found beneath the earth"s surface to help heat or cool a structure in winter or summer, respectively.

Efficiency dictates that thermal conduction of underground temperatures to the thermal conduction fluid loop be maximized. As such, the diameter (referred to as the “caliper”) of the wells must be strictly controlled so that cavitating (also known as washout) of the well bore does not occur. Washout of the well bore caliper, or an unnecessary increase in the diameter of the well bore, results in a loss of the loop"s ability to transfer a considerable percentage of energy. Large voids or large caliper well bores require much more annular space to be filled between the loop and the bore hole wall with grout material. This results in a loss of thermal conductance from the earth to the loop at that point.

A myriad of drilling techniques are available for geothermal well production, including air hammer drilling (which is typically utilized in consolidated, e.g. Bed Rock formations), and circulating mud drilling, (which is utilized in glacial drift or overburden e.g., gravel, sand, and clay).

Air hammer drilling utilizes a rotary bit that slams against, then removes bits of, the consolidated formation being drilled. Air rotary drilling methods are almost exclusively utilized in hard consolidated formations to speed up and cut costs of drilling in bedrock. Air compressors are utilized to force air down the drill pipe through a down hole air hammer on the bottom end of the drill string. Exhaust air from the hammer evacuates the area between the drill string and the wall of the bore hole thereby lifting large volumes of water and mud out of the bore hole.

Air rotary drilling cuts through dense structures (i.e. bedrock layers) quickly, and, compared to circulating mud drilling, it is particularly useful when lost circulation occurs. This is because the air used in air rotary drilling technique tends to lift water, which seeps into the well bore (from fissures, aquifers and other voids).

Environmental containment of the drill site with air rotary drilling is very challenging. Fuel consumption of equipment utilizing this method is extremely high due to massive amounts of horse power spent producing huge amounts of air at extremely high pressures. A 6 inch diameter bore hole at five hundred ft in depth requires constant generation of up to 1000 CFM (cubic feet per minute) at 350 psi (pounds per square inch). This is twice the horse power required by mud rotary systems to drill at the same depth.

Mud rotary drilling uses mud to carry away cuttings. FIG. 2A is a schematic of a standard drill-string 12 with mud rotary drilling in use. The down-pointing and up-pointing arrows show the direction of drilling mud, which is initially injected at the top center of the drill string. The drilling mud is pumped through the center of the drill string and out of the rotary bit 14. With continued pumping, the mud is pushed to the surface of the well bore, taking with it the bore cuttings entrained in the mud. Thus, the mud serves as a vehicle to remove bore cuttings as they are produced.

Mud rotary drilling is less disruptive to nearby geologic structures, but also less effective in penetrating dense structures even when expensive diamond bits (such as those featuring polycrystalline diamond compact (PDC) inserts) are used.

Also, mud rotary drilling stops working when large cavities develop or are encountered during drilling, inasmuch as mud pressure drops significantly in these scenarios. A subsequent drop in the return mud volume through the annulus (i.e., the space between the drill string and the sides of the well bore) results in cuttings not being carried to the surface of the hole for evacuation. This reduction of flow may generally be classified as seepage (less than 20 bbl/hr [3 m3/hr]), partial lost returns (greater than 20 bbl/hr [3 m3/hr] but still some returns), and total lost returns (where no fluid comes out of the annulus). In this severe latter case, the hole may not remain full of fluid even if the pumps are turned off. If the hole does not remain full of fluid, the vertical height of the fluid column is reduced and the pressure exerted on the open formations is reduced. This in turn can result in another zone flowing into the wellbore and a catastrophic loss of well control.

Contained mud rotary systems provide a reserve capacity for generating more mud. But, such systems usually cannot generate enough mud to overcome the aforementioned pressure and/or volume drop when large cavities are encountered in consolidated formations. At that point, the mud rotary drilling is finished, and other drilling methods must be applied.

In light of the foregoing, state of the art geothermal field development relegates the use of geothermal energy to venues able to accommodate large silt ponds, high volume water run off, and substantial scarring of the landscape associated with air hammer drilling. As such, large campuses, outlying industrial sites, or abandoned brown fields heretofore were the only candidates for geothermal well development.

Current industry standards set by The International Ground Source Heat Pump Association (IGSHPA) specifies grid pattern spacing of 10 ft to 20 ft between wells. Often, geothermal wells are 150 ft to 200 ft in depth depending on the relationship and distance from the equator. Each of these wells yield approximately one ton or 12,000 BTU of geothermal energy. Most single family homes are approximately 2000 square feet of living space. Modern built homes require from 3 to 4 ton of geothermal energy to supply heat pump load requirements. Three to four wells spaced 20 feet apartment usually can be accomplished in most rural back yards; however the much larger tonnage requirements of high rise buildings and commercial businesses make the possibility of installing geothermal well fields on sidewalks, alley ways, and parking lots a real challenge. Given that most commercial loads are a minimum of 20 to 30 tons, and therefore require a minimum of 20-30 wells, such a geothermal well field typically requires 200 to 300 foot blocks of space.

3. Lack of a method for competitively using mud rotary drilling in consolidated formations. Loss of mud circulation becomes particularly acute in deep drilling. State of the art mud rotary drilling methods are not effective after lost circulation zones are encountered; therefore casings must be set deep through the zone. This casing installation is neither cost effective nor easy to remove.

