System to Improve the Control of Downhole Tool-Strings Used in Radial Drilling

Abstract

An apparatus, method and system for dampening the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present filing claims priority to provisional patent application 62/285,095 filed on Oct. 19, 2015.

FIELD

The present disclosure generally relates to drilling wellbores into a subterranean formation and more particularly to short radius lateral drilling procedures. This disclosure addresses control efficiency of short radius lateral drilling procedures and has application to oil, gas, water and geothermal wells.

BACKGROUND

Natural resources such as oil and gas located in a subterranean formation can be recovered by drilling a wellbore down to the subterranean formation, typically while circulating a drilling fluid in the wellbore. The wellbore is drilled with the use of a tool string consisting of drill pipe, various tools and having a drill bit on the distal end. During the drilling of the wellbore drilling fluid is typically circulated through the tool string and the drill bit and returns up the annulus between the tool string and the wellbore. After the wellbore is drilled typically the tool string is pulled out of the wellbore and a string of pipe, e.g., casing, can be run in the wellbore. The drilling fluid is then usually circulated downwardly through the interior of the pipe and upwardly through the annulus between the exterior of the pipe and the walls of the wellbore, although other methodologies are known in the art.

Slurries such as hydraulic cement compositions are commonly employed in the drilling, completion and repair of oil and gas wells. For example, hydraulic cement compositions are utilized in primary cementing operations whereby strings of pipe such as casing are cemented into wellbores. In performing primary cementing, a hydraulic cement composition is pumped into the annular space between the walls of a wellbore and the exterior surfaces of the casing. The cement composition is allowed to set in the annular space, thus forming an annular sheath of hardened substantially impermeable cement. This cement sheath physically supports and positions the casing relative to the walls of the wellbore and bonds the exterior surfaces of the casing string to the walls of the wellbore. The cement sheath prevents the unwanted migration of fluids between zones or formations penetrated by the wellbore.

The drilling of a horizontal well typically involves the drilling of an initial vertical well and then a lateral extending from the vertical well which arcs as it deviates away from vertical until it reaches a horizontal or near horizontal orientation into the subterranean formation.

In short radius drilling specialized tools are swept around a tight radius of a whipstock and are then used to form lateral boreholes radiating outward and into the subterranean formation. Short radius lateral drilling is distinct from more-familiar conventional horizontal and coil tubing drilling. In conventional horizontal and coil tubing drilling procedures, the drilling tools are swept around a radius or “heel” that is hundreds or even thousands of feet in size. That is, in both of these procedures virtually all of the change in direction takes place outside of the wellbore proper. By contrast, in short radius drilling, the primary change of direction occurs inside of the wellbore itself—that is, it occurs literally in the matter of a few inches.

As wellbores suited to this procedure commonly have a diameter of between about 4½″ to 7″, this equates to radii of between about 2¼″ to about 3½″ inches. In many short radius lateral drilling procedures a full 90 degree arc or “heel” is completed within the wellbore—that is, within about 0.25 ft (3 inches). This contrasts markedly with coiled tubing drilling, which often requires on the order of 250 feet and with conventional horizontal drilling which can utilize on the order of 2,500 feet for a full 90 degree heel. Conventional horizontal drilling technologies operate at a scale 3 to 4 orders of magnitude larger than those of short radius lateral drilling technologies.

The process of “radial drilling” entails forming extended boreholes (e.g. at least 5 feet) in earthen formations that extend outward from a primary wellbore. In radial drilling, the exit angle from the primary wellbore ranges from 45 degrees to slightly over 90 degrees and form a “radial borehole”. As one might imagine, radial boreholes entail extraordinarily high “build-angles” for the tools. That is, these build-angles are diametrically opposed to those found in conventional rig-based or coiled tubing-based horizontal drilling procedures. In these arts, the tool-string exits the wellbore at extremely shallow exit angles, typically no more than 3 to 5 degrees.

In radial drilling the “heel” of the lateral sweeps out its arc in the matter of a few inches. In fact, typically the entire change of direction takes place inside of the wellbore itself. As typical wellbores range from about 4½ to 9 inches in diameter, the heel (or radius) in radial drilling procedures is literally inches. In more common coiled tubing drilling or conventional horizontal drilling, the heels are 100s or 1000s of feet in size. Basically, radial drilling procedures operate at a scale that is 3 to 4 order of magnitude less than industry-standard methods.

Radial drilling procedures typically entail the placement of a whipstock at a target depth inside the wellbore. Sometimes the whipstock is run on the end of upset or production tubing. Radial drilling related tools and procedures can be used on open-hole completed or cased hole wells. If no opening is present in a cased well, access to the formation is sometimes gained by milling out a section of the metal well casing. More commonly, however, a specialized tool-string is moved down the wellbore and are used to form a small round hole in the casing. In known practices, the tools used to form the hole in the casing are then retracted and a separate formation-drilling tool is inserted downhole. The formation-drilling tools are then directed by the whipstock toward the earthen formation or target zone (through the existing hole in the casing). Obviously, in open-hole completed wells, there is no need to cut the casing. Regardless of whether the well is cased or open hole completed, the tools are manipulated by some form of control-line. The control-line might be a wireline unit, a coil tubing unit (CTU) or jointed-tubing.

The present disclosure generally relates to a system to improve the control efficiency of radial drilling procedures. This disclosure has applicability to oil, gas, water and geothermal wells. In applications this disclosure also allows for wireline units and large diameter coiled tubing units (CTUs) to work efficiently with the “small-scale” tools used in procedures involved in forming or running tools within radial boreholes.

Radial drilling tools are most often deployed by a specialized subcategory of CTUs known as “capillary units”. Presently, the preferred method to deploy radial drilling tools is via purpose-built capillary units. These specialized CTUs are equipped with small-diameter coil tubing—typically ½″ to ¾″ in diameter—and, are paired with smaller, more-precise injector-heads and reels. These “smaller” units contrast with conventional or “full-sized” CTUs in important ways. For example, conventional-scale CTUs utilize much larger and heavier tubing, typically in the range of 1¼″ to over 3″ in diameter. Accordingly, the size of the surface equipment is much larger in order to handle the stiffer and appreciably heavier coiled tubing sting.

Further difference in the injector-heads, the surface-based device above the wellhead that is used to reposition the control-line, also warrants mention. It is ultimately the injector-head that controls the motion on the control-lien and hence weight on bit (WOB) of the downhole tool-string. Again, the “WOB” might be the measure of actual weight on drill bit or merely the set-down force being applied on a tool-string that extends into a radial borehole. Smaller CTUs such as those commonly used in radial drilling applications have injector heads commonly rated for about 5,000 to 10,000 lbs. By contrast, large-diameter CTUs commonly have injector heads capable of pulling over 50,000 lbs. and sometimes can lift well over 100,000 lbs. A further difference between conventional coiled tubing drilling and radial drilling pertains to the range of WOB. In radial drilling, typically the target WOB ranges from about 100 to less than 1,000 pounds. By contrast, in coiled tubing drilling (performed with larger coiled tubing) target WOB commonly ranges from about 5,000 to over 10,000 pounds.

