WO2002097234A1 - Line hanger, running tool and method - Google Patents

Abstract

A liner hanger running tool (120) includes improvements to the running tool release mechanism, the packoff bushing, and the packer setting assembly. A method is provided for reliably releasing a running tool from a liner hanger (110), for allowing stabbing of the running tool packoff bushing (10) into the top of the liner hanger, and for reliably setting the radial set packer element. The port closure member (212) is movable with a tubular body from a port isolation position to an open port position. The tool includes an annular seal assembly and a substantially conical wedge ring having an outer surface configured to radially expand the annular seal assembly. A ball (240) is lowered into a diverter and thus guided into a pocket (286) in one side thereof to permit passage of a pump down plug (180) into a lower wiper plug (181). A slip assembly carried about a liner for lowering into a wellbore includes a C-ring (64), which expands to cause its teeth to engage with the wellbore. A plug holder (10) sub temporarily supports a liner wiper plug, so that a pump down plug may land in the liner wiper plug and be supported from a generally tubular body of the plug holder sub.

Description

LINER HANGER, RUNNING TOOL AND METHOD

Related Applications

The present application claims priority from:

U.S. Provisional Serial 60/292,049 filed May 18, 2001 (attorney ref: 108-P);

U.S. Provisional Serial No. 60/316,572 filed August 31 , 2001 (attorney ref: 108-1);

U.S. Provisional Serial No. 60/316,459 filed August 31 , 2001 (attorney ref: 111 );

U.S. Serial No. 09/943,854 filed August 31, 2001 (attorney ref: 118); U.S. Serial No.

09/943,701 filed August 31 , 2001 (attorney ref: 119); U.S. Serial No. 09/981 ,487

filed October 17, 2001 (attorney ref: 123); U.S. Serial No. 10/083,320 filed October

19, 2001 (attorney ref: 111-1 ); U.S. Serial No. 10/004,945 filed December 4, 2001

(attorney ref: 106);U.S. Serial No. 10/004,588 filed December 4, 2001 (attorney ref:

124); U.S. Serial No. filed May 2, 2002, entitled Apparatus For Use In

Cementing An Inner Pipe Within An Outer Pipe Within A Wellbore (attorney ref:

116); U.S. Serial No. filed May 2, 2002, entitled Slip Assembly For

Hanging An Elongate Member Within A Wellbore (attorney ref: 117).

Background of the Invention

When drilling a well, a borehole is typically drilled from the earth's surface to

a selected depth and a string of casing is suspended and then cemented in place

within the borehole. A drill bit is then passed through the initial cased borehole and

is used to drill a smaller diameter borehole to an even greater depth. A smaller

diameter casing is then suspended and cemented in place within the new borehole. This is conventionally repeated until a plurality of concentric casings are suspended

and cemented within the well to a depth which causes the well to extend through

one or more hydrocarbon producing formations.

Rather than suspending a concentric casing from the bottom of the borehole

to the surface, a liner is often suspended adjacent to the lower end of the previously

suspended casing, or from a previously suspended and cemented liner, so as to

extend the liner from the previously set casing or liner to the bottom of the new

borehole. A liner is defined as casing that is not run to the surface. A liner hanger

is used to suspend the liner within the lower end of the previously set casing or liner.

Typically, the liner hanger has the ability to receive a tie back tool for connecting the

liner with a string of casing that extends from the liner hanger to the surface.

A running and setting tool disposed on the lower end of a work string may be

releasably connected to the liner hanger, which is attached to the top of the liner.

The work string lowers the liner hanger and liner into the open borehole so that the

liner extends below the lower end of the previously set casing or liner. The borehole

is filled with fluid, such as a selected drilling mud, which flows around the liner and

liner hanger as the liner is run into the borehole. The assembly is run into the well

until the liner hanger is adjacent the lower end of the previously set casing or liner,

with the lower end of the liner typically slightly above the bottom of the open

borehole.

When the liner reaches the desired location relative to the bottom of the open

borehole and the previously set casing or liner, a setting mechanism is conventionally actuated to move slips on the liner hanger from a retracted position

to an expanded position and into engagement with the previously set casing or liner.

Thereafter, when set down weight is applied to the hanger slips, the slips are set to

support the liner.

The typical liner hanger may be actuated either hydraulically or mechanically.

The liner hanger may have a hydraulically operated setting mechanism for setting

the hanger slips or a mechanically operated setting mechanism for setting the slips.

A hydraulically operated setting mechanism typically employs a hydraulic cylinder

which is actuated by fluid pressure in the bore of the liner, which communicates with

the bore of the work string. When mechanically setting the liner hanger, it is usually

necessary to achieve relative downhole rotation of parts between the setting tool

and liner hanger to release the hanger slips. The hanger slips are typically one-way

acting in that the hanger and liner can be raised or lifted upwardly, but a downward

motion of the liner sets the slips to support the hanger and liner within the well.

To release the running tool from the set liner hanger, the setting tool may be

lowered with respect to the liner hanger and rotated to release a running nut on the

setting tool from the liner hanger. Cement is then pumped down the bore of the

work string and liner and up the annulus formed by the liner and open borehole.

Before the cement sets, the setting tool and work string are removed from the

borehole. In the event of a bad cement job, a liner packer and a liner packer setting

tool may need to be attached to the work string and lowered back into the borehole.

The packer is set utilizing a packer setting tool. Packers for liners are often called "liner isolation" packers. A typical liner isolation packer system includes a

packer element mounted on a mandrel and a seal nipple disposed below the

packer. The seal nipple stings into the tie back receptacle on top of or below the

previously set and cemented liner hanger. A liner isolation packer may be used, as

explained above, to seal the liner in the event of a bad cement job. The liner

isolation packer is typically set down on top of the hanger after the hanger is

secured to the outer tubular, and the packer is set by the setting tool to seal the

annulus between the liner and the previously set casing or liner.

Generally, the deeper a well is drilled, the higher the temperature and

pressure which is encountered. Thus, it is desirable to have liner packers which will

ensure quality cementing of the liner so as to provide a high safety factor in

preventing gas from the formation from migrating up the annulus between the liner

and outer casing.

During the cementing operation, fluid such as drilling mud in the annulus

between the liner and outer casing is displaced by cement as the cement is pumped

down the flow bore of the work string. First, the drilling mud and then the cement

flows around the lower end of the liner and up the annulus. If there is a significant

restriction to flow in the annulus, the flow of the cement slows and a good

cementing job is not achieved. Any slowing of the cementing in the annulus allows

time for the gas in the formation to migrate up the annulus and through the cement

to prevent a good cementing job.

Running Tool Release Mechanism As a practical matter, the liner hanging running tool must include a release

mechanism so that, once the liner is reliably set to the lower end of the casing, the

running tool can be released from the liner hanger and retrieved to the surface.

Conventional liner hanger running tool releasing mechanisms include hydraulically

actuated mechanisms, and release mechanisms that are manipulated by left-hand

rotation of the running string. The left-hand rotation of the running string is,

however, generally considered undesirable since it may result in an unintended

disconnection of one of the joints of the running string, thereby causing separation

of the running string and a fishing operation to retrieve the running tool, which may

have been damaged by the unintended disconnection. For various reasons,

hydraulically operated running tool release mechanisms may fail to operate, or may

prematurely release the running tool from the liner hanger.

Accordingly, improvements in release mechanisms are desired which will

reliably release the running tool from the set liner only when intended, particularly

when retrieving is easily accomplished and premature disengagement of the

running tool from the liner is highly unlikely. Packoff Bushing

A liner hanger packoff bushing conventionally seals between the liner hanger

and the running tool, and thus between the liner and the running string or work

string, which conventionally may be drill pipe. A packoff bushing is particularly

required during cementing operations so that fluid pumped through the drill pipe

continues to the bottom of the well and then back up into the annulus between the well bore and the liner to cement the liner in place. During cementing operations,

the seal body of the packoff bushing is fitted in the annulus between the liner

hanger and the running tool, and includes OD seals for sealingly engaging the liner

hanger and ID seals for sealingly engaging the running tool. Packoff bushings are

preferably retrievable with the running tool to prevent having to drill out the bushings

after the cementing operation is complete. Also, a packoff bushing is preferably

lockable to the liner hanger by locking within a profile to prevent the bushing from

moving axially with respect to the liner hanger. If the packoff bushing is not lockable to the profile of the liner hanger, the bushing may get "pumped out" through the top

of the receptacle, thereby losing a cementing job.

A conventional retrievable and lockable packoff bushing includes metal dogs

or lugs which are locked into engagement with the liner hanger to prevent the

packoff bushing from moving axially during the cementing operation. The packoff

bushing is retrievable with the running tool, and thus eliminates the need to drill out

the bushing after cementing operations are complete. Depending on the

manufacturer, retrievable packoff bushings are also referred to as retrievable seal

mandrels or retrievable cementing bushings. Regardless of the terminology, the

retrievable and lockable packoff bushing seals the annulus between the running

string and the top of the liner, and may be locked in a profile of the liner hanger by

the slick joint to prevent the bushing from being pumped out of the liner hanger.

Cooperating surfaces on the liner running adapter, the slick joint on the

running tool, and the seal body of the packoff bushing axially interconnect the bushing to the liner hanger while running the liner hanger into the well. These

cooperating surfaces may be unlocked to release the running tool from the liner

hanger and allow axial manipulation of the running tool and slick joint relative to the

packoff bushing. The slick joint thus seals with the packoff bushing during axial

movement of the running tool. Once the cooperating surfaces are unlocked from

each other, shoulders on the packoff bushing and the running tool engage after a

predetermined amount of axial movement between the running tool and the seal

body, so that the packoff bushing may be retrieved to the surface with the running

tool after the cementing operations is complete. A conventional packoff bushing is

disclosed in U.S. Patent 4,281 ,711.

A significant limitation on prior art packoff bushings concerns their desired

retrievability with the running tool, when coupled with the desire to pick up the

running tool relative to the packoff bushing before the cementing operation. An

operator will typically want to pick up the running tool after release from the liner

hanger to ensure that these tools are disconnected. The length of the running tool

slick joint determines the maximum length that the running tool should be picked up

after release from the liner hanger. When the packoff bushing is pulled out of the

liner hanger, the dogs or lugs conventionally carried by the packoff bushing are

allowed to move radially inward, thereby preventing the retrievable packoff bushing

from being stabbed back into and locked into the liner hanger. Conventional liner

hanger running tools do not allow the packoff bushing to be "re-stabbed" into the

liner hanger and thereby re-establish pressure integrity between the liner hanger and the running tool. In many applications, it is difficult for the operator to determine

the exact amount the running tool has been picked up, particularly when operating

in deep or highly deviated wells. If the operator picks up the running tool an axial

distance not permitted by the length of a slick joint, the packoff bushing will be

pulled up with the running tool and will disengage from the liner hanger, which may

cause a cementing failure costing the operator millions of dollars in lost time and

money. The consequences of unintentionally unseating the packoff bushing from

the liner hanger and not being able to re-stab and lock into the liner hanger may

thus be severe.

The slick joint used with the liner hanger running tool has a polished OD surface which seals against the ID seals on the seal body of the packoff bushing.

The slick joint OD surface can become scratched or damaged during handling,

thereby causing a cementing leak during the cementing operation. Since the

running tool is designed to move axially substantial distances relative to the packoff

bushing, the inner seals on the seal body may wear out during the cementing

process due to the reciprocation of the running tool slick joint. This problem is

exacerbated when the quality of the polished surface on the slick joint has

deteriorated. Axially long slick joints are expensive to manufacture and maintain.

Another problem with prior art packoff bushing concerns the limited load

capacity of the lugs that lock the packoff bushing to the liner hanger. Conventional

packoff bushings utilize multiple lugs protruding from the packoff seal body, which

increases the complexity and the cost of the packoff bushing. The limited size of these fugs nevertheless restricts or limits the cementing pressure capacity of the

packoff bushing.

Packer Setting Assembly

A conventional liner hanger running tool includes a packer setting assembly,

which allows the activation and packoff of the linertop packer. Conventional packer

setting assemblies incorporate multiple spring-loaded dogs or lugs which may be

compressed to a reduced diameter position by insertion into the packer setting

sleeve when running the liner hanger in the well and when cementing the liner

within the casing. When the packer setting assembly is raised out of the packer

setting sleeve, the dogs or lugs expand to a diameter greater than the ID at the

upper end of the setting sleeve, which is also the tie back receptacle of the liner

hanger. When the dogs engage the top of the setting sleeve, a setting force may

be transferred from the running string through the dogs and to the packer setting

sleeve as running string weight is slacked off to set the packer element.

Some prior art packer setting assemblies include an axial bearing to facilitate

rotation of the work string while setting the packer element. Other packer setting

assemblies include both a bearing and a shear indicator to provide a visual

confirmation that the proper setting load was applied to the packer, and/or an

unlocking feature that allows the packer setting assembly to be pulled out of the

packer setting sleeve one time without exposing the setting dogs. This latter tool

allows re-stabbing the packer setting assembly into the packer setting sleeve one

time, thereby arming the setting dogs so they are ready to expand the second time the dogs are pulled out of the setting sleeve.

A primary problem concerning prior art packer setting assemblies is poor

reliability. In some well environments, the packer setting dogs of conventional

packer setting assemblies collapse and re-enter the setting sleeve without setting

the packer element. Manufacturers have provided more dogs or lugs to alleviate

this problem, and/or have provided heavier springs to bias the dogs radially

outward. These changes have had little if any affect on achieving higher reliability.

The disadvantages of the prior art are overcome by the present invention,

and an improved liner hanger running tool is hereinafter disclosed which includes

improvements to a running tool release mechanism, a retrievable packoff bushing,

and a packer setting assembly. In addition, the improved packer setting assembly

may be used in operations not involving a liner hanger running tool.

Summary of the Invention

A preferred embodiment of a liner hanger running tool of the present

invention includes improvements to one or more of the running tool release

mechanism, the retrievable packoff bushing and the packer setting assembly. The

running tool may be used for positioning a liner within a casing in a wellbore and

subsequently cementing the liner in place, then retrieving the running tool to the

surface with the packoff bushing and the packer setting assembly. The packer

setting assembly may be used in other downhole packer setting applications.

Running Tool Release Mechanism

The liner hanger running tool release mechanism preferably includes a hydraulically actuated mechanism for releasing the running tool from the set liner

hanger in response to fluid pressure within the running tool, and also a mechanical

right-hand release mechanism which, if necessary, allows the running tool to be

mechanically released from the liner hanger by right-hand rotation of the work

string. The combination of the hydraulic release mechanism and the right-hand

release mechanism significantly improves reliability of the running tool.

It is an object of the present invention to provide an improved running tool

release mechanism for releasing a running tool from a set liner hanger. The running tool may be hydraulically released, but also may be released by right-hand rotation

of the running string. A first piston is used for hydraulic release. A second piston

is used to disengage a clutch, thereby allowing a nut to move downward along the

right-hand threads on the running tool mandrel due to right-hand rotation of the

running string. Once the nut has moved axially downward on the mandrel, the work

string may be picked up to disengage the running tool from the liner hanger.

Yet another feature of the invention is that, after the clutch has been

disengaged to allow right-hand release of the running tool, fluid pressure may be

used to reengage the clutch to allow rotation of the liner during a cementing

operation.

Yet another feature of the invention is that fluid within the running tool which

transmits fluid pressure to the piston for hydraulic release of the running tool may

be isolated by a sleeve, such that the sleeve shifts downward to expose a port and

allow hydraulic fluid to release the running tool. A significant feature of the running tool release mechanism is that the release

mechanism may be actuated both hydraulically and by right-hand rotation of the

running string or work string.

A related feature of the running tool release mechanism is that reliability of

the release operation is significantly improved with little if any cost increases.

Packoff Bushing

During the cementing operation, the packoff bushing serves its function of

providing a seal between the liner hanger and the running string. The packoff

bushing may be axially fixed to the liner hanger during the cementing operation by

a C-shaped lock ring, which is held locked in a groove in the liner hanger by a fluid

pressure responsive piston. The packoff bushing is designed such that it may be

reinserted into the liner hanger when the packoff bushing is raised with the running

string relative to the set liner hanger. Accordingly, the cost of the slick joint may be

avoided. The liner hanger packoff bushing may thus be removed from the liner

hanger when the operator picks up the running tool to check for release of the

running tool from the liner hanger and verify that the liner is properly set in the

casing. When the running tool is slacked back off into the liner hanger before

pumping cement, the packoff bushing can be re-stabbed and resealed to the liner

hanger. When pressure is subsequently applied to the running string during a

cementing operation, the packoff bushing will be locked to the liner hanger by the

fluid pressure to prevent movement out of the liner hanger. Fluid pressure thus

keeps the packoff bushing locked to the liner hanger, while the absence of pressure in the running string allows the packoff bushing to be picked up out of the liner

hanger and subsequently reinserted into the liner hanger. The liner hanger running

tool thus includes a packoff bushing which may be repeatedly "re-stabbed" back into

the liner hanger, as desired by the operator, to re-establish pressure integrity

between the running tool and the liner hanger.

By providing a re-stabbable packoff bushing, the operator has much more

flexibility when picking up to check for release of the running tool. By providing a

packoff bushing which may be repeatedly reinserted into the liner hanger so that a

seal may be repeatedly established between the running string and the liner hanger,

the operator avoids much of the risk of a bad cementing job, and the significant loss

of time and money to correct a bad cementing job. The re-stabbable packoff

bushing may be used on a running tool with or without a liner hanger packer for

sealing between the casing and the liner hanger.

The packoff bushing is preferably designed with a C-shaped lock ring to

increase the cementing pressure capability of the packoff bushing. Compared to

prior art packoff bushings, the one-piece lock ring avoids the use of multiple lugs

and springs which add length and complexity to the packoff bushing without

significantly increasing the cementing pressure capability of the packoff bushing

when locked to the liner hanger.