A need exists in the art for a system and a method for applying geothermal energy to footprints not exceeding a standard city lot. The system and method should accommodate field development on the city lot already containing a house, an ongoing commercial enterprise, or other permanent structure. The system and method should also obviate the need for completely retrofitting the HVAC of the permanent structure to utilize the geothermal energy. The method should also optimize state of the art mud rotary drilling techniques for their use in lost circulation zones.

An object of the invention is to provide a system and a method for utilizing geothermal energy that overcomes many of the disadvantages of the prior art.

Another object of the invention is to provide a system for utilizing geothermal energy extracted from a city-lot to supplement energy needs of permanent structures on the city lot. A feature of the invention is a means for utilizing existing HVAC systems of the structures to provide geothermal energy to the structures. An advantage of the invention is no disruption of activity within the structure during the establishment of the geothermal field, or hook up of the field to the HVAC system.

Yet another object of the present invention is to provide a method for establishing 4 to 5 tons of geothermal energy from one well, making a 30-60 ton geothermal field on 2000 square feet of real estate a possibility. A feature of the invention is enabling the drilling of a plurality of wells in close spatial relationship to each other, each well of which is approximately 300 to 700 feet deep. An advantage of the invention is that the increased depth, and therefore capacity, of each well results in a geothermal well field with a smaller foot print. This provides a means for harvesting geothermal energy from within densely packed, urban areas.

Briefly, the invention provides a system for charging an HVAC system of an existing building with geothermal energy, the system comprising an incoming flux of geothermal energy; a plurality of heat exchange surfaces adapted to receive the incoming flux of geothermal energy; and an interface between the HVAC system and the heat exchange surfaces, said interface adapted to transfer the geothermal energy to the system.

Also provided is a method for repairing aberrations along a drill bore wall, such aberrations including lost circulation zones (LCZ) in geothermal well bores, the method comprising using a rotary mud drill system to produce a drill hole, wherein the system employs a first return mud pressure value; removing the rotary mud drill when return mud pressure decreases to a second return mud pressure value; inserting a reverse auger 22 (i.e., in the case of a right-handed drilling operation, the auger 22 defines left handed flighting) into the drill hole to the point where the return mud pressure decreased to the second pressure value; actuating the auger; introducing loose substrate, (i.e. lost circulation material (LCM)) such as bentonite, into the drill hole; allowing the substrate to contact the auger 22; and lifting and lowering the auger along longitudinally extending regions of the drill hole defining the point P where the return mud pressure decreased to the predetermined value for a time and in substrate amounts sufficient to compress the substrate into that portion of the bore wall defining the lost circulation zone.

Also provided is a system for minimizing vibration of drilling equipment during production of oil, gas and geothermal well bores, the system comprising a multiplier sub for a drill rig having an above ground drive motor to form an elongated hole by dislocating solid material of the earth, the multiplier sub comprising a sleeve having a threaded male connector attached to a sleeve tube, where the sleeve tube includes an sleeve tube interior surface lined with teeth; a mandrel having a threaded female connector attached to a mandrel shaft, where the mandrel shaft is positioned within the sleeve tube and includes a mandrel shaft exterior surface lined with teeth; a first gear cluster having a plurality of first gear cluster pin gears positioned within the sleeve tube between teeth of the sleeve and mandrel; and a second gear cluster having a plurality of second gear cluster pin gears positioned within the sleeve tube between teeth of the sleeve and mandrel, where the first gear cluster is separated from the second gear cluster by an intermediate bearing, and where a teeth ratio between the sleeve the mandrel, the first gear cluster, and the second gear cluster is a value that configures the mandrel to spin at least twice as fast as the sleeve.

FIG. 1 is a schematic diagram of a system for integrating geothermal energy with an existing HVAC system, in accordance with features of the present invention;

FIG. 1 is a schematic depiction of the system, 10, or subunits of the system. Salient features of the system include a means of ingress 24 and means of egress 26 of geothermal treated fluid. The fluid can be any heat exchange media. Typical fluid is enhanced water which comprises water containing rust inhibitor, antifreeze, and perhaps a balanced pH agent such as a buffer. Enhanced water is a term of art used in the geothermal industry with such enhanced water constituents dictated by the manufacturer of the particular heat pump or chiller incorporated in the system.

The means of ingress 24 establishes fluid communication between the system 10 and the fluid. The fluid traverses a closed conduit or loop 11 which in turn traverses a geothermal well 13. The loop serves as a heat exchange surface between the fluid and below-ground temperature zones. The means of egress 26 establishes fluid communication between the system 10 and the loop which redirects fluid back down the well. Both means are controlled via a flow center 28 or plurality 28 of flow centers. These flow centers comprise a (or a plurality of) first circulation pump(s) which first accept loop fluid from the geothermal well bore. The first circulation pump directs the fluid to one or a plurality of pretreatment units 27, whereby the fluid is compressed or expanded to increase or decrease its temperature, respectively.

Fin 31 temperature is controlled by flow rate of incoming and outgoing loop fluids, as determined by flow controllers 40. The flow controllers 40 are in turn monitored by thermostats set at predetermined temperatures. In one embodiment, the flow centers 28, heat pumps 27, and flow controllers 40 are all digitally controlled via a user"s thermostat setting.

