SEAL SYSTEM FOR DOWNHOLE TOOL

Abstract

A downhole tool may include a tubular member having an axis, a wall with a bore, and an orifice extending radially from the bore through the wall. A piston may be configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein, the piston having a piston bore. An aperture may extend radially from the piston bore to the bore of the tubular member. First and second glands formed in an outer surface adjacent the aperture. The first gland may be axially spaced apart from the second gland. In addition, a seal system can be configured to be mounted to the piston. The seal system can include a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a continuation of International Application No. PCT/CA2013/000068, filed on Jan. 24, 2013, which claims priority to U.S. Provisional Patent Application No. 61/632,372, filed on Jan. 24, 2012 and U.S. Provisional Patent Application No. 61/632,374, filed on Jan. 24, 2012, the disclosures of which are incorporated herein by reference in their entireties.

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.

SUMMARY

Embodiments of a downhole and sealing system are disclosed. For example, a downhole tool may include a tubular member having an axis, a wall with a bore, and an orifice extending radially from the bore through the wall. A piston may be configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein, the piston having a piston bore. An aperture may extend radially from the piston bore to the bore of the tubular member. First and second glands formed in an outer surface adjacent the aperture. The first gland may be axially spaced apart from the second gland. In addition, a seal system can be configured to be mounted to the piston. The seal system can include a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.

In another embodiment, a downhole tool may include a tubular member having an axis, a wall with a bore, an orifice extending radially from the bore through the wall, and first and second glands formed in bore adjacent the orifice. The first gland can be axially spaced apart from the second gland. A piston may be configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein. The piston can have a piston bore, and an aperture extending radially from the piston bore to the bore of the tubular member. A seal system may be configured to be mounted to the tubular member. The seal system may include a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.

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:

FIG. 1 is an exploded view of one embodiment of a downhole tool assembly.

FIG. 2 is a longitudinal sectional view through an embodiment of a downhole tool assembly generally as shown in FIG. 1.

FIG. 2A is a longitudinal sectional view through a variant embodiment of the assembly shown in FIG. 1.

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

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

FIG. 5 is an isometric view of one embodiment of a piston for use in a downhole tool.

FIG. 6A is an isometric view of a first embodiment of a mandrel for use in a downhole latching tool.

FIG. 6B is an isometric view of a second embodiment of a latching tool mandrel.

FIG. 7 is an isometric view of one embodiment of a latch sleeve for use in a downhole latching tool.

FIG. 8 illustrates a mandrel as in FIG. 6A disposed within and operatively engaging an outer sleeve of a latch sleeve as in FIG. 7.

FIGS. 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.

FIG. 10 is an exploded isometric view of another embodiment of a downhole tool.

FIG. 11 is a sectional side view of an embodiment of the downhole tool of FIG. 10.

FIGS. 12 and 13 are isometric views of embodiments of a sleeve and a piston, respectively, for a downhole tool.

FIGS. 14 and 15 are isometric views of embodiments of primary and secondary seals, respectively, for a downhole tool.

FIG. 16 is an enlarged sectional side view of an embodiment of a primary seal seated in a gland in a piston.

FIGS. 17A1-17A3 are enlarged sectional side views of an embodiment of seals moving through closed, partially open and fully open positions, respectively, and taken along the line A-A of FIG. 12.

FIGS. 17B1-17B3 are enlarged sectional side views of an embodiment of seals moving through closed, partially open and fully open positions, respectively, and taken along the line B-B of FIG. 12.

FIG. 18 is a sectional side view of an embodiment of a tool with seals in a fully open position.

FIGS. 19A-19C are sectional side views of an alternate embodiment of a tool depicting closed, partially opening and fully open positions, respectively.

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.

Other embodiments of a downhole tool may include a sealing system that allows opening under pressure. In the oil and gas industry, sealing systems that can operate under high pressure are needed. For example, some drilling tools may be required to release fluid either because the flow is too high or the pressure is too high. Seal systems for such applications should be able to move between open and closed positions wherein they are unsealed and sealed, respectively. Exposing a seal while it is under pressure generally results in damage to the seal because of the explosive release of pressure. In particular, it would be desirable for a drilling tool seal that can release fluid from the wellbore to the annulus during drilling operations.

