FIELD OF THE DISCLOSURE

The present disclosure relates in general to downhole tools used in the drilling of wells such as oil and gas wells, including but not limited to downhole valves, and also to means and apparatus for operating downhole tools from the surface.

BACKGROUND

The drilling of an oil and gas well is achieved by attaching a drill bit to the end of a string of drill pipe, and then rotating the drill bit into a subsurface formation. A weighted water slurry called drilling fluid or drilling mud is flowed downward through the drill string and out through the drill bit to lubricate and cool the drill bit and also to wash excavated subsurface material (referred as cuttings) back up to the surface through the annulus between the drill string and the wellbore.

The path of a wellbore can develop undulations and irregularities during the drilling process, particular in deep wells. Drill bit cuttings can become lodged in these undulations and therefore not get washed up to surface. Such unremoved cuttings cause problems in that they can cause the drill string to become stuck within the wellbore, necessitating special measures to dislodge the stuck drill string, at considerable expense in terms of equipment and labor costs and lost production.

The surface-controllable parameters that an operator uses to drill a well (e.g., mud flow rate, drill string rotational speed, and weight on the drill bit) are determined by the properties and characteristics of the subsurface material that is being drilled through, and also on various properties of the drill bit. In addition to those factors, there are other constraints that can limit the magnitude of the drilling parameters being used. For instance, the amount of weight that can be placed on the drill bit is affected not only by the properties of the drill bit but also by the weight of the drill string. Rotational speed is limited by the capabilities of the drilling rig and mud flow rate is limited by the capabilities of the mud pumps. In cases where a downhole motor (or "mud motor") is used, either to increase the rotational speed of the drill bit or to rotate the drill bit without rotating the drill string, then the mud motor will present another restriction on the mud flow rate.

Deviated wells (i.e., wellbores drilled using directional drilling techniques to produce horizontal or otherwise non-vertical wellbores) require the use of a mud motor, and it is such wells that tend to experience the greatest amount of well path undulation and tortuosity. Because of this tortuosity, it would be advantageous to be able to selectively pump greater amounts of mud through the drill string. For instance, after a well has been drilled to a certain depth and the drill string is being "stroked" up and down to facilitate cuttings cleaning, it would be advantageous to be able to pump more fluid without "overpumping" and possibly damaging the mud motor. This would be achieved by allowing a portion of the mud flow to be diverted out of the drill string into the wellbore annulus, thus assisting with cuttings removal while keeping the mud flow reaching the mud motor within appropriate limits.

There are known downhole devices incorporating mud ports that are permanently open to the wellbore annulus, as well as downhole devices incorporating mud valves that are operable by electrical means. However, these devices have drawbacks that detract from their practical utility.

Mud flow into the wellbore annulus through a permanently open mud port will be inconsistent, because it will vary with the backpressure provided by the mud motor. As the mud motor is pulled off bottom and backpressure decreases, proportionally more mud will flow down through the motor and less will flow through the mud port into the annulus. Conversely, as the motor starts drilling and pressure is required to deliver torque through the motor to the drill bit, extra mud flow will be diverted through the mud port, thus reducing the flow of mud to the motor and consequently reducing its power production. This type of system will tend to result in more incidences of motor stalling, plus a decreased ability to re-start drilling operations after a stall without lifting the motor off the bottom of the wellbore and resetting the drilling parameters. Electrically-operated valve systems avoid the above-noted problems with respect to downhole tools with permanently-open mud ports. However, electrically-operated valve systems have drawbacks in terms of high cost, complexity, and tendency for failure.

For the foregoing reasons, there is a need for a downhole mud valve that can be operated from the surface while avoiding problems associated with electrically-operated valves. More particularly, there is a need for such a downhole mud valve that is mechanically actuated. In addition, it is desirable for such a mechanically-actuated downhole valve to be operable by changing one or more drilling parameters from surface, thereby using controls that are already available to the driller, and avoiding the need for extra surface equipment for purposes of operating the downhole valve.

