Hydraulic setting tool for liner hanger

Embodiments of the present invention relates to hydraulically actuated tools, which may be used to actuate a liner hanger assembly. In one embodiment, the present invention provides a hydraulic setting tool for use in wellbore operations. The setting tool includes a first tubular member and a second tubular member disposed around the outer diameter of the first tubular member. A piston is mechanically attached to an upper portion of the second tubular member and adapted to move axially in relation to the first tubular member. The piston acts to transmit a force to the second tubular member. A slip assembly is operatively connected to the second tubular member and the second tubular member transmits the force to the slip assembly thereby actuating the slip assembly.

BACKGROUND OF THE INVENTION

1. Field of the Invention

Embodiments of the present invention generally relate to methods and apparatus for completing a well. Particularly, embodiments of the present invention relate to hydraulically actuated tools, which may be used to set a liner hanger assembly.

2. Description of the Related Art

In the drilling of oil and gas wells, a wellbore is formed using a drill bit that is urged downwardly at a lower end of a drill string. After drilling to a predetermined depth, the drill string and the bit are removed and the wellbore is lined with a string of casing. An annular area is thus formed between the string of casing and the formation. A cementing operation is then conducted in order to fill the annular area with cement. The combination of cement and casing strengthens the wellbore and facilitates the isolation of certain areas of the formation behind the casing for the production of hydrocarbons.

It is common to employ more than one string of casing in a wellbore. In this respect, a first string of casing is set in the wellbore when the well is drilled to a first designated depth. The first string of casing is hung from the surface, and then cement is circulated into the annulus behind the casing. The well is then drilled to a second designated depth, and a second string of casing, or liner, is run into the well. The second string is set at a depth such that the upper portion of the second string of casing overlaps with the lower portion of the upper string of casing. The second “liner” string is then fixed or “hung” off of the inner surface of the upper string of casing. Afterwards, the liner string is also cemented. This process is typically repeated with additional liner strings until the well has been drilled to total depth. In this manner, wells are typically formed with two or more strings of casing of an ever-decreasing diameter.

The process of hanging a liner off of a string of surface casing or other upper casing string involves the use of a liner hanger. The liner hanger is typically run into the wellbore above the liner string itself. The liner hanger is actuated once the liner is positioned at the appropriate depth within the wellbore. The liner hanger is typically set through actuation of slips which ride outwardly on cones in order to frictionally engage the surrounding string of casing. The liner hanger operates to suspend the liner from the casing string. However, it does not provide a fluid seal between the liner and the casing. Accordingly, it is desirable in many wellbore completions to also provide a packer.

During the wellbore completion process, the packer is typically run into the wellbore above the liner hanger. A threaded connection typically connects the bottom of the packer to the top of the liner hanger. Known packers employ a mechanical or hydraulic force in order to expand a packing element outwardly from the body of the packer into the annular region defined between the packer and the surrounding casing string. In addition, a cone may be driven behind a tapered slip to force the slip into the surrounding casing wall and to prevent upward packer movement. Numerous arrangements have been derived in order to accomplish these results.

Liner top packers are commonly run with liner hangers to provide a fluid barrier for the annular area between the casing and the liner. Liner top packers run with liner hangers typically include a tubular member with a seal bore in it that is run on the top end of the packer. This tubular member is commonly referred to as a polished bore receptacle (PBR) or tieback receptacle. This PBR provides a means for a tieback with a “seal stem” or tubular at a later date for remediation or production purposes. The liner top packers are typically set by compressive force transmitted to the packer from the landing string through the PBR. There is typically a seal or seals between the PBR and the body of the packer that allow axial motion of the PBR relative to the liner top packer body. These seals become an integral part of the wellbore when the PBR is tied back. These seals are typically constructed from elastomers, which must be carefully selected to ensure fluid and temperature compatibility with the anticipated downhole conditions. If these seals were to leak, costly remediation would be required.

Hydraulic liner hangers typically have ports disposed through the wall of the liner hanger body that allow fluid to pass into a hydraulic cylinder or piston located external to or in the wall of the liner hanger body. As pressure is applied to the cylinder or piston, a mechanical force is generated to urge the slips up the taper of the cones until they frictionally engage the slips with the inside of the casing wall. This mechanical force is typically imparted along the axis of the liner hanger body or parallel to the axial movement of the slips. Once the slips are actuated and the liner hanger is set, the cylinder or piston and the respective seals become an integral part of the wellbore and are required to function for the life span of the well. The ports and seals disposed between the cylinder or piston and the liner hanger body create potential leak paths. Failure of the cylinder or piston or the respective seals will typically result in costly remedial work to repair the leak. In addition, high downhole temperatures place great demands on the elastomer seals typically used in conjunction with the cylinders or pistons in hydraulic liner hangers. High downhole pressures induce high burst and collapse loads on the hydraulic cylinder or piston along with imparting additional stresses on the seals. The required thickness of the cylinder or piston can create compromises in liner hanger body thickness, which would reduce the pressure and load capacity of the liner hanger body.