There are many different types of sealing systems that are used in the industry. The challenges that exist when sealing downhole are that the pressures are can be quite high (e.g., up to about 15,000 psi pressure differential), the environmental media can be quite varied (e.g., acids, bases, oils, harsh chemicals, suspended solids, steam, etc.), and the temperature can exceed 150 degrees C. The high temperature requirement alone eliminates many plastic products from contention that would otherwise provide an adequate solution.

Situations where a cylinder must seal inside of a bore where the pieces do not move with respect to each other (i.e., static seals) require the most basic seals, such as elastomeric o-rings. O-rings can be effective but they rely on a very close fit between a cylinder (ID) and a piston (OD) where the maximum gap between the two parts is on the order of only several thousandths of an inch. O-rings seal by using a geometry that allows them to be pushed towards and slightly into a gap under pressure. This design allows the rubber of the o-ring to bridge the gap while maintaining the integrity of the seal.

In applications that require a cylinder to reciprocate, o-ring seals are generally not appropriate. The requirement of an o-ring to be pushed into a gap means that there is a high amount of compression on the seal and that movement of the parts results in wear, damage and eventual seal failure. Also, if the seal is working in an abrasive environment there is a high probability that some of the media will abrade the seal. This problem can addressed with a back up ring. Back up rings are typically formed from PEEK, Teflon or other harder plastics. For example, a back up ring can be pushed against the ID of a cylinder to reduce the size of the extrusion gap for an o-ring. This design helps prevent the intrusion of solids and reduces the pinching of the seal. An alternative to back-up rings is a seal with a geometry that is designed to scrape solids away while also effecting a tight seal.

Some applications can tolerate the use of a quasi-seal instead of one that positively excludes fluid movement past the seal. A quasi-seal is generally just a very tight restriction for flow and will hold back some amount of pressure under dynamic situations but will generally allow the pressure to equalize across the seal in a static situation. In general, quasi-seals are useful only in dynamic situations where the pressure is generated by the flow of fluid. This way, even if there is some amount of fluid transfer across the quasi-seal the overall pressure difference is maintained. Another limitation of quasi-seals is that they may be used only in situations where the seal is used to isolate two volumes of the same type of material. They may not be used to separate air and water, for example. The fluid transfer across the seal would otherwise contaminate one or both volumes. An example of a quasi-seal would be the metal piston rings that are used on the piston of an internal combustion engine. The seal is good enough to maintain a certain amount of pressure differential under dynamic conditions, but a certain amount of material transfer through or past the seal can be tolerated.

Since quasi-seals allow some amount of fluid to leak, they are generally best used in situations where: (1) the consequences of a small amount of material transfer across the seal is acceptable; (2) the amount of pressure that is being sealed is low; and/or (3) the media is generally not abrasive. Low or no abrasion is required since high pressure will push media through a quasi-seal at high velocity. If the media is abrasive then some amount of flow erosion can be expected. This limitation can be addressed through the use of very hard materials for the piston and cylinder such as carbide, ceramic, or chrome. However, the amount of time that a quasi-seal can be expected to maintain its integrity under these conditions is limited.

Another limitation of quasi-seals is that they tend to act like a filter and encourage the deposit of solid materials from the fluid. That is, if the fluid being sealed contains particles in it that are of a scale similar to the gap in the quasi-seal then there will be a tendency for those solids to remain at the site of the seal. If there is a limited amount of force available to push the piston through the cylinder then the filtered solids may compromise the use of whatever device the seal is used with.