It is also desirable that such a surface-controllable downhole valve can be opened and then will remain in the open position irrespective of variations in the drilling parameters, until such time as the operator selectively closes the valve. Accordingly, there is a need for downhole latching means that can be used to selectively set or "latch" the downhole valve in the open position, with such downhole latching means being operable from the surface. In addition, it is desirable for such downhole latching means to be mechanically actuated.

Ideally, such downhole latching means would also be adaptable for use in association with other types of downhole tools that can be cycled between "open" and "closed" positions, or "on" and "off positions. By way of non-limiting example, a drill string stabilizer may need to be extended for one section of a bit run and then retracted for another section, without needing to pull the tool to surface to change its configuration. In such a scenario, downhole latching apparatus as contemplated above could be provided in association with the stabilizer to cycle the stabilizer between its extended and retracted positions while still deployed downhole. BRIEF SUMMARY

The present disclosure teaches a downhole valve assembly comprising a generally cylindrical housing having one or more mud ports extending through the housing wall, plus a generally cylindrical piston that is axially movable within the bore of the housing. At least one fluid opening is provided through the piston wall in a medial region of the piston. The end regions of the piston, on either side of the fluid opening, are adapted for sliding and substantially sealing engagement with the housing bore. The seal between the piston and the housing bore does not need to be a perfect seal, and some degree of fluid bypass through the seal zones may be acceptable under high-pressure mud flow conditions. In one particular but non-limiting embodiment of the valve, the piston seals are provided in the form of labyrinth seals (which are known types of mechanical seals that provide a tortuous fluid flow path as a means to help prevent or minimize fluid flow).

To operate the downhole valve, a selected drilling parameter (such as mud flow) can be selectively adjusted to move the valve piston between:

• an upper or "closed" position, in which the fluid opening in the piston is above the mud port(s) through wall of the housing, such that all drilling mud entering the valve assembly will continue downward through the drill string toward the drill bit; and

• a lower or "open" position, in which the fluid opening in the piston is at least partially aligned with the mud port(s) in the housing wall, such that a portion of a drilling mud flow downward through the valve assembly will be diverted through the fluid opening in the piston and will exit the valve assembly through the mud port(s) in the housing.

An increase in mud flow rate or pressure will urge the piston downward within the valve housing, toward the open position. Stop means may be provided or incorporated into the valve assembly to limit the downward travel of the piston. Additional stop means may be provided to limit upward travel of the piston. Preferably, the valve assembly will be provided with biasing means whereby the piston is biased toward the closed position. Valve assemblies with biasing means in accordance with the present embodiment are not limited or restricted to any particular type of biasing means; persons skilled in the art will appreciate that functionally effective biasing means for this purpose can be provided in a variety of forms using known technologies. However, in a particularly preferred embodiment, the biasing means is provided in the form of a helical spring disposed within the housing bore below the piston, such that the helical spring will be compressed as the piston is moved downward toward its open position. Although not essential to all embodiments, a "wash sleeve" is preferably disposed connected to the lower end of the piston and extends downward through the helical spring to facilitate smooth fluid flow through the region of the housing below the piston. A lower region of the housing bore may be formed with an annular shoulder acting as a stop means for the wash sleeve (and, in turn, the piston).

In preferred embodiments of the valve assembly, a latching mechanism may be coupled to the upper end of the piston. In accordance with exemplary embodiments disclosed herein, the latching mechanism may comprise a generally cylindrical mandrel, the lower end of which is coaxially mounted to the upper end of the piston. The mandrel is operatively coupled to a selected input or actuating means (such as mud flow rate, fluid pressure, weight on bit, or other drilling parameter). The latching mechanism is preferably adapted to hold the piston in its open position with every second cycling of the flow rate to a value high enough to cause the induced downward force to exceed a preload force urging the piston toward its closed piston. On the intervening cyclings of the flow rate, the latching mechanism will release the piston so that it is free to move to its closed position.