1. Geothermal heat pumps. Generally, for a typical 3-4 ton load, a heat pump, 27, or a plurality of heat pumps, should be able to move three gallons per ton per minute of geothermal treated fluid. Fluid pressures of from 22 to 32 psi are suitable. Suitable heat pumps are commercially available from a myriad of supply companies, including those manufactured by Climate Master of Oklahoma City, Okla. Insulation placement shall be designed in a manner that may eliminate any exposed edges to prevent the introduction of glass fibers into the air stream.

2. Vertical heat pumps also may be required. These vertical heat pumps provide configurations whereby supply lines (i.e., their exhaust lines) emanate from the top (i.e., superior regions) of their housing while return lines enter their housing from either vertically-disposed side of the housing. Suitable vertical heat pumps are commercially available from such supply outlets as Climate Master (referenced supra), Trane (Tyler, Tex. and Piscataway, N.J.) and Ingersoll Rand (Montvale, N.J.).

3. The hot water system. Commercially available units (such as the flexible R Series® Chillers, manufactured by Trane, of Piscataway, N.J.) are adapted to receive incoming water at a temperature range from 20° to 110° F. (−6.7° to 43.3° C.) as standard. These are relatively large heat pumps.

The heat exchange 30 units comprise a sealed refrigerant circuit including a high efficiency scroll, rotary or reciprocating compressor designed for heat pump operation, a thermostatic expansion valve for refrigerant metering, an enhanced corrugated aluminum lanced fin and rifled copper tube refrigerant to air heat exchanger (such as that depicted as elements 31 in FIG. 1B), reversing valve, coaxial (tube in tube) refrigerant to water heat exchanger, and safety controls including a high pressure switch, low pressure switch (loss of charge), water coil low temperature sensor, and air coil low temperature sensor. Access fittings installed on high and low pressure refrigerant lines facilitate field service. Activation of any safety device prevents compressor operation via a microprocessor lockout circuit. The lockout circuit resets at the thermostat or at the contractor supplied disconnect switch.

Preferably, the system operates via a solid-state control system embodied in the control box 43 and the flow center 40. The control system microprocessor board protects against building electrical system noise contamination, EMI, and RFI interference. The control system interfaces with a heat pump type thermostat. The control system has the following features:

This control system coupled with a multi-stage thermostat may better dehumidify room air by automatically running the heat pump"s fan at lower speed on the first stage of cooling thereby implementing low sensible heat ratio cooling. On the need for higher cooling performance, the system optionally activates the second stage of cooling and automatically switches the fan to the higher fan speed setting. This system may be further enhanced with a humidistat. Units not having automatic low sensible heat ratio cooling may not be accepted; as an alternate, a hot gas reheat coil may be provided with control system for automatic activation.

The method allows drilling into consolidated formations using rotary mud drilling technologies and solves the lost circulation problems such formations usually present in rotary mud operations.

Specifically, the invention provides a method for repairing aberrations (often referred to as “fractures”) along a drill bore wall, the method comprising: using a rotary mud drill system to produce a drill hole, wherein the system employs a first return mud pressure value; stopping the rotary mud drill system when return mud pressure decreases to a second return mud pressure value at a point P in the drill hole; positioning a reverse auger 22 into the drill hole at said point; rotating the auger; introducing loose substrate “S” into the drill hole so as to cause said loose substrate to contact the auger; lifting and lowering the auger along longitudinally extending regions of the drill hole defining the point and/or above the point P for a time and in substrate amounts sufficient to minimize the aberrations; and reestablishing the first return mud pressure of the rotary mud drill system to extend the length of the drill bore below said point. In one embodiment of the method, the middle of the auger is placed opposite the point P where fracture has occurred and is both rotated and moved up and down, while substrate S is fed from above. In this instance, substrate S is directed into the fracture point P before it rolls down the auger flights past the fracture point. Generally, depending or downwardly facing surfaces of the auger flights force the substrate down into the deepest recesses of the bore, as depicted in FIG. 2C.

The rotational speed and the downward force (weight on bit) applied is dependent on conditions at the point of contact of the bit to the structure (e.g. the composition of the consolidated structure, the type of bit, etc). For example, the mud circulation rotary drill bit boring into limestone might be operated at a bit rpm of 150 rpm to 170 rpm with 1000 pound per square inch of weight on the bit (which is empirically proven to be effective). Drilling with a tricone bit generally operates optimally at a rotational speed of about 30 rpm. Accordingly, drilling a pilot hole into bedrock is performed only when deemed absolutely necessary, and then only for the depth required.

It should be noted that given the hardness of bedrock, and the aforementioned difficulty/expense associated with using mud rotary drilling techniques to penetrate bedrock, the inventor has devised a pilot hole method for facilitating drilling. Briefly, a tricone drill bit (e.g. a Tri-Cone™ bit as distributed by Baker Hughes, Houston, Tex.) is used to first drill a pilot hole into the bedrock. Then, drilling with the circulating mud/rotating drill bit drilling process can commence and/or resume.