These types of seals can work well in situations where the piston stays within the bore and the seal (or quasi-seal) can maintain the same shape. However, a further complication is added for applications that require the piston to move out of the cylinder that is retaining the seal while it is sealing high pressure. If a seal is maintaining a high pressure differential and it is pulled out of its cylinder, there is at least a small amount of time where fluid of a very high velocity can be expected to flow past the seal. If the pressure driving this fluid velocity is high (e.g., in the thousands of psi) and the seal is made out of a pliable material like rubber or some other elastomer, then it can be expected that some amount damage to the seal may occur.

Thus, it can be problematic to maintain the integrity of this type of seal over multiple operations when the following conditions are required: (1) two separate volumes need to be intermittently sealed from one another; (2) the pressure exceeds 1000 psi; a positive seal (not quasi-seal) element is required to keep fluid movement between volumes to zero; and (4) the fluid contains abrasive media.

One solution to this combination of conditions is to use an elastomer seal that is not an o-ring. O-rings can be relatively fragile when exposed to high forces, such as those generated by high fluid flow rates. The ideal elastomer seal fills its gland, does not rely on an extrusion gap for seal integrity, and has enough compression to maintain the seal and yet enough open room in the gland for seal compression. In addition, a quasi-seal, such as a metal piston-ring type seal, also may be used on the high pressure side of the piston to act as a “buffer seal” for the elastomer seal. As the elastomer seal is exposed, the buffer seal prevents high velocity fluid from damaging the elastomer. Finally, an element of the cylinder may be extended, such that the metal piston ring is retained on at least a portion of its circumference by elements that have the same diameter as the cylinder bore. In this way the piston may be re-seated inside of the cylinder without having to apply extra axial force to compress the metal piston ring.

Referring now to FIGS. 10-19, other embodiments of a downhole tool 101 may include a sealing system 103 that allows opening under pressure. The other components shown in these drawings but not described may be similar or substantially identical to those described elsewhere herein. Embodiments of the sealing system 103 may include a piston 105 that has at least two seals 107, 109 (e.g., four shown as 107, 109, 111, 113) that are mounted on the outer diameter (OD) thereof. The inside diameter (ID) of a cylinder 115 comprises a bore 117 can include an ID that is very close (e.g., within several thousandths of an inch) of the OD of the piston 105.

One of the at least two seals is a primary seal 107 (FIGS. 14 and 16) that can be an elastomeric element similar to an o-ring. However, instead of a circular cross-sectional shape, the primary seal 107 may include one or more of the following attributes: (1) it can be substantially as wide as the gland or groove 121 that it fits within; (2) the outer (sealing) surface 123 can include beveled edges 125 that substantially come to a crest 127; (3) the crest 127 of the outer edge of the primary seal 107 can have a diameter that is slightly larger than the OD of the piston 105; (4) the cross-sectional area of the primary seal 107 can be slightly less than the cross-sectional area of the gland 121; and/or (5) a small void volume 131 may be included at the ID of the primary seal 107 to allow the primary seal 107 to flex and squeeze into the sealing bore 117.

Embodiments of the second sealing element or second seal 109 may include a quasi-seal or buffer seal that is not a total seal, but rather dramatically slows the passage of fluid past it. The second seal 109 can maintain a pressure differential if the pressure is created by a dynamic situation. The second seal 109 can comprise a split metal ring. The split 110 (FIG. 15) may include a stepped lap joint to reduce fluid flow through the split 110.

In some versions (FIGS. 17A1-17B3), the second seal 109 can be located on the high pressure zone (HPZ) of the primary seal 107. As the piston 105 is moved axially towards a completely open position (FIGS. 17A3 and 17B3) where both seals 107, 109 are withdrawn or exposed from the bore 117 of the housing 115 (thus allowing fluid flow through the seal area), the primary seal 107 is somewhat exposed (FIGS. 17A2 and 17 B2) to the abrasive fluid 112. At the instant that it is exposed there will be an amount of fluid that is at high pressure trying to escape the high pressure zone HPZ. However, this amount is kept to a minimum because as soon as a small amount of fluid moves past the newly exposed primary seal 107 the flow is slowed down by the second seal 109. This design protects the elastomeric primary seal 107 from damage by the potentially high velocity fluid flow.