Hydraulic liner hangers typically have an actuating control mechanism consisting of shear screws or rupture discs that prevent movement of the hydraulic cylinder or piston to prevent actuation of the slips until a specific internal pressure has been reached. If this pressure is exceeded or the actuating control mechanism is prematurely actuated, the slips will be activated and any subsequent hydraulic pressure will directly act on the cylinder or piston to set the slips. If the actuation control mechanism is actuated late, other hydraulic equipment may be actuated out of the desired sequence. The relatively small piston area of a typical hydraulic cylinder combined with the relatively large seals required to place the cylinder around the liner hanger body can lead to unfavorable ratios of activation force to seal friction, which in turn can lead to inaccuracies in the activation pressures.

Typically, the hydraulic cylinders or pistons for hydraulic liner hangers come into contact with wellbore production fluids and are thus considered flow-wetted parts. The hydraulic cylinders or pistons are typically constructed from the same material as the liner body being used to ensure compatibility with the production fluids. This can significantly increase the cost of construction of the liner hanger assembly.

In challenging well conditions, such as horizontal wells or wells with debris or contaminants, the force required to activate the slips on the liner hanger is critical for successful hanger operation. In deviated or horizontal wells, solids may fall out of suspension from the drilling fluids and accumulate on the lower side of the wellbore. In horizontal or deviated wellbore operations, the liner hanger typically rides on the lower side of the wellbore during run in. The liner hanger slips that are located on the low side of the wellbore are required to move up the cone during actuation in order to engage the casing. Furthermore, all of the slips on the slip assembly are axially fixed together to ensure centralization of the liner and to provide for an even loading of the slips onto the inner surface of the casing. If the slips disposed on the lower side are allowed to contact the casing before the remaining slips, then the remaining slips will not engage the casing until the cones become centralized in the wellbore. Since the plurality of cones is disposed on the liner hanger body, the liner will have to be lifted by the lower slips to centralize the cones, which can require a considerable force. If insufficient hydraulic force is available to centralize the liner alone, then a combination of hydraulic force on the slips and downward movement of the cone and liner will be required to hold the slips stationary while the cones ride up the slips. If the friction of the slips on the lower side of casing combined with the hydraulic force on the slips is less than the force required to “ramp” the cones up the slip, then the cones will not ride up the slips sufficiently to radially extend the slips to a point where the remaining slips become engaged with the casing.

If the liner being run into the wellbore is short in length or very light in weight, it can be challenging to determine whether the running tools have been released from the liner by simply raising the landing string. Difficulty in determining whether the running tools have been released can also be incurred if the well is deviated or horizontal. Release of the running tools from the liner can be determined by a loss of weight from the landing string. To overcome this challenge, liners may also be run with hold down devices, such as a hydraulic actuated hold down sub that provides a means of anchoring the liner so that it will resist upward movement. Also bi-directional gripping slip devices are known to maintain the compressive force in the slips that is applied to the liner hanger after it is set. However, if the liner is in a deviated well, then applying adequate compressive force can prove difficult due to the frictional drag created between the wellbore and the landing string. Currently, hold-down devices and known bi-directional slip devices add considerable complexity to the liner hanger assembly, in particular when utilized with rotating liner applications.

As a liner is run into a wellbore, fluid along with cuttings and other solids are displaced from the well bore and urged past the outside of the liner. When the fluid traverses past the top of the PBR and the running tools, the velocity of the fluid decreases due to entering a larger annulus. This decrease in fluid velocity negatively affects the ability of the fluid to carry solids and therefore, causes the heavier solids in the fluid to accumulate at the top of the liner. Consequently, the solids may enter the area around the running tools located within the PBR causing difficulties in releasing or retrieving the running tools.

Therefore, there is a need for an improved device and method for setting a liner within a wellbore.

SUMMARY OF THE INVENTION

The present invention generally relates to methods and apparatus for completing a well. Particularly, embodiments of the present invention relate to hydraulically actuated tools, which may be used to set a liner hanger assembly.

In one aspect, the present invention provides a setting tool for use in a wellbore. The tool comprises a first tubular member and a second tubular member disposed around the outer diameter of the first tubular member. The tool further includes a force transmission member engaged to an upper portion of the second tubular member and axially movable relative to the first tubular member, wherein the force transmission member is adapted to transmit a force to the second tubular member. The tool is equipped with a gripping member operatively connected to the second tubular member, the gripping assembly actuatable by the force transmitted to the second tubular member.

In another aspect, the present invention provides a method for setting a tool in a wellbore. The method includes disposing a first tubular around a second tubular, transmitting an axial force to the first tubular, and moving the first tubular axially relative to the second tubular. The method also includes actuating a gripping member operatively connected to the first tubular, wherein the gripping member sets the tool in the wellbore.