As will be described in detail later herein, the latching mechanism can be used to hold the valve piston in the open position after every second period of increased flow rate, such that mud can flow from the valve to the wellbore annulus even when the flow rate is reduced below the valve activation threshold, and yet may be re-closed at any time, and can be opened and closed an unlimited number of times. An upper region of the mandrel is formed with two or more circumferentially- equally- spaced protrusions (or "bosses") projecting radially outward from the mandrel. The bosses are of generally saw-toothed configuration, with each boss having sloped upper and lower edges configured to define upper and lower notches. The bosses may be formed by any suitable fabrication procedure, such as machining the mandrel from a cylindrical workpiece.

Persons skilled in the art will appreciate that embodiments in which the mandrel has only one boss are feasible, and such embodiments are intended to be within the scope of the present disclosure. However, in preferred embodiments the mandrel will have at least two bosses.

The upper portion of the mandrel carrying the "saw-toothed" bosses defining is disposed within a cylindrical sleeve (or "latch sleeve"), which in turn is disposed within the valve housing such that the latch sleeve's axial position relative to the housing is fixed but the sleeve is free to rotate relative to the housing.

The latch sleeve has two or more pairs of latch pins that protrude radially inward from the inner cylindrical surface of the latch sleeve. As will be explained in greater detail later herein, the latch pins are engageable with the bosses on the mandrel to limit its axial motion, and also to impart rotation of the sleeve within the housing in response to interactions between the pins and the bosses.

The number of pairs of latch pins will depend on the number of saw-toothed bosses on the mandrel. For example, for a mandrel having four protrusions, the latch sleeve can have two pairs or four pairs of latch pins. For a mandrel having three protrusions, three pairs of latch pins would be used. However, the operative interaction between the mandrel bosses and the latch pins is essentially the same regardless of how many bosses and corresponding latch pins are provided.

Each pair of latch pins comprises an upper pin and a lower pin, which are axially spaced and circumferentially offset from each other. The upper and lower sloped edges of the mandrel bosses act as inclined planes or ramps that will bear against either an upper pin or a lower pin as the piston moves up or down within the valve housing. The axial force exerted by the piston against a given latch pin will cause that pin to move along one of the sloped edges, thus rotating the latch sleeve, until, in one operational phase, the lower pin is disposed in one of the lower latch pin pockets on the mandrel so as to prevent downward movement of the mandrel (and valve), or, in another operational phase, the upper pin is disposed in one of the upper latch pin pockets so as to prevent upward movement of the mandrel (and valve).

In the latter configuration, the valve is "latched" in the open position, and will remain open, even if the mud flow rate is decreased. If the valve were not latched in this position, a decrease in the mud flow rate would result in relaxation of the downward force on the piston, which would therefore be urged backed toward its closed position by the biasing means. This ability to latch the valve in the open position allows mud to drain out of the drill string and into the annulus when pipe is being tripped out of the wellbore, acting like a type of "dump valve" that is directly operable by the driller from the surface.

In typical operation, the valve will begin a given bit run in the closed position. In order to open the valve, the mud flow rate is increased to some percentage above the normal operating range (thus opening the valve) and then decreased back to the operating range after the valve has been latched open. With the valve open, some portion of the mud flow will be diverted out of the drill string and into the wellbore annulus. In order to close the valve, the mud flow rate is increased again (thus unlatching the valve, as will be described in greater detail later herein), and then decreased to close the valve such that all of the mud flow will be directed through the bottom of the tool, with no diversion of flow into the wellbore annulus.

The present disclosure makes reference to the mud flow rate being used to actuate the valve and latching system. However, this is by way on non-limiting example only, and persons skilled in the art will understand that the system can be adapted to use one or more other drilling parameters as the actuating input, such as but not limited to pump pressure or weight on the bit. BRIEF DESCRIPTION OF THE DRAWINGS

Embodiments in accordance with the present disclosure will now be described with reference to the accompanying figures, in which numerical references denote like parts, and in which:

FIGURE 1 is an exploded view of one embodiment of a downhole valve and latching tool assembly in accordance with the present disclosure.