As can be noted in FIG. 2A, a predetermined distance defining an annular space should be maintained between the walls 18 of the drilled hole and the drill string surface. The annular space is critical with utilizing mud rotary drilling. This space between the drill pipe string and the wall of the hole being bored must be sufficient to allow drill cuttings to be pumped away from the drill bit and carried back to surface. Any obstruction to this annular space will stop the drilling procedure and can result in loss of thousands of dollars in drilling bits and drill pipe. If the annular space is allowed to become inconsistent or ‘washed out”, then the mud flow to surface is no longer constant with a steady rate. Drill cuttings start to build up around the drill string causing a similar loss of the drill bit and/or drill string. As such return mud must be constantly monitored for pressure, flow rate and amount of drill cuttings being carried back to surface.

FIG. 2B depicts the rotary bit 14 piercing the ceiling of the fracture 16. Upon such an event, a portion of the drill mud spills into the fracture, as the downward and laterally pointing arrows show. A loss of mud pressure occurs, and if the fracture is large enough, drilling must cease. In typical situations, the drilling operator either chooses to stop the depth at that point “P” of the drill bore, or else drills another hole.

FIG. 2C depicts the invented reverse auger method in operation. In this scenario, the operator, upon experiencing mud pressure loss, backs the drill string out of the hole, and replaces the rotary bit 14 with an auger defining a left hand flighting. This auger when rotated to the right, provides a means for forcing aggregate downward, thereby pushing aggregate into the fracture site, 16.

In one embodiment of the method, the turning of the auger directs substrate downwardly. When the depending end of the auger is in close spatial relationship to the bottom of the bore, (which may be the case if mud rotary operations are stopped soon after pressure loss occurs), then the substrate is forced into the fracture space which surrounds the bottom of the bore. In this instance, the auger is moved upwardly from a first position in the bottom of the bore hole (i.e., from the fracture point P). The auger, upon being raised to a second position, or end point of its longitudinal movement. The auger is then moved back down to its first position. Movement of the auger may be stopped between the first and second points (i.e., at an intermediate point), particularly in instances where aggregate has completely filled or temporarily overloaded the flights of the auger and the aggregate is in the process of being compacted into the fracture point P situated below the auger at that intermediate point.

The inventor has discovered that the auger manipulations necessary to fill fractures are multi-directional and often simultaneous with each other. For example, it is not uncommon for the reverse auger to be raised and lowered along the fracture point P several times a minute, while the auger is rotating at the speeds mentioned supra. Ultimately, these manipulations will stress above-hole structures. As such, many of the manipulations are not attainable and/or sustainable with conventional equipment. Rather, a multiplier-sub arrangement may be required, that arrangement disclosed infra. The multiplier-sub is a below ground connection to the drill string that allows the end of the string to rotate and speeds which are multiples of the speed that the above-hole drill string rotates. For example, while the drill string rotation above the hole is 20 rpms, the rotation at the site of fracture may need to be faster than 20 rpms.

Furthermore, it should be appreciated that a breach in a well bore wall should be addressed sooner than later. As such, the auger-multiplier sub combination should be applied on site immediately. Otherwise, in-flows from the formation may cause collapse of the well, or slow but dangerous pressure build up of fluids, which ultimately will breach the surface of the well and cause environmental issues. In operation of an embodiment of the reverse auger method, the multiplier sub is removably attached to the reverse auger and in between the derrick and the reverse auger. The auger is mated with the depending end of the multiplier-sub in a standard male/female threaded configuration, similar to how sections of drill string are attached.

FIG. 3A is a caliper log for a hole drilled using conventional drilling techniques. From a 180 foot depth, a mud rotary was switched to air rotary due to the driller encountering the fractured formation. Caliper deviations (i.e., washout) seen on that graph are concomitant with lost circulation.

FIG. 3B is a caliper log for a hole drilled approximately 100 feet away using the invented technique. When the invented reverse auger process was applied at the first instance of mud pressure drop, the fractures sealed, or at least were greatly minimized. The reverse auger method was used in this drilling at between 180 and 260 feet. Upon repair of the fractures, the mud circulation was reestablished. Unlike the well depicted in FIG. 3A, the well was completed using mud rotary techniques.

The well which resulted in the caliper log depicted as FIG. 3B provided a more uniform diameter for calculating group specification. The results in more efficient geothermal energy conductivity from the formation to the loops. Also, less spoils are produced, therefore minimizing environmental remediation activity.

As to the reverse auger process described supra, a myriad of aggregate types are suitable, including but not limited to clays, red mud, cement, asphalt, polymers such as bentonite, volcanic clay material, and combinations thereof.

Thus, bentonite or an alternative grout is extruded into the fracture. Most geothermal collection fields are artesian and thus bentonite grouts are nearly ideal sealants. That is, bentonite grouts are flexible and do not shrink and crack when hydrated, thus creating a low permeability seal. Also, bentonite grouts are chemically inert, and have generally low impact to the environment, persons, equipment, and water quality. Of course in situations where excessive chlorides or other contaminants such as alcohols or ketones are present, grouts other than bentonite may be used. At the completion of the sealing operation (when the grout has hardened) the process returns to once again preparing the mud extruder. With the fracture now sealed, pressure can be maintained at a maximal level (e.g., the first return mud pressure value) so that the bit may be advanced beyond the fracture.