In one embodiment of the present invention, a hydraulic setting tool for use in wellbore operations comprises a first tubular member and a thin second tubular member disposed around the outer diameter of the first tubular member. A piston is mechanically attached to an upper portion of the second tubular member and adapted to move axially in relation to the first tubular member. The piston acts to transmit a force to the second tubular member. A slip assembly is operatively connected to the second tubular member and the second tubular member transmits the force to the slip assembly thereby actuating the slip assembly.

A method for the use of a hydraulic setting tool in wellbore operations according to one embodiment of the present invention is also provided. The hydraulic setting tool is operated by providing a first tubular member and a thin second tubular member, wherein the second tubular member is disposed around the outer diameter of the first tubular member. A force is transmitted to the second tubular member through a piston, wherein the piston is operatively connected to an upper portion of the second tubular member and adapted to move axially in relation to the first tubular member. The force is then transmitted to a slip assembly, wherein the slip assembly is operatively connected to the second tubular member thereby actuating the slip assembly.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENT

Embodiments of the present invention generally relate to methods and apparatus for completing a well. Particularly, embodiments of the present invention relate to a thin outer sleeve disposed around a liner hanger assembly and to a plurality of hydraulic tools in combination with the thin outer sleeve used to set a liner hanger and a liner top packer.

Embodiments of the invention are described below with terms designating orientation in reference to a vertical wellbore. These terms designating orientation should not be deemed to limit the scope of the invention. Embodiments of the invention may also be used in a non-vertical wellbore, such as a horizontal wellbore.

FIG. 1illustrates a partial schematic view of one embodiment of a liner hanger assembly100and a running tool assembly105in a run-in position.FIG. 2shows a partial schematic view of the liner hanger assembly100and the running tool assembly105with the liner hanger176set within a wellbore.FIG. 3shows a partial schematic view of the liner hanger assembly100and the running tool assembly105in the liner top packer actuated mode.

The liner hanger assembly100generally includes a polished bore receptacle (PBR)130, a liner top packer148, and a liner hanger176. As shown inFIG. 1, the PBR130is disposed above the packer148. InFIG. 1, the PBR130is shown rigidly connected to a liner body146by a metal to metal sealing, threaded connection; however, it is assumed that the PBR may be attached to the liner body146by any connection means known to a person of ordinary skill in the art or the PBR130can be an integral part of the liner body146. The liner top packer148is shown on a common liner body146with the liner hanger176; however, it is assumed that they could have two separate bodies threadedly coupled together.

The running tool assembly105generally includes an inner tubular104, a hydraulic setting apparatus113disposed at an upper end of the inner tubular104, and a floating piston134located below the hydraulic setting apparatus113. Common liner running components such as a packer actuator, releasing tool, cementing pack-off, and wiper plugs, make up the remainder of the running tool assembly105and will be discussed in further detail below. A landing string (not shown) can be used to lower, support, and retrieve the running tool assembly105and the liner hanger assembly100during operation. As illustrated inFIG. 1, a thin tubular sleeve128is positioned around the exterior of the PBR130and extends from above the PBR130to the packer148. InFIG. 1, the hydraulic setting apparatus113is located adjacent to the upper end of the PBR130. The hydraulic setting apparatus113includes a setting piston110and a hydraulic actuation piston118. The setting piston110is sealably disposed on the inner diameter of the PBR130and is connected to an upper portion of the thin tubular sleeve128by an upper locking dog124. The setting piston110is also selectively connected to an upper portion of the PBR130by a lower locking dog126. The hydraulic actuation piston118is sealably engaged to the outer diameter171of the inner tubular104and is disposed between the inner tubular104and the setting piston110. In one embodiment, the actuating piston118is selectively connected to the setting piston110using a shearable screw114. Although, locking dogs124,126and shearable screw114are used to secure the setting piston110, other releasable securing devices such as collets, frangible members, and any others known to a person of ordinary skill in the art may be used.

As shown inFIG. 1, the floating piston134is disposed between the hydraulic setting apparatus113and the cementing pack-off142. The floating piston134is sealably and movably disposed on a sealing surface183of the tubular104. A fluid chamber141is formed between the inner tubular104and the floating piston134. Preferably the floating piston134is biased so that it is in an intermediate position with respect to its permitted travel when no external pressures or forces are applied to it. This may be accomplished in the preferred embodiment by compression springs136and140. The cementing pack-off142is disposed below the floating piston134. The cementing pack-off142serves to prevent the upward flow of cement (not shown) through the annular area between the liner body146and the polished mandrel173. Together the tubular104, the setting piston110, the actuating piston118, the PBR130, the liner body146, the cementing pack-off142, polished mandrel173, and the running tool components between the cementing pack-off142and the floating piston134form a contained fluid chamber139. The floating piston134serves to transmit pressure to the inside of the contained fluid chamber139without direct fluid communication to the working fluid (not shown) in the tubular104. A port138is disposed through the tubular104and places the fluid in the tubular104in communication with the fluid chamber141.