In radial drilling, the smaller purpose-built CTUs are often designed in an effort to more precisely control the up-and-down movement of the coiled tubing string. For example, manufacturers try to control the tubing movement in increments as small as ⅛ of an inch. By contrast, conventional CTUs with their large injector-heads cannot reliably reposition coil-tubing in such fine increments, instead they often operate more on the scale of a 1 inch or so. This is not surprising given that these injector-heads are commonly designed to move 10,000 to over 100,000 pounds at speeds sometimes exceeding 125 feet per minute. It is hard to combine the “brute force” necessary to handle such large weights with a “feather-touch” desirable for radial drilling applications. For one wanting to use a large CTU/injector-head for radial drilling this situation presents an enormous challenge as WOB may need to be managed to below 100 pounds.

Regardless of the control-line and surface equipment used, another need in radial drilling pertains to maintaining a near-constant WOB. The equipment operator needs to feed the control-line into the well at exactly the same rate that the cutting head optimally drills the radial borehole. If the tubing is put in too fast, WOB can be excessive, helical buckling of the control-line can occur and tool-string strings can be damaged. If WOB is too low, the rate of penetration (ROP) suffers, drilling times (and costs) are increased and excessive wear-and-tear can occur on the downhole tools. Basically, regardless of the control-line type, e.g. whether a large CTU or small one, there is a need for an apparatus that aids the equipment operator in maintaining the correct WOB during radial drilling applications.

Radial drilling systems require specialized tools to form the radially-oriented boreholes. Typically these purpose-built drill-strings include some form of flexible hose or short-segmented elements, either of which can be moved around the extremely tight radius inside the whipstock. Because of the scales involved, the tools used in radial drilling procedures are a far smaller in size than those used in conventional horizontal drilling, where there is the luxury of sweeping out the majority of the bend (the heel) after the tool has exited the wellbore.

In most radial drilling procedures the well casing is cut mechanically, but the lateral borehole through the formation is produced by a jetting nozzle run on the end of a hose. Since hoses are flexible, the obvious appeal to this approach is the ease with which the hose transitions around the tight radius of the whipstock. The tools described in this disclosure are different from and not intended for use with the jetting tools used to erode boreholes in radial drilling applications. In jetting drilling systems, the jet head typically has back-jets used to pull the hose forward. By contrast, the tools of this disclosure pertain to applying a desired WOB by pushing on a mechanical tool.

Certain newer and more reliable forms of radial drilling entail mechanically cutting the earthen formation. In some instances, these tools are composed of short individual-elements which transition around the tight radius of the whipstock. Yet other radial drilling embodiments entails some form of counter-wound spring or flexible tubular member that is also pushed against the formation face. Problems with these new systems include: ambiguity of applied WOB; the need to “dampen” or soften the applied WOB (such as when using large CTUs); the need to stop the reverse-torque transferred back up the flexible drill-string if the control-line cannot resist this torque; and the need to transfer or deliver torque from the motor to the flexible tool-string being run into or used to form the radial borehole.

In current radial drilling procedures, the equipment operator attempts to estimate the WOB by looking at their string weight or tare weight. Typically this is done by looking at the reported value from a load-cell positioned on the injector head. In other instances (where an injector head is not used) weight can be indicated by a load-cell measuring the forces acting on a “gooseneck” or rotating sheave. If a radial drilling procedure is being performed at a depth of say 5,300 feet, this effectively means that the equipment operator is trying to determine the WOB using sensors positioned more than a mile away.

While such great distances invite accuracy errors, several other problems arise in radial drilling applications. For example as coiled tubing is spooled into the well, it retains a residual-bend. This residual-bend loads onto whatever the coiled tubing first contacts, typically production tubing that is attached to the whipstock. This side-loading has the effect of “holding-up” or stacking-off some of the weight of the tubing. This stacking-off translates into ambiguity in the reported WOB via the tare weight. A further problem that affects radial-drilling procedures performed with small “flexible” control-lines (e.g. small diameter coiled tubing) is helical buckling. Thus, as the operator lowers the control-line and the attached tool-string encounters an obstruction, the control-line begins to helically-buckle, adding yet further ambiguity to reported WOB values.

A further problem that can affect radial-drilling applications pertains to the reverse torque caused by tool-strings that mechanically drill the radial borehole or otherwise rotate a lower tool-string. This issue is not a problem with large diameter coiled tubing because of the high torsional stiffness of the tubing. However, it is a significant factor in control-lines that involve small diameter coiled tubing or e-lines. Basically, these later control-lines lack the torsional stiffness to resistance the reverse-torque transmitted up the drill-string. Given this flaw, yet another solution is needed for efficient radial drilling applications. For systems that utilize a jetting nozzle to form the hole in the earthen formation this is not an issue, as no meaningful reverse torque is created, not even by a rotating nozzle. Another requirement is that the tool used to resist the torque does so without adding inaccuracies in the WOB values. More specifically, the solution needs to avoid introducing sliding members that producing high-friction/drag that once again creates reported WOB inaccuracies. A final feature of the solution is that it must allow drilling fluid to pass to the lower tool-string in order to wash cuttings out of the radial borehole and/or to exit a cutting head.

Thus, a need exists for a practical system in short radius lateral drilling to maintain desired WOB.

SUMMARY

This disclosure provides a method and apparatus for efficiently forming extended radial boreholes in earthen formation while maintaining a desired WOB. This system can be deployed by a variety of control-lines such as a wireline unit, jointed-tubing or coiled tubing.

This system addresses several problems that currently trouble known radial drilling systems including: 1) it allows the equipment operator to more accurately determine WOB; 2) it enables cutting fluid to wash cuttings debris out of the radial borehole; 3) it dampens the applied weight downhole as the control-line is vertically manipulated; 4) it allows one to continuously form (or drill) the radial borehole without the need to reset or stop the tool during the process; 5) it allows for the efficient transmission of torque to a lower tool-string in mechanical radial drilling applications; and 6) it offers a low-drag solution to simultaneously counteract the reverse-torque of a mechanical tool-string as that string drills into earthen formation.

This disclosure allows radial drilling tools to be run on jointed-tubing, wireline units or coiled tubing of any size. Essentially any of these deployment means can be used in conjunction with and benefit from the system and apparatus described herein. To address the weight control problem, which is especially pronounced when using “clumsy” full-sized CTUs, this disclosure employs a “dampening” sub-assembly. Thus, regardless of the type of control-line or surface control equipment, the equipment operator is able to slowly and smoothly feed tools into the radial borehole.