It is an object of the present invention to provide a liner hanger running tool

with the packoff bushing which may be repeatedly restabbed into the top of the

liner. A feature of this invention is that the packoff bushing incorporates a C-

shaped one-piece lock ring, which effectively locks the packoff bushing to the liner

hanger in response to fluid pressure, which acts on a piston to retain the lock ring

in the locked position. The absence of fluid pressure allows the lock ring to be

collapsed, thereby permitting the restabbing of the packoff bushing into the top of

the liner hanger. The C-shaped lock ring may include radially external or internal

slots for facilitating expansion and contraction of the lock ring.

The packoff bushing includes a radially outer shoulder for engaging a radially

inner shoulder on the liner hanger when the lock ring is aligned with the groove in

the liner hanger, so that set down weight may be applied to the liner hanger. The

packoff bushing also includes a radially inner shoulder, so that the packoff bushing

is retrieved with the tool to the surface. In addition to the packoff bushing, the

running tool may include a packer setting assembly for activating the packer

element to seal between the casing and the liner hanger.

It is a feature of the invention that the running tool may include a retrievable

packoff bushing which may be reinserted or "restabbed" into the liner hanger

numerous times. A related feature of the invention is that the cost of a slick joint

may be avoided.

It is a further feature of the present invention to provide an improved liner

hanger running tool packoff bushing wherein fluid pressure keeps the packoff

bushing locked to the liner hanger, while the absence of fluid pressure may allow

the packoff bushing to be picked up out of the liner and subsequently reinserted into the liner. A related feature of the running tool with the improved packoff bushing is

the reduced risk of a bad cementing job.

Packer Setting Assembly

The packer setting assembly may be used with the liner hanger running tool

to set the liner top packer after the liner hanger has been set, and after the running

tool has been released from the liner hanger. The packer setting assembly may be

positioned on the running tool at a desired location, which may be axially between

the liner hanger releasing assembly and the slip setting assembly at the lower end

of the running string or work string. When the running tool is assembled at the

surface, the packersetting assembly is thus contained within the tie back receptacle

or setting sleeve of the liner hanger assembly.

The packer setting load is preferably transferred to the packer setting sleeve

through a one piece C-shaped setting ring. The C ring design enables more weight

to be set down on the setting sleeve than with the plurality of dogs used in the prior

art. A lock out feature keeps the setting ring in weight-transfer engagement with the

setting sleeve so that the setting ring will not prematurely snap radially inward

toward the packer setting housing before the packer is set. Seals on both the ID

and the OD of the packer setting assembly also aid in setting the packer. Once the

initial load has been set down on the liner hanger, the ID seal which seals to the

running tool mandrel, and the OD seal which seals to the setting sleeve, act as a

piston responsive to pressure applied to the annulus to assist in setting the packer

element. This fluid pressure assist along with the set down weight achieves the proper setting force to the liner top packer element. By using annulus pressure to

aid in setting the packer element, a significant additive hydraulic force complements

the set down weight to reliably set the liner hanger packer element.

A preferred packersetting assembly includes an unlocking feature that allows

the assembly to be pulled out of the packer setting sleeve one time without

releasing a setting ring. Upon re-stabbing the assembly into the setting sleeve, the

packer setting ring becomes activated and is ready to expand the second time the packer setting assembly is pulled out of the setting sleeve. An adjustable shear

indicator may be included to provide immediate visual confirmation, when the

running tool is retrieved to the surface, that adequate setting force was applied to

the liner top packer. A bearing assembly in the packer setting tool allows rotation

and slack off of the running string without damaging the packer setting sleeve or

setting ring. Rotation also breaks the static friction between the running string and

the casing, thereby reducing buckling and insuring maximum transfer of setting

force to the liner packer element.

It is an object of the present invention to provide a packer setting assembly

which uses an expandable and collapsible one-piece C-ring to set weight down to

a packer element. The packer setting assembly also includes O.D. seals and I.D.

seals, so that fluid pressure may be used to increase the setting force applied to the

packer element.

It is a feature of the packer setting assembly according to the present

invention that the C-ring may be locked in a collapsed position by a locking mechanism to prevent the C-ring from moving to its expanded position. This allows

the packer setting assembly to be pulled out of the tie back receptacle one time

without releasing the C-ring, and allows the lockout mechanism to engage the top

of the tie back receptacle for weight set down. The next time the packer assembly

is pulled out of the tie back receptacle, the C-ring is allowed to expand radially

outward for engagement with the top of the tie back receptacle.

It is a further feature of the present invention that the packer setting assembly

has multiple uses. The packer setting assembly may be used as part of a liner

hanger running tool, although the packer setting assembly may also be used for

other applications wherein an operator desires to radially set a downhole packer.

It is a feature of the invention that the packer setting assembly transfers the

packer setting load to the packer setting sleeve through a C-shaped setting ring.

A related feature is that seals on both the I.D. and O.D. of the packer setting

assembly may assist in setting the packer.

Yet another feature of the packer setting assembly is that the setting ring

may be easily and reliably locked out to prevent premature actuation.

Yet another feature of the packer setting assembly is that it may include an

unlocking feature so that the assembly may be pulled out of the packer setting

sleeve one time without releasing the setting ring.

An advantage of the improvements to each of the running tool release

mechanism, the retrievable packoff bushing, and the packersetting assembly is that

these mechanisms rely upon components which have been found highly reliable in the oilfield services industry. The complexity of the running tool with one or more of these features is not significantly increased and, in many cases, is made simpler.

Tool reliability has been increased to perform the desired downhole operations.

Brief Description of the Drawings

Figures 1A-1J illustrate sequentially lower portions of a liner hanger setting

tool run into a well. Figure 1A illustrates the interconnection of the tool to a work

string. Figure 1 B illustrates the liner hanger slip setting assembly. Figure 1C

illustrates the packer setting assembly. Figure 1 D illustrates the liner hanger

releasing assembly. Figure 1 E illustrates the retrievable cementing bushing. Figure

1 F illustrates the packer element. Figure 1G illustrates the hanger slip assembly.

Figure 1 H illustrates the lower end of the running tool mandrel. Figure 11 illustrates

the ball diverter. Figure U illustrates the liner wiper plug.

Figure 2A illustrates the tie back receptacle raised to set the slips. Figure 2B

illustrates the slips in the set position.

Figure 3A shows the upper seat after release of the ball. Figure 3B shows

the ball landed on the lower seat. Figure 3C illustrates the lower seat moved

downward to open ports and allowed the lock ring of the releasing assembly to contract.

Figure 4A illustrates the ball released from the lower seat and dropped into

the diverter. Figure 4B is a crossed section through Figure 4A.

Figure 5A illustrates the pump down plug landed on the wiper plug. Figure

5B illustrates the liner wiper plug and pump down plug released. Figure 5C

illustrates the plug set landed within a landing collar.

Figure 6A illustrates the tool positioned to weight set the packer element.

Figure 6B illustrates the packer element in the set position. Figure 7A illustrates the running tool packoff bushing unlocked from the liner

hanger.

Figures 8A and 8B show the lower end of the running tool released from and

pulled upward from the set liner hanger, with the upper portion of the set liner

hanger being shown in Figures 8C and 8D.

Figure 8E shows one embodiment of a slip element raised into engagement

with the casing; Figure 9A shows the packer elements and another embodiment of

a slip assembly in the run in position. Figure 9B shows the components moved to

set slip assembly. Figure 9C shows the slip assembly engaged with the casing and

the packer element moved to seal with the casing.

Figures 10A and 10B illustrates running tool components for a hydraulic

release when run in the well. Figure 10C illustrates the components once the

pressure is increased to shift the ball seat, thereby releasing the running tool and

disengaging a clutch. Figure 10D illustrates fluid pressure acting on the second

piston so the clutch can reengage the liner hanger.

Figures 11 A and 11 B show sequential components of the running tool during

a mechanical release from the liner hanger. Figure 11C shows the components

with the ball seat shifted to release the running tool and disengage the clutch.

Figure 11 D illustrates the second piston activated to engage the clutch with the

running tool released.

Figure 12A is a cross-sectional view of a preferred retrievable packoff

bushing according to the present invention, which may be positioned below a liner hanger packer setting assembly and above the ball diverter.

Figure 12B is a cross-sectional view of the retrievable packoff bushing shown

in Figure 12A.

Figure 13 is a cross-sectional view of a preferred embodiment of a packer

setting assembly on a liner hanger running tool according to the present invention.

Figure A1 is a vertical cross-sectional view of the head itself;

FIGS. A1A and 1 B are a top view and a cross-sectional view,

Fig. A1 C is a bottom view of the head Fig. A1 , and Fig. A1 D is a side view

of a part of the head; and

Figure A2 is another, enlarged vertical sectional view of the head installed

between a cementing swivel and a lower indication sub connecting to the work

string, and showing the balls and plugs in the passages in position to be dropped.

Figs. B1 A and B1 B are respectively an elevational view, broken away in part,

and an end view of the c-ring along in its fully contracted position wherein its side

edges are engaged with one another; the outer side of the c-ring having vertical

slots to facilitate the passage of fluid between the liner and outer well casing when

the slip is expanded.

Figs. B2A and B2B are similar views of the c-ring in fully expanded position.

Figs. B3A and B3B are vertical sectional views of the slip assembly wherein

the collapsed c-ring is shown in Fig. B3A disposed about the liner with its lower end

received within the recess of the liner, and in Fig. B3B, raised from the recess and

expanded to a position in which the liner may be raised to move its outer side upwardly over the frusto conical surface of the liner so as to cause its teeth to

engage the well casing; and

Fig. B3C is an enlarged detailed view of a portion of Fig. 3B to illustrate the

controlled friction teeth on the inner slide of the c-ring.

Figs. B4, B5, and B6 are enlarged vertical sectional views of the assembly

showing the c-ring as it moved by the liner from the retracted to the expanded

position, the c-ring being shown in retracted position in Fig. 4, raised out of the

recess by the tie bar in Fig. 5 to release it for expanding outwardly to engage the

casing, and, in Fig. 6, the tie bar has raised frusto conical surface of the liner over

the inner surface of the c-ring to cause the c-slip to be moved outwardly into

engagement with the well casing.

Figs. B3AA and B3BB are detailed sectional views as indicated on Figs. B3A

and B3B.

Figure C1 is a vertical sectional view of the outer casing joint having its bore

configured to cooperate with a hanger mounted on an inner casing or liner as it is

lowered into the outer casing.

Figure C2 is a view of the liner with the hanger mounted thereon for landing

within the profiles in the outer casing;

Figure C3 is a view similar to Figure C2, but showing the liner and its hanger

being lowered into the outer casing; and

Figure C4 is another similar view, but with the liner lowered further to cause

its hanger to engage with the profile in the outer casing, and then lowered to a position to lock the hanger in position.

Figure D1 is a half-sectional view of the seal element according to the

present invention positioned at the lower end of a tie back receptacle for moving

down along a cone and sealing with a casing.

Figure D2 is an enlarged view of a seal element shown in Figure 1 positioned

when the seal element initially engages the casing.

Figure D3 is a cross-sectional view of the seal element in its final set position

for sealing engagement between the cone and the casing.

Figure E1 is a vertical sectional view of the diverter including the sub from which the cementing assembly is suspended.

Figure E2 is a view similar to Figure E1 , with a ball landed in the diverter

pocket.

Figure E3 is a cross sectioned view of the diverter, as seen along broken

lines 3-3 of Figure E2, but on a larger scale to illustrate the "U" shaped slot formed

in the ramp to one side of the diverted ball to permit passage of a pump down plug.

Figure E4 is another vertical sectional view of the liner beneath the diverter

and showing the pump down plug following passage through the slot in the ramp

and into a landed position in the liner wiper plug of the cementing equipment; and

Figure E5 is a further vertical sectional view, but in which the connection of

the wiper plug has been sheared from the lower end of the tubular member beneath

the ball diverter.

Figure F1 is a cross-sectional view of a plug holder sub according to the present invention, illustrating the position of components for attachment to the liner

wiper plug on the left side of the centeriine and positioned for release of the liner

wiper plug from the plug holder sub on the right side of the centeriine.

Figure F2 is a cross-sectional view of a lower portion of plug holder sub

shown in Figure fl , illustrating the upper portion of a liner wiper plug attached to the

plug holder sub on the left side of the centeriine, and released on the right side of

the centeriine.

Detailed Description of Preferred Embodiments

Figures 1-9 Running Tool

To hang off the liner, the running tool 120 may initially be attached to the

lower end of a work string WS and releasably connected to the liner hanger, from

which the liner is suspended for lowering into the bore hole beneath the previously

set casing or liner C. The assembly may easily be run in at a rate that does not

adversely affect the well formations or the running tool.

A tie back receptacle 130 as shown in Figure 1B is supported about the

running tool 120, with its upper end having the liner hanger slip setting assembly

140. The upper end of the tie back receptacle 130, upon removal of the running

tool, provides a means by which a casing tie back (not shown) may subsequently

extend from its upper end to the surface. As shown in Figures 1A-11, the tool 120

includes a central mandrel 132, which may comprise multiple connected sections.

The lower end of the tie back receptacle 130 is connected to the packer

element pusher sleeve 148 as shown in Figure 1 F, whose function will be

described in connection with the setting of the packer element 150 about an upper

cone 152, as well as setting of one alternative embodiment of slip 142A about a

lower cone 144A (see Figure 1G) below the packer element 150. The running tool

120 includes a cementing bushing 160 (see Figure 1 E) from which a tubular body

162 is suspended for supporting the ball diverter 280 (see Figure 11) and liner wiper

plug 180 (see Figure U) at the lower end of the running tool. The retrievable

cementing bushing 160 provides a retrievable seal between the running tool 120 and the liner hanger assembly for fluid circulation purposes. By incorporating an

axially movable slick joint, the running tool can be moved without breaking the seal

provided by the packoff bushing.

The liner hanger slip setting assembly 140 as shown in Figure 1 B includes

a sleeve 212 disposed within and axially moveable relative to a portion 210 of the

running tool mandrel 132. The piston sleeve 212 is held in its upper position by

shear pins 222 in mandrel portion 210. A tubular ball seat 232 is supported at the

lower end of sleeve 212. The lower end of the ball seat has a neck portion 234

which is reduced in diameter and is thinner, for the purpose described below. A

ball 240 is dropped from the surface into the running tool bore 126 and onto the

seat 232. An increase in fluid pressure within the mandrel 132 will shear the pins

222 and lower the ball seat to a landed position in the bore of the running tool, e.g.,

against the stop shoulder 236.

Ball Dropping Head

This invention also relates to improved apparatus for dropping a ball as

above mentioned which includes a head suspended from a top drive for use in

sequentially dropping balls and plugs into a liner suspended from the head. More

particularly, it relates to the use of such equipment in cementing the liner within the

outer casing, wherein the one or more balls are to be dropped onto a seat within the

liner to actuate certain parts for the purpose of hanging the liner in the outer casing,

followed by the dropping of pump down plugs through the liner for pumping cement beneath them into the annulus between the liner and outer casing.

In previous heads of this type, the balls and wiper plugs were mounted in

individual manifolds with each having an opening onto a bore leading to the

equipment to be actuated. As will be appreciated, this increased greatly the vertical

height of the equipment beneath the top drive, thus making it that much more

inaccessible, not only during loading and releasing of the balls and pump down

plugs, but also in obtaining visual access to the interior of each manifold in which

the plugs and balls were located.

U.S. Patent Nos. 6,182,752 and 6,206,095 allege to solve the problem of

excess height by means of heads of such construction as to permit the balls and

plugs to be mounted and dropped from essentially the same vertical location

beneath the top drive. Nevertheless, their construction is complicated and requires

large internal rotating parts which increased the possibility of leakage and other

need for repair.

It is therefore another object of this invention to provide such a head in which

the balls and plugs are mounted on generally the same level, but which does not

include the large rotating parts and other mechanisms increasing the risk of repair

and replacement.

This and other objects are accomplished, in accordance with the illustrated

embodiments of this invention, by a housing having an inlet adapted to be fluidly

connected in line with the lower end of a top drive, an outlet generally aligned with

the inlet, and passages extending downwardly within the housing at circumferentially spaced locations. Each passage has an upper end opening to the

side of the inlet and a lower end connecting with the outlet, and lateral passages in

the housing each connect the inlet with a passage. A closure member is removably

mounted in the upper end of each passage to permit a ball or plug to be installed

therein, and plug valves are mounted in the housing each for opening and closing

a passage beneath the lateral passage connecting thereto so as to support the ball

or plug, when closed, and permit it to pass therethrough, when open. Circulating

fluid may pass downwardly through an open passage when a ball or plug is not in the passage.

With reference now to the details of Figures A1 and A2, the head A10

comprises a housing A11 having a vertical opening A12 in its upper end and a

vertical opening A13 in its opposite lower end, the openings being generally

vertically aligned. The upper opening is threadedly connected to a tubular member

A14 whose upper end is threaded for connection with a top drive.

Intermediate the upper and lower ends of the member A14 is a Kelly valve

A16 installed for opening or closing its bore A15. When closed, the valve allows

cement to be supplied to the bore A15 through one or more side openings A16 in

member A14 beneath the Kelley valve. The member A14 is installed on a swivel

A20 which has openings therethrough aligned with openings A16 in fittings A17

leading to the bore A15 of the member. As well known in the art, this permits

relative rotation between the swivel and tubular member so that the tubular member

and cementing truck are fluidly connected during relative rotation. The lower end opening A13 in the head is threadably connected to the upper

end of a sub A21 having a bore A22 therethrough adapted to be connected with the

liner or other tubular member suspended therefrom. A "flag" A23 is mounted on a

stem A24 rotatable in the sub for indicating the passage of a ball or plug

therethrough.

As shown, the housing is of a generally frustoconical shape and has four

passages P^ P₂, P₃ and P₄ extending downwardly and inwardly therethrough to

connect at their lower ends with the opening A13. More particularly, these

passageways are equally spaced apart about the center line of the housing, and

thus to opening A12, to connect at their lower ends with a common opening A21 A

in the upper end of the sub A21.