FIGURE 2 is a longitudinal cross-section through a downhole valve and latching tool assembly generally as shown in FIG. 1.

FIGURE 2A is a longitudinal cross-section through a variant embodiment of the assembly shown in FIG. 1.

FIGURE 3 is an enlarged section through the downhole valve in FIG. 2, shown in the open position.

FIGURE 4 is an enlarged section through the downhole valve in FIG. 2, shown in the closed position.

FIGURE 5 is an isometric view of one embodiment of a piston for use in a downhole valve in accordance with the present disclosure.

FIGURE 6A is an isometric view of a first embodiment of a mandrel for use in a downhole latching tool in accordance with the present disclosure.

FIGURE 6B is an isometric view of a second embodiment of a latching tool mandrel in accordance with the present disclosure.

FIGURE 7 is an isometric view of one embodiment of a latch sleeve for use in a downhole latching tool in accordance with the present disclosure.

FIGURE 8 illustrates a mandrel as in FIG. 6A disposed within and operatively engaging an outer sleeve of a latch sleeve as in FIG. 7. FIGURES 9A-9E are sequential representations of interactions between the saw-tooth bosses of the latching tool mandrel and the latch pins projecting into the bore of the latching tool sleeve.

DETAILED DESCRIPTION

FIG. 1 is an exploded view of one embodiment of a downhole valve and latch assembly 100 in accordance with the present teachings. Assembly 100 comprises a generally cylindrical valve housing 10 having an upper end 10U, a lower end 10L, and a bore 11. At least one and preferably two or more mud ports 12 are provided through the wall of housing 10 to permit fluid flow from bore 11 to the exterior of housing 10. Preferably, hardened steel or tungsten carbide outlet nozzles 13 of known type are fitted into mud ports 12 to prevent abrasive erosion of the housing wall due to high-velocity flow of drilling mud through mud ports 12.

In the embodiment shown in FIG. 1, the exterior surface of housing 10 is configured to define helical centralizer elements 15. As well, mud ports 12 are shown in FIG. 1 as being directionally oriented so that drilling fluid exiting mud ports 12 will be directed into the wellbore annulus in a substantially uphole direction, thus augmenting the flow of mud washing cuttings to the surface while also preventing or minimizing damage that might otherwise result from high-velocity flows of abrasive drilling mud directed substantially radially outward from mud ports 12 against a wellbore into which the valve assembly has been inserted. Although centralizer elements 15 and directionally- oriented mud ports 12 will be desirable and preferred in many operational situations, neither of these features is essential to the broadest embodiments of downhole valves in accordance with this disclosure. For simplicity of illustration, therefore, centralizer elements are not shown in the other Figures, and mud ports 12 are shown as simple openings through the wall of housing 10.

The valve assembly also includes a generally cylindrical piston 40 which is slidably disposed within bore 11 of valve housing 10. Piston 40 has an upper end 40U, a lower end 40L, and a bore 41. In the illustrated embodiment, piston 40 has two medially-located fluid openings 44, flanked by upper and lower seal sections 45U and 45L carrying or incorporating sealing means (shown by way of non-limiting example as labyrinth seals comprising multiple, closely-spaced annular grooves). In FIGS. 1 , 2, and 3, piston 40 is shown in the open position, with fluid openings 44 aligned with mud ports 12 in valve housing 10 to allow diversion of fluid from bore 11 to the exterior of housing 10. However, piston 40 is biased toward the closed position (as in FIG. 4) by means of a helical spring 35 disposed below piston 40.

In certain embodiments, spring 35 will have a spring constant of less than 25 pounds per inch, but that is by way of example only, and embodiments incorporating biasing means in the form of a spring are not limited to the use of springs having spring constants in the above-noted range. Spring 35 will preferably be preloaded when the valve assembly is in the closed position, such that the piston will not move to the open position until a predetermined flow level has been reached. The amount of preload will be a matter of design choice to suit specific cases, but in certain embodiments the preload will be 200 pounds or greater.