Certain embodiments of this disclosure entail a means of reporting to the equipment operator the force (or weight) being applied at the tool-string so that accurate determinations of WOB can be ascertained. This combination of more accurately reporting WOB and dampening the applied WOB (drive thrust) allows the operator to stay within the desired WOB/ROP “sweet spot” throughout the process of forming the radial borehole. It also has particular applicability when deploying radial drilling procedures out of horizontal wells, where the force acting on the tool must be measured since the “weight” (vertical) becomes very inaccurate.

Particularly noteworthy is the fact that this solution has been designed for a continuous dampening of WOB during the formation drilling step. For example, one can drill 5, 10, 50 feet or more using this approach and, the operator does not need to reset or otherwise stop the tools to insure the tools operations. Moreover, this dampening functionality is integral to the tool-string itself and does not require some form of “landing out” on an external member.

As this disclosure is ordered to improving the operation of tools used in connection with forming radial boreholes in the earthen formation, provisions are made to insure that fluid (or gas) can reach the end of the tool-string. Further, as embodiments of the apparatus are intended to be used tools used to mechanically drill the radials, a means for transmission of torque through certain apparatus is provided. Embodiments of this disclosure can be placed in a tool-string below a motor and used to transmit torque to a lower tool-string. In certain embodiments this disclosure also provides a means to resist torque such as might be required when using a wireline unit or small diameter coiled tubing that lacks the torsional stiffness necessary to counteract reverse torque created by mechanically drilling the radial borehole. The different embodiments of this disclosure can be placed at varying positions in the downhole tool-string and these positions are also noted.

BRIEF DESCRIPTION OF DRAWINGS

The accompanying views of the drawing are incorporated into and form a part of the specification to illustrate several aspects and examples of the present disclosure, wherein like reference numbers refer to like parts throughout the figures of the drawing. These figures together with the description serve to explain the general principles of the disclosure. The figures are only for the purpose of illustrating preferred and alternative examples of how the various aspects of the disclosure can be made and used and are not to be construed as limiting the disclosure to only the illustrated and described examples. The various advantages and features of the various aspects of the present disclosure will be apparent from a consideration of the figures.

FIG. 1 illustrates a zoomed out view during a radial drilling procedure wherein a downhole toolstring has exited a whipstock and is drilling a hole in earthen formation with the benefit of a dampener subassembly and separate weight indicator assembly.

FIGS. 2A & 2B illustrate a no weight on bit (WOB) and WOB condition, respectively.

FIG. 3a illustrates a dampener sub-assembly having a spring and piston in a “no-load” or no WOB condition.

FIG. 3b illustrates the apparatus of FIG. 3A but in a WOB on bit situation, with the spring dampening the load.

FIG. 4 illustrates a dampener sub-assembly that utilizes a gas charge as the dampener and has a pressure transducer located in a piston so that the amount of force can be communicated up the control-line.

FIG. 5A illustrates a dampener sub-assembly with a fluid-based weight indicator mechanism. The dampener sub-assembly is in a no-load (no WOB) condition.

FIG. 5B illustrates the dampener sub-assembly of FIG. 5A in a WOB condition, evident by the compressed spring. Furthermore, certain ports in the push-rod can no longer vent-off, causing a change in the fluid pressure that can be read at the surface by the operator.

FIG. 6A illustrates an integrated sub-assembly that can transmit torque, dampen applied forces, indicate weight and allows for the transmission of fluid.

FIG. 6B illustrates the FIG. 6A in cross-section at line B and shows the spline-nut.

FIG. 6C illustrates the FIG. 6A in cross-section at line C and shows the dampener sub housing, spline-nut, spline-rod or push-rod, and a hole at the center of the push-rod to allow flow. As evident, torque can be transferred through the spline-rod to the spline-nut.

FIG. 6D illustrates the FIG. 6A in cross-section at line D and shows how this portion of the push-rod also has splines in order to carry torque when in contact with the spline-nut of FIG. 6A.

FIG. 6E illustrates the FIG. 6A in cross-section at line E and shows an inside hole that runs through the push-rod.

FIG. 7A illustrates an anti-torque tool situated above the output shaft of a downhole motor. Projections on the anti-torque tool engage an extended track in a rigid external member to prevent rotation. A flexible drill-string and a drill-head hang below the motor.

FIG. 7B illustrates the apparatus of FIG. 7A drilling a lateral borehole.

FIG. 7C illustrates the apparatus of FIG. 7A in cross-section at line B.

The projections attached to the motor engage the rigid external member, which in this case is an extended slot made into the production tubing.

DETAILED DESCRIPTION

The disclosure described herein has several features most of which can be selectively employed depending upon the tools being run downhole and the control-line and surface equipment deploying them. The various embodiments of this systems can be used with wireline, jointed-tubing or coiled tubing (and CTUs) of any size. As described more fully below, this disclosure helps the equipment operator more easily keep the downhole tools within the WOB/ROP “sweet-spot” when those tools are in the extended radial borehole.

The apparatus of this disclosure can involve more than one sub-assembly and these sub-assemblies can be positioned at varying points along the downhole tool-string. For example, an anti-torque apparatus disclosed herein can be positioned above a downhole motor, while the dampening system disclosed herein could be positioned below the motor. Notably, as the parts comprising the apparatus are generally long and of a large diameter, they do not traverse around the radius of the whipstock, i.e. they do not extend into the lateral borehole itself.

In most embodiments, the apparatus of this disclosure comprises a dampening sub-assembly to allow the equipment operator to better control WOB. In each such case, this dampening sub-assembly is a mechanically compliant element used to slow and soften the transference of weight as the control-line is fed into the well and the head of the tool-string encounters resistance from the formation face. This dampener apparatus reduces any “jerky” motion in the control-line from being transferred to the downhole tools. For example, if a large CTU injector-head “surges” forward in a 1 inch increment, the dampener sub-assembly softens the force seen at the head of the tool-string. This feature helps prevent the tool-sting from becoming overloaded or damaged by the excessive force. Of course, once the lower tool-string has extended a little further into the formation, the now-compressed dampener would extend slightly and thereby help to maintain a favorable WOB. In instances where the downhole tool-string is being used to cutting the radial borehole, this can allow for an optimal ROP.

The dampening sub-assembly would consist of an exterior housing, a piston (or push-rod) and a dampening means. The upper end of the dampener-sub would affix to the tool-string by means of the housing on its one end and the lower end of the dampener-sub would affix to the lower tool-string by means of the piston; these connections can be accomplished by means of threading. In embodiments, the dampening means within the dampener sub would be a compression-spring or Bellville washer(s); in other embodiments the dampening mechanism could be a tension-spring or gas-filled chamber. In yet other embodiments, dampening could be achieved by elastomeric material or the use of magnets that are positioned proximally and in identical polarity so as to repel one another.