The upper end of each passage is adapted to receive a closure member 25,

the threaded connection between each closure member and its passage enabling

the closure member to be selectively removed or installed. The housing also has

a lateral opening A26 connecting the lower end of its upper opening A12 with one

of the passages P.,, P₂, P₃ and P₄ beneath the closure member therefor.

Each passage P_{1 (} P₂, P₃ and P⁴ is in turn open and closed by means of

through bore plug valves PV.,, PV₂, PV₃, and PV₄ installed in the housing beneath

the lateral openings A26, and vertically staggered to accommodate the valves.

These valves of course control the passage of a plug or a ball as well as circulating

fluid through the top drive, the head and into the liner below it. Thus, with the

valves controlled in the manner to be described, circulation of the fluid may be continuous through at least one passage, even though the individual passages are

closed to contain balls or wiper plugs.

As shown, each plug valve comprises a body having an opening A30

therethrough adapted, upon rotation of the body between its alternate positions, for

alignment with or across a passage. These valve bodies may of course be rotated

in any suitable manner and are held in place by a mounting plate MP bolted to the

outside of the housing.

As indicated in Figure A2, one of the passages may receive a ball B between

the top closure member and valve, while another passage may receive a pump

down plug PDP. One of the other passages may be used to receive a ball or a

plug, depending on the use of the balls and plugs in the system in which the head

is installed. The fourth passage may be left open for enabling fluid to be freely

circulated downwardly therethrough on a continuous basis.

A plug or a ball may be installed in a passage by removal of the closure

member A25, which provides easy visual access to the passage to determine if the

ball or plug in place or has been dropped downwardly. Each ball drops freely by

virtue of its own weight when the plug valve in its passage is opened. The pump

down plug, however, has wiper blades on it which are flexibly engaged with the

passage, so that the downward movement of the wiper blade into the liner may be

assisted by the passage of fluid through the ports connecting with the passage.

The fourth passage may receive either a plug or a ball, depending on the needs of

the system in which the head is installed or left open for free downward flow of the circulating fluid.

As will be understood, the only parts of the head requiring movement, and

thus bearings and seals, are the plug valves PV for the individual passages.

Closure of the plug valve in the three passages may facilitate downward pressure

through the fourth passage when its plug valve is open, thus forcing the ball or plug

downwardly into the liner.

As shown, each plug valve is mounted for rotation within its passage by

means of a mounting plate MP bolted to a recessed portion of the outer side of the

head and engaging an annular shoulder about the plug valve member.

Running Tool

Continuing with a description of the running tool 120 previously described,

piston sleeve 220 is disposed about and is axially moveable relative to portion 210.

An upper sealing ring 214 is disposed about a smaller O.D. of the running tool

mandrel than is the lower sealing ring 216 to form an annular pressure chamber

218 between them for lifting the tie back receptacle 130 from the position shown in

Figure 1 B to an upper position, as will be described in connection with setting the

slips 142A. Ports 242 formed in the running tool mandrel 132 connect the running

tool bore with the surrounding pressure chamber 218 once the sleeve 212 is

lowered. An increase in pressure through the ports 242 will raise the piston sleeve

220. Upward movement of the sleeve 220 causes the upper end 312 of the piston

sleeve 220 to overcome the resistance of the split ring 244 as shown in Figure 1A in order to raise the tie back receptacle 130, as shown in Figure 2A, and thereby

raise the slips 142A, as shown in Figure 2B. Sleeve 245 as shown in Figure 1D

may move downward to expose ports 260, raising the piston 252 to release the ring

244 which was connected to the top of the tie back receptacle 130. A further

increase in pressure will force the ball through the reduced neck of the seat 232 to

pump the ball to a seated position on a lower seat 246 (see Figure 1 D), which is

similar to the upper seat 232.

One problem with a conventional slip assembly is the need to coordinate the

setting of the individual slips so that teeth thereof en'gage the outer casing

substantially simultaneously. Also, it is of course costly to machine multiple wedge

surfaces about the liner, as well as to provide multiple slip elements, and it is the

principle object of this invention to provide a slip assembly for this purpose which

requires only a single slip element cooperable with only a single wedge surface of

the liner or other elongate member.

Thus, in the embodiment of Fig. 9A-9C, and as also shown and described in

the aforementioned provisional application 60/292,099, the slip assembly include

slip segments 141 which are raised by a tie bar over the outer conical surface of a

cone 143 to cause teeth 142 about the slips to grip the casing C. In a preferred

embodiment of the invention, the frusto conical surfaces of the member and slip

extend downwardly and inwardly, the lower end of the slip is received in an

upwardly facing recess in the member, and the teeth of the c-ring face downwardly

in position to engage the wellbore, as the c-ring is raised over the surface of the member whereby the member may be suspended within the wellbore. The means

for raising the lower end of the c-ring from the recess to a position for sliding along

the conical surface of the member comprises at least one tie bar extending vertically

through the memberfor guided reciprocation with respect thereto. More particularly,

the inner side of the c-ring and lower end of the tie bar have interfitting parts which

enable the lower end of the c-ring to be raised out of the recess, but which are

disengageable when the bar is raised to permit the ring to expand into engagement

with the wellbore.

Preferably and as illustrated, the inner frusto conical surface of the c-ring has

relatively blunt teeth about its frusto conical surface for engagement with the frusto

conical surface of the member so as to control the friction between them, and thus

control the force applied to the casing.

As illustrated and described, the elongate member is a liner and the recess

to receive the end of the slip is of annular shape.

C-Ring Slip

With reference to the above described drawings, and as best shown in Figs.

B3A and B3B, the liner B20 has a downwardly and inwardly extending frusto conical

surface B22 thereabout above an upwardly facing annular recess B23. The liner

has been lowered on a suitable running tool (not shown) to a position in the outer

well casing in which the liner is to be hung off.

As will be described in more detail to follow, c-ring C is initially expanded to permit it to be disposed about the conical wedge surface of the liner. It may then

be contracted and forced downwardly to cause its lower end B26 to move into the

recess B23. When so installed, the c-ring slip is held in retracted position in a

shape somewhat larger than its fully contracted shape of Figs. B1A and B1B.

When the c-ring has been pulled upwardly to remove its lower end from the

recess B23, it expands towards its fully expanded position of Figs B2A and B2B,

whereby downwardly facing teeth B22 about its outer side engage the outer well

casing, as shown in Fig. B3B, in a somewhat less than fully expanded position.

Then, when the c-slip is raised, the inner surface of the c-ring will slide over wedge

surface B22 to urge it outwardly to cause its teeth to bite into the outer well casing,

and thus permit the weight of the liner and its associated parts to be hung off on the

casing.

As shown in Figs. B3A and B3B and in detail in Figs. B3AA and B3BB, the

inner frusto conical surface of the c-ring slip has blunt teeth CF thereon which, as

well known in the slip art, control the frictional engagement with the liner and thus

the outward force applied to the casing. Thus, as the teeth take on initial bite into

the casing, the blunt teeth on the inner side of the slip will begin to gall the wedge

surface of the liner so as to control the extent to which the teeth bite into the casing.

The force thus applied to the casing and liner may be controlled by the relationship

of the inner and outer teeth to one another. Although the teeth CF are preferred,

the inner surface of the c-ring may be smooth.

With reference to Figs. B4 to B6, one or more tie bars B30 extend downwardly through a slot B40 in the liner for guided reciprocation with respect

thereto. The lower end of each tie bar is connected to the upper end of the slip for

raising its lower end out of the recess. Thus, as shown in Figs. B4 - B6, the lower

end of each tie bar B30 has a flange 50 which is received in a groove B36 about the

inner diameter of the c-ring, as the c-ring is initially mounted in the recess.

As the tie bar is raised to lift the c-ring out of the recess B23, the flange B50

on its lower end moves out of the groove B36 to release the c-ring therefrom, as

shown in Fig. B5. At this time, of course, the weight of the liner may be slacked off

on to the outer frusto conical surface of the c-ring to force the teeth of the c-ring

outwardly into gripping engagement with the outer casing as shown in Fig. B6.

As an alternative to slip assemblies, as previously described, other apparatus

for this purpose - i.e. hanging an inner casing within an outer casing, have locking

elements adapted to be expanded into matching locking grooves formed in the

outer casing. In some cases, the locking elements are adapted to be spring biased

into matching grooves formed in the outer casing. However, these springs are

susceptible to breaking or other malfunctions. This is especially true since the

hanger often comprises a large number of intricate parts which are expensive to

replace, and which require a delay in the overall well operations. In still other cases,

the hangers having only a single latching part for fitting within a single groove, thus

limiting its load carrying capacity. Another object of this invention is to provide a

casing hanger system which overcomes these and other problems inherent in prior

hangers for such systems. These and other objects are accomplished , in accordance with the illustrated

embodiment of this invention, by a liner hanger system comprising a joint of casing

adapted to be connected as part of an outer casing installed within a wellborn, and

a liner adapted to be lowered and landed within the outer casing. The bore of the

casing joint has a polished bore and vertically spaced, upwardly facing landing

surfaces formed therein, and the liner includes a tubular body having a recess

formed about its body, and a hanger element comprising a circumferentially

expandible and contractible C-ring disposed within the recess. The ring has teeth

on its outer diameter for landing on the landing surfaces of the casing joint when in

its expanded portion, and upon relative vertical movement with respect to the liner,

is expanded outwardly against the polished bore. Upon continued relative

movement of the liner and ring, the teeth will move into a position in which they

expand further outwardly into landed positions on the landing surfaces to permit the

liner to be suspended therefrom.

Liner Hanger

With reference now to Figure C1 , the joint C10 of the outer casing section is

threaded at its upper and lower ends to permit it to be connected as part of the

outer casing installed in the well bore, as in the liner hanger systems referred to

above. The polished bore of the casing section has an annular recess C11 in its

lower portion, and a series of vertically spaced, upwardly facing landing shoulders

C12 above the recess C11 and separated therefrom by annular restriction C14. There is another annular recess C15 formed in the bore above and separated from

the landing surfaces C12 by means of an upper restriction C16 above an annular

recess C13. The restrictions and landing shoulder are of essentially the same

diameter of the polished bore above them.

Hanger C17 is shown in Figure C2 to be carried within a recessed portion 18

about the liner L. The hanger C17 is a C ring split about its circumference in

position to be urged circumferentially outwardly to engage the inner diameter of the

casing when expanded, but held in its contracted position, as shown, as the liner

is run into the outer casing. In this position, its lower end C20 is adapted to be

received within a groove C19 in the upper end of an enlarged outer diameter portion

C21 of the liner.

The upper end of the hanger has teeth C22 formed thereabout in vertically

spaced relation corresponding to the landing surfaces C12 of the casing and fitting

within recess C18 about the liner. The toothed section and lower end of the ring are

connected by an outwardly enlarged cylindrical portion C35 whose inner surface

engages the outer surface of enlargement C25 about the liner.

As will be described and shown in Fig. C3, the hanger is adapted to be raised

relative to the liner to release it for expansion outwardly into engagement with the

polished bore of the outer casing. Thus, liner hanger system includes a suitable

mechanism to raise the hanger out of its retained position, to free its lower end from

groove C19. This may be accomplished by raising the hanger by means of tie bars

C30 connected at their upper ends to a cone C cover which a packing element is adapted to be lowered to set it against the outer casing. The tie bars extend

through vertical slots in the recessed portion of the liner, and have an outer flange

C31 releasably connected in a groove C32 about a lower extension of the cone C.

Thus, it will be seen, from a comparison of Figure C2 and Figure C3, that

raising of the packer cone will raise the lower end of the hanger free from the

retaining groove C19, and thus permit the hanger to expand outwardly to the

position of Figure C3. This then permits rib C61 on the lower end of the tie bar to

disengage from groove 62 in the lower end of the hanger and release the tie bars

from the hanger as it moves into its upper relative position with respect to the liner.

This relative vertical movement between the liner and packer element cone has

resulted from shearing of pin C33 releasably connecting them in the position of

Figure C2. This of course can be accomplished by raising of the packer cone

relative to the liner, prior to lowering of the hanger into a position opposite the

grooves forming landing surfaces in the bore of the outer casing.

Upon lowering of the hanger with the liner from the Figure C2 to the Figure

C3 position, the lower radially enlarged section C35 of the hanger, which extends

over the outer enlargement 25 of the liner, is free to move outwardly into the recess

C11 in the outer casing. Thus, when lowered to a position opposite the landing

surfaces C12 within the outer casing, the teeth C22 about the upper end of the

hanger move outwardly onto the landing surfaces, thus forming multiple shoulders

on which to support the load of the liner within the outer casing. This outward

expansion of the hanger element has occurred after it has been lowered beneath the enlargement in the bore of the outer casing as the liner is lowered from its Fig.

C3 to its Fig. C4 position.

When the hanger has sprung outwardly to the position of Figure C4,

continued lowering of the liner will move the enlargement C25 thereabout into the

lower end of the hanger on which the teeth are formed, thus maintaining it in its

outer hanging position, as shown in Fig. C4. A downwardly facing shoulder C51 is

formed on the outer diameter of the liner above the outward enlargement C50 so

as to land on the upper end of the hanger, as shown in Figure C4. The outward

enlargement is moved into the inner diameter of the hanger, as shown in Figure

C4, by virtue of a tapered shoulder C50B formed on its upper end slidable over an

inwardly and downwardly tapered shoulder C50A surface on the liner.

As the hanger moves into landed position, enlargement C35 thereabout

beneath its teeth fits closely within the recess C16 in the outer casing bore so as to

limit outward expansion of the hanger element once it is moved into hanging

position.

An inwardly enlarged portion C60 on the lower end of the hanger, beneath

its outwardly enlarged portion C35 moves over the outer diameter of the lower end

of the liner, thereby cooperating with the enlargement C50 to maintain the hanger

element in its outer hanging position.

Running Tool

Referring back again to the running procedure, the annular packer element 150 (see Figure 1F) is disposed about a downwardly-enlarged upper cone 152

beneath the pusher sleeve 148. The packer element 150 is originally of a

circumference in which its O.D. is reduced and thus spaced from the casing C.

However, the packer element 150 is expandable so that it may be moved

downwardly over the cone 152 to seal against the casing.

The packer element 150 is adapted to be set by means which includes

spring-pressed lugs 328 which, when moved upwardly out of the tie back receptacle

130, will be forced to an expanded position, as shown in Figure 6A, to engage the

top of the tie back receptacle. When weight is set down, the expanded lugs 328

transmit this downward force through to the pusher sleeve 148 and the packer

element 150. A body lock ring 270 (see Figure 1 F) is disposed between the tie back

connector 130 and the pusher sleeve 148 and permits the packer element 150 to

be forced downwardly over the upper cone 154 by lowering of the tie back

connector. Upward movement of the set packer element is prevented.

The packer element 150 may be of a construction as described in U.S.

Patent No.4,757,860, comprising an inner metal body for sliding over the cone and

annular flanges or ribs which extend outwardly from the body to engage the casing.

Rings of resilient sealing material may be mounted between such ribs. The seal

bodies may be formed of a material having substantial elasticity to span the annulus

between the liner hanger and the casing C. Radial Set Packer

The present invention also relates to an improved radial set packer for

sealing with a casing or other downhole cylindrical surface which is configured with

a primary seal and a backup seal, and may be part of a downhole tool including a

conveyance tubular and a conical wedge ring, and thus may be used for reliable

sealing engagement between a liner hanger and a casing string.

Packer elements or packers which are radially set by axial movement of the

packer element relative to a conical wedge ring have been used for sealing in

subterranean well bores. A conveyance tubular is conventionally provided for

positioning the packer element at the desired position within the well bore, and an

actuator causes the packer element to move axially with respect to a conical wedge

ring and thereby expand into sealing engagement with the cylindrical surface to be

sealed.

U.S. Patents 4,757,860 (previously mentioned)and 5,076,356 disclose radial

set packer elements which may be used in various applications, including a subsea

wellhead. In a typical wellhead application, the packer element may need to

expand in diameter approximately 0.030 inches in orderto obtain a reliable seal with

the polished bore. U.S. Patents 5,511 ,620 and 5,333,692 disclose packer elements

intended for sealing between a liner hanger and a casing. More specifically, a

conical member is moved axially with respect to the packer element to expand the

packer element into engagement with a casing. That expansion may be

significantly greater than the expansion of a packer element in a wellhead application due to the difference in diameter of the casing from the drift ID ( smallest

allowable ID for a particular size casing) to the maximum ID allowed by API for that

size casing. The difference between this drift ID and the maximum ID for a

particular size casing may thus be 0.300 inches or greater.

Several problems exist with the packer element disclosed in the '620 Patent.

Because the seal element is stationary with respect to a movable conical element,

the radially extending flanges or ribs of the seal element may not expand as desired

into portions of the non-uniform diameter casing string to obtain reliable metal-to-

metal sealing engagement. Also, the packer element does not always form a

reliable metal-to-metal seal with the conical wedge ring, and the conical wedge ring

similarly does not form a reliable metal-to-metal seal with the tool mandrel. Also,

the elastomeric sealing portions of the seal element are not allowed to thermally

expand in response to high temperature downhole conditions, and thus exert

uncontrollable forces on the spaced apart metal radial flanges or ribs.

Other problems with prior art packer elements concern poor sealing reliability

under high pressure conditions. The metal ribs may not reliably seal with the

cylindrical surface, and the elastomeric portion of the seal assembly may not reliably

seal over extended time periods. Some packer elements function reasonably well

when high pressure is applied to one side of the packer element, but do not perform

well when high fluid pressure is applied to the other side of the packer element.

The disadvantages of the prior art are overcome by the present invention,

and an improved packer element and a tool including the improved packer element is hereinafter disclosed for reliably sealing between the packer mandrel and a

downhole cylindrical surface.