The hydraulic setting apparatus113may also contain hydraulic control devices including a rupture disc117and a check valve116disposed on the hydraulic actuation piston118, which serve to control the pressure within the PBR fluid chamber139by regulating the ingress and exit of annular fluid from the fluid chamber139. A filter screen112is disposed on the outside of the setting piston110. The filter screen112functions to segregate solids from the fluid entering the fluid chamber139through the above devices. The hydraulic setting apparatus113is configured to transmit an upward force from the hydraulic actuating piston118and the setting piston110to the outer tubular sleeve128.

Near the lower end of the PBR130, the outer tubular sleeve128traverses underneath the packing element177and connects to a first shoulder member150that is further attached to a second shoulder member152. The second shoulder member152comprises the upper portion of the liner hanger176and acts to transmit an upward force to a plurality of slips162resulting from the upward movement of the outer tubular sleeve128.

The liner hanger176also includes a plurality of cones160disposed on the outer diameter of the liner body146and configured to orient the plurality of slips162radially outward to engage the casing166, as shown inFIG. 2. A thrust bearing151is disposed between the second shoulder member152and the liner body146proximate the upper portion of the cones160. A one-way ratchet profile154is disposed on the exterior of the cylindrical upper portion of the cones160. A connecting ring163is attached to the slips162to maintain the slips162in the same axial position relative to their respective cones160. The connecting ring163includes a ratchet ring156that serves to matingly engage the ratchet profile154thereby allowing the slips162to only travel in an upward direction. A biasing member158, such as a compression spring, is disposed between the cones160and the ratchet profile154to lock in the setting force applied by the hydraulic setting apparatus113into the slips162and cones160.

The liner hanger assembly100and running tool assembly105as shown inFIG. 1are assembled to a liner tubular103and prepared at the surface. The assemblies100,105are adapted to hang and seal a liner tubular103to an existing casing in the wellbore. Before being run into the wellbore, the PBR fluid chamber139on the liner hanger assembly100is filled through a fill port119disposed through the setting piston110with a clean fluid, such as water. The liner hanger assembly100and running tool assembly105are then run into the wellbore on a landing string (not shown) to a desired setting depth. The floating piston134and the one way check valve116serve to compensate for any variation in the volume of the PBR fluid chamber139due to fluctuations in the temperature or pressure of the fluid while the liner hanger assembly100is being run into the wellbore.

Once the liner hanger assembly100has reached the desired setting depth, a ball or other suitable device (not shown) is deployed from the surface through the landing string until landing on a ball-seat (not shown) positioned below the liner hanger assembly100thereby preventing the fluid from flowing below the ball-seat and allowing the fluid above the seat to be pressurized. The pressurized fluid within the tubular104will enter the chamber141through the port138causing the floating piston134to travel downward to a position, as illustrated inFIG. 2. Accordingly, the downward movement of the floating piston134will compress the fluid in the PBR fluid chamber139until the pressure in the PBR fluid chamber139and the pressure in tubular104are equal. The check valve116is configured to prevent fluid from exiting fluid chamber139. The increased pressure in the PBR fluid chamber139is applied to the hydraulic actuation piston118and the setting piston110of the hydraulic setting apparatus113. The differential pressure between the PBR fluid chamber139and the annulus168between the running tools and the casing urges the actuating piston118upward along the outer diameter171of the tubular104. When the pressure in the chamber139reaches a predetermined pressure, the shear screw114on the hydraulic actuation piston118will release or shear, thereby allowing the114actuating piston118to move axially with respect to the PBR130. Since the actuating piston118is positioned around the inner tubular104the seal contact area is relatively small.

A sufficient upward travel of the actuating piston118releases the lower locking dog126from the PBR130. The actuating piston118shoulders against the setting piston110and the combined piston area is from the inner diameter of the PBR130to the outer diameter171of the inner tubular104,thereby creating a large piston area for the pressure to be applied across. The upper locking dog124transmits the upward motion of the setting piston110to the thin tubular sleeve128. As previously described, the outer tubular sleeve128transmits this upward force to the liner hanger176through the first and second shoulder members,150and152, respectively. In turn, the second shoulder member152, which connects to an upper portion of the slips162, urges the slip162upward against the tapered surface of the cones160disposed on the liner body146causing the slips162to extend radially outward towards the casing166. The slips162continue to expand radially until the gripping surface165on the exterior of the slips162engages the inner diameter of the casing166. Additional hydraulic setting force acts to fully compress the spring158located above the cones160. Accordingly, the ratchet ring156will lock into position on the ratchet teeth profile154to prevent the slips162from moving back down the tapered surfaces of the cones160and to maintain the setting force on the slips162supplied by the biasing member158.