The dampening means would be used in conjunction with and in order to act upon the aforementioned piston or push-rod and housing. The dampening means (e.g. a compression-spring) and the piston could be positioned inside the aforementioned housing, with one side of the piston extending beyond the housing. In this fashion one can protect the dampening system from wellbore contaminants. In embodiments involving compression-springs, the spring would generally be positioned away from the lower tool-sting to as sit in a space between the piston and housing so as to be compressed when WOB was applied. One end of the spring would act upon the piston while the other end of the spring would “push” against the housing. In embodiments, the spring could circumscribe the piston and yet act upon the piston by means of a nut or other rest affixed to the piston. Like the compression-spring, embodiments using a gas-filled chamber, elastomeric material or opposing magnets would be generally situated toward the top of the dampener-sub-assembly so as to compress in when WOB was applied. In embodiments entailing a tension-spring, the location of the spring would be reversed from that of the compression spring, namely this spring would be nearer the lower tool-string. Moreover, usage of a tension spring would require that it be firmly affixed to both the housing and the piston.

As is more evident in the figures, the dampener sub-assembly could easily be flipped end-wise. That is, the piston could extend out of the top of dampener-sub-assembly (and then connect to the upper tool-string), while the main housing of the dampener sub is positioned below and connects to the lower tool-string. Similarly, when a gas-filled chamber (or shock) was employed, the piston on which it acts could extend upward or downward.

The dampener assembly is always position above the flexible portion of the tool-string that moves through the whipstock. In operation, as the control-line is moved downward and the end of the flexible tool-string contracts the formation, the housing and piston would act against one another via the dampening means. This dampening means would thus moderate any spike in force applied by a jerky lowering of the tool-string. As the lower tool-string formed a slightly longer lateral, the dampener assembly would then re-extend slightly to assure the continued application of WOB. Notably, this is a continuous drilling system. That is, the operator does not simply “land out” a portion of the tool-string against some form of external stop in the wellbore or on the whipstock and then let the weight “drill off”. Instead the operator continuously feeds the tool-string down the wellbore as the lower tool-string penetrates further into the zone. The combined functionality of dampened WOB and continuous feeding allows for high ROPs, reduced stalling, and an increased life-span of the sensitive tools used in radial drilling of the borehole.

Embodiments of the tool involve using a control-line that is incapable of sufficiently counter-acting torque, such as when deployed by wireline or small-diameter coiled tubing. To address this problem one or more anti-torque projections or “projections” would be incorporated into the downhole tool-string. These projections would be integral or rigidly affixed to the tool-string and would be positioned above the rotating, lower portion of the tool-string. The outside of the projections would engage with a stationary and stiff/unyielding external member such as a slot, rail, or similar “extended slide” mechanism. With this combination of projections and extended slides, the reverse torque could be resisted over the full length of the lateral being drilled. In embodiments, this stiff extended slide would be made of specially modified upset tubing such as that to which the whipstock may be attached.

These projections might not slide freely against the extended slide—such as when resisting high reverse-torque loads. Besides impacting ROP this tends to negating accurate WOB reporting. To negate this problem, this disclosure incorporates means for low-drag travel between the projections and extended slot. This could be accomplished using low-friction materials or some form of bearings or rolling member. For example, the low-friction materials might be brass, Teflon, oil impregnated bronze, or other known materials having a low friction co-efficient. If drag were still too high for smooth lateral movement of the tool-string while under torque, the anti-torque projections could comprise a rolling means, such as cam-followers. Moreover, the slides could be polished or ground to attain an extremely smooth.

Certain embodiments of this disclosure provide the equipment operator an accurate indication of the downhole WOB. This can be done by specially modifications to the dampener-sub-assembly. In embodiments, this is done by placing a load-cell between the end of the springs and the housing in order to measure the applied load. In embodiments where a gas-filled chamber is compressed a pressure transducer can be used.

The WOB value can be sent to the surface by means of the control-line. In the instance of wireline deployments, this can be done directly thru a conductor cable in the wireline, while in the instance of coiled tubing or jointed-tubing it can be done by mud pulse telemetry. In one variant discussed below, no special electrical componentry is required to convey this information thru the drilling fluid to the surface.

In these embodiments, WOB is ascertained at the surface by directly measuring pressure or flow change that occur in the drilling fluid when a specially-modified dampening apparatus experiences changing loads. In these embodiments when the drilling fluid flowing through the special dampener apparatus, the fluid passes a number of ports that would be either opened or closed depending upon the degree of compression (or extension) of the dampening tool. If the special dampener assembly was highly compressed, such as when experiencing a high WOB, several of these ports could be open. The opening of successive ports would vent pressure/flow causing a corresponding drop in the fluid pressure and slight increase in the drilling fluid flow rate. The pressure loss evident through each of these pre-defined ports would be known and would correspond to known changes in the applied weight on this special dampener-sub (based upon the known spring). That is, with a known spring rate and with known travel distances between the ports, one could accurately infer WOB based on the changes in the drilling fluid pressure. Again, these values could be measuring the drilling fluid pressure or flow rate at the surface. With this tool, the operator could know the WOB and thereby easily keep the downhole tool in its ROP “sweet spot”. The damping apparatus could have sealing mechanisms (e.g. o-rings) between the piston and the cylinder walls to negate any unwanted leakage out of the tool. This could prevent any unwanted leakage out of the dampener-sub-assembly. Furthermore, in embodiments one or more other o-ring could be employed to isolate an upper and lower chamber between the piston and dampener housing, such as would be useful when wanting to shut off certain vent ports. In certain embodiments, the dampener-sub incorporates a balanced-piston mechanism. That is, one could create a situation where the hydraulic forces acting on the piston (from above and the from below) were acting over equal areas so as to negate any resultant hydraulic forces imbalance that would bias the piston or rod in a lateral direction. In this fashion only the overall compression of the dampening-sub via WOB would move the piston.

The vent ports would be of known sizes. Under any minimal or zero WOB scenario, all of the ports could be blocked or “closed” because of an o-ring on the piston/push rod. In operation, the operator would know that they either had zero or below-threshold WOB as no ports were opened (no pressure drop was seen). However, once the threshold WOB was attained—hence moving the spring and piston—a first vent port would open and some pressure would bleed off. This would tell the operator they had exceeded the corresponding first (known) WOB value. Knowing the size of the various holes and the resultant change in pressure/flow readings (from prior testing), the operator could determine approximately how much WOB was being applied at the dampener-sub.