The radial set annular packer element according to the present invention is

positioned downhole by a conveyance tubular. The packer element may be moved

by a setting tool from a reduced diameter rυn-^' position to a set and expanded

diameter position, such that the packer element engages a casing, a polished bore

receptacle, or other downhole cylindrical surface in a well. If the cylindrical surface

is a casing or other member which may be irregularly shaped, the packer element

is preferably moved axially relative to a conical wedge ring or cone during the

setting operation. The packer element is particularly well suited for reliably sealing

against high pressure either from above or below the element, and includes a

primary elastomeric seal and a secondary elastomeric seal, and a primary metallic

seal and a secondary metallic seal. The metal ribs of the packer element are

angled so that the primary elastomeric seal is pressed against a rib angled toward

the high pressure, and the secondary elastomeric seal is similarly pressed against

a rib angled toward the high pressure. The secondary elastomeric seal body acts

on the primary rib to prevent the primary rib from becoming perpendicular with

respect to the sealing surface, and thereby enhances the reliability of the seal.

It is an object of the present invention to provide an improved packer element

which may be used in downhole applications for reliably sealing with a cylindrical

surface. It is a feature of the present invention that the packer element is

particularly well suited for sealing between a liner hanger and a casing under conditions where the casing may grow considerably in response to thermal and/or

pressure expansion during downhole operations.

It is a related object of the invention to provide a downhole tool including a

conveyance tubular, a conical wedge ring and an annular seal assembly or packer

element according to the present invention.

It is a feature of the present invention that each of the primary and the

backup metallic ribs of the sealing element are angled at least 15° with respect to

a plane perpendicular to a central axis of the sealing element.

Another feature of the invention is that axially spaced metal protrusions

provide a reliable metal-to-metal seal between the packer element and the cone,

and also preferably between the cone and the mandrel or body interior of the cone.

Still another feature of the invention is that the elastomeric seal bodies of the

packer element include specifically designed volumetric voids so that, after the seal

bodies engage the surface, the elastomeric seal bodies will be compressed until the

ends of the ribs engage the sealing surface. At this stage, the now smaller voids

in the seal bodies allow for thermal expansion of each seal body between the metal

ribs to minimize undesirable stress force on the ribs.

Seal Element

Figure D1 depicts an annular packer element D10 according to the present

invention positioned at the lower end of a pusher sleeve D12 at the lower end of a

tie back receptacle prior to sealing engagement with a casing C. Conventional grooves or threads D28 or similar connectors may be used to interconnect the

packer element to the tie back receptacle. Axial movement of the packer sleeve

D12 and thus the packer element D10 in response to the packer setting operation

pushes the packer element downward relative to the tapered cone D14 to expand

the seal element into sealing engagement with the casing. The cone D14 is in turn

supported on a liner hanger body D16. In an environment where the packer

element is not the top liner hanger seal, the packer element D10 may be supported

on the end of a seal actuator which replaces the pusher sleeve D12, and the liner

hanger body D16 may be a packer mandrel or other conveyance tubular for

positioning the packer element in the well. In the Figure D1 embodiment, the body D16 is thus part of the conveyance tubular which positions the packer element at

a selected position within the well bore. The pusher sleeve of the tie back

receptacle shown in Figure D1 represents a lower portion of an actuator sleeve

which urges the packer element from a reduced diameter run-in position to an

expanded diameter activated or sealed position. The actuator sleeve may thus

apply a selected axial force to the packer element to set the packer. The actuator

may be selectively activated by various mechanisms, including set down weight or

other manipulation of the conveyance tubular, and may include axial movement of

a piston in response to fluid pressure, either with or without dropping plugs or balls

to increase fluid pressure. Further details with respect to the use of the packer

element in a liner hanger application are disclosed in U.S. Provisional Application

Serial No. 60/292,049 filed 18 May 2001. The packer element as shown in Figure D1 is in its original configuration in

which the OD is reduced prior to being sealed with the casing. Packer element D10

is expandable so that it is moved downwardly over the stationary cone D14 to seal

against the casing, as discussed below and as shown in Figure D3. It is a feature

of the invention that the packer element D10 be moved into reliable sealing

engagement with the casing by a setting operation which includes moving the

packer element D10 axially with respect to the packer cone D14, ratherthan moving

the cone with respect to the stationary packer element. This setting operation forms

a more reliable seal with the casing by allowing the ribs D20, during the setting

operation, to flex or deform into the shape of the casing.

Referring to Figures D1 and D2, the packer element D10 comprises an inner

metal body or base D18 for sliding over the conical wedge ring or cone D14 and > annular flanges or ribs D20 which extend radially outwardly from the base D18 to

engage the casing. The base D18 is relatively thin to facilitate radial expansion.

The base D18 and the ribs D20 form a metal framework to support the rubber or

other resilient and preferably elastomeric seal bodies. Rings of resilient seal bodies

D22, D24 and D26 are provided between the ribs D20, and preferably the upper

and lower sides of each seal body are in engagement with a respective rib. The

body D18 and the ribs D20 are formed from material having sufficient ductility to

expand into the annulus between the casing and the liner hanger. The metal

portion of the packer element, namely the base D18 and the radially projecting ribs

D20, is thus formed from material which is relatively soft compared to metals commonly associated with downhole tools. This allows the packer element to

reliably expand into sealing engagement with the casing at a reduced setting load.

The radially projecting ribs D20 of the packer element are each substantially

angled with respect to a plane perpendicular to a central axis of the packer element.

More specifically, the centeriine of each rib is angled in excess of 15°, and

preferably about 30°, relative to the plane D38 perpendicular to the central axis of

the packer element. Although the ribs may be slightly tapered to become thinner

moving radially outward, the ribs preferably have a substantially uniform axial

thickness. Rib D32 is shown in Figure D2 at an angle D33 between the rib

centeriine and the plane D38. This feature allows each of the ribs D20 to expand

substantially as the diameter of the casing varies or "grows", whether in response

to internal pressure and/or thermal expansion. Because of the ability of the angled

ribs D20 to flex, reliable metal-to-metal contact is maintained between the ends of

the ribs and the casing, as shown in Figure D3.

A particular feature of the invention is that the packer element D10 inherently

forms both a primary seal with the casing and a secondary seal with the casing, with

the secondary seal depending upon the direction of pressure. Also, the packer

element may include both a primary and a backup elastomeric seal, and a primary

and a backup metallic seal. Referring to Figure D3, it should be understood that the

downward inclination of the ribs D30 and D32 is such that relatively high fluid

pressure above the packer element may pass by these ribs and the annular

elastomeric upper seal body D22, so that the interior seal body D24, which constitutes a majority of the elastomeric seal area, forms the primary elastomeric

seal against fluid flow. The term "fluid" as used herein includes gas, liquids and

combinations of gas and liquid. Seal body D24 preferably engages the ribs D32,

D34 and the base D18, and substantially fills the annular void between these

surfaces. When fluid pressure is above the seal element D10, the lower seal body

D26 positioned between ribs D34 and D36 forms a backup secondary elastomeric

seal in the event the primary elastomeric seal were to leak. Similarly, when high

fluid pressure is below the packer element, high pressure fluid would likely flow past

the ribs D36 and D34, so that seal body D24 is the primary seal element. Seal body

D22 between the ribs D30 and D32 thus becomes the secondary elastomeric seal

element. The primary elastomeric seal element is thus pressed in an axial direction

(generally along the central axis of either the conveyance tubular body or the

casing) in response to pressurized fluid, against an inclined rib which is angled

toward the high pressure, and the secondary elastomeric seal element is captured

between two ribs each angled toward the high pressure side, so that the secondary

seal element is also pressed in an axial direction against a rib angled in the direction

of the high pressure. Most importantly, the backup seal, whether that be seal body

D22 or D26, is captured between two ribs and thus minimizes the likelihood that the

axially innermost rib D32 or D34 will flex outward to come in line with the plane D38,

i.e., perpendicular to the wall of the casing. The material of the seal body D22 or

D26 thus acts as a biasing force which tends to retain the rib D32 or D34 at a

desired angle, which then supports the primary seal body D24 and prevents the rib D32 or D34 from becoming perpendicular to the wall of the casing C. Should the

ribs flex past the point of being perpendicular to the casing wall, the packing

element likely will lose its sealing integrity with the casing. The radial ribs D20 are

thus vertically spaced from one another and act independently with respect to

upward and downward directed pressure forces.

Packer element D10 also includes multiple metal sealing surfaces, namely

the ends of each of the ribs D20, to form annular metal-to-metal seals with the

casing. More particularly, these angled ribs are configured to keep a constant

metal-to-metal seal with the casing even though the packing element may be

subjected to variable fluid pressure and temperature cycles. Under high pressure,

the two ribs adjacent the high pressure may flex toward the base D18 and thus not

maintain sealing integrity. A primary metal seal is nevertheless formed by one of

the axially innermost ribs D32 or D34 on the downstream side of elastomeric packer

body D24, and a backup metal-to-metal seal is formed by the axially outermost rib

D30 or D36 spaced axially farthest from the high pressure. High fluid pressure

forces both the primary and secondary backup ribs to reduce the angle D33,

thereby forming a tighter sealed engagement with the casing. The redundant or

backup elastomeric seal D22 or D26 exerts a biasing force which tends to prevent

the primary metal seal D32 or D34 from moving past the position where it is

perpendicular to the wall of the casing.

Referring again to Figure D2, each of the elastomeric seal bodies D22 or D24

and D26 is provided with a substantial void area D23, D25 and/or D27 to allow for compression of the elastomeric body and forthermal expansion so that, during both

the final setting operation and during use downhole, the rubber-like material is not

squeezed outwardly past the ends of the ribs, or squeezed to exert substantial

forces on the ribs which will alter the flexing of the ribs. Preferably the void area

between the ends of the ribs and the base of the sealing element is such that at

least about 5% to 10% thermal expansion of elastomeric material may occur. This

5% to 10% void area thus allows for thermal expansion of each elastomeric resilient

seal, thereby avoiding the creation of additional forces to act on the ribs D20. Each

of the elastomeric seal bodies thus preferably includes voids that allow each resilient seal body to compress between the metal ribs without over-stressing or

buckling the ribs. These voids will thus be substantially filled due to compression

of the resilient sealing material, and will become substantially filled, as shown in

Figure 3, due to compression of the seal bodies and thermal expansion of the

resilient seal bodies. The stress level on each of the elastomeric seals may

therefore remain substantially constant with varying thermal cycles in the well bore.

As shown in Figure D3, the elastomeric seal bodies have been compressed

to reduce the void area, leaving only a small void volume for additional thermal

expansion. The void area is preferably designed to be from 5 to 10% of the volume

of the resilient seal bodies once each seal body is in its compressed position with

the ends of the ribs engaging the casing, but prior to thermal expansion.

Figure D3 depicts the packer element D10 according to the present invention in sealed engagement with the casing C, and at a temperature wherein the

elastomeric material has already expanded to fill most of the void area discussed

above. Figure D3 also shows the flexing or bending of these ribs from the run in

position as shown in dashed lines to the sealing position as shown in the solid lines.

The inclination of the ribs, i.e., angle D33 as shown in Figure D2, is thus increased

during the packer setting operation. The ribs D30 and D32 at the upper end of the

packer element D10 are angled downwardly, and the ribs D34 and D36 at the lower

end of the packer element are angled upwardly. As explained above, the centeriine

of each rib is angled at least 15° with respect to the plane D38 perpendicular to the

central axis of element 10 prior to setting, i.e. when of a reduced diameter as shown

in Figure D1.

The base D18 of the packer seal includes a plurality of inwardly projecting

protrusions D40. These annular protrusions or beads on the packer element

provide a reliable metal-to-metal sealing engagement with the packer cone D14.

These protrusions provide high stress points to form a reliable metal-to-metal seal.

Similar protrusions D42 on the packer mandrel D16 provide metal-to-metal sealing

engagement between the packer mandrel D16 and the packer cone D14.

Accordingly, the seal of the present invention operates in conjunction with the

packer cone to obtain a complete metal-to-metal seal between the packer mandrel

and the packer cone, between the packer cone and the seal element, and between

the seal element and the casing. The multiple seal protrusions or beads D40 form

axially spaced metal-to-metal seals between the base D18 of the sealing element D10 and the tapered cone D14, while protrusions D42 seal between the cone D14

and the packer body or other conveyance tubular D16. These metal-to-metal seals

are energized as the packer seal is set, and preferably include multiple redundant

annular metal-to-metal seals. Alternately, one or both of the radially inner and

intermediate metal-to-metai seals could be formed by annular protrusions on the

packer cone for sealing with either or both the packer element base D18 and the

packer mandrel D16.

The resilient elastomeric seals D48 on the ID of the seal bore D18 may be

backup seals, since the spaced apart metal protrusions D40 form the metal-to-metal

seal between the packing element and the cone once the packer element is fully

set. Another elastomeric seal, such as a V packing D15, provides an elastomeric

backup seal between the cone D14 and the body D16. These metal protrusions

D40 on the ID of the element D10 are axially in line with (laterally substantially

opposite) the area where the ribs D20 seal against the casing. The interface

between the casing and the metal ribs D20 of the packing element D10 thus force

the metal seal protrusions D40 into tight metal-to-metal sealing contact with the

cone D14. The protrusions D42 on the body D16 are similarly axially in line with

the element D10. The metal-to-metal seals between the packer element and the

cone are preferably provided on the packer element, since its axial position relative

to the cone when in the set position may vary with the well conditions.

With the desired setting force applied to the packer element D10, the packer

element will be pushed down the ramp of a cone D14 so that the ribs D20 come into metal-to-metal engagement with the casing. Metal seal protrusions D40 and D42

between the packing element D10 and the cone D14 and between the body D16

and the cone D14 are in contact, but have not been energized. When the setting

pressure is increased, the ribs on the packing element may be flexed inward to a

position in solid lines in Figure D3. This high setting force will compress the seal

bodies between the ribs and cause the outer diameter of each seal body into tight

sealing engagement with the casing. This high setting force will also cause the

metal protrusions D40 along the ID of the seal element D10 and the metal

protrusions D42 along the OD of the mandrel D16 to form a reliable metal-to-metal

seal with the cone D14. Under this load, these metal protrusions form high localized

stress at the point the protrusions engage the cone to achieve a reliable metal-to-

metal seal. The metal protrusions which provide the desired metal-to-metal seals

between the body or mandrel D16 and the cone D14 could be provided on either

the outer generally cylindrical surface of body D16 or the inner generally cylindrical

surface of cone D14. A reliable fluid pressure tight barrier, which may be both a

liquid barrier and a gas barrier, is thus formed with high reliability under various

temperatures, pressures and sealing longevity conditions, due to the combination

of the elastomeric and metal seals. After the sealing element comes into contact

with the casing, the BOP preventer rams may be closed around the drill pipe (or

other conveyance tubular) and fluid pressure may be applied to the annulus to

pressure assist the setting of the packer element.

The sealing element of the present invention is well suited for use in a liner hanger for sealing between the packer mandrel of the liner hanger and the casing.

The initial set down weight on the seal element D10 will thus force the seal element

down the cone D14 and into contact with the casing C. Initially, the seal material

which is radially outward of the ends of the ribs D20 will be compressed to occupy

much of the void area in the seal bodies. Once the elastomeric bodies have been

deformed so that the ends of the ribs engage the casing, the remaining void area

may be from 5% to 10% of the volume of each seal body, assuming there has been

no significant expansion of the seal bodies due to thermal expansion. If the seal

bodies experience high thermal expansion prior to a setting operation, the void area

will be reduced by compression of the seal bodies.

During well operations, the pressure may cause the casing to expand in

diameter and, this expansion will cause the ribs to expand with the casing, so that

the position of the ribs with respect to the expanded casing may return to the

configuration as shown in dashed lines in Figure D3. The ability of the ribs to "grow"

in diameter with the expanding casing keeps the ends of the ribs in reliable metal-to-

metal contact with the casing as the well goes through pressure and temperature

cycles. When pressure is released and the casing shrinks, the ribs may return to

the solid line configuration as shown in Figure 3.

The seal element D10 of the present invention is thus ideally suited for

applications in which high pressure may be applied from either direction to the seal

element, since the seal element inherently provides both a primary seal and a

secondary seal, with each elastomeric seal being supported in a direction to resist axial movement in response to the high pressure by a rib which is angled in the

direction of the high pressure, and which allows flexing to conform to the casing.

The rib on each side of the primary seal body is supported by the secondary seal

body, which biases the rib toward the high pressure.

In the case of a liner hanger, the liner hanger running tool conventionally

includes the actuator which provides the compressive force to the packer element

D10 to set the packer. In other applications where the seal element is used, an

actuator may be used for applying the compressive force to move the seal from a

run in or radially reduced position to a sealing or radially expanded position. The

actuator may be hydraulically powered or may use mechanical setting operations.

Thereafter, a retainer keeps the seal element in sealing contact with the casing,

after the running tool is returned to the surface, by preventing or limiting axial

movement of the packer element when fluid pressure is applied.

The sealing element of the present invention may be used in various

applications in a well bore having a tubular disposed therein, wherein a packer

mandrel or other conveyance tubular is positioned within the well bore to position

the packer element at a selected location. The packer element is disposed about

the conveyance tubular and includes a plurality of elastomeric seal bodies for

sealing engagement with the well bore tubular, and a plurality of metal ribs which

separate the elastomeric seal bodies, with the rib ends intended for metal-to-metal

sealing engagement with the tubular. The packer element may be run into the well

in a configuration similar to that shown in Figure D1 in which the sealing element has a reduced diameter, and the packer element deformed radially outward into

sealing engagement with the well bore tubular as it moves relative to a conical

wedge ring, until the packer element reaches the final set position, as shown in

Figure D3. The radial set sealing element of the present invention may thus be

used for various types of downhole tools. Additional back-up secondary metal ribs

could be provided, as well as additional back-up elastomeric bodies engaging these

additional ribs.