Casing 16 may surround a borehole cavity 18. Borehole cavity 18 may be an empty space within casing 16 that extends from blowout prevention equipment 110 at a borehole cavity top 19 to a borehole cavity bottom 20. The distance between blowout prevention equipment 110 and borehole cavity bottom 20 typically is about 15,000 feet (4.6 km) long for an oil or gas well vertically drilled onshore. The excess in the diameter of borehole cavity 18 over a diameter of drill string 112 is an overgauge 22. Overguage 22 may be an annular gap whose distance may vary vertically along borehole cavity 18. Overguage 22 may be a passageway to allow drilling mud fluid 154 to carry fragmented cuttings 156 from borehole cavity bottom 20 to blowout prevention equipment 110. During the process of drilling, drill rig 100 continuously circulates pressurized drilling fluid (mud) down a center of drill string 112, out of holes in drill bit 202 at the bottom of drill string 112, and back up to the surface via the overgauge 22 space between the rotating drill-string 112 and casing 16. The circulated drilling mud 154 cools and lubricates drill bit 202 as well as to remove cuttings 156 produced by drill bit 202.

Operation systems 106 may be an arrangement of power controlling devices utilized to impart electrical, mechanical, and other energy into drill rig 100. Operations system 106 may include a rotary system 128, a hoisting system 130, and a drilling mud circulation system 132. In addition, operations system 106 may include engines 133. Engines 133 may include any of various types of power units such as a hydraulic, internal combustion, air, or electric motor that develops energy or imparts rotary motion to power other machines.

Rotary head 136 may provide a reasonably tight seal at the top of well pipe casing 16 while permitting kelly drive 140 to rotate therein. Drill rig 100 may provide rotary head 136 with a 16-inch diameter pipe secured to a conductor pipe of casing 16. Rotary head 136 may facilitate handling drilling mud flowing upward through casing 16.

Swivel 142 may be a mechanical device that suspends the weight of drill pipe 170, provides for the rotation of the drill pipe 170 beneath it while keeping the upper portion stationary, and permits the flow of drilling mud 154 from a standpipe 162 without leaking. Swivel 142 may hang directly under a traveling block 150 of hoisting system 130 directly above kelly drive 140. Swivel 142 may provide the ability for the kelly and subsequently drill string 112 to rotate while allowing hoisting system 130 to remain in a stationary rotational position. In addition, swivel 142 may allow vertical movement of drill string 112 up and down derrick 102 while simultaneously allowing the introduction of drilling fluid into drill string 112.

Drilling mud circulation system 132 may be a group of independent but interrelated elements that cooperate to circulate drilling fluid 154 into and out of borehole 10. Drilling fluid 154 may be a fluid such as water based and non-aqueous mud or gaseous drilling fluid used to drill boreholes into the earth. Drilling fluid 154 may provide hydrostatic pressure within wellbore 10 to prevent formation fluids from entering into wellbore 10. In addition, drilling fluid 154 may keep drill bit 202 cool and clean during drilling, and may carry out drill cuttings 156 from wellbore 10. This description may use the term mud, drilling mud, and drilling fluid 154 interchangeable.

Drilling mud circulation system 132 may include a mud pump 158, a mud pit 160, a standpipe 162, a kelly hose 164, and a mud return line 166. Drill rig 100 may connect mud pump 158 to mud pit 160. Drill rig 100 may position standpipe 162 between mud pump 158 and kelly hose 164. In addition, drill rig may connect kelly hose to drill string 112 and may connect mud return line 166 between overgauge 22 of borehole cavity 18 and mud pit 160. In operation, mud pump 158 may draw mud 154 from mud pit 160 to pass mud 154 down through standpipe 162, kelly hose 164, drill string 112, and up through casing annulus 22 and mud return line 166 to return mud 154 and the retrieved cuttings 156 to mud pit 160.

Mud pump 158 may be a large, high-pressure reciprocating pump used to circulate drilling mud 154 on drill rig 100. Mud pit 160 may be a steel tank secured to ground 12 or an open pit dug in ground 12 to hold drilling mud 154 or waste materials such as well bore cuttings or drilling mud sediments. Standpipe 162 may be a rigid metal conduit fixed to metal beams 114 to provide a pathway for drilling mud 154 to travel about one-third of the way up derrick 102, where it connects to kelly hose 164. Kelly hose 164 may be a flexible, steel reinforced, high pressure hose that connected to swivel 142 to connect standpipe 162 to a goose-neck on swivel 142 above the kelly. Kelly hose 164 allows free vertical movement of the kelly while facilitating the flow of drilling fluid 154 through the system and down drill string 112. Mud return line 166 may be a pipe to connect mud pathways in blowout prevention equipment 110 to mud pit 160.

Drill string 112 may be a hollow column/string of mechanical components to transmit rotational power and drilling fluid to a drill bit 202. Drill string 112 may include a transition pipe 168, a drill pipe 170 (or drill rod 170), and a bottom hole assembly 200 joined together in series using special threaded connections such as tool joints. Drill string 112 may be hollow to allow drill rig 100 to pump drilling fluid 154 down through drill string 112 and circulated back up annulus 18, since annulus 18 presents a void between drill string 112 and formation borehole 10.

Drill pipe 170 may be heavy seamless steel tubing utilized to rotate drill bit 202 and circulate drilling mud 154. Each section of drill pipe 170 may be about 30 feet long, where threaded tool joints may fasten them together. In addition, drill string 112 may use drill stem subs to connect drill string 112 elements. Drill string 112 typically may be about 15,000 feet (4.6 km) long for an oil or gas well vertically drilled onshore in the United States and may extend to over 30,000 feet (9.1 km) for an offshore deviated (non-vertical) well. Drill pipes 170 makes up the majority of drill string 112.