The engagement of the slips162onto the casing166allows the liner hanger assembly100to carry the weight of the liner tubular103at which point the support provided by the landing string (not shown) to the running tool assembly105from the surface to suspend the liner hanger assembly100and liner tubular103in position may be relieved. The weight of the liner tubular103is transmitted from the liner body146through the cones160, to the slips162which are in frictional engagement with the casing166. Any upward pull through liner body146is transmitted through load ring174into the upper part of cone160above the biasing member158. The force is then transferred to connector ring163and to the slips162and casing166via ratchet ring156. The slips162provide moderate hold down capacity in this configuration. An over-pull on the landing string may be used to confirm that the liner hanger assembly100is set in place by ensuring that the no upward movement of the liner hanger assembly100occurs during the over-pull.

Additional hydraulic pressure on the hydraulic actuation piston118from the fluid chamber139will open the pressure control mechanism117, such as a rupture disc, disposed through the hydraulic actuation piston to place the annulus168between the running tools and the casing in communication with the PBR fluid chamber139thereby allowing the pressure in the chamber139and annulus168to equalize. The pressure required to open the pressure control mechanism117is set higher than the pressure required to urge the setting piston110upward and fully engage the slips162with the casing166. In response to fluid exiting through the open pressure control mechanism117, the floating piston134will travel downward until a travel stop132disposed at an upper portion of the floating piston134reaches a shoulder133protruding from the inner tubular104wherein the floating piston134has reached the end of its stroke.

A new pressure differential can then be established between the fluid in the tubular104and the PBR fluid chamber139. This pressure differential may be used to release liner hanger assembly100from the running tool assembly105. In one embodiment, pressurized fluid entering port180deactivates a frangible member181holding the piston179and urges the piston179to move upward. Continual upward movement of the piston179causes a release mechanism, such as a collet167, to release from the liner body146. As a result, the running tool assembly105is released from the liner hanger assembly100.

In order to confirm that the liner hanger assembly100has been released, the running tool assembly105and landing string are raised upward from the surface. Additional assurance that the liner hanger assembly100remains stationary while picking up the running tool assembly105is provided by the hold down capabilities of the liner hanger assembly100. Preferably the outer diameter171of the inner tubular104on the hydraulic setting apparatus113and the outer diameter172on the polished mandrel173through the cementing pack-off142are of the same diameter, thereby allowing the running tools to be raised and lowered without changing the volume within the PBR chamber139. If the diameters are not the same, the change in volume can be compensated for by the floating piston134and/or fluid influx through the control device117, such as a rupture disc, which is now open with respect to the annulus168. All fluid entering the fluid chamber139is directed through the screen112to prevent entry of solids that could cause retrieval of the running tools to be more difficult.

The running tool assembly105remains within the liner hanger assembly100as it is lowered back into contact with the liner hanger assembly100. The ball or sealing device (not shown) may now be released so that it no longer impedes fluid passage in the tubular104. This is typically accomplished by pressuring up to a higher pressure against a ball seat located below the liner hanger176held by frangible members (not shown) at which point they break at a predetermined pressure and the seat moves from its sealing position to an open position, thereby re-establishing fluid communication with the annulus below the ball seat (not shown). Provisions for rotation of the liner body146during cementing are provided for in the liner hanger176by the thrust bearing151located between the upper part of cone160and liner body146, which allows the slips162and cones160to remain stationary with respect to the casing166while the liner body146and liner hanger assembly100rotate. During cementing operations wherein cement (not shown) is pumped down the landing string, the tubular104, and around the bottom of the liner tubular103to fill the annular area168between the liner tubular103and the casing166. As described above, the cementing pack-off142prevents the inadvertent upward flow of cement to the PBR fluid chamber139.

After the cementing operations are completed, further pick up of the running tool assembly105by the landing string causes the shoulder175under the actuation piston118on inner tubular104to contact release sleeve120, thereby moving it upward so that it compresses biasing member122. This releases the setting piston110from the thin tubular sleeve128by allowing the upper locking dogs124to move from their locked position to an unlocked position. As shown inFIG. 3, further upward movement of the running tool assembly105past the thin tubular sleeve128allows a packer actuator to extend radially. A shoulder on the packer actuator170may now engage the top of the thin tubular sleeve128to transmit a downward force to the tubular sleeve128. The downward force applied to the sleeve128acts to expand the sealing element177on the packer148to form a seal with the casing166, as illustrated inFIG. 3. A pressure test may be performed on the packer148at this time to ensure its sealing performance. Further pick up of the running tool assembly105by the landing string will disengage the cementing pack-off142and allow the run-in tool assembly105to be retrieved with the landing string. The thin tubular sleeve128may be left in the well or retrieved along with the run-in tool assembly105.