Various types of conveyance tubulars may be used for positioning the packer

element at a selected location below the surface of the well. The substantially

conical wedge ring or cone may have various constructions with a generally outer

conical surface configured to radially expand the annular seal assembly or packer

upon axial movement of the packer element relative to the wedge ring, due either

to axial movement of the packer element relative to the stationary wedge ring or

axial movement of the wedge ring relative to the stationary packer element. In a

preferred embodiment, the seal assembly includes an upper elastomeric seal body,

a primary elastomeric seal body, and a lower elastomeric seal body. While each of

the upper and lower seal bodies ideally provide the backup elastomeric seal in the

event the primary elastomeric seal were to leak, it is an important function of the

upper seal body D22 and the lower seal body D26 to provide a desired biasing force

against the respective rib D32 or D34. These elastomeric seal bodies thus function

as biasing members between the axially outermost rib and the adjacent inner rib to

exert a force which prevents the inner rib from flexing beyond a predetermined stage. For example, the lower seal body D26 engages both the inner rib D34 and

the outer rib D36, and exerts an upward biasing force to prevent rib D34 from

moving downward past a position where it is perpendicular to the wall of the casing.

At the same time, the lower seal body D26 exerts a downward biasing force which

tends to increase the downward flexing to the outer rib D36 when the inner rib D34

flexes downward in response to high pressure above the packer element.

In addition to the primary metal-to-metal seal, the secondary metal-to-metal

seal, the primary elastomeric seal and the secondary elastomeric seal, additional

sets of metal-to-metal and elastomeric seals could be provided in the packer element. Elastomeric bodies which are configured other than shown herein may

thus be used for this purpose. Various types of plastic materials in various

configurations may provide the desired biasing force, and ideally also a secondary

resilient seal. Alternatively, a wave spring or other metallic material biasing

member may be used instead of or in cooperation with the elastomeric bodies D22

and D26.

Preferably each of the metal ribs of the packer element as disclosed herein

are annular members with the outermost surface of each rib, when in the run-in

position, being substantially the same radial spacing from a central axis of the tool

for reliable sealing engagement with the surface to be sealed. In other

embodiments, one or more of the ribs could include radial notches so that the rib

would not form a complete annular metal-to-metal seal, which then could be

provided by the elastomeric seal, although then the complete annular metal seal would not be obtained. Preferably a plurality of axially spaced protrusions are

provided for metal-to-metal sealing engagement between the packer element and

the cone, and between the cone and the conveyance tubular. In other applications,

a single annular protrusion may be sufficient to form the desired metal-to-metal

sealing function.

Ball Seats

Continuing further with a description of the overall system, the lower ball seat

246 (see Figure 1 D) is mounted within the running tool bore by shear pins 248

opposite the pressure chamber 256. Sleeve 245 thus supports seat 246. The

lower end of the ball seat has reduced thinner section or neck 258. Furthermore,

one or more ports 260 formed in the running tool are positioned to be uncovered to

permit fluid pressure in the running tool to be admitted to the pressure chamber 256

upon lowering of the seat 246. The ball 240 when released from the upper seat 232

will land onto the second seat 246, whereby pressure within the running tool above

the ball will move the seat 246 downward upon shearing the pins 248 to open the

ports 260 leading to the pressure chamber 256.

The ball 240 may thus pass through the first seat 232 for seating on the

reduced diameter 258 of the second seat 246 so that additional pressure may be

supplied through the ports 260 for raising the outer piston sleeve 252. This in turn

permits split ring 264 having outer teeth gripping the liner hanger 110 to move into

position opposite a reduced diameter lower end 268 of the sleeve 252 and thus out of gripping engagement with the liner hanger, whereby the running tool is released

from the liner hanger.

At this stage, the operator will pressure up to pass the ball through seat 246,

so that the drop in pressure will indicate that the ball 240 has passed through the

ball seat 246, allowing circulation through the running string to continue, and the ball

to be pumped downwardly into the ball diverter 280 (see Figure 11). Fluids are then

circulated through the tool awaiting cement displacement. The cement is then

injected into the running tool and pumped downwardly, and the pump down plug

182 follows the cement and into the liner wiper plug 180 (see Figures U, 5A and

5B). This then forms a barrier to the previously displaced cement and the

displacement fluid.

The lower end of the running tool mandrel 132 extends downwardly below

the slip assembly and has an enlarged body 145 (see Figure 11) adapted to

reciprocate within the liner 146. This enlarged body 145 has an upwardly facing

shoulder 147 which may be raised into engagement with a downwardly facing

shoulder to permit the running tool to be raised out of the set liner hanger, as will

be described.

As previously described generally in connection with Figs. 1 , 4A and 4B, to

improvements in apparatus of this type in which the cementing operation requires

the sequential lowering of balls and pump down plugs within the inner pipe, wherein

in a preferred and illustrated embodiment, the inner pipe is a liner having an upper

end installed within an outer casing by a column of cement pumped out the lower end of the liner into the annulus between it and the outer casing.

As above described, in a system of this type, a ball is dropped onto a seat

in the bore of the liner to permit circulating fluid to be directed into a portion thereof

for hydraulically actuating a part in the system external to the liner bore, and an

opening on which the ball is seated may be circumferentially yieldable, upon

application of higher circulating pressure, to cause the ball to pass therethrough and

out the lower end of the liner. The ball may then be followed by a pump down plug

to force the cement downwardly through the lower end of the liner and into the

annulus between it and the outer casing.

In the system shown and described in the aforementioned provisional

application, the ball is relatively large, and, in any case larger than the bore of the

liner wiper plugs (LWP) into which the pump down plugs (PDP) are to be installed.

Unless, the bore through the wiper plug is as small as possible, the inner diameter

of the liner to be cemented in the outer hanger is necessarily enlarged to

accommodate the wiper plugs which are carried about it. Consequently, it is the

object of this invention to provide apparatus for such a system in which the balls

may be substantially larger than the pump down plugs, and thus larger than the

bore through the wiper plugs in which the pump down plugs are to be landed.

This and other objects are accomplished, by apparatus which includes the

previously described diverter 280 comprising a tubular member such as a sub

having an upper end connected to a well pipe for lowering into a casing in the well

to permit it to be cemented therein, and having a bore with a relatively large diameter upper portion and a relatively smaller diameter lower portion. The larger

portion enables one or more balls to be lowered therethrough, but the LWP in the

smaller diameter portion prevents passage of the balls while permitting passage of

the pump down plugs into the liner wiper plug.

For this purpose, a sub installed beneath the larger portion has a pocket to

one side of its bore into which the bail, or at least a portion of it, diverted to thereby

permit the pump down plug to pass between the ball and the side of the sub

opposite the pocket, whereby the pump down plug may continue downwardly to enter the liner wiper plug. The sub also includes a ramp extending across the bore

of the sub and slanting downwardly toward the pocket so that, when the ball is

dropped, it will land on the ramp and thus be guided into the slot. More particularly,

the ramp has a U-shaped slot which is too narrow to pass a ball but is wide enough

to pass a plug down between its closed end and the inner side of the diverted ball.

Ball Diverter

With reference now to the details of the above described drawings, each of

Figs. E1 , E2 and E4 shows, in vertical cross section, a tubular member E10

suspended within a liner L installed within an outer casing C within a wellbore, its

purpose being to circulate cement downwardly through the lower portion of the

tubular member and into the annulus between the liner and the casing to cement

the liner within the casing. As also shown in Figs E4 and E5, a liner wiper plug

LWP is suspended from the tubular member with a pump down plug is installed therein.

The ball diverter BD comprises a sub wjaich is installed between the upper

and lower portions of the tubular member, and has a pocket P formed in side of the

sub to receive a portion of a ball B adapted to pass downwardly through the tubular

member. A ramp R mounted on the sub has an upper face which is slanted

downwardly from its upper end to its lower end to terminate opposite the pocket P.

A slot S in the ramp is narrower than the ball, so that when the ball is dropped

through the running tool and into the upper end of the tubular member of the

cementing tool, it will be guided into the pocket.

As shown in Fig. A3, the opening between the inner end of the slot permits

the lips of the pump down plug to flex inwardly so that the pump down plug is free

to continue downwardly to a seated position in the liner wiper plug LWP, as shown

in Fig. A4. That is, following dropping of the ball into the pocket, the pump down

plug will, under the influence of downwardly directed circulating fluid, pass between

the ball and closed end of the slot in the ramp. The pump down plug continues to

be lowered until it lands in the liner wiper plug, as shown in Fig. A4, thus closing the

lower end of the bore through the tubular member, all in a matter well known in the

art.

Increased pressure of the circulating fluid shears the pin P holding the liner

wiper plug in place to permit liner wiper plug to be moved downwardly in the liner,

as shown in Fig. A5. Thus, the released plug assembly will continue to force the cement downwardly through the liner and then upwardly within the annulus between

the liner and into the outer casing, whereby the liner may be cemented within the

casing, all in the manner well known in the art.

Running Tool

Again, continuing with the overall rights, Figure 2-8 illustrate movement of

components of the tool 120 in the process of setting the liner. Once the liner is

lowered to the desired depth, fluids are circulated through the well bore "bottoms

up". After conditioning the well bore, the ball 240 is dropped from handling

equipment at the surface and allowed either to free fall or be pumped at a desired rate onto the upper seat 232. Upon application of pressure to the seated ball, pins

222 between the seat and the liner hanger setting assembly are sheared to permit

the ball and seat to move downwardly to a position uncovering ports 242 in the body

of the slip setting assembly 140. The further application of fluid pressure will cause

the surrounding piston sleeve 220 to travel upwardly. As a result, the tie back

receptacle 130, the actuator slip slat 149 and slips 142 are pulled upward until the

circumferentially spaced slips engage with the casing C. Thus, as shown in Figure

2A, the piston sleeve 220 of the slip setting assembly 140 surrounding the running

tool mandrel 132 has been moved upwardly by the increase in pressure above the

ball 240. The piston sleeve 220 is moved upwardly until the upper end 312 of the

piston sleeve 220 engages and releases the split lock ring 244. This enables the tie back receptacle 130 to continue to be moved upwardly.

On the other hand, raising of the tie back receptacle 130 raises the cone

144A, slip arm 149 and slip 142Ato the set position, as shown in Figure 2B. At this

time, the load on the liner can be slacked off onto the slips, whereby the weight of

the liner is "hung" in the casing. While holding pressure constant in the drill pipe

to keep the slips in contact with the casing, the liner hanger thus may be slacked

off onto the slips. To be certain that the entire liner load is slacked off onto the liner

hanger assembly 110, additional pipe weight may be applied to check for hanger

movement. Once it is determined that the slips have been hung, the fluid pressure

can be reapplied to the seated ball 240 to a higher predetermined level, so that the

ball may be pumped to the lower seat 246 in the liner hanger releasing assembly

250. With the ball so seated, a predetermined pressure may be applied to move the

ball seat 246 and sleeve 245 downward to uncover the ports 260 in the liner hanger

releasing assembly. Higher fluid pressure may then be applied to cause the piston

sleeve 252 to move upwardly, thereby allowing the liner hanger releasing ring 264

to collapse within the reduced diameter lower end 268 of the sleeve 252, thereby

disengaging the running tool from the liner hanger. If the hydraulic release is not

operable to move the ring 264 to disengage the running tool, the operator may

resort to a mechanical release mode. The function of the ball in releasing the

running tool from the set liner hanger is discussed below.

The further increase in pressure on the ball 240 and the lower seat 246 will release the ball from the lower seat so that circulation through the running string

may continue while the ball 240 is pumped downwardly into the ball diverter 280.

Fluids may then be circulated through the tool awaiting cement displacement. The

cement and the displacement fluid are then injected into the running tool and

pumped downwardly. When the cement has been pumped, the pump down plug

which seals with the drill pipe is released from the surface handling equipment to

land on a seat in the liner wiper plug, thereby forming a barrier between the

previously displaced cement and the displacement fluid. A calculated amount of

displacement fluid is required to pump the drill pipe plug down to the lower liner

wiper plug. The operator observes the pressure increase when the pump down

plug 182 latches into the liner wiper plug 180. The pump-down plug 182 (see

Figure 5A) thus follows the cement into the liner wiper plug 180. As the pump-

down plug gets close to the running tool, the pump rate may be lowered so as to

reduce the risk of malfunction between the latching and sealing of the lower wiper

plug and the pump-down plug. This allows observation of the pump pressure

increase when the pump-down plug 182 has landed in the lower wiper plug 180, as

shown in Figure 5A.

It takes a calculated amount of displacement fluid to force the cement to the

desired height in the annulus between the liner and casing. The drill string may be

pressured to the predetermined level to shear the pins 186 (see Figure 5A)

connecting the plug set to the running tool. With the liner wiper plug released as shown in Figure 5B, displacement fluids move the plug set down the liner 146 to the

landing collar 370. The plug set thus forms a barrier between the cement and the

displacement fluid, and keeps the displacement fluid from contaminating the cement

fluids. A calculated amount of displacement fluid may be used to force the cement

to desired height in the annulus between the liner and the casing.

The operator continues to pump displacement fluid until the liner wiper and

pump down plug set latches into the landing collar 370 (see Figure 5C) located in

a lower portion of the casing. When so landed, seals 372 about the plug set seal

within the upper reduced bore of the landing collar 370, and slips 374 with toothed

surfaces engage the opening in the landing collar to prevent upward movement of

the landed plug by any downhole pressure. At this time, pressure in the running

tool may be increased to a substantial level above circulating pressure to be sure

that the wiper plug is properly landed and held down, and that the seals between

the plug set and the landing collar are effected. The plug may then be tested by

bleed-off pressure to insure that the flotation equipment belowthe landing collar 370

is holding.

Plug Holder Sub

As above mentioned, conventional liner hanger running tools include a plug

holder sub adapted to support a liner wiper plug on the running tool during a

cementing operation. The plug holder sub is conventionally latched to the running string, and the liner wiper plug is attached to the plug holder sub by a shear

connection. Unfortunately, these shear connections frequently are prematurely

weakened or are sheared either by running tool manipulation or by the momentum

of the pump down plug landing and seating on the liner wiper plug.

Some manufacturers have included a plug holder sub that has a latching lug

and a shifting sleeve. The plug cannot be released until the pump down plug shifts

the sleeve to allow the latching lugs to relax and thereby allows the plug set to

separate from the running tool. U.S. Patents 4,624,312 and 4,934,452 disclose

plug holder subs which use a collet instead of a latching lug. U.S. Patent 5,036,922

discloses a running tool which employs a piston that is shifted in order for the plug

set to be released.

While the above systems may prevent premature release of the plug set due

to running tool movement or manipulation, they do not prevent premature release

of the plug set due to the momentum of the pump down plug and the column of fluid

behind that plug when it lands and seats on the liner wiper plug. In many

applications, this landing or "hammering" force will cause the plug set to release so

fast that the operator cannot detect the release and therefore cannot properly

calculate the fluid displacements. This "hammering" effect of the pump down plug

hitting the liner wiper plug and the effect of prematurely releasing the plug set may

ruin a cementing job. The prior art has not addressed the problem of prematurely

releasing the plug set due to this hammering effect of the pump down plug hitting the liner wiper plug. As a consequence, the operator may not be able to

calculate the fluid displacement after the pump down plug has sealed and

latched into the liner wiper plug.

The disadvantages of the prior art are overcome by the present invention,

and an improved downhole plug. holder and method for supporting a liner wiper

plug are hereinafter disclosed which increase the reliability of cementing

operations.

The plug holder sub of the present invention may be used for positioning

a wiper plug which may be released from a liner hanger running tool or the end

of a tubular string during a cementing operation. The plug holder sub may be

releasably positioned on the lower end of the liner hanger running tool, and is

sized to pass a pump down plug, which lands in the liner wiper plug supported

on the running tool by the plug holder sub. The liner wiper plug is connected to

the plug holder sub in a manner which prevents premature release of the plug

set from the running tool, either upon manipulation of the running tool or due to

the hammering effect of the pump down plug entering and latching into the liner

wiper plug. Once the pump down plug is sealingly seated and latched within the

bore of the liner wiper plug, fluid pressure acts on a piston which is moved to

unlock the plug set from the running tool so that the plug set is released and

allowed to be pumped to the landing collar.

The piston that unlocks the plug set from the running tool acts on a fluid

filled chamber which is vented to the annulus through an orifice. When the pump down plug is sealed within the bore of the liner wiper plug, increased fluid

pressure acts on the piston. The type and volume of fluid vented, as well as the

size of the orifice, determine the time it takes to move the piston to a plug

release position. This time is important to allow the operator to determine the

correct displacement of cement volumes for cementing the liner in the well.

The plug holder sub allows the running tool to be manipulated without any

detrimental effects on the liner wiper plug. The pump down plug may be pumped

at any desired speed to the liner wiper plug and sealed and latched. The

hammering effect of landing the pump down plug on the liner wiper plug will not

prematurely release the plug set. After the pump down plug has been seated

and latched, the operator may increase pressure to the running tool, thereby

confirming to the operator that the plug has been seated in the liner wiper plug.

The operator may calculate the exact amount of displacement fluids it will take to

cement the liner in the well. The fluid pressure may then be increased, causing

the piston to start to move to the plug release position. The pump down plug

and the liner wiper plug as a set will thus be released after a predetermined

amount of time, which again is important to the operator being able to determine

the correct displacement volumes for cementing the liner in the well.

It is an object of the present invention to provide a plug holder sub for

releasing a liner wiper plug in response to high fluid pressure acting against a

piston, which in turn expels fluid from a chamber through a metering jet.

It is a further object of the invention to provide an improved method of releasing a liner wiper plug in response to fluid pressure, such that fluid pressure

moves a piston from a retaining position to a release position. The time it takes

for high pressure to expel fluid through a metering jet is monitored to increase

the reliability of properly releasing the liner wiper plug during the cementing

operation.