When the seal system 103 is being reseated the concept also can work in reverse, though there are some other design elements that come into play. The second seal 109 seats first, thereby dramatically slowing the fluid flow and making the zone ready for the primary seal 107 to seat. The piston ring that comprises the secondary seal 109 does not expand in diameter. If it had expanded and it had to fit within a smaller diameter, a higher amount of axial force would be required to force the ring to compress. In some cases this may be permissible, although it may be desirable to provide a predictable amount of force to effect movement. To limit expansion of the piston ring 109, the cylinder bore 117 can be provided with some form of extension 116 (FIG. 12), or the opening that the seals enter can be a radial opening or window rather than a fully open bore 117.

Embodiments of the sealing system 103 also may be provided with a bevel or chamfer 118 on the leading edge of the bore 117 or aperture 120 that the primary seal 107 will rest within. Such a chamfer 118 can assist the primary seal 107 to avoid becoming stuck and resist moving back into the sealing bore 117. Thus, the sealing system 103 can include a smooth even chamfer 118 as well as a bore 117 with elements or extensions 116 that effectively extend for the entire axial range of motion of the seals 107, 109 to constrain the diameter of the secondary seal 109. Once the primary seal 107 is back within the seal bore 117 then a total seal may again be established.

In some embodiments, a sealing system 103 for a downhole tool 101 allows for opening and closing while there is a pressure differential across the sealing elements 107, 109. A piston 105 can reciprocate within a housing 115. The piston 105 may include at least two seals 107, 109 in glands or grooves 121, 122 (FIG. 17A1) on the OD of the piston 105. The first seal 107 may include an elastomer to effect a seal due to compressive force of the sealing element into the seal bore 117. The primary seal 107 can have a geometry that allows it to be easily seated inside the bore 117 of the cylinder 115. The first seal 107 can have a chamfer or sloped top surface 123 (FIG. 16) leading to a crest 127. The ID of the primary seal 107 can be slightly less than the OD of the gland 121 so that it is slightly stretched on installation. A void 131 can be on the ID of the primary seal 107 that is larger than the volume of material that has to be compressed for the seal 107 to fit into the sealing bore 117. The primary seal 107 may be formed from a rubber material, such as HNBR.

Versions of the second seal 109 can be a buffer seal formed from a hard and tough material. The buffer seal can be located to the high pressure side or zone HPZ of the primary seal 107. When both of the seals 107, 109 on the piston 105 move out of the area where the seal is maintained (FIGS. 17A3 and 17B3), the buffer seal 109 can be radially constrained to keep it from expanding. The buffer seal 109 may include a piston ring type of seal that is made out of metal, and is split 110 for installation on the piston 105. A chamfer 118 on the internal surface of the edge of the seal bore 117 may be employed.

In some embodiments, a downhole tool 101 may include a tubular member 115 having an axis 102, a wall with a bore 117, and an orifice 120 (FIG. 12) extending radially from the bore 117 through the wall. A piston 105 may be configured to be co-axially mounted in the bore 117 of the tubular member 115 and be axially reciprocated therein. The piston 105 can have a piston bore 106 (FIG. 13), an aperture 108 (FIGS. 13 and 17A3) extending radially from the piston bore 106 to the bore 117 of the tubular member 115, an outer surface and first and second glands 121, 122 (FIG. 17A1) formed in the outer surface adjacent the aperture 108. The first gland 121 can be axially spaced apart from the second gland 122.

Embodiments may include a seal system 103 configured to be mounted to the piston 105. The seal system 103 may include a primary seal 107 for the first gland 121, a secondary seal 109 for the second gland 122, and the secondary seal 109 can be harder than the primary seal 107. Versions of the primary seal 107 can have a hardness in a range of about Shore 60A to about Shore 90D. Alternatively, the primary seal 107 can have a hardness in a range of about Shore 60D to about Shore 90D. The primary seal 107 may include an elastomer formed in a continuous ring. The primary seal 107 may include hydrogenated nitrile butadiene rubber (HNBR).

