Pressure Control System and Optional Whipstock Repositioning System for Short Radius Lateral Drilling

Abstract

An apparatus and method for pressure control of a tool string and for repositioning of a whipstock that includes an upper sealing mechanism capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole, a chamber connected to the upper sealing mechanism, the chamber having a length greater than the tool string and positioned at least partially within a wellbore and a lower valve connected to the distal end of the chamber within the wellbore wherein the tool-string can be isolated within the chamber from wellbore pressure. A lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within the wellbore, an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock and a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present filing claims priority to provisional patent application 62/284,853 filed on Oct. 13, 2015.

FIELD

The present invention relates to an improved system for easily, economically, and safely working-over or completing wells involving short radius lateral drilling procedures. This invention allows the operator to maintain pressure control and to efficiently reposition a whipstock during short radius laterals drilling procedures.

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. Said in other words, conventional horizontal drilling technologies operate at a scale 3 to 4 orders of magnitude larger than those of short radius lateral drilling technologies.

Short radius lateral drilling procedures entail the placement of the whipstock within a wellbore. Sometimes the whipstock is run on the end of upset or production tubing. Typically, the whipstock is locked into position within the wellbore at a specific elevation and azimuth by means of a packer. Many such packers are set by twisting the production tubing at the surface; and, in turn, rotating the attached whipstock downhole. Often, the packer is set or locked into position by applying a pick-up (tension) or set down (compression) force on the production tubing string. Sometimes it is desirable to direct the lateral wellbore in a particular azimuth—such as to intersect a preferential fracture plane. This can be accomplished when setting the anchor by the aid of a gyro or similar orienting indicator. If the whipstock is aiming in the wrong azimuth, the packer can be unset, twisted and then reset in the correct direction.

During short radius drilling procedures, specialized tools are moved down the wellbore and are directed at the casing (if present) and into the earthen formation by means of the whipstock. A variety of tools can be used to form the laterals in short radius lateral drilling procedures. For example, sometime a high-pressure jetting nozzle-head is used in an attempt to erode or dissolve the rock. An example of this method can be found in U.S. Pat. No. 8,424,620 by Perry et al and incorporated herein by reference. In other cases a motor drives a sort of flexible drilling shaft and attached cutting head as described in U.S. patent application Ser. No. 13/226,489 by Savage and incorporated herein by reference; while in yet other cases ballistic, laser or other means can be employed to form the lateral. In the case of a flexible drilling shaft, the lateral borehole is formed by means of drill bit which mechanically cuts into the earthen formation.

In further contrast with conventional horizontal and coiled tubing drilling, because of the small sizes involved in short radius lateral drilling, any relatively long or larger diameter tools in the tool-string, such as a mud motor, cannot transition around the tight radius of the whipstock; and hence, these items never exit the wellbore. Thus, the only portions of the drill-string to exist the wellbore and extend into the lateral borehole is the lower portion, which must be sufficiently flexible so as to transition thru the tight radius of the whipstock.

After a given lateral is drilled, the whipstock can be rotated to a new azimuth at the same elevation and another lateral can be drilled. In other instances, the whipstock is moved to a new elevation, where one or more additional laterals are formed. Short radius lateral drilling procedures can be used in conventional vertical wells, horizontal wells, slant wells or even multi-lateral wells; and, on cased or open-hole completed wells. While many of these laterals exit the wellbore casing at a full 90 degrees, it is possible for laterals drilled with short radius lateral drilling tools to exit the wellbore at anywhere between about 45 to slightly over 90 degrees.

The tool-string used to form the lateral is often maneuvered by means of a coiled tubing unit (CTU), with the coiled tubing acting as both a control-line and a source of fluid for the tool-string. It is also possible, however, to run certain formation drilling tools on the end of a wireline unit or by means of jointed tubing running to the surface. Most commonly, however, a wireline or CTU serves as the control-line and the control-line is run thru production tubing.

Historically, short radius lateral drilling procedures have been performed as an economical work-over procedure on marginal, low-pressure wells and, sometimes even on “dead” wells. On such wells pressure control measures were sometimes neglected or consisted of a relatively low-pressure Guiberson style “oil-saver” apparatus.