It is a feature of the present invention that a C-shaped retainer member

may be used for attaching the liner wiper plug to a tubular body, wherein

movement of a piston to a release position releases the C-shaped retainer to

release the liner wiper plug.

It is a further feature of the invention that the C-shaped ring may have

threads or other internal gripping members for gripping engagement with the

liner wiper plug. A metering jet may also have external threads for threaded

engagement with the tubular body.

It is an advantage of the present invention that the plug holder sub is

highly reliable and is relatively inexpensive.

These and further objects, features, and advantages of the present

invention will become apparent from the following detailed description, wherein

reference is made to the figures in the accompanying drawings.

Figure 1 depicts a plug holder sub F110 for supporting a conventional

liner wiper plug. The sub f 110 includes the body f 112 secured to the lower end

of the running tool mandrel. Before the running tool and liner is lowered in the

well, the liner wiper plug engages locking ring F114, which is supported between body F112 and the lower body F116 by piston F134. Locking ring F114 includes

grooves or threads F115 or other suitable members for grippingly engaging the

liner wiper plug. Seal F120 on the lower body F116 seals the plug holder sub to

the liner wiper plug. Threads F128 connect the body F112 to lower body F116,

and seal F122 seals between these connected bodies.

The body F112 includes a passageway F128 which is open to the annulus

about the running tool. An orifice jet F130 with a relatively sized orifice is

positioned along this port, and preferably includes threads for engagement with

threaded port F126. Fluid containing chamber F132 is pressurized by the piston

F134, which includes an OD seal F136 and an ID seal F138.

When the pump down plug lands within the liner wiper plug, the increased

pressure within the running tool acts on the piston F134, which in turn is forced

upward to expel fluid from the chamber F132. The rate fluid exits the chamber

will be determined by the characteristics of the fluid within the chamber F132,

and the size of a selected orifice in the jet F130 positioned downstream from the

chamber. The left side view of Figure F1 shows a pin F131 sealing off a weep

port to the chamber F132. The pin F131 has a small port therein for slowly

releasing pressurized fluid to the annulus. The pin F131 may be secured within

the weep port by a swaging operation, and is another form of a metering jet. The

right side illustrates a jet F130 for threading to the body F112.

A significant advantage of the plug holder sub according to the present

invention is that the increase in fluid pressure is not the primary factor that determines the release of the plug set. The rate at which the piston moves up to

expel fluid from the chamber is primarily a function of a particular jet size and the

type of fluid in the chamber. Accordingly, the operator will see an increase in

pressure when the pump down plug is landed on the liner wiper plug, and will

then know, within selected limits, that a predetermined amount of time should

elapse from that increase in pressure until the plug set is released. Once the

piston F134 moves up to reduce or eliminate the volume within the chamber

F132, the C-shaped locking ring F114 is free to move radially outward, thereby

releasing the liner wiper plug and the pump down plug. The C-shaped locking

ring F114 may be biased out but normally held radially in by the piston F134, or

may be biased in and moved outward to release by the downward force on the

liner wiper plug.

Plugs are conventionally run in a well in pairs, and the plug holder sub as

shown in Figure F1 is suited for supporting one pair of liner wiper plugs. In some

applications, one pair of plugs are preferably used before the cement fluid, and

another set of wiper plugs are used after the cement fluid and before the

displacing fluid. For this latter application, each of the plug sets may be

separately released in response to an increase in fluid pressure, which moves a

respective piston to expel fluid from the chamber and thereby release the plug

set. One piston responsive to a low pressure fluid could thus be provided on the

support sub, with that piston releasing the first plug set. At a higher fluid

pressure, a second piston may move in response to fluid pressure to release the second plug set. Each piston may force fluid through a selective orifice in a jet.

If desired, the second piston and/or both first and second piston may be shear

pinned so that no movement occurs until a selected pressure level is obtained. If

desired, the first plug set alternatively could isolate the port for the second plug

set so pressure could not act on the second plug set till the first plug set was

released.

Figure F2 depicts the piston F134 in its retaining position, with the C-

shaped retaining member F114 held radially inward so that its threads engage

the mating threads F152 on the liner wiper plug F154. The through passageway

in liner wiper plug F154 is provided with a seat F156 for sealing with a

conventional pump down plug, as discussed above. The liner wiper plug F154

conventionally includes at least one and preferably two cup shaped elastomeric

sealing members F158 on an exterior thereof so that high fluid pressure behind

the liner wiper plug forces the liner wipers outward into sealing engagement with

the liner. An annular body F159 with o-rings F160 and latch ring F161 may be

provided for sealing and latching the plug set with the landing collar.

The spacer and cement fluids may bβ mixed while circulating fluids for

cement displacement. When the cement has been pumped, the pump down

plug may be released from the surface, forming a barrier between the previously

displaced cement and the displacement fluid. A calculated amount of

displacement fluid may thus be used to pump the pump down plug to the liner

wiper plug. As the pump down plug get close to the running tool, fluid pressure may be reduced, e.g. to about 500 psi, and this pressure will increase when the

pump down plug lands in the liner wiper plug, as discussed above.

Once the pump down plug is latched into the liner wiper plug, the work

string can be pressured up and after a selected period of time, the liner wiper

plug and the pump down plug will be released from the plug holder sub.

Increased fluid pressure thus moves a piston to release a lock ring, which

releases the liner wiper plug from the plug holder sub.

The piston within the plug holder sub preferably acts on a fluid with a

known viscosity at the downhole temperature of the plug holder sub. Fluid flow

through a predetermined size orifice will take a predetermined period of time to

release the liner wiper plug. This time may be used by the operator to positively

calculate displacement fluid volumes. A calculated amount of displacement fluid

will thus force the cement to the desired height in the annulus between the liner

and the casing. Fluid will thus be pumped until the liner wiper plug and the pump

down plug set latches into the landing collar, at which time pressure may be

increased to, e.g. 1000 psi, over circulating pressure to complete latching of

plugs and check that the seals between the plugs and the landing collar are

holding. Pressure may then be bleed off and checked for bleed back to ensure

that the float equipment is holding pressure.

Various types of metering jets may be used for selectively metering fluid

from the chamber F132. Significant restrictions can be formed within the

passageway F128 to effectively constitute a metering jet. Fluid in the chamber F132 will be at a known viscosity for the downhole conditions, and with a

selectively size metering jet the operator will know with reasonable accuracy the

time it will take for the piston F134 to move from the retaining position to the

release position.

Other forms of retainer members may be used for interconnecting the

tubular body F116 with the liner wiper plug. A preferred retainer member has a

C-shaped configuration with internal grooves or teeth for attaching to the liner

wiper plug. The internal surface of the piston F134 thus prevents the retainer

member from moving to the released position until the piston moves axially to its

release position, as shown on the right side of Figure F1.

As discussed above, the liner wiper plug may be used at the lower end of

the liner hanger running tool. The plug holder sub of the present invention may

be used more generally at the lower end of any conveyance tubular, such as

conveyance tubular F140 as generally shown in Figure F1. The conveyance

tubular F140 may thus be used to both transmit fluid pressure to the interior of

the plug holder sub, and also to position the plug holder sub at a selected

location within the well. The plug holder sub of the present invention may thus

be used at the lower end of various types of tools, including a liner hanger

running tool, or at the lower end of the tubular string used in a cementing

operation, in order to reliably release the wiper plug from the plug holder sub

during the cementing operation. The wiper plug once released may seal with the

liner or with another downhole tubular. Running Tool

Continuing again with a description of the overall system, conventional

cementing equipment may be used beneath the diverter, including the above

described plugset which forms a barrier to different fluids flowing down the liner.

A pump down plug F182 as shown in Figure F5A may include upwardly facing

cups 183 for cleaning the drill string, so that increased pressure in the running

string when the plug 182 seals with the liner wiper plug 120 releases both plugs

(the set) from the lower end of the liner hanger. The liner wiper plug 180 has

similar cups 181 , and lands on the collar 186 to be sealingly locked in place and

close off the lower end of the casing.

The released running tool 120 may be picked up until the packer setting

assembly 380 (see Figure 1C) is removed from the top of the tie back

receptacle130, whereby the spring pressed lugs 328 are raised to a position

above the top of the tie back receptacle, at which time they expand outwardly.

With the packer setting assembly 380 in its expanded position, weight can be

slacked off by engaging the lugs 328 with the top of the tie back receptacle to

cause the packer element 150 to begin its downward sealing sequence. This

weight also activates a sealing ring 384 between the packer setting assembly

380 and the tie back receptacle to aid in further setting the packer element with

annulus pressure assist. With the packer element 150 in engagement with the

casing, rams on a BOP at the surface may be closed onto the drill pipe to form a

pressure vessel between the rams and the expanded packer. The cross sectional area between the casing and the drill pipe is known and the load

required to fully set the packer element 150 is known, so that the operator may

apply pre-determined fluid pressure to the annulus to cause the tie back

receptacle to move down applying a predetermined additional axial load to the

packer element.

Downward movement of the pusher sleeve 148 to set the packer element

150 will disengage the internal threads 386 (see Figure 6B) of the pusher sleeve

from the tie back receptacle 130. The pusher sleeve 148 thus moves radially

outwardly as the pusher sleeve moves down the cone 152. The pusher sleeve

148 may be split along its circumference in such a manner that in its normal

contracted position, its internal threads 386 would engage the external threads

131 on the tie back receptacle 130. Other types of pusher sleeves may be used.

The mandrel 132 of the released running tool 120 may then be raised to

raise the cementing bushing 160 to cause the lugs 392 on the bushing to move

in and unlock from the liner hanger 110. After pulling the lower end of the

running tool to a predetermined position at the upper end of the liner, the

operator may circulate fluid through the running tool to pump any excess cement

to the surface. Circulation effectively reduces the amount of cement that will

need to be drilled out before reentering the top of the liner, and enables the

operator to check for fluid flow and/or fluid loss.

After the running tool is picked up to a pre-determined position above the

liner top, the operator circulates through the drill string to pump any excess cement to the surface, thus reducing the amount of cement that will need to be

drilled out before reentering the top of the liner. Figure 8A shows the released

running tool 120 raised from the liner. Upon checking for fluid flow and/or fluid

loss, the operator pulls the running tool out of the hole. Once the tool reaches

the surface, the operator may check for damage to the running tool, wash fluids

off the tool, and flush the tool I.D. before returning the tool to the shop. Figure

9C also shows what remains in the casing C, namely the set packer 150 and set

slips 142.

The liner hanger releasing assembly 250 as shown in Figure 1D and 1 E

may be replaced with the releasing assembly shown in Figures 10 and 11. The

liner hanger releasing assembly as shown in Figures 10 and 11 may still be

disposed beneath the packer setting assembly 380 as described above or the

packer setting assembly 52 described below, and includes an inner piston sleeve

340 sealably disposed about the running tool mandrel 132, and another piston

sleeve 342 disposed about the inner piston sleeve. The piston sleeve 340 forms

a pressure chamber similar to the sleeve 252 shown in Figure 1D for releasing

the liner hanger. The liner hanger releasing assembly as shown in Figures 10

and 11 releases the lock ring 326 which is externally grooved for engaging the

grooved inner diameter of the liner hanger 110 of the upper end of the liner 146.

The lock ring 326 is held in locking position by the enlarged upper outer diameter

of the piston sleeve 340 which, as shown in the Figure 10A, is in its lower

position. At this time, the clutch 316 as shown in Figure 1 D is pressed downwardly by springs 318 to engage the liner hanger 110, which is threaded for

engagement with right-handed threads 324 on the running tool mandrel 132.

The nut 322 carries lugs 326 which are pressed outwardly by springs 327 into

vertical slots formed in the liner hanger 110 to prevent relative rotation between

the mandrel 132 and the liner hanger.

Upon raising of the inner piston 340, the lock ring 326 is free to contract

inwardly about the lower reduced outer diameter 268 of the piston sleeve 340

and thereby free the running tool to be raised after setting of the slips but prior to

setting of the packer, thus permitting circulation of cement downwardly through

the tool and upwardly within the annulus between the tool and casing.

In the event the lock ring 326 is not released for any reason, such as

frictional engagement between the I.D. of the lock ring 326 and the O.D. of

piston 340 (see Figure 11 A), the operator has the option of releasing the running

tool mechanically, as shown in Figure 11. As shown in Figure 11C, lowering of

the ball 240 to open the port 260 in the running tool mandrel will permit pressure

fluid to pass through the port 262 in the inner piston 340 to act upon the outer

piston 342 and cause the outer piston to be moved upwardly upon shearing of

the pin 358 (see Figure 11A) between the inner and outer pistons. This permits

the outer piston 342, which is connected to the clutch 316 by a shear pin 360, to

raise the clutch 316 and to de-clutch it from the liner hanger.

Once the clutch 316 is disengaged, the operator may rotate the tool to the

right so that with the right-hand threads between the threaded nut 322 and the running tool mandrel 132 lower the nut on the mandrel 132, as shown in Figure

11C. Once the threaded nut 322 is lowered, the running tool may be picked up

the distance the nut 322 moved down, thereby releasing the lock ring 326 and

thus disengaging the running tool from the liner hanger. As shown in the Figure

11 D, the locking ring 326 has collapsed on the reduced O.D. 341 of the inner

piston 340.

The running tool 120 may thus be lowered to engage its clutch with that of

the liner hanger. The clutch 316 is pressed downwardly by the spring 318, so

that the lower teeth 317 (see Figure 8C) at the upper end of liner hanger 110 are

engaged with similar teeth at the lower end of clutch 316 to maintain rotary

engagement between the running tool and the liner hanger. As shown in Figure

1 D, the upper end 332 of the clutch 316 may be splined to the O.D. of the

running tool mandrel 132 so as to permit relative axial movement with respect

thereto under the urging of the spring 318. When the clutch 316 is engaged,

rotation of the work string rotates the liner hanger. When the clutch is

disengaged, rotation of the work string rotates the running tool mandrel 132 to

move nut 322 with respect to thread 324, as described below.

Figures 11A-C accordingly illustrates a liner hanger release assembly

which enables the operator to release mechanically by right-hand rotation, in the

event he is unable to release hydraulically. As shown in Figure 11A and 11B,

the running tool mandrel 132 is surrounded by the pair of inner and outer sleeve

pistons 340 and 342. The inner piston 340 has a shoulder 272 for engaging shoulder 274 of the running tool mandrel 132. Intermediate seal rings above and

below ports 260 are uncovered upon lowering of the ball 240 on the ball seat 246

to the lower position, as shown in Figure 11C. Outer sleeve piston 342

surrounds the inner piston 340 and, while in the position as shown in Figure 11 A,

is supported on the inner piston 340 by engaging an outer shoulder 348 on the

inner piston with the generally opposite shoulder on the outer piston 342. More

particularly, this shoulder 348 is generally aligned with the port 262 in the inner

sleeve 340 and intermediate the upper and lower seal rings 346 between the

inner and outer sleeves. A ring 350 forms a stop shoulder at the upper end of

the inner piston 340 to limit upward movement of the outer piston 342 with

respect to the inner piston. The inner piston 340 is stopped in a upward direction

by a downwardly facing shoulder 344 on the running tool.

In the initial position of the assembly as shown in Figure 11 A, prior to

lowering of the lower ball seat 246 and opening of the port 260 from the bore of

the running tool, the lock ring 326 is held in a locked position between an

enlarged diameter portion of the inner piston 340 and the inner diameter of the

liner hanger 110. The nut 322 as shown in Figure 11B is positioned below

reduced diameter portion 341 of the inner piston 340, with the internal threads

352 engaged with the threads 324 about the running tool mandrel 132. As in the

case of the previously described embodiment, the threaded nut 322 is prevented

from rotation relative to the liner hanger assembly by spring pressed lugs 326 in

vertical slots in the liner hanger 110. If the running tool is not hydraulically released by opening of the ports 260 to raise the inner piston 340 and release

the lock ring 326, the running tool may be mechanically released by a second

hydraulic release operation, as discussed above.

If the operator wishes to rotate the liner while cementing, higher fluid

pressure is then applied to the outer piston 342 to shear pins 360 between the

outer piston 342 and clutch 316, at which time the spring 318 will re-engage the

clutch. The operator may then rotate the running tool mandrel 132, thereby

rotating the liner hanger. Additional fluid pressure may then be applied to the

ball 240 to force it through the reduced thinner diameter of the seat 246.

Figure 12 Packoff Bushing

Referring now to Figure 12A, a preferred embodiment of a packoff

bushing 10 is depicted for sealing between a radially outward liner running

adapter of the liner hanger and a radially inward running tool mandrel. The

packoff bushing 10 is axially captured on the running tool mandrel or tubular

body 12. The compact design of the packoff bushing and its limited axial

movement on the running tool body 12 facilitates re-stabbing the packoff bushing

into the liner hanger, as explained below. The upper end 14 of body 12 includes

threads 16 and seal 18 for sealed engagement with the lower end of the liner

hanger releasing assembly of the running tool. The lower end 20 of the body 12

includes similar threads 22 for interconnection with a sleeve which extends

downward to a ball diverter. The body or sub 12 is thus part of the mandrel of

the running tool, and a slick joint is not required. As shown in Figure 12A, an internal seal 24 and an external seal 28 are

provided on the locking piston 26. Seal 24, which may be a V-packing seal, thus

seals between the locking piston 26 and the body 12 and seal 28, which may

also be a V-packing seal, seals between the piston 26 and the running adapter

of the liner hanger 48. Retainer 30 is threadably connected to the piston 26 for

holding the seals 24 and 28 in place.

Retaining member 32 is threadably connected to top cap 34 so that the

one-piece C-ring 36 is positioned between the top cap 34 and the piston 26.

Retaining member 32 includes a shoulder 38 for engaging shoulder 40 on the

body 12. The lower flange portion 33 of the retaining member 32 and the upper

end 27 of the piston 26 are each splined, so that the spline fingers are

circumferentially interlaced about the packoff bushing. Flange portions 33 thus

capture the lock ring 36 axially when the piston 26 is forced upward. The lock

ring 36 is a unitary C-shaped ring having a circumference in excess of 200°, and

normally less than about 350°, and is intended for engaging and axially locking

to the liner hanger. A preferred lock ring 36 may have a circumference of from

300° to 340°, thereby providing substantially full circumferential contact with the

liner hanger while allowing for radial expansion and contraction of the lock ring.