A practical example, here, may be helpful. For example, if every port bled off 50 psi in the drilling fluid, if the operator saw a 200 psi drop in pressure from baseline, they could quickly ascertain the WOB by knowing the spring rate. Let's say each port was spaced 1 inch apart, then this 200 psi pressure drop would equated to 4 ports being vented (at 50 psi/port) or 4 inches of travel. If the spring rate (known) was 100 lbs/inch, then the WOB would be 400 lbs. In this fashion, an operator could now monitor the downhole WOB in real-time. Moreover, using such an apparatus along with the continuous drilling methods discussed above, one can reliable drill at the optimal ROP.

In embodiments where the dampener-sub is positioned below a motor, it is necessary for the dampener-sub to transmit torque. This can be accomplished by a spline. Optionally, the spline may be incorporated into a special a dampener-sub that indicates weight or one that does not indicate weight. In most embodiments, the spline is integral to the dampener-sub and comprises a series of grooves extending lengthwise along an extended portion of the push rod or cylinder. Said in other words, the design entails the push rod of the dampener-sub also serving as an extended spline shaft. A spline nut rides on the spline shaft and is integral or firmly attached to the dampener-sub housing. In this fashion, the spline shaft and mating nut transmit torque. This arrangement allows for the transmission of toque under compression/extension—an ideal feature, especially in instance where the spline is integral to a dampening-sub.

To assure fluid (or gas) through the tool-string, each of the apparatus of this disclosure would allow flow through their inside or around their outside. For example, this could be accomplished by a hose running through the interior of the respective sub-assembly or an external by-pass tube. As the dampener assembly requires compression and extension, one could use a coiled hose either within or along the outside of the main dampener housing. In other embodiments, flow could be thru a hole running the length of the piston in the dampener assembly. Furthermore, one or more o-rings could provide a seal between the piston or push-rod and the inside housing of the dampener assembly.

In embodiments an extension of the spline shaft also incorporate the ported vents used to indicate weight, as discussed above. In these embodiments, this apparatus has accomplished the very desirable objectives of: smoothing the application of WOB (via the dampener), reporting the WOB to the equipment operator (via the ports and pressure changes); and, transmitting torque (via the spline).

Similar to the issue discussed above for assuring a low-friction surface between the projections and extended slots, the splines subs of this disclosure also provide for a low-drag means experiencing high torque loads. In embodiments the “male” and “female” members of the spline could be made of or coated with a material whose coefficient of friction is low, could incorporate hardened or ground and polished surfaces or could transmit the torque through a series of recirculated balls positioned between the spline shaft and the spline nut.

In another embodiment, the spline apparatus consists of a series of long axial rods positioned toward the outside of the tool and forming a sort of “cage”. The rods could be held into position by a housing. An extended, mating “star” would be positioned inside the cage created by the axial rods. Torque could thus be transferred through this “spline” by means of the extended axial rods and mating star. A dampening mechanism, like those described above could be positioned between the housing and the end of the star so as to again moderate the applied WOB.

The present disclosure also has applicability to forming radial boreholes out of conventional horizontal or slant wells. As the radial drilling string sweeps out the horizontal or slant, the reported weight of the coiled tubing and tool-string becomes inaccurate. This occurs because the weight of the coiled tubing and the tool-string is being supported by the horizontal or slant leg and hence the load-cell at the surface becomes highly unreliable. Moreover, as one pushes the control-line out the horizontal or slant leg, the inferred WOB can become increasing inaccurate due to helical buckling. Used on horizontal wells, the disclosure discussed above can be used to provide operating personnel more accurate WOB values (via the weight indicator means) and to control WOB (via the dampener).

In the sections above we've discussed the different aspects of this disclosure and how they address various current short-coming in the art of radial drilling. In essence this disclosure addresses the following four shortcomings: 1) Weight Indication: the means of this disclosure to indicate WOB to the operator; 2) Dampening: the means of this disclosure to smooth the application of WOB; 3) Torque-Transmission: the means to convey torque through a tool-string with this disclosure; 4) Stopping Reverse-Torque: the projections and external member of this disclosure used to counteract torque.

Common to most, but not all, of these embodiments is the need to allow fluid flow-thru during the extension of the tool into the radial borehole. For example, when actually drilling the radial borehole itself drilling-fluid needs to reach the cutting head. On the other hand, this disclosure can also be used to with tool-strings that do not require fluid to reach the lower tool-string. For example, a tool that is set into position within a pre-created radial borehole by the application of a specific weight, which the operator wants to assure has been attained by a downhole weight indication means.

Having discussed the individual aspects of this disclosure, let us turn now to a summary discussion of how the combinations of these might be incorporated into a downhole tool-string system that is used with radial boreholes—i.e. with boreholes that exit a primary wellbore at between 45 to about 90 degrees.

In embodiments, this disclosure entails a fluid flow-thru means and a means for dampening the forces/weight exerted on a downhole tool-string used while in a radial boreholes.

In embodiments, this disclosure entails a fluid flow-thru means and a torque-resisting system used in conjunction with a downhole tool-string used while in a radial borehole.

In embodiments, this disclosure entails a weight indicator means and a means to dampen the forces/weight applied on a downhole tool-string used while in a radial borehole.

In embodiments, this disclosure entails a weight indicator means and a spline for the transmission of torque through a downhole tool-string used while in a radial borehole.

In embodiments, this disclosure entails a weight indicator means and the means to resist torque generated from a rotating downhole tool-string used while in a radial borehole.

In embodiments, this disclosure entails a spline to transfer torque through a downhole tool-string and a means to dampen the forces/weight exerted on a downhole tool-string used while in a radial borehole.

In embodiments, this disclosure entails a means to resist torque generated from a rotating downhole tool-string and to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, weight indicator means and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, weight indicator means and a spline to transmit torque through a downhole tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, weight indicator means and the means to resist torque generated from a rotating downhole tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, a spline to transfer torque through a downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, a means to resist torque generated from a rotating downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a weight indicator means, a means to resist torque generated from a rotating downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a spline to transfer torque to a downhole tool, a means to resist torque generated from a rotating downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, a weight indicator means, a spline to transfer torque through a downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, a weight indicator means, a means to resist torque generated from a rotating downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, a spline to transfer torque through a downhole tool-string, a means to resist torque generated from a rotating downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

In embodiments, this disclosure entails a fluid flow-thru means, a weight indicator means, a spline to transfer torque through a downhole tool-string, a means to resist torque generated from a rotating downhole tool-string and a means to dampen the forces/weight exerted on that tool-string used while in a radial borehole.

The embodiments above where the tool is placed below a motor would require the spline be positioned below the motor. Similarly, in the embodiments above where a torque-stopping means were employed, this tool would be placed above the output shaft of the motor.