Positioned above the wellhead, the oil-saver acts as wiper on the control-line. If further engaged, the oil-saver can provide a modest seal to about 3,000 psi against the control-line. Aside from their low pressure control rating, using only an oil-saver is also problematic because the well must be opened to the atmosphere whenever the control-line and attached tool-string are placed into or retrieved from the wellbore. This occurs because the packing glad, the sealing mechanism within the oil-saver, must be removed from the oil-saver in order to pass the tool-string.

As mechanical short radius lateral drilling systems drill out further they can be used to complete new wells, such as when fracture treatment isn't technically or economically feasible. To work on such wells, however, short radius lateral drilling systems must develop and employ improved solutions to address pressure risks. Concerns of high-pressure also pertain to mature oilfields, however, because of the possibility of encountering “kicks” from high-pressure fractures or zonal compartments.

The typical pressure control option is a lubricator stack. Lubricator stacks essentially consists of a lower valve positioned near ground level and attached to the wellhead and one or more intervening joints of tubing connected to a second upper seal or valve. With the upper seal open and the lower valve closed, a tool-string connected to a control-line can be safely inserted into the lubricator stack. Once the entire tool-string has been inserted in the lubricator stack, the upper seal can be engaged or “packed off” to form a seal around the control-line. The lower valve can then be opened and the tool-string safely tripped downhole by lowering or “snubbing” in the control-line. Oftentimes, the lubricator stack is positioned above a blow-out preventer (BOP), attached to the wellhead.

As short radius lateral drilling procedures drill out further, its tool-strings become increasingly longer. For example, to form a 75 foot long lateral might require a tool-string having a length of over 100 feet. The extra 25 feet or so of length accounted for by items such as a downhole motor, check valve, swivel assembly, shear sub and connection sub (in addition to the 75 foot length of the flexible portion of the tool-string). In order to accept such a large tool, however, would require that this lubricator stack be at least 100 foot tall.

This presents sizable challenges, complications and costs. For example, a taller lubricator stack requires employing significantly larger and more expensive cranes or rigging mechanism. The tool-strings for lateral drilling are placed into the top of the lubricator stack. As such, the crane must be able to reach significantly higher than the top of the lubricator stack in order to suspend that tool-string over the top of the lubricator stack. Moreover, the crane is not a single use item that can be dismissed after its first use. Instead, it must be present whenever the tool-string is inserted into or removed from the wellbore. As short radius lateral drilling procedures typically entail many tool-string trips over several days (or perhaps even weeks), the crane costs alone can render the procedure prohibitively expensive.

While the direct cost of a large crane is one consideration, it is not the only one. For example, with such a tall pressure control/lubricator stack even mild wind-gusts run the risk of damaging or breaking equipment. The job can be shut-down, but this is highly undesirable. More importantly, such a tall lubricator stack entails subjecting personnel to the significant safety-risks associated with working at ever increasing heights. Again, personnel may need to work at over 100 feet in height to place a long tool-string into the top of a tall lubricator stack and then make-up the necessary tool connections.

An alternative is to use weighted drilling muds to provide wellbore pressure control. This option, however comes with its own technical and economical complications. Besides the added cost of the drilling mud and associated freight charges, there are drilling fluid compatibility and formation damage risks. Often these risks/costs render this option infeasible in practice, given the requirement that this procedure must offer an economical well stimulation.

Because of the above complications and costs, full pressure control is rarely if ever used currently on short radius lateral drilling procedures, therefore well work-overs that are likely to encounter high pressures are simply avoided. This is an unacceptable situation and clearly an easier, more economical and safer solution which maintains full pressure control throughout the duration of the procedure is needed.

A further and inter-related problem with the current paradigm of short radius lateral drilling pertains to the method of repositioning the whipstock. At present moving the whipstock to a new elevation is done by a full-sized work-over rig which must be capable of handling the heavy upset or production tubing sting. If a tall lubricator stack were in place, it must first be rigged-down and set aside so the work-over rig can gain access to the production tubing. Given the heights and weights involved, this is no small endeavor. This step alone adds considerable time, costs and risks to this already “economically-sensitive” procedure.