The relaxed diameter of the lock ring 36 is substantially as shown in Figure 12A.

The packing retainer 30 is normally spaced axially a slight distance above the

stop surface 44 on the body 12 for locking and unlocking the bushing.

When fluid is pumped downward through the liner hanger running tool, the lower end of the piston 26 is exposed to high pressure, which moves the piston

26 away from stop surface 44, as shown in Figure 12A, so that the lock surface

46 on the end of the piston 26 retains the C-ring 36 radially outward and into

locking engagement with the liner hanger to axially lock the packoff bushing to

the liner hanger. The lock ring 36 thus prevents the packoff bushing from

moving axially when pressure is increased during the cementing operation, while

the seals 24 and 28 maintain fluid integrity between the running tool and the liner hanger.

Since the top cap 34 is axially secured to the body 12, the load shoulder

44 on the top cap 34 provides a means for transmitting forces downward to the

liner hanger during the running-in and cementing operation. Shoulder 44 would

thus engage shoulder 45 on the running adapter 48 of the liner hanger when a

set down weight is applied to the liner hanger so that the liner hanger is "hung

off". A bearing 46 may be provided to allow the running tool body 12 to rotate

relative to a set packoff bushing during an emergency releasing operation. The

packoff bushing may thus be reliably maintained in the locked position, with the

piston 26 up and the C-ring 36 expanded, as shown in Figure 12A, when fluid

pressure is applied to the packoff bushing. Those skilled in the art should

appreciate that engagement shoulders 38 and 40 allow the packoff bushing

assembly 10 to be retrieved with the running tool to the surface after the

cementing operation. Retrievable packoff bushing 10 as shown in Figure 12A

thus replaces the bushing shown in Figure 1. Use of the C-ring 36 rather than circumferentially spaced dogs allows high

cementing pressure forces to be applied to the packoff bushing without "pumping

out" the packoff bushing. As shown, in Figure 12A, an annular groove 47 in the

running adapter 48 of the liner hanger receives the lock ring 36 to securely lock

the packoff bushing to the liner hanger when fluid pressure is applied to the

piston 26. Without fluid pressure, the C-ring 36 thus retracts radially inward

toward the retaining member 32 when the lock ring 36 engages the top surface

of the groove 47 as the bushing is pulled out of the liner hanger. When the

bushing is re-stabbed into the liner hanger, the C-ring 36 is retracted radially

inward, e.g., when the lock ring 36 engages load shoulder 45 on the liner

hanger. During upward movement of the running tool relative to the liner hanger,

the C-ring 36 thus may move radially inward when engaged, and may also move

radially inward when the packoff bushing is re-stabbed back into the liner hanger.

The C-ring design significantly increases reliability of the tool according to the

present invention, and reduces both the complexity and the costs of prior art

tools which use multiple lugs or dogs. Figure 12B illustrates the splined

members 27 of the piston 26 and the splined members 33 of the retaining

member 32, and the C shape of the lock ring 36. External slots 37

circumferentially spaced about the C-ring 36 facilitate expansion and contraction

of the C-ring.

The liner hanger running tool with the packoff bushing disclosed herein

may be used on various types of liner hanger operations. The packoff bushing may be used with or without a packer setting assembly and a packer element for

sealing between the liner hanger and the casing. Although the packoff bushing

as disclosed herein is positioned axially between the liner hanger releasing

assembly and the slip setting assembly, the packoff bushing could be provided

at other locations in the liner hanger running tool.

Figure 13 Packer Setting Assembly

Figure 13 illustrates a preferred embodiment of a packer setting assembly

52, which will allow activation and packoff of the liner top packer. The packer

setting assembly is provided on the sleeve shaped body or sub 54 which is part

of the mandrel of the running tool, and includes lower threads 55 for engagement

with a lower sub of the mandrel. The packer setting assembly 52 includes a

housing 56 carrying a V packing seal 58. Other conventional elastomeric seals

may replace the V packing 58. A flow slot 53 in the body 54 ensures fluid

communication with the splines or ribs 57 on the body 54, so that the housing 56

moves axially along these splines without trapping fluid pressure. Packing

retainer 60 and snap ring 62 hold the V packing in place. A packer setting or

force transmitting C-ring 64 is positioned on the housing 56, and includes an

internal sleeve portion 66. A C-shaped trip ring or lockout ring 70 is positioned

between the lock sleeve 68 and retainer cap 72. Lock sleeve 68 engages the

sleeve portion 66 to retain the C-ring 64 in the compressed position as shown in

Figure 13, so that when released the C-ring 64 will snap out. A housing

extension 74 is threadably secured to housing 56, and bearing 80 allows the body 54 to rotate relative to housing 56. Bearing sleeve 78 is connected to the

sub 54 by shear member 82. Sleeve portion 84 of the bearing sleeve 78

engages the body 54 as shown in Figure 13, although sealing between the body

54 and the bearing sleeve 78 is not required. Packing members 86 on the body

54 are discussed below.

The first time the packer setting assembly is moved out of the polished

bore receptacle 90 (which is the same as the receptacle 130 discussed in the

Fig. 1-9 running tool), trip ring 70, which was positioned within the polished bore

receptacle, will snap to a radially outward position, as shown in Figure 13, due to

the natural biasing of the C-shaped trip ring. When the packer setting assembly

is subsequently reinserted into the polished bore receptacle, the trip ring 70 will

engage the top of the polished bore receptacle 90 as shown in Figure 13, and

the packer setting C-ring 64 is positioned within the polished bore receptacle.

When set down force is applied, housing 56 will move downward relative to lock

sleeve 68, and the trip ring 70 will move radially inward due to camming action.

The entire packer setting assembly may thus be lowered to bottom out on a

lower portion of the running adapter prior to initiating the cementing operation.

The next time the packer setting assembly is raised out of the polished bore

receptacle, the radially outward biasing force of the C-ring 64 will cause the C-

ring to engage the top of the polished bore receptacle of the liner hanger. More

particularly, the shoulder 65 will engage the top of the polished bore receptacle

90, since the natural or released diameter of the C-ring 64 approximates the outer diameter of the receptacle 90. The flat surface 65 on the C-ring 64 thus

engages the top surface of the tie back receptacle 90. In this position, the

tapered surface 73 at the lower end of retainer cap 72 engages the mating

tapered surface 63 of the upper end of C-ring 64, and the setting weight thus

results in a radially outward force applied to the C-ring 64 to effectively lock the

C-ring in the weight-transfer position, so that the C-ring will not prematurely snap

radially inward before the packer is set. Once the C-ring 64 is set against the

liner hanger, the body 54 may be moved downward relative to the housing 56,

thereby shearing members 82 .

The packer setting assembly 52 has high reliability since a substantial

downward set weight may be transmitted through the C-ring 64 to the tie back

receptacle, and since the mechanical setting pressure is assisted by fluid

pressure between the ID of the casing and the OD of the running tool or drill

pipe. After members 82 shear and body 54 moves downward relative to housing

56, the radially inward surface of projection 88 on the housing 56 is then

supported on the larger diameter surface 90 of the sub 54, with packing

members 86 sealing with the housing 56. A collar or similar stop on the body 54

engages the top of bearing sleeve 78 to limit downward travel of the mandrel.

Seal 58 remains sealed to the tie back receptacle. After the packer setting

assembly 52 is set, the increase in pressure in the annulus between the casing

and the running tool allows the housing 56 to act as a piston which is forced

downward in response to the annulus pressure, thereby providing increased downward force to reliably set the liner hanger packer when the packer is forced

radially outward as it is pushed down the packer setting cone.

A complete running procedure for running, setting, and releasing the liner

hanger system according to the present invention will now be discussed. The

setting tool is conventionally attached to the lower end of a work string, typically

a drill pipe, and is releasably connected to a liner hanger, which is attached to

the top of the liner. The work string lowers the liner into the borehole into a

position above the lower end of the previously set casing or liner. With the liner

at a desired depth, well bore fluids are circulated "bottoms up" to clean the hole.

A setting ball may initially be dropped from a cementing manifold at the surface.

The ball may either free fall or may be pumped to the liner hanger slip setting

assembly, where the ball will rest on the expandable ball seat. Fluid pressure

may then be increased to a selected value, e.g. 500 psi, which exerts a force on

the shear screws acting between the ball seat and the mandrel of the slip setting

assembly. When this force surpasses the design limits, the screws will shear to

release the ball and seat to a position that uncovers hydraulic ports in the

mandrel. Continued pumping of fluid will then force the ball through the seat,

and allow the ball to be pumped to the second ball seat within the releasing tool.

Fluid pressure is then increased to shear screws between the piston and

the mandrel of the liner hanger setting assembly. The piston, which was

exposed to pressure within the running string when the ball was first released, is

responsive to fluid pressure and travels upward, thereby forcing the slips to release and come into contact with the casing. The liner load may then be

slacked off onto the set slips. Once the slips are supporting the weight of the

liner, the liner is "hung off".

With the liner load slacked off onto the hanger slips, additional slack off or

"set down weight" may be applied to the hanger to check for any hanger

movement. The set down weight will be transmitted through the running tool to

the liner hanger, which is supported by the liner hanger slips. This set down

weight may, for example, be transmitted through the running tool mandrel to the

packoff bushing and then from the load shoulder on the packoff bushing to the

liner hanger. A ball may then be landed, and the ball seat moved to expose

fluid ports. Pressure may then be increased to a selected value, e.g. 1200 psi,

which is transmitted through ports in the mandrel of the liner hanger releasing

assembly. This increased pressure shears screws on the primary piston,

thereby moving the piston to allow the liner hanger release ring to collapse and

disengage the running ring from the liner hanger. At this stage, the liner hanger

running tool is free from the liner hanger. Since the clutch that keys the running

tool to the liner hanger is shear pinned to the releasing piston, it moves from the

clutched position to an unclutched position as the piston moves up to release the

running ring. The running tool is preferably released by the increase in fluid

pressure acting on the primary piston. If the running tool is still engaged to the

liner hanger after pressuring up on the primary releasing piston, the operator

may continue to pressure the drill sting to the maximum allowable pressure checking for release in small pressure increments up to the shear pressure of the

secondary piston. If the primary piston does not release the running tool from

the liner hanger, continued pressure will shear the secondary piston from the

primary piston and the secondary piston will move axially up to disengage the

clutch of the running tool from the clutch on the liner hanger. With the clutch

disengaged, the running tool may be rotated 5-6 turns to the right to disengage

the running tool from the liner hanger.

The operator at this stage may pick up the running string and note the

loss of liner weight on a rig weight indicator, thereby indicating that the running

tool is released from the liner hanger. This pick up operation will also disengage

the packoff bushing from the liner hanger running adapter or tie back receptacle.

As previously indicated, the packoff bushing is designed to be re-stabbable so

that the operator may pull the running tool and the packoff bushing upward as

desired to check that the running tool is released from the liner hanger. After it is

confirmed that the running tool is released, the packoff bushing will be re¬

stabbed when the running tool is slacked back off into the liner hanger. When

there is pressure below the packoff bushing, the bushing is securely locked to

the liner hanger.

A selected fluid pressure, e.g. 2500 psi, may then be used to shear the

secondary piston from the clutch to allow the clutch to re-engage the liner

hanger. Once the liner hanger running tool is released from the liner, pressure

may then be applied to the ball and seat. At a predetermined pressure, e.g. 3000 psi, the ball will pass through the port isolation ball seat, expanding the

diameter of the seat. The ball is forced through the seat to permanently

deforming the ball seat. The drop in pressure and re-gaining fluid circulation will

then indicate that the ball has successfully passed through the ball seat. The

ball is then allowed to free fall or be pumped to the ball diverter.

The spacer and cement fluids may be mixed while circulating fluids for

cement displacement. When the cement has been pumped, the pump down

plug may be released from the surface, forming a barrier between the previously

displaced cement and the displacement fluid. A calculated amount of

displacement fluid may thus be used to pump the pump down plug to the liner

wiper plug. As the pump down plug get close to the running tool, fluid pressure

may be reduced, e.g. to about 500 psi, and this pressure will increase when the

pump down plug latches in the liner wiper plug. Once the pump down plug is

latched into the liner wiper plug, the work string can be pressured up and after a

selected period of time, the liner wiper plug and the pump down plug will be

released from the plug holder sub. Increased fluid pressure thus moves a piston

to release a ring, which releases the liner wiper plug from the plug holder sub.

The piston within the plug holder sub acts on a fluid with a known viscosity, and

fluid flow through a predetermined size orifice will take a predetermined period of

time to release the liner wiper plug. This time may be used by the operator to

positively calculate displacement fluid volumes. A calculated amount of

displacement fluid will thus force the cement to the desired height in the annulus between the liner and the casing. Fluid will thus be pumped until the liner wiper

plug and the pump down plug set latches into the landing collar, at which time

pressure may be increased to, e.g. 1000 psi, over circulating pressure to

complete latching of plugs and check that the seals between the plugs and the

landing collar are holding. Pressure may then be bleed off and checked for

bleed back to ensure that the float equipment is holding pressure.

It should be remembered that the packer setting assembly incorporates

an unlocking feature that allows the packer setting assembly to be pulled out of

the liner hanger tie back receptacle one time without unlocking the packer setting

ring. Upon re-stabbing the assembly into the tie back receptacle, the packer

setting ring becomes armed and is ready to expand the second time the packer

setting assembly is pulled out of the tie back receptacle. Accordingly, the

running tool may be picked up until the packer setting assembly is removed from

the tie back receptacle, which allows the trip ring to expand and engage the top

of the tie back receptacle. Slacking off on the running string collapses the trip

ring so that it may reenter the tie back receptacle, and moves a locking sleeve

out of contact with packer setting ring. Since the C-shaped packer setting ring is

compressed but is now released from the locking sleeve, the packer setting

assembly is ready to be activated the next time it is pulled from the tie back

receptacle. Accordingly, the running tool may be picked up sufficiently to expose

the packer setting assembly, then set down weight used to set the packer

element. Once the packer setting ring is in its expanded position, drill pipe weight

may be slacked off on top of the tie back receptacle. This downward force

through the packer setting assembly and to the tie back receptacle initiates the

packer setting sequence. This action will shear screws and allow the setting

load to be transmitted to the packing element. As a load increases, the packer

element will expand in OD as it moves down the cone, thereby pushing the

expanding packer element out into engagement with the casing.

With the packer element in engagement with the casing, the rig rams may

be closed around the drill pipe, so that a pressure vessel is formed between the

casing and the running tool and between the packer element and the seals of the

ram at the surface. Knowing how much load is required to properly set the

packer element, a known fluid pressure can be applied to the annulus to cause

the tie back receptacle to move down, thereby applying a greater and known

load to the packer element. A desired setting load to the packer element may

thus be applied through a combination of set down weight and fluid pressure.

After pulling the setting tool to a predetermined position above the top of

the liner, fluid may be circulated through the drill string to circulate any excess

cement to the surface, thereby reducing the need for drill out. Once the excess

cement has been circulated out of the well, the operator may pull the setting tool

from the well. Once at the surface, the tool may be checked for damage and

serviced.

The tools as discussed above function as an assembly for a specific application, i.e., for the running and releasing of the liner hanger, the cementing

of the liner into the wellbore and the setting of the packer element. One could

run a liner hanger without a packer element and therefore the running tool would

not require the packer setting assembly. Also, a packer element could be run

into a wellbore without a liner hanger slip mechanism and therefore the slip

releasing assembly would not be required in the running tool. Various

combinations of the disclosed tools could be put together to run a variety of

downhole tools.

While preferred embodiments of the present invention have been

illustrated in detail, it is apparent that modifications and adaptations of the

preferred embodiments will occur to those skilled in the art. However, it is to be

expressly understood that such modifications and adaptations are within the

spirit and scope of the present invention as set forth in the following claims.

Claims

What is claimed is:

1. A tool for suspending from a running string to position a liner

hanger in a casing within a wellbore, suspending a liner from the liner hanger

and retrieving portions of the tool, comprising:

the tool mandrel supported from the running string;

a slip setting assembly about the mandrel for setting slips to engage the

casing and suspend the liner hanger from the casing; and

a releasing assembly for releasing from the set liner hanger portions of

the tool to be retrieved to the surface, the releasing assembly including a

connecting member for engaging the tool with the liner hanger, a first piston

hydraulically moveable in response to fluid pressure within the tool mandrel from

a lock position to a release position for releasing the connecting member, a

clutch for rotationally connecting the tool mandrel with the liner hanger, and a

second piston moveable in response to fluid pressure within the tool mandrel for

disengaging the clutch, such that right-hand rotation of the running string moves

the nut downward along the mandrel so that the running string may then be

picked up to disengage the tool from the liner hanger.

2. The tool as defined in Claim 1 , further comprising:

a piston shear member for interconnecting the first piston and the second

piston, such that the second piston may be disconnected from the first piston in

response to fluid pressure within the tool mandrel.

3. The tool as defined in Claim 1 , further comprising:

a clutch shear member for interconnecting the second piston and the

clutch, such that shearing the clutch shear member reengages the clutch with

the liner hanger to permit rotation of the set liner hanger with the running string.

4. The tool as defined in Claim 1 , further comprising:

a port in the tool mandrel for fluid communication with the first piston; and

a sleeve for blocking the port, such that the increase in fluid pressure

when a ball lands on a seat shifts the sleeve downward to open the port.

5. The tool as defined in Claim 1 , wherein the engaging member is a

radially collapsible C-ring.

6. The tool as defined in Claim 5, wherein the C-ring includes external

threads for engagement with internal threads on the liner hanger to secure the

tool to the liner hanger.