Aspects of the present invention also provide a liner hanger assembly200and a running tool assembly205adapted to activate the packer248and the liner hanger276using tension as a setting force.FIG. 4illustrates a partial schematic view of the assemblies200,205in a run-in position.FIG. 5illustrates a partial schematic view of the assemblies200,205with the liner hanger276set within a wellbore and the packer248decoupled from the liner hanger276.FIG. 6illustrates a partial schematic view of the assemblies200,205after the running tool assembly205has been released and after setting of the liner top packer248has just begun.FIG. 7illustrates a partial schematic view of the assemblies200,205in the liner top packer actuated position.

The liner hanger assembly200generally includes a polished bore receptacle (PBR)230, a liner top packer248, and a liner hanger276. As shown inFIG. 4, the PBR230is disposed above the packer248. InFIG. 4, the PBR230is shown rigidly connected to a liner body246by a metal to metal sealing, threaded connection; however, it is assumed that the PBR may be attached to the liner body246by any connection means known to a person of ordinary skill in the art or the PBR230can be an integral part of the liner body246. The liner top packer248is shown on a common liner body246with the liner hanger276; however, it is assumed that they could have two separate bodies threadedly coupled together.

The running tool assembly205generally includes an inner tubular204, a hydraulic setting apparatus213disposed at an upper end of the inner tubular204, and a cylinder235having a floating piston234located below the hydraulic setting apparatus213. Common liner running components such as a packer actuator, releasing tool, cementing pack-off, and wiper plugs, make up the remainder of the running tool assembly205and will be discussed in further detail below. A landing string (not shown) can be used to lower, support, and retrieve the running tool assembly205and the liner hanger assembly200during operation. As illustrated inFIG. 4, a thin tubular sleeve228is positioned around the exterior of the PBR230and extends from above the PBR230to the packer248. InFIG. 4, the hydraulic setting apparatus213is located adjacent to the upper end of the PBR230. The hydraulic setting apparatus213includes a setting piston210and a hydraulic actuation piston218. The setting piston210is sealably disposed on the inner diameter of the PBR230and is selectively connected to the PBR230by a locking dog226. The setting piston210is also connected to an upper portion of the outer sleeve228. The hydraulic actuation piston218is sealably engaged to the outer diameter271of the inner tubular204and is disposed between the inner tubular204and the setting piston210. In one embodiment, the actuating piston218is selectively connected to the setting piston210using a shearable screw214. Although, locking dog226and shearable screw214are used to secure the pistons210,218, other releasable securing devices such as collets, frangible members, and any others known to a person of ordinary skill in the art may be used.

The cementing pack-off242is disposed near the bottom of the running tool assembly205. The cementing pack-off242serves to prevent the upward flow of cement (not shown) through the annular area between the liner body246and the inner tubular204. Together the inner tubular204, the setting piston210, the actuating piston218, the PBR230, the liner body246, the cementing pack-off242, and the running tool components form a contained fluid chamber239.

As shown inFIG. 4, the cylinder235and floating piston234are disposed between the hydraulic setting apparatus213and the cementing pack-off242. The cylinder235is disposed inside the chamber239and on a sealing surface of the inner tubular204such that a cylinder chamber243is formed. The floating piston234is sealably and movably disposed in the cylinder chamber243and is arranged and adapted to separate the cylinder chamber243into an upper chamber244and a lower chamber241. The upper chamber244is in fluid communication with the contained fluid chamber239through one or more ports247formed in the cylinder235. The lower chamber241is in fluid communication with the interior of the inner tubular204through a port238formed in the inner tubular204. Preferably, the floating piston234is biased so that it is in an intermediate position with respect to its permitted travel when no external pressures or forces are applied to it. This may be accomplished in the preferred embodiment by compression springs236and240. The floating piston234serves to transmit pressure to the inside of the contained fluid chamber239without direct fluid communication to the working fluid (not shown) in the tubular204.

The hydraulic setting apparatus213may also contain hydraulic control devices including a check valve216disposed on the hydraulic actuation piston218, which serve to control the pressure within the PBR fluid chamber239by regulating the ingress and exit of annular fluid from the fluid chamber239through one or more ports321formed on the setting piston210. A filter screen212is disposed on the outside of the setting piston210segregate solids from the fluid entering the fluid chamber239through the ports321. The hydraulic setting apparatus213is configured to transmit an upward force from the hydraulic actuating piston218and the setting piston210to the outer tubular sleeve228.