Short radius lateral drilling procedures typically take about 1-2 day per lateral and, oftentimes between 4 and 8 laterals are created from a wellbore. Under the current norm, the work-over rig stays on location for the duration of the procedure. This adds significant costs as it is not uncommon for the work-over rig to be on location for a week or more and sometimes for several weeks. With current commercial day-rates for work-over rigs at around $3,000 per day, this cost alone can readily exceed $15,000. An alternative, is to release the work-over rig (to perform other jobs) and then call it back only when it is needed a day or two later (to again move the whipstock). This option is also unsatisfactory, however. Sometimes the work-over rig becomes delayed on another job and if no other work-over rig is available, one incurs costly downtime. Of course, even if the work-over rig is available, one still incurs extensive unproductive time and cost associated with: mobilizing the work-over rig and crew to the wellsite; positioning and rigging up; and then, rigging-down and demobilizing the work-over rig. All of these steps can easily take 4-6 hours on a typical procedure above and beyond the actual time spent repositioning the whipstock. This inefficient situation can easily increase the total cost of short radius drilling procedures by 25% or more.

Thus, a need exists for a practical system in short radius lateral drilling that addresses the following three issues: a more thoughtful, efficient and economic means for maintaining well pressure control; an efficient and economical means to reposition the whipstock; and a safe and easy means for field personnel to get tools into and out of the wellbore.

SUMMARY

This disclosure provides an efficient and economical system and method to control well pressure during short radius lateral drilling procedures. This system eliminates the need for a tall lubricator stack positioned high above the wellbore and in so doing dramatically improves the safety and efficiency of deploying short radius lateral drilling procedures. In certain applications, an integrated whipstock repositioning system can also be used to further improve the efficiency and reduce the cost of short radius lateral drilling procedures.

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 drawings.

FIG. 1 illustrates a tubing jacking system located above a wellbore with tubing running through the jacking system and into the wellbore.

FIG. 2 illustrates a tubing jack system above a wellbore with tubing running through the tubing jack and into the wellbore. A whipstock and anchor have been raised from a lower elevation where two lateral boreholes have been drilled, one lateral has already been formed at the new elevation and the whipstock is positioned to drill another.

FIG. 3a illustrates a downhole valve, in the closed positioned, situated inside a wellbore along a string of tubing. The valve has isolated the pressure inside the tubing from that in the wellbore. A downhole tool assembly, located above the valve in the tubing, cannot pass through the closed valve.

FIG. 3b illustrates the downhole valve of FIG. 3a in the open position. The downhole tool assembly hanging above the valve can now be lowered through the valve.

FIG. 3c illustrates a downhole tool assembly running through the opened downhole valve that has been positioned along a string of tubing.

FIG. 4 illustrates a downhole valve located inside a wellbore with said valve in the open position. A downhole tool assembly is passing through the valve and inside of the tubing. The downhole tool assembly is connected to a control-line, in this case coil-tubing, which has been snubbed through an oil-saver.

FIG. 5 illustrates a tubing jacking system used in conjunction with a pressure control system comprised of a downhole valve and oil-saver. A downhole tool has been tripped through the downhole valve on its way toward a whipstock, positioned downhole on production tubing.

DETAILED DESCRIPTION

The present disclosure makes short radius lateral drilling procedures safer and more economical by providing suitable well pressure control without necessitating a tall, precarious and otherwise costly pressure control/lubricator stacks. In addition, this integrated system can be used to negate the need for and cost of having a work-over rig on location to reposition the whipstock. The apparatus and method described herein is particularly well suited to proving a means to work-over marginal wells wherein even modest additional costs can quickly render the work-over procedures cost-prohibitive.

To provide well pressure control, this solution entails the usage of two pressure control mechanisms: one an upper seal and the second a lower valve. Instead of locating both of these items above ground, however, as is the current lubricator stack paradigm, in this invention the upper seal is located at the surface, while the lower valve is located downhole in the wellbore.