As well, a cylindrical wash sleeve 30 having a bore 31 is disposed within helical spring 35 largely preventing drilling fluid from entering the annular space 37 between wash sleeve 30 and housing 10 and occupied by spring 35. However, because of the possibility of minor fluid leakage past piston 40 into annular space 37 under high- pressure flow conditions, at least one drainage hole 32 is preferably provided through a lower region of the wall of sleeve 30 so that any excess fluid that may accumulate within annular space 37 can drain into sleeve bore 30 and thus will not impede downward movement of piston 40 and compression of spring 35. The upper end 30U of wash sleeve 30 is connected to lower end 40L of piston 40 (by means of a threaded connection, for example), such that wash sleeve 30 and piston 40 are axially movable as a unit. As seen in the Figures, piston 40 may be provided with flattened areas ("wrench flats") 42 for engagement by a wrench or other tool being used to tighten the threaded connection of between piston 40 and wash sleeve 30.

In the embodiment in FIG. 1, lower end 10L of valve housing 10 comprises a standard "box" connection, which receives a "double-pin" sub 20 having an upper pin end 20U which serves as a bearing shoulder for the lower end 35L of helical spring 35. The upper region of bore 21 of pin sub 20 is shown machined to define an annular shoulder 25 which serves as stop means limiting the downward travel of wash sleeve 30 and piston 40 relative to valve housing 10. However, valve assemblies in accordance with the present disclosure are not restricted to the use of stop means provided in this particular fashion. By way of non-limiting example, FIG. 2A illustrates a variant valve housing 10' the lower end of which has a pin end (rather than a box end as in FIGS. 1 and 2) and in which bore 11 is machined to form an annular shoulder 18 for receiving lower end 35L of spring 35, and, below shoulder 18, another annular shoulder 19 serving as a lower stop means for wash sleeve 30. This variant embodiment has the advantage of avoiding the need to incorporate a pin sub 20 into the valve assembly.

In the illustrated embodiment, the valve assembly as described above is coupled with a latching assembly comprising a generally cylindrical mandrel 80 having upper and lower ends 80U and 80L and a bore 81, with lower end 80L being coaxially coupled to upper end 40U of piston 40 (such as by way of a threaded connection as shown in the Figures). As shown in FIGS. 1 through 4, flow restriction means in the form of an orifice 50 of known type and selected characteristics is disposed within bore 41 of piston 40 below lower end 80L of mandrel 80 and above fluid openings 44 in piston 40. Orifice 50 is preferably a carbide orifice in which the internal diameter can be selectively varied as may be appropriate to suit different fluid flow rates. As best seen in FIGS. 3 and 4, orifice 50 may be secured within piston bore 41 by suitable means (such as radial pins 52), in conjunction with suitable sealing means (such as O-ring 54).

The internal diameter of orifice 50 is selected such that a prescribed mud flow rate will generate enough of a pressure drop across orifice 50 to induce a downward force on piston 40 greater than the resisting force of helical spring 35 (or other biasing means), such that piston 40 moves downwards. When the flow rate is reduced enough that the downward force induced by the pressure drop across orifice 50 is less than the resistance of spring 35, piston 40 will slide upward to a stop. Seal sections 45U and 45L on either side of fluid openings 44 prevent mud from leaking through fluid openings 44 when they are not aligned with mud ports 12 in housing 10. Mandrel 80 may optionally be provided with wrench flats 82, as well as one or more drainage holes 83 to allow any fluid accumulating in the annular space between mandrel 80 and housing 10 to drain into mandrel bore 81.

In the mandrel embodiment shown in FIG. 6A, an upper region of mandrel 80 is formed with four circumferentially-spaced bosses 85 of generally saw-toothed configuration, projecting radially outward from the mandrel. Each boss 85 can be considered as comprising contiguously adjacent trapezoidal sections 86 and 87, with respective upper and lower sloped edges 86U, 87U, 86L, and 87L.