FIG. 1 is a zoomed-out view illustrating the downhole tool assembly (15) used in conjunction with a flexible drilling-string (10) with attached drill-head (11). The system is deployed by a control-line (2), in this case large-diameter coiled-tubing (2) controlled by a coiled tubing unit (1a). The coiled tubing unit (1a) can measure the pressure (1c) in the control-line (2) as well as flow by virtue of an in-line flow meter (1b). Evident in the figure is a wellbore (5), a wellhead (5b), production tubing (3), a whipstock (9), an anchor (13) and the earthen formation (14) into which a lateral borehole (12) is being drilled. In this case, the downhole-tool assembly (15) consists of a weight indicator sub-assembly sub (4) positioned above a downhole motor (6) and a dampener sub-assembly (7) positioned below the downhole motor (6). The dampener sub-assembly (7) is connected to the flexible drill-string (10).

FIG. 2A a flexible drill-string (10), with attached drill-head (11), is positioned in a lateral borehole (12). As the drill-head (11) is not in contact with the earthen formation (14) being drilled, there is no weight-on-bit (WOB).

FIG. 2B illustrate the flexible drill-string (10), drill-head (11), earthen formation (14) and borehole (12) of FIG. 2A, but the drill-head (11) is in contact with and is drilling the earthen formation (14) causing WOB.

FIG. 2C shows a cross-section of the apparatus of FIG. 2A and how a flow path (16) and exit passageways (17) in the drill-head (11) allow for fluid flow (as shown by arrows).

FIG. 3A illustrates a dampener sub assembly (7) comprising of a tension spring (18) contained in a main housing (19). The main housing (19) is connected to an upper housing (20) through which a push-rod (21) can travel. The push-rod (21) is in turn connected to an upper tool-string (22), while the main housing (19) is connected to a lower tool-string (23). One end of the tension spring (18) rests against the main housing (19) while the other end of the spring (18) rests against a piston (24) that is connected to the push-rod (21). A passage-way (25) through the push-rod (21), a chamber (26) in the main housing (19) and an opening (27) in the main housing (19) assure fluid flow (as shown by arrows) through the dampener sub-assembly (7). There is no WOB on the lower tool assembly (not shown but as exemplified in FIG. 2A) and hence the tension spring (18) is fully-extended in the main housing (19).

FIG. 3B illustrates the same dampener sub assembly (7) as in FIG. 3A. In this case, however, WOB has been applied to the end of the lower tool-assembly (not shown but as exemplified in FIG. 2B). This has caused the lower tool-string (23) and attached main housing (19) to move upward (as shown by the arrow) relative to the push-rod (21) and piston (24). In the process, the spring (18) has been compressed between the piston (24) and main housing (19). The spring (18) has thus acted to dampen the applied load (not shown) on the lower tool-string (23).

FIG. 4 is an illustration in which the dampener subassembly (7) comprises a gas-filled chamber (28) and transducer (29) to report the load reading (not shown) to the equipment operator (not shown, but at surface). This dampener assembly (7) has an upper housing (20) that is connected to a main housing (19) in which is are an upper chamber (30) and a lower chamber (31) that are separated by a movable piston (24) attached to a push-rod (21). The piston (24) has an o-ring seal (37) that seals against the inside wall (33) of the main housing (19). The push-rod (21) also has an o-ring (34) that seals against the top housing (20). A pressure transducer (29) measures the pressure in the gas-filled chamber (28) and reports this value (not shown) via a wire (35) running inside of the control-line (2), which in this case is coiled tubing. Fluid (shown by arrows) travels through the coiled tubing (2), the push-rod (21), the lower chamber (31) and enters the lower tool string (23). As WOB is applied (as indicated by the direction of the arrow at left) to the downhole tool (not depicted here but shown in FIG. 2B) the downhole tool moves the main housing (19) upwards relative to the piston (24), compressing the gas (36) in the upper chamber (30). The gas (36) in the upper chamber (30) serves to dampen the load.

FIG. 5A illustrates a dampener sub-assembly (7) with integrated weight indicator (38) shown inside of upset tubing (3) in a no WOB condition of a downhole tool-string (not shown but exemplified in FIGS. 2A and 2C). The dampener sub-assembly (7) comprises a spring (18) that sits against a top rest (39). The top rest (39) is attached to the control-line (2) and also to a push-rod (21) that extends thru a main housing (19). An o-ring (34) seals between the push-rod (21) and main housing (19). The spring (18) pushes against the top (40) of the main housing (19). The lower end (41) of the push-rod (21) extends through the main housing (19) and through a barrier (42) that is securely affixed to the main housing (19). An o-ring (43) seals between the barrier (42) and the push-rod (21). A cylinder (44) is securely fixed to the push-rod (21) and an o-ring (54) seals between the cylinder (44) and the inside wall (33) of the main housing (19). This arrangement defines an upper chamber (45), a middle chamber (46) and a lower chamber (47). A lower housing (48) connects securely to the main housing (19); the lower housing (48) is also securely fixed to a lower tool-string (23). The middle chamber (46) has a vent (49) in the main housing (19) so as to allow free travel of the cylinder (44). Fluid or gas (shown by arrows) can flow from the control line (2), through the push-rod (21) and cylinder (44) into the lower chamber (47). A hole (50) in the lower housing (48) allows flow (shown by arrow) from lower chamber (47) into the lower tool-string (23). A lower port (51) crosses from the push-rod (21) into the upper chamber (45), allows flow (shown by dotted-line arrow) into the upper chamber (45) so as to balance the hydraulic forces acting on the push-rod (21). A middle port (52) and upper port (53) of known sizes and positions also traverse through the push-rod (21). Without any WOB, the spring (18) is fully extended; and as such, the middle port (52) and upper port (53) are venting (as shown by dotted-line arrows) a known amount of fluid/pressure out of the push-rod (21) and into the upset tubing (3), thereby indicating to the equipment operator (not shown) a no WOB condition.

FIG. 5B is illustrates of the dampener sub-assembly (7) of FIG. 5A when a lower tool-string (23) is under a WOB condition (not shown but exemplified in FIG. 2B). In this case, the main housing (19) has moved upwards (as indicated by the vertical arrow at left), compressing the spring (18). This has caused the middle port (52) and upper port (53) to no longer vent into the upset tubing (3) but instead they “vent” into the already-filled upper chamber (45). This causes an increase in pressure and decrease in flow in the control line (2) which can be measured at the surface by items 1b and 1c shown in FIG. 1, allowing the operator (not shown) to know and control the WOB. That is, by using a spring (18) with a known spring-rate and by knowing the placement and sizing of the upper port (53) and middle port (52) the equipment operator (not shown) can ascertain the WOB from changes to pressure and flow seen by items 1b and 1c shown in FIG. 1.