Some embodiments of the primary seal 107 can have an inner diameter (ID) that is less than an outer diameter (OD) of the first gland 121 in a range of about 0.020 inches to about 0.060 inches. The primary seal 107 can have an inner diameter ID with a recess 131 (FIG. 16) formed therein. In some versions, annular legs 132 may be formed on each axial side of the recess 131. Versions of the recess 131 can be concave. Some versions have a volume that is configured to be equal to or greater than a volume of the primary seal 107 that is displaced when the primary seal 107 is fully engaged with the bore 117 of the tubular member 115. In a version, the primary seal 107 can have an axial dimension A, a radial dimension B, and an aspect ratio A:B in a range of about 1:1 to about 1:2.

Embodiments of the primary seal 107 can have an outer diameter OD, which can comprise one or more of: a non-planar surface; an incline in a range of about 5 degrees to about 30 degrees; a surface that is symmetrical; a crest 127 that forms a line that circumscribes the primary seal 107; and/or inclines 125 that slope radially inward from the crest 127, and the crest 127 bisects the outer diameter OD. In a version, the primary seal 107, in a relaxed state, can include a radial dimension that exceeds that of the first gland 121 in a range of about 0.004 inches to about 0.020 inches.

Embodiments of the secondary seal 109 may include a metallic split ring. It can be steel, and can include a stepped lap joint 110 (FIG. 15). The secondary seal 109 can be a buffer seal that is configured to quasi-seal between the piston 105 and the bore 117 of the tubular member 115 and allow a leakage rate of less than about 5% of a total flow rate through the tool. In other versions, the leakage rate can be less than 4%, less than 3%, less than 2%, or even less than 1% of a total flow rate through the tool.

Embodiments of the piston 105 (FIG. 13) can further comprise first and second axial ends, third and fourth seals 111, 113 can be located adjacent the first and second axial ends, respectively. The first and second glands 121, 122 can be axially spaced apart from the first and second axial ends and the third and fourth seals 111, 113.

In some versions, the tubular member 115 can be the housing 140 (FIG. 11) itself, or it can be a sleeve as shown. The sleeve 115 can be mounted coaxially inside the housing 140. The housing 140 can have a housing aperture 142 that axially registers with the orifice 120. The housing 140 can have an axial length that is greater than that of the tubular member 115.

In some versions (FIG. 12), the bore 117 of the tubular member 115 can include a coating 150 having a hardness greater than that of the tubular member 115 itself. For example, the hardness of the coating 150 can be in a range of about 45 HRc to about 65 HRc. The coating 150 may include chromium or other hard materials.

An embodiment of the downhole tool 101 may further include a chamfer 118 (FIG. 17A1) formed on the tubular member 115 at an interface between the bore 117 and the orifice 120. For example, the chamfer 118 can be formed at an angle in a range of about 10 degrees to about 30 degrees. As shown in FIG. 12, the orifice 120 may include a plurality of orifices 120. In an example, each adjacent pair of the orifices 120 can be separated by an extension or bar 116 that extends parallel to the axis 102. The bars 116 can have an inner diameter ID that is substantially equal to that of the bore 117. In an example, the bar 116 can be configured to constrain an outer diameter OD of the secondary seal 109.

Embodiments of the operation of downhole tool 101 may include configuring the piston 105 to move axially but not rotationally within the tubular member 115. The seal system 103 can be configured to have a closed position (FIGS. 17A1 and 17B1) wherein neither the primary seal 107 nor the second seal 109 is in the orifice 120 of the tubular member 115. Versions may include a partially open position (FIGS. 17A2 and 17B2) wherein only the primary seal 107 is located at least partially in the orifice 120 of the tubular member 115 and the second seal 109 is not in the orifice 120 of the tubular member 115. Other versions may include a completely open position (FIGS. 17A3, 17B3 and 18) wherein both the primary seal 107 and the second seal 109 are located at least partially in the orifice 120 of the tubular member 115.