Between the upper seal and lower valve is an extended chamber. This chamber is long enough and of sufficient diameter to capture or “swallow” the longest tool-string used during the short radius drilling procedure. This chamber is connected and seals to the upper seal and to the lower valve. This system allows for isolation of pressure within the chamber from that found in the wellbore itself. This chamber can be created by using one or more coupled joints of production tubing that are then threaded to the upper seal and lower valve.

The lower valve could be positioned at any number of locations within the wellbore. For example, it might be located closer to the surface, toward a middle depth, or above but in proximity with a whipstock. In embodiments, the downhole valve would be positioned about 150 feet above the whipstock that is attached to a production tubing string which runs to the surface.

The surface pressure control mechanism or upper seal can be an “oil-saver” system that seals onto the control-line that is used to maneuver the downhole tool-string. As oil-savers are typically only rated to 3,000 psi, in certain embodiments, the oil-saver can be positioned above a BOP to enable pressure control to higher pressures.

To maintain full pressure control during the short radius drilling procedure, the pressure control system entails a second valve positioned downhole. As discussed, above, this valve can be placed in-line with the production tubing string. The downhole valve may consist of any number of designs capable of providing pressure isolation. For example, designs might include: a flapper valve that can be toggled open or closed; a ball-valve having a center “thru-hole”; or a set of concentrically-oriented bladders that can be inflated to seal against one another.

In embodiments, the downhole valve can consist of a ball valve that is opened or closed by turning the production tubing string to which it is attached. In yet other embodiments, the downhole valve could be operated by means of a hydraulic, pneumatic, or electrical conductor line. In instances where the downhole valve is operated by a separate control-line, this control-line would also entail a sealing means when running through the wellhead and in order to maintain pressure control. In yet other embodiments, the downhole valve could be activated by radio frequency (RF) signal, in which case the need to provide an additional sealing mechanism at the wellhead is negated.

Each of the designs herein would allow the operator to control the opening and closing of the downhole valve and hence isolate wellbore pressure. When in the open position, each of these valves would allow a large enough diameter passageway (e.g. 2″ to 3″) through which the tool-string and attached control-line could be traversed.

When the drill-string and control-line are above this lower valve or out of the well altogether, the downhole valve can be closed in order to provide full isolation of pressure from above and below the valve. One can see that by opening the upper seal while the lower valve was still closed, the tool-string can be safely inserted into or retrieved from the wellbore, even if there is high-pressure in the well below the lower valve. Once the tool-string and attached control-line have been inserted into the pressure control system, the upper seal can then be engaged to seal around the control-line. At this point, the lower valve can be opened so the tool-string safely lowered or “snubbed” into the well with full pressure control. Naturally, to remove the tool-string from the wellbore would essentially involve reversing the above steps.

An optional pressure release valve can be incorporated into the extended chamber so that pressure in the chamber can be equalized slowly. That is, if there is an extreme differential pressure between the extended pressure control chamber and the wellbore, the pressure release valve can be used to slowly normalize these two different pressure levels.

As noted earlier, often it is desirable to repeat the short radius lateral drilling procedure at multiple depths in a wellbore. Sometimes the difference in depth might be a few inches while in other instances it might be several hundred feet. Using the apparatus and method described below, one can efficiently add or remove joints of tubing from the production tubing string so as to properly reposition the attached whipstock. Moreover, this system can be seamlessly integrated with the pressure control system described above, or the two can be deployed independently of one another.

The system to reposition the whipstock entails a dual-slip jacking system that engages and moves the production tubing and thereby moves the attached whipstock. This dual-slip jacking system is positioned above the wellhead and comprises an upper and a lower set of slips. The system also includes a vertical lifting/lowering mechanism that can move the production tubing by means of the upper set of slips. Positioned between the two sets of slips is the vertical lifting apparatus, which may be comprised of a set of hydraulic cylinders or threaded screws and jack-bolts.