The below description provides details on a multiplier sub 300 (FIG. 5). The multiplier sub 300 may be utilized as part of a bottom hole assembly 200 in a drill rig to maintain a desired revolutions per minute (rpm) of a drill bit 202 while decreasing the speed of rotary equipment such as drill rods 170, a rotary head (not shown), and a rotary table (not shown).

For example, a drill rig may include an above ground tool drive prime mover and may operate both the drill bit 202 and the above-ground rotary equipment at 200 rpms. However, a drill rig utilizing a series of two multiplier subs in a drill string 12 may operate the aboveground rotary equipment at 50 rpm. The first multiplier sub may double the 50 rpm speed to 100 rpm. The second multiplier sub then may double the 100 rpm to 200 rpm so that the drill bit 202 turns at the desired 200 rpm. The relatively slower 50 rpm speed of drill rods 170, a rotary head, and a rotary table reduce the vibrations experienced in the drill rig. In addition to this below ground mechanical system reducing vibrations in the above ground drill rig 100, the multiplier sub 300 provides benefits similar to that of a downhole motor without the added cost of a separate high-pressure drilling mud system needed to operate a down-hole motor. Various elements of conventional rotating drilling systems referenced throughout this portion of the specification, including above-ground portions of such systems, are found in textbooks and widely disseminated literature related to oil and gas well drilling, including, but not limited to, R. Baker, “A Primer of Oilwell Drilling” (5thEdition, Petroleum Extension Service, Univ. of Tex., Austin, 1996), the entirety of which is incorporated herein by reference.

FIG. 5 is a detailed view of a bottom-hole assembly 200. The bottom-hole assembly (BHA) 200 may be the lowest 70-100 meters portion of the drill string. As a group of components that make up the lower end of the drill string, the bottom-hole assembly 200 may include the drill bit 202, a drill bit sub 204, a first multiplier sub 206, and a second multiplier sub 208. The bottom hole assembly 200 may connect the first multiplier sub 206 and the second multiplier sub 208 together and may connect the drill bit sub 204 between the drill bit 202 and the second multiplier sub 208.

The bottom-hole assembly 200 additionally may include drill collars, which are heavy, thick-walled tubulars, used to apply weight to the drill bit 202, and stabilizers to keep the drilling assembly centered in the borehole 11. The bottom-hole assembly 200 also may contain other components such as a rotary steerable system, a measurement while drilling (MWD) tool, and a logging while drilling (LWD) tool. The drill bit 202, drill bit sub 204, first multiplier sub 206, and second multiplier sub 208 are discrete components and the bottom hole assembly 200 may place other elements between them.

The cutting elements 210 may be a roller-cone device attached to the end of the drill string 12 having cutters to break apart, cut, or crush rock formations when drilling the wellbore 11. In one example, the cutting elements 210 may be part of a polycrystalline diamond compact (PDC) cutter as discussed, supra. The circulating element 212 may permit the passage of drilling fluid (such as mud) and may use hydraulic force of drilling mud to improve drilling rates. The drill bit pin connector 214 may be a male threaded part of a thread coupling having a cooperating female thread box to mate two discrete parts of the drill string 12. The drill bit pin connector 214 may be a rotary-shouldered tool joint having a conical shape.

“Sub-” is a prefix that may mean under or below. In wellbore drilling, subs are small sections of pipe run between and below drill collars and other drill string elements to do various functions. The bottom hole assembly 200 may use the drill bit sub 204 to make a connection between drill bit 202 and the second multiplier sub 208. The drill bit sub 204 may include a drill bit sub box connector 216 connected to a drill bit sub pin 218 via a drill bit sub body 220. The bottom hole assembly 200 may screw the drill bit pin connector 214 into the drill bit sub box connector 216 and secure the two together with a cotter pin, for example. Here, the drill bit pin connector 214 and the drill bit sub box connector 216 may form a pin-to-box joint where one end of this male-to-female coupling is threaded on the outside (pin) and the opposite end threaded on the inside (box).

In operation, the drill pipe 170 and an outside portion of the first multiplier sub 206 may spin in a clockwise direction (i.e., a right hand rotation) shown by a first arrow 222. FIG. 7 provides an axial view of this rotation.

The right hand rotation of the superior or first sub causes both an inside portion of the first multiplier sub 206 and an outside portion of the second multiplier sub 208 to rotate in an opposite direction, namely in a counterclockwise (i.e., left hand rotation) direction shown by a second arrow 224. FIG. 8 provides an axial view of this left hand rotation.

The simultaneous left hand and right hand rotations of the first and second multiplier subs respectively causes an inside portion of the second multiplier sub 208, drill bit sub 204 and drill bit 202 to rotate in the originally intended direction, namely a clockwise direction (i.e. right hand direction) shown by a third arrow 226. Here, the rotational speed of bottom hole assembly 200 may increase by a factor of two for each change in direction. Thus, as the drill pipe 170 is rotated at 50 rpms, the first multiplier sub 206 will multiply that speed by a factor of two to increase it from 50 rpms to 100 rpms. The second multiplier sub 208 then may increase that 100 rpms by a factor of two, so that the drill bit 202 eventually turns at 200 rpms—or some other desired rotational speed.