FIG. 6A illustrates a dampener sub-assembly (7) similar to that shown in FIGS. 5A and 5B. In this case, however, the dampener sub-assembly (7) not only allows for dampening of applied forces, indication of WOB (to the equipment operator at the surface) and the transmission of fluid, but it also allows for the transmission of torque. In this version, the dampener sub-assembly (7) consists of a push-rod (55) the upper portion of the push rod (55a) has an external spline (evident in FIG. 6D) so as to transmit torque to a mating spline-nut (65), with internal splines (evident in FIG. 6B). The upper portion of the push-rod (55a) runs through the mating spline-nut (65) as shown in FIG. 6C. The spline-nut (65) is securely affixed to the main housing (19) in order to transmit torque to the main housing (19). The push-rod (55) defines a passageway (56) for the passage of fluid or gas (shown by arrows) to an attached lower tool-string (23). The push-rod (55) also defines an upper port (53), middle port (52) and lower port (51) that allow flow (as shown by dotted arrows). The top (57) of the spline-rod (55) is connected to a top rest (39) and the top rest (39) is connected to a downhole motor (6). As the downhole motor (6) rotates the top rest (39), the attached spline-rod (55) is rotated, rotating the spline-nut (65), attached main housing (19), lower housing (48) and lower tool-string (23). Furthermore, in operation, the spring (18) dampens the WOB while the spline-rod (55) and mating spline-nut (65) assure the transmission of torque. WOB is indicated by changes in pressure via upper port (53) and middle port (52), as described in FIGS. 5A and 5B. The lower portion (55b) of the push-rod (55) is without a spline (evident in FIG. 6E).

FIG. 6B illustrates the FIG. 6A in cross-section at line B. The spline nut (65) with internal spline teeth (66) can be seen.

FIG. 6C illustrates the FIG. 6A in cross-section at line C. Evident are the main housing (19), spline-nut (65), upper spline-rod (55a), and the passageway (56) at the center. Torque is transmitted via the mating spline teeth (66 and 67).

FIG. 6D illustrates a portion of the FIG. 6A in cross-section at line D. Evident in this figure are the external spline teeth (67) and inner passageway (56) of the upper push rod (55a).

FIG. 6E illustrates a portion of the FIG. 6A in cross-section at line E. Evident in this picture is the lower portion of the spine-rod (55b) and inner passageway (56).

FIG. 7A illustrates an anti-torque tool (70) situated above the output shaft (6f) of a downhole motor (6) for use with a control-line (2) that poorly resists torque. The anti-torque tool or projections (70) is wider (evident along line B) than the downhole motor (6) and mates with an extended, rigid anti-torque member (71) positioned below production tubing (3). The anti-torque member (71) and anti-torque tool (70) when used in conjunction provide continuous resistance to the reverse torque caused by the drill-head (11) and flexible drill-string (10) when in operation. The vertical length (shown by extended arrow at right) of the anti-torque member (71) allows for the anti-torque tool (70) to travel vertically along the anti-torque member (71) and thus this system allows for continuous torque resistance as the downhole motor (6) travels vertically. In this figure the drill-head (11) is located above the whipstock (9) and a hole (5d) has previously been cut in the casing (5c). The top of the downhole motor (6) is connected to a weight indicator sub-assembly (4) which in turn is connected to the control line (2), in this case coil tubing (2).

FIG. 7B illustrates the same set up as FIG. 7A except in this case a lateral borehole (12) is being drilled. The figure shows that as the drill-head (11) cuts the lateral borehole (12) the anti-torque tool (70) moves along the anti-torque member (71), thereby providing continuous torque resistance so that the torque does not twist the downhole motor (6) and thin control-line (2).

FIG. 7C illustrates the apparatus of FIG. 7A in cross-section at line B. As can be seen the anti-torque tool (70) mates inside the rigid anti-torque member (71). The output shaft (6f) and inner passageway (6e) of the downhole motor (6) are also evident. The anti-torque tool (70) is securely affixed to the motor (6) and rides along slots (72) in the anti-torque member (71).

In an embodiment of the present disclosure there is an apparatus for dampening the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, the dampening apparatus includes a housing, a push-rod and at least one dampening member. The dampening member can be a tension spring, a compression spring, a gas-filled chamber, an elastomeric material or a magnet.

Optionally the apparatus can include one or more of the following elements: a spring that extends when additional weight on bit is applied at a cutting head, a spring that compresses when additional weight on bit is applied at a cutting head, magnets oriented such that they repel each other or a sealed gas-charged chamber.

In an optional embodiment the apparatus includes an internal hose running the length of the apparatus, one or more inner passageways running the length of the apparatus, and a conduit running the length of the apparatus external to the housing.

In an optional embodiment the apparatus includes one or more anti-torque projections extending from the housing. The anti-torque projections can provide continuous, low-drag movement when in contact with an external member. The anti-torque projections in contact with an external member resists applied torque.

In an optional embodiment the apparatus includes a weight-on-bit measurement device. Optionally includes a weight-on-bit measurement transmission device. The weight-on-bit measurement transmission device can include changes in the pressure of a drilling-fluid stream, changes in the flow of a drilling-fluid stream and an electrical transmission line.

In an embodiment of the present disclosure there is a method of dampening the force applied on a tool-string when a lower portion of that tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, the method includes providing a dampening apparatus comprising a housing, a push-rod, and at least one dampening member. The method includes engaging the dampening member. Engaging the dampening member can result in the extension of a tension spring positioned in the dampening apparatus, the compression of a spring positioned in the dampening apparatus, the compression of a gas-filled chamber positioned in the dampening apparatus, the compression of an elastomeric material positioned in the dampening apparatus; overcoming the repulsion of two like-poled magnets positioned in the dampening apparatus, or combinations thereof.

In an alternate embodiment of the present disclosure there is an apparatus for measuring the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore. The measuring apparatus includes one or more ports that are successively opened or closed based on changes in the applied force and thereby causing a change in the pressure of a fluid within the tool-string that can be measured.

In an alternate embodiment there is an apparatus for measuring the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore. The measuring apparatus can include a pressure transducer in the tool-string that reports either the pressure in a gas or fluid-filled chamber or the pressure applied by a spring in the apparatus.

In an alternate embodiment there is a method for measuring the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore. The method includes making a first pressure measurement made by a pressure measurement device. The pressure measurement device can include changes in drilling fluid pressure due to opening and closing of ports that vent said fluid, a pressure transducer that measures pressure in a gas or fluid-filled chamber, or a pressure transducer that measures the force applied by a downhole spring and then transmitting the first pressure measurement.

In an embodiment the transmission of the first pressure measurement can be made through changes in pressure of a fluid within the tool-string or through an e-line.

In an alternate embodiment there is an apparatus for the transmission of torque in a drill-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore. The apparatus remains in the primary wellbore and includes an inner spline member and an outer spline member. The inner spline member is in contact with the outer spline member and there is a low coefficient of drag between them.