When hydraulic pressure is applied to the cylinders they can lift the upper set of slips along with the production tubing and attached whipstock. By contrast the threaded screw and jack-bolt system would operate by rotation of the screws, but the affect would be the same, the lifting or lowering of production tubing and whipstock via the set of upper slips.

Obviously, if a packer attached to the whipstock has been set, it will first be necessary to unset the packer. As will be more fully evident below, the system described herein can be efficiently used with common packers requiring twisting and vertical movement to be set/unset.

In certain embodiments the wellhead slips, traditionally located in the bowl at the top of the wellhead, will serve as the lower set of slips. The upper set of slips rest in an upper bowl that sits atop an upper plate. This plate would be thick and/or gusseted in order to resist bending when holding the weight of the production tubing. The production tubing with attached whipstock can proceed through the lower set of slips, through the upper plate and through the upper set of slips. As the upper plate is moved vertically, whether by the hydraulic cylinders or the jack bolts system, the upper slips grab onto the production tubing and correspondingly move the attached whipstock.

In other embodiments, the set of slips normally positioned in the aforementioned wellhead bowl can be removed altogether and a special lower plate can be threaded onto the wellhead. On the top of this lower plate would be a new lower bowl in which is placed the lower set of slips. Given the interference caused by the presence of the cylinders or thread-screws and jack-bolts, moving the lower bowl to this location has the advantage of improving access to this set of slips. This embodiment would also have an upper plate on which sits an upper bowl and upper set of slips is positioned. Similar to the prior example, in this embodiment, the production tubing runs through the lower plate and lower slips as well as the upper plate and upper slips. Both the upper and lower plate would be thick so as to resist bending when holding the heavy production tubing string. In these embodiments, the hydraulic cylinders or jack bolt system would push against the lower plate when lifting the upper plate.

While hydraulic pressure can cause the cylinders to extend and lift the upper plate, the upper plate can be lowered under the force of gravity, that is by removing the pressure on the cylinders. This contrasts with the jack-bolt system wherein rotation is required to both raise and lower the entire system.

In certain embodiments, just below the upper or lower set of slips a bearing set can be located. This bearing set can enable the easy rotation of the heavy upset tubing sting and attached whipstock. The desirability of easily rotating the heavy upset tubing string includes not only the need to change the azimuth of the whipstock but also to set and unset the downhole packer. It should also be noted that this same bearing allows for easy operation of downhole valve systems that are opened/closed by means of rotation.

As noted above, certain short radius drilling procedures may require that the whipstock be raised or lower by a distance in excess of the system stroke length. In these cases, the lower set of slips can be used to hold the production tubing as the cylinders or jack-bolts are reset to take another stroke. In this fashion, sequential strokes of the lifting system can be made to ultimately lift or lower the production tubing great distances. Conversely, the jacking system can also be used to lower the production tubing, attached whipstock and anchor.

With this dual-slip jacking system joints of production tubing can be easily added or removed above the wellhead. In this fashion the top of the production tubing, where the oil-saver sits (for pressure control) can be set at a convenient working height.

This disclosure addresses two significant and unmet challenges for practitioners of short radius lateral drilling: 1) it provides a safe, efficient and affordable means of assuring wellbore pressure control throughout the drilling procedure; and 2) it provides an easy and affordable means to quickly reposition the whipstock.

To illustrate, FIG. 1 shows a tubing jacking system (25) located at the surface and attached to a wellhead (9). The jacking system (25) includes a bottom plate (8), a lower slip bowl (4), lower slips (18), hydraulic cylinders (7) and pushrods (19), a top plate (6), bearing (5), upper slip bowl (3) and upper slips (17). The tubing (1) runs inside the wellbore (2) and is held by the jacking system (25). There is an anchor (15) and a whipstock (14) located on the end of the upset tubing (1).