FIG. 6 is a side, elevated view of the multiplier sub 300. A drill rig may utilize the multiplier sub 300 to form an elongated hole 11 by dislocating solid material of the earth 9. The multiplier sub 300 may be a device to multiply the revolutions per minute of drill pipe 170 above it. Rather than requiring a separate mud machine to push extremely high pressure mud into a downhole motor to turn the drill bit as in U.S. Pat. No. 4,613,002 (Pitman et al.), the drill rig 200 may mechanically drive the multiplier sub 300 with the torque of drill pipe 170 itself to increase the revolutions per minute of drill bit 202. Here, the multiplier sub 300 may be a drilling sub designed to mechanically increase the rotations per minute (RPM) of drill bit 202 without increasing the speed of drill rods 170, rotary head, or rotary table 138 above hole. The multiplier sub 300 will have benefits expected from a downhole motor without the added cost of high pressure drilling mud systems to operate the device. In one example, the multiplier sub 300 may have an overall length of approximately thirty inches.

The multiplier sub 300 may include a sleeve 302, a mandrel 304, a first gear cluster 402, a second gear cluster 404, a mandrel bearing 310, an upper bearing 312, an intermediate bearing 314, a lower bearing 316, and a lock 318. The multiplier sub 300 may arrange the mandrel bearing 310, the first gear cluster 402, the intermediate bearing 314, second gear cluster 404, lower bearing 316, and lock 318 top down within the sleeve 302 in series to form a stack centered on a main axis 320. The multiplier sub 300 may center the mandrel 304 on the main axis 320 within this stack to extend out of the sleeve 302. The drill string 12 may attach the second multiplier sub 206 or drill bit sub 204 to the multiplier sub 300. In operation, the drill string 12 may spin the sleeve 302 in a first direction at a first speed. The first gear cluster 402 and second gear cluster 404 may increase this speed so that the second gear cluster 404 changes directions and speeds up.

The pin connector 322 may be a threaded male connector to engage female threads to form a rigid sealed pipe joint. The pin connector 322 may receive motion from uprotation components. The pin connector 322 may include pin threads 334 extending radially outward from sleeve top 330 to a pin base 336 and a make and break pin shoulder 338 positioned around pin base 336 and positioned above a pin tong area 340. That area within the sleeve inner surface 328 from the sleeve top 330 through pin tong area 340 may form a pin fluid conduit 342. The pin fluid conduit 342 may be a hollow cylindrical shape through which drilling mud may pass downward.

The mandrel tube 360 may be a long, hollow, cylindrical object so as to receive motion from the sleeve 302 through the first gear cluster 402 and second gear cluster 404 and impart that rotational motion to box connector 358. That area within mandrel inner surface 364 from the mandrel top 366 through the box tong area 376 may form a box fluid conduit 378. This conduit 378 may be a hollow cylindrical shape to receive drilling mud from pin fluid conduit 342 to pass the mud downward. In one example, the box fluid conduit 378 may have a diameter of approximately 1½ inches.

FIG. 7 is a section view of multiplier sub 300 taken along line 6-6 of FIG. 6. As noted above, first gear cluster 402 may be a grouping of pin gears 406 positioned between the first sleeve teeth set 348 and the first mandrel teeth set 384 to reside radially around main axis 320. In this example, first gear cluster 402 may include six pin gears 406 equally spaced around the main axis 320. A limit diameter may be a diameter on a gear at which a line of action intersects a maximum addendum circle of the mating gear for an external gear and intersects a minimum addendum circle of the mating gear for an internal gear. Each pin gear 406 may include a first pin gear limit diameter 420. In one example, the first pin gear limit diameter 420 may range from ⅝ to ¾ inches.

Each pin gear 422 may include a second pin gear limit diameter 438. In one example, the second pin gear limit diameter 438 may be different from the first pin gear limit diameter 420. In practice, the first gear cluster 402 will receive the load before the second gear cluster 404 potentially to cause uneven wear between the two gear clusters. By making the second pin gear limit diameter 438 different from first pin gear limit diameter 420, multiplier sub 300 may work to adjust the transmitted load to be balanced between the first gear cluster 402 and second gear cluster 404 so that each gear system may experience substantially similar wear. In one example, the second pin gear limit diameter 438 may be more than the first pin gear limit diameter 420. In another example, second pin gear limit diameter 438 may be ninety percent of the first pin gear limit diameter 420.

The mandrel bearing 310 may be a support placed between pin tong area 340 and mandrel top 366 to allow them to move easily. In addition to permitting rotation between the parts, the mandrel bearing 310 may take thrusts from mandrel 304 parallel to the main axis 320 of revolution to support a high axial load while permitting rotation between the pin connector 322 and mandrel tube 360. The mandrel bearing 310 also may act as a seal to prevent leakage of lubrication fluid and drilling fluid 154. The multiplier sub 300 may position mandrel bearing 310 within sleeve tube interior 344 and secure mandrel bearing 310 within a seat formed in pin tong area 340.