Embodiments of the first gland 121 (FIG. 17A1) can be axially spaced apart from the second gland 122 by about 0.1 inches to about 0.8 inches. Versions can have a radial clearance provided between an outer diameter OD of the piston 105 and an inner diameter ID of the tubular member 115, and the radial clearance can be in a range of about 0.001 inches to about 0.010 inches. In an example, the secondary seal 109 and the second gland 122 can be configured to be closer to the aperture 108 in the piston 105 than the primary seal 107 and the first gland 121. The primary seal 107 and the first gland 121 can be larger than the secondary seal 109 and the second gland 122, respectively.

In other embodiments (FIGS. 19A-C), the seal system may be mounted to the bore 117 of the tubular member 115 or housing, rather than to the piston 105. For example, a downhole tool may include a tubular member 115 having an axis, a wall with a bore 117, an orifice 120 extending radially from the bore through the wall, and first and second glands 121, 122 formed in bore 117 adjacent the orifice 120. The first gland 121 can be axially spaced apart from the second gland 122. A piston 105 may be configured to be co-axially mounted in the bore 117 of the tubular member 115 and be axially reciprocated therein. The piston 105 may include a piston bore 106, and an aperture 108 extending radially from the piston bore 106 to the bore 117 of the tubular member 115. In addition, a seal system may be configured to be mounted to the tubular member 115. The seal system may include a primary seal 107 for the first gland 121, a secondary seal 109 for the second gland 122, and the secondary seal 109 can be harder than the primary seal 107.

The embodiments of the seal system disclosed herein are suitable for numerous applications, and are not limited to the downhole tool systems described herein.

Still other embodiments may include one or more of the following items:

Item 1. A downhole tool, comprising:

• • a tubular member having an axis, a wall with a bore, and an orifice extending radially from the bore through the wall;
  • a piston configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein, the piston having a piston bore, an aperture extending radially from the piston bore to the bore of the tubular member, an outer surface and first and second glands formed in the outer surface adjacent the aperture, and the first gland is axially spaced apart from the second gland; and
  • a seal system configured to be mounted to the piston, the seal system comprising a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.

Item 2. The downhole tool of any of these items, wherein:

the primary seal has a hardness in a range of about Shore 60A to about Shore 90D;

the primary seal has a hardness in a range of about Shore 60D to about Shore 90D;

the primary seal comprises an elastomer formed in a continuous ring; or the primary seal comprises hydrogenated nitrile butadiene rubber (HNBR).

Item 3. The downhole tool of any of these items, primary seal has an inner diameter that is less than an outer diameter of the first gland in a range of about 0.020 inches to about 0.060 inches.

Item 4. The downhole tool of any of these items, wherein the primary seal has an inner diameter with a recess formed therein, and annular legs are formed on each axial side of the recess.

Item 5. The downhole tool of any of these items, wherein the recess has a volume that is configured to be equal to or greater than a volume of the primary seal that is displaced when the primary seal is fully engaged with the bore of the tubular member.

Item 6. The downhole tool of any of these items, wherein the primary seal comprises an axial dimension A, a radial dimension B, and an aspect ratio A:B in a range of about 1:1 to about 1:2.

Item 7. The downhole tool of any of these items, wherein the primary seal has an outer diameter, and wherein the outer diameter comprises one or more of:

a non-planar surface;

an incline in a range of about 5 degrees to about 30 degrees;

a crest that forms a line that circumscribes the primary seal; and

inclines that slope radially inward from a crest, and the crest bisects the outer diameter.

Item 8. The downhole tool of any of these items, wherein the primary seal, in a relaxed state, comprises a radial dimension that exceeds that of the first gland in a range of about 0.004 inches to about 0.020 inches.

Item 9. The downhole tool of any of these items, wherein the secondary seal comprises a metallic split ring.

Item 10. The downhole tool of any of these items, wherein the secondary seal comprises steel and has a stepped lap joint.