FIG. 2 illustrates the tubing jacking system (25) attached to a wellhead (9) and comprised of a bottom plate (8), a lower slip bowl (4), lower slips (18), hydraulic cylinders (7) and pushrods (19), a top plate (6), bearing (5), upper slip bowl (3) and upper slips (17). Tubing (1) runs inside the wellbore (2) and held by the jacking system (25). The pushrods (19) have been extended, raising the tubing (1), whipstock (14) and anchor (15). A new lateral borehole (21) has been drilled at a higher elevation than the previously-drilled boreholes (16) and the whipstock (14) is oriented to create another borehole.

FIG. 3A illustrates a downhole valve assembly (11) positioned along a string of tubing (1) that is located inside a wellbore (2). A downhole tool assembly (10) is positioned above the downhole valve assembly (11). The valve assembly (11) shows the sealing mechanism (12) of the valve assembly (11) in the closed position. The sealing mechanism (12) consists of a passageway (13), which can be opened or closed in relation to the tubing (1).

FIG. 3B illustrates a downhole valve assembly (11) located along a string of tubing (1) positioned inside a wellbore (2). A downhole tool assembly (10) has also been positioned inside of the string of tubing (1) and is situated above the downhole valve assembly (11). The sealing mechanism (12) of the valve assembly (11) is in the open position, aligning the passageway (13) with the string of tubing (1).

FIG. 3C illustrates a downhole tool assembly (10) running through the opened downhole valve assembly (11) that has been positioned along a string of tubing (1). The sealing mechanism (12) consists of a passageway (13) that is in the open position, allowing the downhole tool assembly (10) to freely pass through the valve assembly (11).

FIG. 4 illustrates a downhole valve assembly (11) position along tubing (1) with the sealing mechanism (12) in the open position. By virtue of the passageway (13) of the sealing mechanism (12) being opened i.e. in line with the upset tubing (1) a downhole tool assembly (10) has been run through the valve assembly (11). There is a packing gland (24) in an oil-saver (20) that seals against the control-line (22) that is connected to the downhole tool assembly (10).

FIG. 5 illustrates a tubing jacking system (25) located on a wellhead (9) and comprising a bottom plate (8), a lower slip bowl (4), lower slips (18), hydraulic cylinders (7) and pushrods (19), a top plate (6), bearing (5), upper slip bowl (3) and upper slips (17). A downhole valve assembly (11) is positioned along upset tubing (1) with the sealing mechanism (12) in the open position. The passageway (13) of the sealing mechanism (12) is in line with the upset tubing (1) and a downhole tool assembly (10) is running through the valve assembly (11) toward a whipstock (14) set on an anchor (15). There is an oil saver (20) at the surface that used a packing gland (24) to seals against the control-line (22) holding the downhole tool assembly (10).

In an embodiment of the present disclosure an apparatus for isolating wellbore pressure in short radius lateral drilling procedures includes an upper sealing mechanism located above ground level capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole, a chamber connected to the upper sealing mechanism, the chamber having a length greater than the tool string and positioned at least partially within a wellbore, a lower valve connected to the distal end of the chamber within the wellbore, wherein the tool-string can be isolated within the chamber from wellbore pressure.

In an embodiment the upper sealing mechanism is an oil-saver type sealing mechanism. In an embodiment the chamber comprises production tubing. In an embodiment the lower ball valve is selected from one of the group consisting of: a ball valve, a flapper valve, a bladder inflated by gas, a bladder inflated by fluid, and combinations thereof. In an embodiment the lower valve when in the open position has an inside diameter capable of passing the tool-string there through. In an embodiment the lower valve is activated from the surface by one or more of: pulling or pushing vertically on said apparatus; rotating the lower valve; by means of an electrical, hydraulic or pneumatic line running from the surface to the lower valve; or by means of radio frequency (RF) that communicates from the surface to the lower valve.

In an alternate embodiment an apparatus is used in short radius lateral drilling procedures that allows for vertical repositioning of a whipstock that includes a lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within a wellbore, an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock, and a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips.

In an optional embodiment the apparatus includes a bearing positioned below at least one of the upper and lower set of slips, said bearing(s) allowing the rotation of the tubing string, attached whipstock and an optional anchor. Optionally the apparatus includes a bearing positioned below at least one of the upper and lower set of slips, said bearing(s) allowing the rotation of the tubing string, attached whipstock and an optional anchor. Optionally the apparatus includes cylinders used to vertically reposition a plate on which supports the upper set of slips.