Near the lower end of the PBR230, the outer tubular sleeve228is coupled to the packer248and the liner hanger276and is adapted to selectively actuate these two tools248,276. The lower portion of the outer tubular sleeve228below the PBR230is supported by two mating cylinder rings311,312. In the preferred embodiment, the upper and lower rings311,312, respectively, are mated using a finger and slot connection to allow relative axial movement therebetween. As shown inFIG. 4, the two rings311,312are at an extended position wherein the fingers313of upper ring311have a short overlap with the fingers314of lower ring312. The tubular sleeve228is attached to the non-slotted portion of the lower ring312. The lower ring312includes one or more axial channels317for housing a rod316. The rods316extend through the channel317and into a portion of the slot315in the lower ring312.FIG. 4Ais a cross-sectional view of the lower ring312.

The packer248is connected to the lower ring312through a setting sleeve325. A packer cone330is connected to the other end of the setting sleeve325. Other components of the packer248are disposed on the setting sleeve and between the lower ring and the packer cone. The seal element277is initially disposed on the lower end of the incline of the packer cone during run-in. The seal element is attached to an extension arm331that is coupled to a cone332for a retaining slip333. The retaining slip333is selectively connected to the setting sleeve using a shearable screw320.

The liner hanger276is selectively connected to the lower end of the packer248. In one aspect, the connection350between the packer cone and the liner hanger is adapted to allow the packer248and the liner hanger276to be activated using tension as the setting force. In the preferred embodiment, the packer248and the liner hanger are connected using a left hand engagement threaded connection350. In this respect, after the liner hanger276has been activated, the liner may be rotated at the surface via the running tool assembly205to disengage the connection350that axially couples movement of the outer packer components with the liner hanger slips263. A key336may be used to rotationally lock the packer cone330to the liner body246. The lower half of connection350is held stationary by connecting ring263, slips262, and cones260which are engaged with the casing266when the hanger276has been set. The thrust bearing151permits rotation between these components and the liner body246. The packer cone330may also include a ratchet ring337to ensure one way movement.

The liner hanger276includes a plurality of cones260disposed on the outer diameter of the liner body246and configured to orient the plurality of slips262radially outward to engage the casing266, as shown inFIG. 5. In this embodiment, the liner hanger is provided with dual slips and cones. A thrust bearing251is disposed proximate the upper portion of the liner hanger276. A one-way ratchet profile254is disposed on the exterior of the cylindrical upper portion of the upper cone260. A connecting ring263is attached to the slips262to maintain the slips262in the same axial position relative to their respective cones260. The connecting ring263includes a ratchet ring256that serves to matingly engage the ratchet profile254thereby allowing the slips262to only travel in an upward direction. A biasing member258, such as a compression spring, is disposed between the cones260and the ratchet profile254to lock in the setting force applied by the hydraulic setting apparatus213into the slips262and cones260.

Before being run into the wellbore, the PBR fluid chamber239on the liner hanger assembly200is filled through a fill port219disposed through the setting piston210with a clean fluid, such as water. The liner hanger assembly200and running tool assembly205are then run into the wellbore on a landing string (not shown) to a desired setting depth. The floating piston234and the one way check valve216serve to compensate for any variation in the volume of the PBR fluid chamber239due to fluctuations in the temperature or pressure of the fluid while the liner hanger assembly200is being run into the wellbore.

Once the liner hanger assembly200has reached the desired setting depth, a ball or other suitable device (not shown) is deployed from the surface through the landing string until landing on a ball-seat (not shown) positioned below the liner hanger assembly200thereby preventing the fluid from flowing below the ball-seat and allowing the fluid above the seat to be pressurized. The pressurized fluid within the tubular204will enter the lower chamber241through the port238and cause the floating piston234to travel upward, thereby increasing the pressure in the PBR fluid chamber239. The check valve216is configured to prevent fluid from exiting fluid chamber239. The increased pressure in the PBR fluid chamber239, in turn, causes the shearable screw214to fail, thereby releasing the actuation piston218from the setting piston210. Once released, the pressure in the fluid chamber239urges the actuation piston218to move upward with respect to the setting piston210.

A sufficient upward travel of the actuating piston218releases the locking dog226from the PBR230. The actuating piston218shoulders against the setting piston210and forms a larger combined piston area for the pressure to be applied across. Because the thin tubular sleeve228is attached to the setting piston210, further upward movement of the pistons210,218also causes upward movement of the thin tubular sleeve228.

Upward movement of the thin tubular sleeve228activates the liner hanger276. As previously described, the outer tubular sleeve228transmits this upward force to the liner hanger276through the packer248and the disengagement connection350. In turn, the slips262are urged upward against the tapered surface of the cones260disposed on the liner body246, thereby causing the slips262to extend radially outward towards the casing266, as shown inFIG. 5. The slips262continue to expand radially until the gripping surface265on the exterior of the slips262engages the inner diameter of the casing266. Additional hydraulic setting force acts to fully compress the spring258located above the cones260. Accordingly, the ratchet ring256will lock into position on the ratchet teeth profile254to prevent the slips262from moving back down the tapered surfaces of the cones260and to maintain the setting force on the slips262supplied by the biasing member258.