Upper sloped edges 86U and 87U both slope in the same general direction, but are not necessarily parallel. Similarly, lower sloped edges 86L and 87L both slope in the same general direction without necessarily being parallel, but their general angular orientation is opposite to that of upper sloped edges 86U and 87U. This is most clearly understood with reference to mandrel 80 in FIG. 6A, in which upper sloped edges 86U and 87U both slope downward and to the right, while lower sloped edges 86L and 87L both slope upward and to the right. Alternatively, bosses 85 could be formed such that upper sloped edges 86U and 87U both slope downward and to the left, while lower sloped edges 86L and 87L both slope upward and to the left. (In the preceding discussion, the terms upward, downward, right, and left are referable to mandrel 80 when vertically oriented as it would be when valve and latch assembly 100 is being used in the drilling of a vertical wellbore - see FIG. 8, for example.)

An upper notch 88U is formed where upper sloped edge 86U of trapezoidal section 86 meets the left side of trapezoidal section 87, and a lower notch 88L is formed where lower sloped edge 86L of trapezoidal section 86 meets the left side of trapezoidal section 87.

FIG. 6B illustrates another variant mandrel 80' having three saw-toothed bosses 85' generally similar to bosses 85 in FIG. 6A, but with an axially-oriented latch pin slot 89 extending upward into each boss 85' from a location analogous to lower notch 88L in boss 85. Beyond the general configuration described above, mandrel bosses 85 (or 85') do not need to conform to any particular geometric constraints. The appropriate angular orientation of the sloped upper and lower edges and the various dimensions of the bosses will be matters of design choice to suit the requirements of a given case. The sloped upper and lower edges do not necessarily have to be linear, but could incorporate curved portions (with or without linear portions).

Mandrel 80 is disposable within the bore 61 of a cylindrical latch sleeve 60 which has upper and lower ends 60U and 60L. As best seen in FIGS. 2, 3, and 4, latch sleeve 60 is disposed within an upper region of bore 11 of valve housing 10 in such a manner that sleeve 60 is in a fixed axial position relative to housing 10 but is free to rotate within bore 11. In FIG. 1, latch sleeve 60 is shown as having canted or helical ribs 62 projecting from its outer surface. Such ribs will typically be desirable to provide fluid flow paths to facilitate removal of any drilling fluid solids that might accumulate in the annular space between sleeve 60 and bore 11 and otherwise might impede rotation of sleeve 60 within bore 11. However, these ribs are not essential to the broadest embodiments of downhole valve and latch assemblies in accordance with this disclosure.

As seen in FIGS. 2 through 4, upper end 60U of sleeve 60 is preferably positioned such that it can bear against the lower end of a pipe section 70 connecting to upper end 10U of housing 10, preferably with a thrust bearing 73 and a washer 74 disposed between upper end 60U of sleeve 60 and the lower end of pipe section 70. (It should be noted here that pipe section 70 does not form part of the broadest embodiments of any mechanisms or assemblies in accordance with the present disclosure.)

FIG. 7 illustrates a variant of latch sleeve 60 having two pairs of latch pins which project into sleeve bore 61 far enough to be operably engageable with bosses 85 on mandrel 80. Each pair of latch pins comprises an upper latch pin 90 and a lower latch pin 95 which are axially spaced but circumferentially offset from each other. This relationship between upper and lower latch pins 90 and 95 is most clearly seen in FIG. 8 and FIGS. 9A-9E. Each of FIGS. 9A through 9E is a horizontal projection of three of the four bosses 85 of a mandrel 80 as in FIG. 6A, schematically illustrating how bosses 85 interact with two pairs of upper and lower latch pins 90 and 95 carried by latch sleeve 60 as in FIG. 7, at different stages of operation of the latching mechanism. To facilitate a clear understanding of how the latching mechanism works, the three bosses shown in FIGS. 9A-9E are differentiated by reference numbers 85.1, 85.2, and 85.3; the two upper latch pins are differentiated by reference numbers 90.1 and 90.2; and the two lower latch pins are differentiated by reference numbers 95.1 and 95.2.