Item 11. The downhole tool of any of these items, wherein the secondary seal comprises a buffer seal that is configured to quasi-seal between the piston and the bore of the tubular member and allow a leakage rate of less than about 5% of a total flow rate through the tool.

Item 12. The downhole tool of any of these items, wherein the piston further comprises first and second axial ends, third and fourth seals are located adjacent the first and second axial ends, respectively, and the first and second glands are axially spaced apart from the first and second axial ends and the third and fourth seals.

Item 13. The downhole tool of any of these items, wherein the tubular member is a sleeve, the sleeve is mounted coaxially inside a housing, the housing has a housing aperture that axially registers with the orifice, and the housing has an axial length greater than that of the tubular member.

Item 14. The downhole tool of any of these items, wherein the bore of the tubular member comprises a coating having a hardness greater than that of the tubular member itself, the hardness of the coating is in a range of about 45 HRc to about 65 HRc, and the coating comprises one or more of chromium, carbide and ceramic.

Item 15. The downhole tool of any of these items, further comprising a chamfer formed on the tubular member at an interface between the bore and the orifice.

Item 16. The downhole tool of any of these items, wherein the chamfer is formed at an angle in a range of about 10 degrees to about 30 degrees.

Item 17. The downhole tool of any of these items, wherein the orifice comprises a plurality of orifices, each adjacent pair of the orifices is separated by a bar that extends parallel to the axis, and the bar has an inner diameter that is substantially equal to that of the bore.

Item 18. The downhole tool of any of these items, wherein the bar is configured to constrain an outer diameter of the secondary seal.

Item 19. The downhole tool of any of these items, wherein the piston is configured to move axially but not rotationally within the tubular member.

Item 20. The downhole tool of any of these items, wherein the seal system is configured to have a closed position wherein neither the primary seal nor the second seal is in the orifice of the tubular member, a partially open position wherein only the primary seal is located at least partially in the orifice of the tubular member and the second seal is not in the orifice of the tubular member, and a completely open position wherein both the primary seal and the second seal are located at least partially in the orifice of the tubular member.

Item 21. The downhole tool of any of these items, wherein the first gland is axially spaced apart from the second gland by about 0.1 inches to about 0.8 inches.

Item 22. The downhole tool of any of these items, wherein a radial clearance is provided between an outer diameter of the piston and an inner diameter of the tubular member, and the radial clearance is in a range of about 0.001 inches to about 0.010 inches.

Item 23. The downhole tool of any of these items, wherein the secondary seal and the second gland are configured to be closer to the aperture in the piston than the primary seal and the first gland, and the primary seal and the first gland are larger than the secondary seal and the second gland, respectively.

Item 24. A downhole tool, comprising:

• • a tubular member having an axis, a wall with a bore, an orifice extending radially from the bore through the wall, first and second glands formed in bore adjacent the orifice, and the first gland is axially spaced apart from the second gland;
  • a piston configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein, the piston having a piston bore, and an aperture extending radially from the piston bore to the bore of the tubular member; and
  • a seal system configured to be mounted to the tubular member, the seal system comprising a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.

Item 25. The downhole tool of item 24, wherein the aperture in the piston comprises a plurality of apertures, each adjacent pair of the apertures is separated by a bar that extends parallel to the axis, and the bar has an outer diameter that is substantially equal to that of the piston, and the bar is configured to constrain an inner diameter of the secondary seal.

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.

Claims

1. A downhole tool, comprising:

a tubular member having an axis, a wall with a bore, and an orifice extending radially from the bore through the wall;

a piston configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein, the piston having a piston bore, an aperture extending radially from the piston bore to the bore of the tubular member, an outer surface and first and second glands formed in the outer surface adjacent the aperture, and the first gland is axially spaced apart from the second gland; and

a seal system configured to be mounted to the piston, the seal system comprising a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.

2. The downhole tool of claim 1, wherein:

the primary seal has a hardness in a range of about Shore 60A to about Shore 90D;

the primary seal has a hardness in a range of about Shore 60D to about Shore 90D;

the primary seal comprises an elastomer formed in a continuous ring; or

the primary seal comprises hydrogenated nitrile butadiene rubber (HNBR).