The engagement of the slips262onto the casing266allows the liner hanger assembly200to carry the weight of the liner tubular203at which point the support provided by the landing string (not shown) to the running tool assembly205from the surface to suspend the liner hanger assembly200in position may be relieved. The weight of the liner hanger assembly200is transmitted from the liner body246through the cones260, to the slips262which are in frictional engagement with the casing266. Any upward pull through liner body246is transmitted through load ring274into the upper part of cones260above the biasing member258. The force is then transferred to connector ring263and to the slips262and casing266via ratchet ring256. The slips262provide moderate hold down capacity in this configuration. An over-pull on the landing string may be used to confirm that the liner hanger assembly200is set in place by ensuring that the no upward movement of the liner hanger assembly200occurs during the over-pull.

After the liner hanger276is set, the packer248maybe decoupled from the liner hanger276. Initially, the pressure in the inner tubular204is bled off at the surface. Thereafter, the running tool assembly205and the liner tubular203are rotated to the right to disengage the connection350with the liner hanger276, as shown inFIG. 5.

The running tool205may now be released from the liner body246, as shown inFIG. 6. Initially, pressure is again supplied from the surface to pressurize the lower chamber241. The pressurized fluid urges the floating piston234to move upward and increase the pressure in the PBR fluid chamber239. The increased pressure causes the setting piston210and the actuation piston218to move upward relative to the PBR230until a relief port355in the setting piston210moves past the PBR230, thereby placing the PBR fluid chamber239in fluid communication with the annulus268. Opening of the relief port355reduces the pressure in the fluid chamber239and allows the floating piston234to continue to move upward in the cylinder chamber243to its maximum stroke. Thereafter, pressurized fluid enters port280, deactivates a frangible member281retaining the piston279, and urges the piston279to move upward. Continual upward movement of the piston279causes a collet267to release from the liner body246. As a result, the run-in tool assembly205is released from the liner hanger assembly200. To confirm that the liner hanger assembly200has been released, the running tool assembly205and landing string are raised upward from the surface. Additional assurance that the liner hanger assembly200remains stationary while picking up the running tool assembly205is provided by the hold down capabilities of the liner hanger assembly200. Preferably, the outer diameter271of the inner tubular204on the hydraulic setting apparatus213and the outer diameter272on the polished mandrel273through the cementing pack-off242are of the same diameter, thereby allowing the running tools to be raised and lowered without changing the volume within the PBR chamber239. The ball or sealing device (not shown) may now be released so that it no longer impedes fluid passage in the tubular204. This is typically accomplished by pressuring up the inner tubular204to a predetermined pressure to cause frangible members retaining a ball seat located below the liner hanger276to break, thereby moving the seat from its sealing position to an open position to re-establish fluid communication with the annulus below the ball seat (not shown). Rotation of the liner body246during cementing are provided for in the liner hanger276by the thrust bearing251located at the upper portion of the liner hanger276. The thrust bearing251allows the slips262and cones260to remain stationary with respect to the casing266while the liner body246and liner tubular203rotate. During cementing operations wherein cement (not shown) is pumped down the landing string, the tubular204, and around the bottom of the liner tubular203to fill the annular area268between the liner tubular203and the casing266. As described above, the cementing pack-off242prevents the inadvertent upward flow of cement to the PBR fluid chamber239.

The running tool assembly205may now be used to set the packer248by applying tension force. Initially, the running tool assembly205is pulled upwards until an upper end275of the floating piston cylinder235contacts the actuation piston218. Thereafter, continual upward pull causes the tubular sleeve228to also move upward. The packer is pulled upward until the rod316contacts the finger313of the upper ring311. Because the packer is prevented from moving further, the upward pull of the running tool assembly205causes the shearable screw320to fail, thereby releasing the setting sleeve325from the retaining slip333. At this point, moving the cone332for the retaining slip333toward the slip333will extend the slip333radially into engagement with the casing266due to the incline on the cone332, as illustrated inFIG. 6. It can also be seen that the lower ring312has moved relative to the rod316and the overlap between the upper ring311and the lower ring312has increased.

Engagement of the retaining slip333with the casing266limits the upward travel of the seal element277. As a result, the packer cone330is urged toward the seal element277and expands the seal element277into engagement with the casing266, thereby sealing off the annulus268. The one way ratchet ring337in the packer cone330assists in maintaining the integrity of the seal formed. In this respect, the present invention provides a packer248that can be set using tension.

After the packer248is set, continued pick up of the running tool assembly205causes the tubular sleeve228to separate at the perforation380, which may be seen inFIG. 7. Thereafter, the running tool assembly205may be retrieved from the wellbore, leaving the behind the liner hanger assembly200and liner tubular203.

While the devices and methods described above incorporate a packer, it is within the scope of this invention that a liner hanger and hydraulic setting tools of the above description may be utilized without the packer.