In an embodiment a method for repositioning a whipstock used in short radius lateral drilling that includes providing an apparatus having a lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within a wellbore, an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock, a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips, and cylinders used to vertically reposition a plate on which supports the upper set of slips. The method includes engaging the cylinders to vertically reposition the tubing string and attached whipstock and rotating the tubing string to change the azimuth of the attached whipstock.

In an alternate embodiment there is disclosed a method to maintain pressure control during insertion of a tool string used for short radius lateral drilling procedures into a wellbore, providing an apparatus having an upper sealing mechanism located above ground level capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole, a chamber connected to the upper sealing mechanism, the chamber having a length and diameter greater than the tool string and the chamber positioned at least partially within a wellbore, and a lower valve connected to the distal end of the chamber within the wellbore. The method further includes closing the lower valve and opening the upper sealing mechanism, inserting the tool-string and a portion of an attached control-line into the chamber, engaging the upper sealing mechanism to seal onto the control-line, opening the lower valve and running the tool-string into the wellbore through the lower valve.

An alternate embodiment is a method to maintain pressure control during extraction of a tool-string used for short radius lateral drilling procedures. The method includes providing the apparatus described above and retracting a tool-string into the chamber from a location within the wellbore below the chamber, closing the lower valve, opening the upper sealing mechanism, retracting the tool-string out of the upper sealing mechanism.

In a further alternate embodiment there is disclosed a system for efficient short radius lateral drilling procedures comprising an apparatus for pressure control and an apparatus for repositioning of a whipstock. The system includes an upper sealing mechanism located above ground level capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole, a chamber connected to the upper sealing mechanism, the chamber having a length greater than the tool string and positioned at least partially within a wellbore and a lower valve connected to the distal end of the chamber within the wellbore. The tool-string can be isolated within the chamber from wellbore pressure. The system includes a lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within the wellbore, an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock and a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips.

In an embodiment of the system the upper sealing mechanism is an oil-saver type sealing mechanism. In an embodiment the chamber comprises production tubing. In an embodiment the lower ball valve is selected from one of the group consisting of: a ball valve, a flapper valve, a bladder inflated by gas, a bladder inflated by fluid, and combinations thereof. In an embodiment the lower valve when in the open position has an inside diameter capable of passing the tool-string there through. In an embodiment the lower valve is activated from the surface by one or more of: pulling or pushing vertically on said apparatus; rotating the lower valve; by means of an electrical, hydraulic or pneumatic line running from the surface to the lower valve; or by means of radio frequency (RF) that communicates from the surface to the lower valve.

An optional embodiment of the system includes a bearing positioned below at least one of the upper and lower set of slips, said bearing(s) allowing the rotation of the tubing string, attached whipstock and an optional anchor. Optionally the apparatus includes a bearing positioned below at least one of the upper and lower set of slips, said bearing(s) allowing the rotation of the tubing string, attached whipstock and an optional anchor. Optionally the apparatus includes cylinders used to vertically reposition a plate on which supports the upper set of slips.

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 isolating wellbore pressure in short radius lateral drilling procedures comprising:

an upper sealing mechanism located above ground level capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole;

a chamber connected to the upper sealing mechanism, the chamber having a length greater than the tool string and positioned at least partially within a wellbore;

a lower valve connected to the distal end of the chamber within the wellbore;

wherein the tool-string can be isolated within the chamber from wellbore pressure.

2. The apparatus of claim 1 wherein the upper sealing mechanism is an oil-saver.

3. The apparatus of claim 1 wherein the chamber comprises production tubing.

4. The apparatus of claim 1 wherein the lower ball valve is selected from one of the group consisting of: a ball valve, a flapper valve, a bladder inflated by gas, a bladder inflated by fluid, and combinations thereof.

5. The apparatus of claim 1 wherein the lower valve when in the open position has an inside diameter capable of passing the tool-string there through.