The upper bearing 312 may be a device to allow constrained relative motion between the sleeve tube 324 and mandrel tube 360 so that each may rotate with very little rolling resistance and with little sliding. In addition to allowing rotation movement of the sleeve tube 324 and mandrel tube 360, the upper bearing 312 may function as an upper support for the first gear cluster 402 and allow each pin gear 406 to rotate about its pin gear axis 412 while taking thrusts from the first gear cluster 402 parallel to the main axis 320 of revolution. The upper bearing 312 also may act as a seal to prevent leakage of lubrication fluid and drilling fluid 154. The multiplier sub 300 may position upper bearing 312 within the sleeve tube interior 344 and secure the upper bearing 312 against the pin tong area 340 between the sleeve tube 324 and mandrel tube 360. The multiplier sub 300 may rotatably fix each first upper stem 414 within upper bearing 312.

In addition to allowing rotation movement of the sleeve tube 324 and mandrel tube 360, the intermediate bearing 314 may function as an intermediate support for the first gear cluster 402 and second gear cluster 404. The intermediate bearing 314 may allow each pin gear 406 and each pin gear 422 to rotate about its pin gear axis while taking thrusts from the first gear cluster 402 and second gear cluster 404 parallel to the main axis 320 of revolution. The intermediate bearing 314 also may act to allow lubrication fluid to flow through intermediate bearing 314. The multiplier sub 300 may position intermediate bearing 314 within the sleeve tube interior 344 and secure the intermediate bearing 314 between the sleeve tube 324 and mandrel tube 360. The multiplier sub 300 may rotatably fix each first lower stem 416 and each second upper stem 430 within intermediate bearing 314.

The lower bearing 316 allows constrained relative motion between the sleeve tube 324 and mandrel tube 360 so that each may rotate with very little rolling resistance and with little sliding. In addition to allowing rotation movement of sleeve tube 324 and mandrel tube 360, the lower bearing 316 may function as a lower support for the second gear cluster 404 and allow each pin gear 422 to rotate about its pin gear axis 428 while taking thrusts from the second gear cluster 404 parallel to the main axis 320 of revolution. The lower bearing 316 also may act as a seal to prevent leakage of lubrication fluid and drilling fluid carrying fragmented cuttings. The multiplier sub 300 may position the lower bearing 316 within sleeve tube interior 344 at a position above and against the lock 318 and secure the lower bearing 316 between the sleeve tube 324 and mandrel tube 360. The multiplier sub 300 may rotatably fix each second lower stem 432 within lower bearing 316.

The lock 318 may be a threaded ring that may hold elements within the sleeve tube interior 344. The lock 318 may screw into the sleeve tube interior 344 at a position near the sleeve bottom 332. The main axis 320 may be a straight line through multiplier sub 300 to act as a center around which the multiplier sub 300 may rotate.

When assembled, multiplier sub 300 defines a lubrication channel 390. The lubrication channel 390 may be an empty space between the sleeve tube 324 and mandrel tube 360 and between the components residing between sleeve tube 324 and mandrel tube 360. The multiplier sub 300 may pack the lubrication channel 390 with lubricant such as oil, grease, or other friction-lessening substance to reduce friction and minimize heating. In addition to lubricating the mandrel bearing 310, upper bearing 312, intermediate bearing 314, and lower bearing 316, the lubricant 392 may lubricate first gear cluster 402 and second gear cluster 404.

A teeth ratio between sleeve 302, mandrel 304, and first gear cluster 402 and between sleeve 302, mandrel 304, and second gear cluster 404 may be such that the rotational speed of sleeve 302 may be stepped upwards by a multiple so that a rotational speed of mandrel 304 may be greater than a rotational speed of the sleeve 302. In one example, the teeth ratio may step up the rotational speed of sleeve 302 by a multiple of two so that the mandrel 304 spins twice as fast as the sleeve 302. Generally, the invented multiplier sub can impart rotation speeds to the bit 14, or 212 that are between approximately 2 to 6 times faster than the rotation of the drill string 12 or sleeve 302.

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The most widely used mud pumps across the industry are Triplex Reciprocating Pumps. Their application has gained immense popularity with time because they are 30% lighter than duplex reciprocating pumps with relatively less operational cost. Moreover, through these pumps the discharge of mud is smooth and they are capable of moving large volume of mud at higher pressure.

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The most widely used mud pumps across the industry are Triplex Reciprocating Pumps. Their application has gained immense popularity with time because they are 30% lighter than duplex reciprocating pumps with relatively less operational cost. Moreover, through these pumps the discharge of mud is smooth and they are capable of moving large volume of mud at higher pressure.

The different parts of a mud pump are Housing itself, Liner with packing, Cover plus packing, Piston and piston rod, Suction valve and discharge valve with their seats, Stuffing box (only in double-acting pumps), Gland (only in double-acting pumps), and Pulsation dampener. A mud pump also includes mud pump liner, mud pump piston, modules, hydraulic seat pullers along with other parts.

The wearing parts of a mud pump should be checked frequently for repairing needs or replacement. The wearing parts include pump casing, bearings, impeller, piston, liner, etc. Advanced anti-wear measures should be taken up to enhance the service life of the wearing parts. This can effectively bring down the project costs and improve production efficiency.

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mgj-50l crawler drill rig for anchoring and jet-grouting is a type of integration of crawler, mud pump and control panel based on original mgj-50 drill rig for anchoring and jet-grouting.