In an alternate embodiment there is a method for the transmission of torque in a drill-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore. The method includes providing a torque transmission apparatus having an inner spline member and an outer spline member, the inner spline member in contact with the outer spline member and having a low coefficient of drag between them. Placing the torque transmission apparatus within the drill-string in the primary wellbore and connecting the torque transmission apparatus to a tool string that extends into the lateral borehole.

In an alternate embodiment there is a system to improve the efficiency of a tool-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore. The system includes at least one projection extending from the tool-string and at least slot on an external device into which the at least one projection can engage. When the projection engages with the slot they resist a counter torque exerted on the tool-string.

In an alternate embodiment there is a system to improve the efficiency of a tool-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore. The system includes a weight indicator and a load dampener. The system can optionally include a load-balanced piston and a spring for additional dampening. The system can optionally include a spline mechanism for the transmission of torque.

The various embodiments of the present disclosure can be joined in combination with other embodiments of the disclosure and the listed embodiments herein are not meant to limit the disclosure. All combinations of various embodiments of the disclosure are enabled, even if not given in a particular example herein.

While illustrative embodiments have been depicted and described, modifications thereof can be made by one skilled in the art without departing from the scope of the disclosure. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Moreover, the indefinite articles “a” or “an”, as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents, the definitions that are consistent with this specification should be adopted. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Depending on the context, all references herein to the “disclosure” may in some cases refer to certain specific embodiments only. In other cases it may refer to subject matter recited in one or more, but not necessarily all, of the claims. While the foregoing is directed to embodiments, versions and examples of the present disclosure, which are included to enable a person of ordinary skill in the art to make and use the disclosures when the information in this patent is combined with available information and technology, the disclosures are not limited to only these particular embodiments, versions and examples.

Numerous other modifications, equivalents, and alternatives, will become apparent to those skilled in the art once the above disclosure is fully appreciated. While embodiments of the disclosure have been shown and described, modifications thereof can be made by one skilled in the art without departing from the teachings of this disclosure. The embodiments described herein are exemplary only, and are not intended to be limiting. Many variations and modifications of the disclosure disclosed herein are possible and are within the scope of the disclosure.

Use of the term “optionally” with respect to any element of a claim is intended to mean that the subject element is required, or alternatively, is not required. Both alternatives are intended to be within the scope of the claim. It is intended that the following claims be interpreted to embrace all such modifications, equivalents, and alternatives where applicable. Other and further embodiments, versions and examples of the disclosure may be devised without departing from the basic scope thereof and the scope thereof is determined by the claims that follow.

Claims

1. An apparatus for dampening the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said dampening apparatus comprising:

a housing;

a push-rod; and

at least one dampening member selected from the group consisting of: a tension spring, a compression spring, a gas-filled chamber, an elastomeric material, and a magnet.

2. The apparatus of claim 1, further comprising one or more of the elements selected from the group consisting of: a spring that extends when additional weight on bit is applied at a cutting head; a spring that compresses when additional weight on bit is applied at a cutting head; magnets oriented such that they repel each other; and a sealed gas-charged chamber.

3. The apparatus of claim 1, further comprising an internal hose running the length of the apparatus, one or more inner passageways running the length of the apparatus, and a conduit running the length of the apparatus external to the housing.

4. The apparatus of claim 1, further comprising one or more anti-torque projections extending from the housing.

5. The apparatus of claim 4, wherein the anti-torque projections provide continuous, low-drag movement when in contact with an external member.

6. The apparatus of claim 5, wherein the anti-torque projections in contact with an external member resists applied torque.

7. The apparatus of claim 1, further comprising a weight-on-bit measurement device.

8. The apparatus of claim 7, further comprising a weight-on-bit measurement transmission device.

9. The apparatus of claim 8, wherein the weight-on-bit measurement transmission device is selected from the group consisting of: changes in the pressure of a drilling-fluid stream, changes in the flow of a drilling-fluid stream, an electrical transmission line.

10. A method of dampening the force applied on a tool-string when a lower portion of that tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, the method comprising: providing a dampening apparatus comprising a housing, a push-rod, and at least one dampening member;

engaging the dampening member;

wherein the engaged dampening member results in at least one of the group consisting of: the extension of a tension spring positioned in the dampening apparatus; the compression of a spring positioned in the dampening apparatus; the compression of a gas-filled chamber positioned in the dampening apparatus; the compression of an elastomeric material positioned in the dampening apparatus; overcoming the repulsion of two like-poled magnets positioned in the dampening apparatus; and combinations thereof.

11. An apparatus for measuring the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said measuring apparatus comprising: one or more ports that are successively opened or closed based on changes in the applied force and thereby causing a change in the pressure of a fluid within the tool-string that can be measured.

12. An apparatus for measuring the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said measuring apparatus comprising: a pressure transducer in the tool-string that reports either the pressure in a gas or fluid-filled chamber or the pressure applied by a spring in the apparatus.

13. A method for measuring the force exerted on a tool-string when a lower portion of said tool-string is in a subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said method comprising: making a first pressure measurement made by a pressure measurement device selected from the group consisting of: changes in drilling fluid pressure due to opening and closing of ports that vent said fluid, a pressure transducer that measures pressure in a gas or fluid-filled chamber, and a pressure transducer that measures the force applied by a downhole spring; and transmitting the first pressure measurement.

14. The method of claim 13, further comprising transmitting the first pressure measurement through changes in pressure of a fluid within the tool-string.

15. The method of claim 13, further comprising transmitting the first pressure measurement through an e-line.

16. An apparatus for the transmission of torque in a drill-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said apparatus remaining in the primary wellbore and comprising an inner spline member and an outer spline member, the inner spline member in contact with the outer spline member and having a low coefficient of drag between them.

17. A method for the transmission of torque in a drill-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said method comprising:

providing a torque transmission apparatus comprising an inner spline member and an outer spline member, the inner spline member in contact with the outer spline member and having a low coefficient of drag between them;

placing the torque transmission apparatus within the drill-string in the primary wellbore; and

connecting the torque transmission apparatus to a tool string that extends into the lateral borehole.

18. A system to improve the efficiency of a tool-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said system comprising:

at least one projection extending from the tool-string; and

at least one slot on an external device into which the at least one projection can engage;

wherein when the at least one projection engages with the at least one slot that resist a counter torque exerted on the tool-string.

19. An system to improve the efficiency of a tool-string used to form an extended subterranean lateral borehole radiating outward at least 5 feet at an angle between 45 to about 90 degrees from a primary wellbore, said system comprising:

a weight indicator; and

a load dampener.

20. The system of claim 19, further comprising a load-balanced piston and a spring for additional dampening.

21. The system of claim 19, further comprising a spline mechanism for the transmission of torque.