In FIG. 9A, the mechanism is latched in the closed position, with lower latch pin 95.2 being lodged in lower notch 88L.2 of boss 85.2 such that downward movement of mandrel 80 is prevented.

From the position shown in FIG. 9A, the application of an upward force on mandrel 80 (such as by a reduction in fluid flow rate) will force upper ramp 87U.2 into contact with upper latch pin 90.2, inducing a counterclockwise rotation of latch sleeve 60 (as viewed looking down) within housing 10 such that upper latch pin 90.2 moves to the right relative to boss 85.2 until it is clear of boss 85.2 and "drops" into the gap between bosses 85.2 and 85.3, and thus does not further restrict upward movement of mandrel 80, as may be seen in FIG. 9B. However, suitable stop means (not shown) will typically be provided to limit upward travel of mandrel 80.

From the position shown in FIG. 9B, the application of a downward force on mandrel 80 (such as by an increase in fluid flow rate) will force lower ramp 87L.2 into contact with lower latch pin 95.2, inducing a further counterclockwise rotation of latch sleeve 60 such that lower latch pin 95.2 moves to the right until it is clear of boss 85.2 and "rises" into the gap between bosses 85.2 and 85.3, and thus does not further restrict downward movement of mandrel 80, as may be seen in FIG. 9C.

From the position shown in FIG. 9C, the application of an upward force on mandrel 80 will force upper ramp 86U.1 into contact with upper latch pin 90.1, and upper ramp 86U.3 into contact with upper latch pin 90.2, inducing a further counterclockwise rotation of latch sleeve 60 until upper latch pin 90.1 is lodged in upper notch 88U.1 of boss 85.1 and upper latch pin 90.2 is lodged in upper notch 88U.3 of boss 85.3, all as seen in FIG. 9D. The apparatus is now latched in the open position, with upward movement of mandrel 80 being prevented by upper latch pins 90.1 and 90.2.

From the position shown in FIG. 9D, the application of a downward force on mandrel 80 will force lower ramp 86L.1 into contact with lower latch pin 95.1, and lower ramp 86L.3 into contact with lower latch pin 95.2, inducing a further counterclockwise rotation of latch sleeve 60 until lower latch pin 95.1 is lodged in lower notch 88L.1 and lower latch pin 95.2 is lodged in lower notch 88L.3, all as seen in FIG. 9E. It can be seen that the position shown in FIG. 9E is essentially identical to the position shown in FIG. 9A, with the only difference being that latch sleeve 60 has been rotated ninety degrees counterclockwise.

It is to be understood that the scope of the claims appended hereto should not be limited by the preferred embodiments described and illustrated herein, but should be given the broadest interpretation consistent with the description as a whole. It is also to be understood that the substitution of a variant of a claimed element or feature, without any substantial resultant change in functionality, will not constitute a departure from the scope of the disclosure.

In this patent document, any form of the word "comprise" is to be understood in its non-limiting sense to mean that any element following such word is included, but elements not specifically mentioned are not excluded. A reference to an element by the indefinite article "a" does not exclude the possibility that more than one of the element is present, unless the context clearly requires that there be one and only one such element.

Any use of any form of the terms "connect", "engage", "couple", "attach", or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the subject elements, and may also include indirect interaction between the elements such as through secondary or intermediary structure. Relational or relative terms (such as but not limited to "horizontal", "vertical", "parallel", "perpendicular", and "coaxial") are not intended to denote or require absolute mathematical or geometrical precision. Accordingly, such terms are to be understood as denoting or requiring substantial precision only (e.g., "substantially horizontal") unless the context clearly requires otherwise.

Wherever used in this document, the terms "typical" and "typically" are to be interpreted in the sense of representative or common usage or practice, and are not to be understood as implying invariability or essentiality.