6. The apparatus of claim 1 wherein the lower valve is activated from the surface by one or more of: pulling or pushing vertically on said apparatus; rotating the lower valve; by means of an electrical, hydraulic or pneumatic line running from the surface to the lower valve; or by means of radio frequency (RF) that communicates from the surface to the lower valve.

7. An apparatus used in short radius lateral drilling procedures for vertical repositioning of a whipstock comprising:

a lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within a wellbore;

an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock;

a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips.

8. The apparatus of claim 7 further comprising a bearing positioned below at least one of the upper and lower set of slips, said bearing(s) allowing the rotation of the tubing string, attached whipstock and an optional anchor.

9. The apparatus of claim 7 further comprising cylinders used to vertically reposition a plate on which supports the upper set of slips.

10. A method of repositioning a whipstock used in short radius lateral drilling comprising:

providing an apparatus comprising: a lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within a wellbore, an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock, a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips, and cylinders used to vertically reposition a plate on which supports the upper set of slips;

engaging the cylinders to vertically reposition the tubing string and attached whipstock; and

rotating the tubing string to change the azimuth of the attached whipstock.

11. A method to maintain pressure control during insertion of a tool string used for short radius lateral drilling procedures into a wellbore, said method comprising:

providing an apparatus comprising: an upper sealing mechanism located above ground level capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole; a chamber connected to the upper sealing mechanism, the chamber having a length and diameter greater than the tool string and the chamber positioned at least partially within a wellbore; and a lower valve connected to the distal end of the chamber within the wellbore;

closing the lower valve and opening the upper sealing mechanism;

inserting the tool-string and a portion of an attached control-line into the chamber;

engaging the upper sealing mechanism to seal onto the control-line;

opening the lower valve; and

running the tool-string into the wellbore through the lower valve.

12. A method to maintain pressure control during extraction of a tool-string used for short radius lateral drilling procedures, said method comprising:

providing an apparatus comprising: an upper sealing mechanism located above ground level capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole; a chamber connected to the upper sealing mechanism, the chamber having a length and diameter greater than the tool string and the chamber positioned at least partially within a wellbore; and a lower valve connected to the distal end of the chamber within the wellbore;

retracting a tool-string into the chamber from a location within the wellbore below the chamber;

closing the lower valve;

opening the upper sealing mechanism;

retracting the tool-string out of the upper sealing mechanism.

13. A system for efficient short radius lateral drilling procedures comprising an apparatus for pressure control and an apparatus for repositioning of a whipstock comprising:

an upper sealing mechanism located above ground level capable of sealing around a control-line used to manipulate a tool-string used to form a lateral borehole;

a chamber connected to the upper sealing mechanism, the chamber having a length greater than the tool string and positioned at least partially within a wellbore;

a lower valve connected to the distal end of the chamber within the wellbore;

wherein the tool-string can be isolated within the chamber from wellbore pressure;

a lower set of slips positioned above a wellhead capable of holding a tubing string and attached whipstock suspended within the wellbore;

an upper set of slips positioned above the lower set of slips and capable of supporting the tubing string and attached whipstock;

a vertical manipulation mechanism that can raise or lower the tubing string and attached whipstock by raising or lowering the upper set of slips.

14. The system of claim 13 wherein the lower ball valve is selected from one of the group consisting of: a ball valve, a flapper valve, a bladder inflated by gas, a bladder inflated by fluid, and combinations thereof.

15. The system of claim 13 wherein the lower valve is activated from the surface by one or more of: pulling or pushing vertically on said apparatus; rotating the lower valve; by means of an electrical, hydraulic or pneumatic line running from the surface to the lower valve; or by means of radio frequency (RF) that communicates from the surface to the lower valve.

16. The system of claim 13 further comprising a bearing positioned below at least one of the upper and lower set of slips, said bearing(s) allowing the rotation of the tubing string, attached whipstock and an optional anchor.

17. The system of claim 13 further comprising cylinders used to vertically reposition a plate on which supports the upper set of slips.