3. The downhole tool of claim 1, primary seal has an inner diameter that is less than an outer diameter of the first gland in a range of about 0.020 inches to about 0.060 inches.

4. The downhole tool of claim 1, wherein the primary seal has an inner diameter with a recess formed therein, and annular legs are formed on each axial side of the recess.

5. The downhole tool of claim 1, wherein the primary seal has an outer diameter, and wherein the outer diameter comprises one or more of:

a non-planar surface;

an incline in a range of about 5 degrees to about 30 degrees;

a crest that forms a line that circumscribes the primary seal; and

inclines that slope radially inward from a crest, and the crest bisects the outer diameter.

6. The downhole tool of claim 1, wherein the primary seal, in a relaxed state, comprises a radial dimension that exceeds that of the first gland in a range of about 0.004 inches to about 0.020 inches.

7. The downhole tool of claim 1, wherein the secondary seal comprises a metallic split ring.

8. The downhole tool of claim 1, wherein the secondary seal comprises a buffer seal that is configured to quasi-seal between the piston and the bore of the tubular member and allow a leakage rate of less than about 5% of a total flow rate through the tool.

9. The downhole tool of claim 1, wherein the piston further comprises first and second axial ends, third and fourth seals are located adjacent the first and second axial ends, respectively, and the first and second glands are axially spaced apart from the first and second axial ends and the third and fourth seals.

10. The downhole tool of claim 1, wherein the tubular member is a sleeve, the sleeve is mounted coaxially inside a housing, the housing has a housing aperture that axially registers with the orifice, and the housing has an axial length greater than that of the tubular member.

11. The downhole tool of claim 1, wherein the bore of the tubular member comprises a coating having a hardness greater than that of the tubular member itself, the hardness of the coating is in a range of about 45 HRc to about 65 HRc, and the coating comprises one or more of chromium, carbide and ceramic.

12. The downhole tool of claim 1, further comprising a chamfer formed on the tubular member at an interface between the bore and the orifice.

13. The downhole tool of claim 12, wherein the chamfer is formed at an angle in a range of about 10 degrees to about 30 degrees.

14. The downhole tool of claim 1, wherein the orifice comprises a plurality of orifices, each adjacent pair of the orifices is separated by a bar that extends parallel to the axis, and the bar has an inner diameter that is substantially equal to that of the bore.

15. The downhole tool of claim 14, wherein the bar is configured to constrain an outer diameter of the secondary seal.

16. The downhole tool of claim 1, wherein the piston is configured to move axially but not rotationally within the tubular member.

17. The downhole tool of claim 1, wherein the seal system is configured to have a closed position wherein neither the primary seal nor the second seal is in the orifice of the tubular member, a partially open position wherein only the primary seal is located at least partially in the orifice of the tubular member and the second seal is not in the orifice of the tubular member, and a completely open position wherein both the primary seal and the second seal are located at least partially in the orifice of the tubular member.

18. The downhole tool of claim 1, wherein a radial clearance is provided between an outer diameter of the piston and an inner diameter of the tubular member, and the radial clearance is in a range of about 0.001 inches to about 0.010 inches.

19. The downhole tool of claim 1, wherein the secondary seal and the second gland are configured to be closer to the aperture in the piston than the primary seal and the first gland, and the primary seal and the first gland are larger than the secondary seal and the second gland, respectively.

20. A downhole tool, comprising:

a tubular member having an axis, a wall with a bore, an orifice extending radially from the bore through the wall, first and second glands formed in bore adjacent the orifice, and the first gland is axially spaced apart from the second gland;

a piston configured to be co-axially mounted in the bore of the tubular member and be axially reciprocated therein, the piston having a piston bore, and an aperture extending radially from the piston bore to the bore of the tubular member; and

a seal system configured to be mounted to the tubular member, the seal system comprising a primary seal for the first gland, a secondary seal for the second gland, and the secondary seal is harder than the primary seal.