7. The tool as defined in Claim 1 , further comprising:

a plurality of dogs carried by the nut for fitting within slots in the liner

hanger to rotationally lock the nut to the liner hanger.

8. The tool as defined in Claim 1 , further comprising:

a flow-through port in the first piston, such that fluid pressure within the

mandrel passes through the flow-through port to act upon the second piston.

9. The tool as defined in Claim 1 , further comprising:

a stop on the first piston for limiting travel of the second piston.

10. The tool as defined in Claim 1 , wherein the first piston is a radially

inner piston for sealing with the tool mandrel, and the second piston is a radially

outer piston for sealing with the inner piston.

11. A tool for suspending from a running string to position a liner

hanger is a casing within a wellbore, suspending a liner from the liner hanger in

place and retrieving portions of the tool, comprising:

a tool mandrel supported from the running string;

a slip setting assembly about the mandrel for setting slips to engage the

casing and suspend the liner hanger from the casing;

a releasing assembly about the tool mandrel for releasing the liner hanger

from the portions of the tool to be retrieved to the surface; and

a packoff bushing for sealing between the liner hanger and the tool

mandrel, including a radially moveable locking member and a fluid pressure

responsive piston moveable in response to fluid pressure within the tool mandrel between a release position whereby the packoff bushing may be removed from

the liner hanger and reinserted into the liner hanger, and a lock position for

retaining the locking member in a groove in the liner hanger to lock the packoff

bushing to the liner hanger.

12. The tool as defined in Claim 11 , wherein the radially moveable

locking member comprises a C-shaped lock ring.

13. The tool as defined in Claim 12, wherein the C-shaped lock ring

includes radially external slots for facilitating expansion and contraction of the

lock ring.

14. The tool as defined in Claim 12, wherein the C-shaped lock ring

has a circumference from 200°- 350°.

15. The tool as define in Claim 12, wherein the lock ring retracts when

engaging a shoulder on the liner hanger, thereby allowing the lock ring to be

reinserted into the liner hanger after being raised above the liner hanger.

16. The tool as defined as Claim 11 , wherein the piston is axially

moveable with respect to the tool mandrel to move the locking member to the

lock position in response to fluid pressure within the tool mandrel.

17. The tool as defined in Claim 11 , wherein the packoff bushing

comprises:

a radially internal seal for sealing between the piston and the mandrel;

and

a radially external seal for sealing between the piston and the liner hanger.

18. The tool as defined in Claim 11 , wherein the packoff bushing

includes a radially outer shoulder for engaging a radially inner shoulder on the

liner hanger for applying set down weight to the liner hanger.

19. The tool as defined in Claim 11 , wherein the packoff bushing

includes a radially inner shoulder, and the tool mandrel includes a radially outer

shoulder, such that the engagement of the inner shoulder and outer shoulder

allow the packoff bushing to be retrieved with the retrieving portions of the tool.

20. The tool as defined in Claim 11 , further comprising:

a packer setting assembly about the tool mandrel for setting a packer to

seal between the casing and the liner hanger.

21. A packer setting assembly for setting a radial set packer element, the packer setting assembly applying a force on one of the packer element and a

cone to move the packer element relative to the cone, the packer setting

assembly comprising:

a radially expandable force transmitting C-ring, the force transmitting C-

ring when expanded acting to engage a setting sleeve for applying a set-down

weight through the setting sleeve to set the radial set packer element.

22. The packer setting assembly as defined in Claim 21 , further

comprising:

a lockout mechanism for preventing the force transmitting C-ring from

moving to the expanded position.

23. The packer setting assembly as defined in Claim 22, wherein the

lockout mechanism includes a lockout C-ring for radially expanding to engage

the top of the liner and thereby disengage the lockout mechanism.

24. The packer setting assembly as defined in Claim 22, further

comprising:

the lockout mechanism moves from an expanded position to a retracted

position due to a camming surface on a housing of the packer setting assembly,

thereby releasing the force transmitting C-ring.

25. The packer setting assembly as defined in Claim 22, wherein the

lockout mechanism moves axially to release the force transmitting C-ring.

26. The packer setting assembly as defined in Claim 21 , further

comprising:

a lock-out mechanism for allowing the force transmitting C-ring to be

raised out of the top of a liner hanger one time without moving the force

transmitting C-ring to the expanded position, such that the next time the force

transmitting C-ring is moved out of the liner hanger, the force transmitting C-ring

expands to its expanded position for engagement with the liner hanger.

27. The packer setting assembly as defined in Claim 21 , further

comprising:

a packer setting housing;

an I.D. seal for sealing between a packer mandrel and the packer setting

housing; and

an O.D. seal for sealing with between the setting sleeve and the packer

setting housing, such that fluid pressure may be used to assist in applying a

setting force through to the setting sleeve to the packer element.

28. The packer setting assembly as defined in Claim 21 , further

comprising: a packer setting housing about a mandrel; and

a bearing for facilitating rotation of the mandrel relative to the housing.

29. The packer setting assembly as defined in Claim 21 , wherein the

radial set packer element includes a metal radially inward base and one or more

radially outer seal bodies.

30. The packer setting assembly as defined in Claim 21 , wherein the

setting sleeve acts on the packer element of a liner hanger to seal between the

liner hanger and a casing.

31. A method of releasing a running tool while supported on a running

string from a liner hanger in a casing within a wellbore, the liner hanger being

secured to a casing by a slip assembly to suspend the liner hanger from the

casing, the method comprising:

providing a releasing assembly about a tool mandrel, the releasing

assembly including a connecting member for engaging the running string with

the liner hanger, a first piston hydraulically moveable in response to fluid

pressure within the tool mandrel from a lock position to a release position for

releasing the connecting member, a clutch for rotationally connecting the tool

mandrel with the liner hanger, and a second piston moveable in response to fluid

pressure within the tool mandrel for disengaging the clutch; and pressurizing the running string to move the first piston to the release

position for releasing the running string.

32. The method as defined in Claim 31 , further comprising:

pressurizing the running string to move the second piston to disengage

the clutch;

rotating the running string to move a nut downward along the tool

mandrel; and

thereafter picking up the running string to disengage the running tool from

the liner hanger.

33. The method as defined in Claim 31 , further comprising:

shearably interconnecting the first piston and the second piston, such that

the second piston may be disconnected from the first piston in response to fluid

pressure within the tool mandrel.

34. The method as defined in Claim 31 , further comprising:

shearably interconnecting the second piston and the clutch, such that

shearing the clutch shear member re-engages the clutch to permit rotation of the

liner hanger with the running string.

35. The method as defined in Claim 31 , further comprising:

providing a port in the tool mandrel for fluid communication with the first piston; and

blocking the port with a sleeve, such that the increase in fluid pressure

when a ball lands on a seat shifts the sleeve downward to open the port.

36. The method as defined in Claim 31 , wherein the engaging member

is formed to be a radially collapsible C-ring.

37. The method as defined in Claim 31 , further comprising:

providing a plurality of dogs carried by the nut for fitting within slots in the

liner hanger to rotationally lock the nut to the liner hanger.

38. The method as defined in Claim 31 , further comprising:

providing a flow-through port in the first piston, such that fluid pressure

within the tool mandrel passes through the flow-through port to act upon the

second piston.

39. The method as defined in Claim 31 , further comprising:

providing a stop on the first piston for limiting travel of the second piston.

40. The method as defined in Claim 31 , wherein the first piston is a radially inner piston for sealing with the tool mandrel, and the second piston is a

radially outer piston for sealing with the inner piston.

41. A method of sealing between a liner hanger suspended in a casing

within a wellbore and supporting a tool mandrel from a running string, the

method comprising:

providing a packoff bushing for sealing between the liner hanger and the

tool mandrel, the packoff bushing including a radially moveable locking member

and a fluid pressure responsive piston;

moving the piston in response to fluid pressure within the tool mandrel

between a release position whereby the packoff bushing may be removed from

the liner hanger and reinserted into the liner hanger, and a lock position for

retaining the locking member in a groove in the liner hanger to lock the packoff

bushing to the liner hanger.

42. The method as defined in Claim 41 , further comprising:

forming the radially moveable locking member to have a C-shaped lock

ring configuration.

43. The method as define in Claim 41 , wherein the lock ring retracts

when engaging a shoulder on the liner hanger, thereby allowing the lock ring to

be reinserted into the liner hanger after being raised above the liner hanger.

44. The method as defined as Claim 41 , wherein the piston is axially

moveable with respect to the tool mandrel to move the locking member to the

lock position in response to fluid pressure within the tool mandrel.

45. The method as defined in Claim 41 , further comprising:

providing a radially internal seal for sealing between the piston and the

mandrel; and

providing a radially external seal for sealing between the piston and the

liner hanger.

46. The method as defined in Claim 41 , further comprising:

providing a radially outer shoulder on the packoff bushing for engaging a

radially inner shoulder on the liner hanger when the locking member is aligned

with the groove in the liner hanger for applying set down weight through the

radially outer shoulder to the liner hanger.

47. The method as defined in Claim 41 , further comprising:

providing a radially inner shoulder on the packoff bushing;

providing a radially outer shoulder on the tool mandrel; and

engaging of the inner shoulder and outer shoulder to retrieve the packoff

bushing to the surface.

48. The method as defined in Claim 41 , further comprising;

providing a packer setting assembly about the tool mandrel for setting a

packer to seal between the casing and the liner hanger.

49. A method of setting a radial set packer element by applying a force

on one of the packer element and a cone to move the packer element relative to

the cone, the method comprising:

providing a radially expandable force transmitting C-ring;

expanding the force transmitting C-ring to engage a setting sleeve; and

applying a set-down weight through the setting sleeve to set the radial set

packer element.

50. The method as defined in Claim 49, further comprising:

providing a lockout mechanism for preventing the force transmitting C-ring

from moving to the expanded position.

51. The method as defined in Claim 50, further comprising:

engaging the lock out mechanism with the top of the liner hanger to

release the force transmitting C-ring.

52. The packer setting assembly as defined in Claim 51, further comprising:

providing a C-ring lockout mechanism;

moving the C-ring lockout mechanism from an expanded position to a

retracted position by applying set down weight to the C-ring lockout mechanism

due to a camming surface on a housing of the packer setting assembly, thereby

releasing the force transmitting C ring.

53. The method as defined in Claim 50, wherein the lockout

mechanism moves axially to release the force transmitting C-ring.

54. The method as defined in Claim 49, further comprising:

allowing the force transmitting C-ring to be raised out of the top of a liner

hanger one time without moving the force transmitting C-ring to the expanded

position, such that the next time the force transmitting C-ring is moved out of the

liner hanger, the force transmitting C-ring expands to its expanded position for

engagement with the liner hanger.

55. The method as defined in Claim 50, further comprising:

providing a packer setting housing;

providing an I.D. seal for sealing between a packer mandrel and the

packer setting housing; and

providing an O.D. seal for sealing with between the setting sleeve and the

packer setting housing, such that fluid pressure assists in applying a setting force to the setting sleeve.

56. The method as defined in Claim 49, wherein the radial set packer

element includes a metal radially inward base and one or more radially outer

seal bodies.

57. A retrievable hydraulically operated tool for running in a wellbore to

perform a downhole tool activation, the tool comprising:

a running tool tubular body for suspending in the wellbore from a

conveyance tubular, such that fluid may be circulated through a bore in the

conveyance tubular and in the tubular body, the tubular body including a fluid

inlet port from the bore in the tubular body;

a fluid pressure responsive member in fluid communication with the fluid

inlet port and moveable relative to the tubular body from an initial position to an

activated position in response to fluid pressure within the tubular body;

a port closure member moveable with respect to the tubular body from a

port isolation position to an open port position, the port closure member in the

port isolation position blocking fluid communication from the bore in the tubular

body, and permitting fluid communication from the bore in the tubular body

through the fluid inlet port when in the open port position;

a seat supported on the port closure member, such that an increase in

fluid pressure to the fluid inlet port when a plug lands on the seat shifts the port

closure member from the port isolation position to the open port position in

response to fluid pressure above the landed plug; and a plug release mechanism for releasing the plug after the port closure

member has moved to the open port position.

58. The retrievable tool as defined in Claim 57, wherein the port

closure member comprises a sleeve axially moveable within the bore of the

tubular body.

59. The retrievable tool as defined in Claim 57, wherein the fluid

pressure responsive member includes a piston moveable from the initial position

to the activated position in response to fluid pressure.

60. The retrievable tool as defined in Claim 59, wherein the piston

moves axially upward from the initial position to the actuated position in

response to fluid pressure.

61. The retrievable tool as defined in Claim 53, wherein the plug is a

ball.

62. The retrievable tool as defined in Claim 61 , wherein the ball lands

on the seat to substantially seal off the bore through the tubular body.

63. The retrievable tool as defined in Claim 57, wherein the port

closure member is retained in the port isolation position by a shear member.

64. The retrievable tool as defined in Claim 57, wherein the seat

permanently deforms in response to increased fluid pressure to pass the plug

through the seat.

65. A retrievable liner hanger running tool for running in a wellbore to

perform a downhole tool actuation on a liner hanger, the running tool comprising:

a running tool tubular body for suspending in the wellbore from a

conveyance tubular, such that fluid may be circulated through a bore in the

conveyance tubular and in the tubular body, the tubular body including a fluid

inlet port from the bore in the tubular body;

a piston axially moveable with respect to the tubular body and in fluid

communication with the fluid inlet port, the piston being moveable from an initial

position to an activated position in response to fluid pressure within the tubular

body, axial movement of the piston to the activated position causing one of (a)

axial movement of a slip to set the liner hanger, (b) movement of a release

mechanism to release the liner hanger from the running tool, and (c) relative

movement between a cone and a seal to seal between the liner hanger and

surrounding casing;

a sleeve axially movement with respect to the tubular body from a port

isolation position to an open port position, the sleeve in the port isolation position

blocking fluid communication from the bore in the tubular body, and permitting

fluid communication from the bore in the tubular through the fluid inlet port when

in the open port position; a seat supported on the port closure member, such that an increase in

fluid to the fluid inlet port pressure when a ball lands on the seat shifts the port

closure member from the port isolation position to the open port position in

response to fluid pressure above the landed ball; and

a plug release mechanism for releasing the ball after the port closure

member has moved to the open port position;

66. The running tool as defined in Claim 65, wherein the piston moves

axially upward from the initial position to the actuated piston in response to fluid

pressure.

67. The running tool as defined in Claim 65, wherein the ball lands on

the seat to substantially seal off the bore through the tubular body.

68. The running tool as defined in Claim 65, wherein the sleeve is

retained in the port isolation position by a shear member.

69. The relative tool as defined in Claim 65, wherein the seat

permanently deforms in response to increased fluid pressure to pass the ball

through the seat.

70. A method of hydraulically operating a tool for running in a wellbore

to perform a downhole tool activation, the method comprising: suspending a running tool tubular body in the wellbore from a conveyance

tubular;

providing a fluid inlet port from the bore in the tubular body;

providing a fluid pressure responsive member in fluid communication with

the fluid inlet port and moveable relative to the tubular body from an initial

position to an activated position in response to fluid pressure;

providing a port closure member moveable with respect to the tubular

body from a port isolation position to an open port position, the port closure

member in the port isolation position blocking fluid communication from the bore

in the tubular body, and permitting fluid communication from the bore in the

tubular through the fluid inlet port when in the open port position;

supporting a seat on the port closure member;

landing a plug on the seat to shift the port closure member from the port

isolation position to the open port position in response to fluid pressure above

the landed plug;

performing the downhole tool activation in response to movement of the

fluid pressure responsive member to the activated position; and

releasing the plug after the port closure member has moved to the open

port position.

71. The method as defined in Claim 70, wherein the fluid pressure

responsive member includes a piston moveable from the initial position to the

activated position in response to fluid pressure.

72. The method as defined in Claim 71 , wherein the piston moves

axially upward from the initial position to the actuated position in response to fluid

pressure.

73. The method as defined in Claim 70, wherein the plug is a ball

which lands on the seat to substantially seal off the bore through the tubular

body.

74. The retrievable method as defined in Claim 70, further comprising:

retaining the port closure member in the port isolation position by a shear

member.

75. The method as defined in Claim 70, wherein the seat permanently

deforms in response to increased fluid pressure to pass the plug through the seat.

76. The method as defined in Claim 70, wherein movement of the fluid

pressure responsive member causes one of (a) axial movement of a slip to set

the liner hanger, (b) movement of a release mechanism to release the liner

hanger from the running tool, and (c) relative movement between a cone and a

seal to seal between the liner hanger and surrounding casing.

77. The method as defined in Claim 70, wherein the plug is released after the downhole tool has been activated in response to movement of the fluid

pressure responsive member to the activated position.

78. A ball and plug dropping head adapted to be installed above the

upper end of the liner for use in sequentially dropping one or more balls and

plugs into a liner of a liner hanger system, comprising:

a housing having an inlet adapted to be fluidly connected in line with the

lower end of a top drive, an outlet generally aligned with the inlet and adapted to

be connected to the upper end of a running tool, generally in line with, and

passages extending downwardly within the housing at circumferentially spaced

locations,

each passage having an upper end opening to the side of the inlet and a

lower end connecting with the outlet,

lateral passages in the housing each connecting the inlet with a passage,

a plug removably mounted in the upper end of each passage to permit a

ball or plug to be installed therein, and

valves mounted in the housing each for opening and closing a passage

beneath the lateral passage connecting thereto so as to support ball or plug

when closed and permit the ball or plug to pass therethrough, and circulating

fluid to pass downwardly therethrough when a ball or plug is not in the passage.

79. As in claim 78, wherein each valve is removably mounted in a side

opening in the housing to permit it to be installed and removed from outside of

the housing.

80. A liner hanger system, comprising

a joint of casing adapted to be connected as part of an outer casing

installed within a wellbore,

a liner adapted to be lowered within the outer casing,

the bore of said casing joint having vertically spaced, upwardly facing

landing surfaces formed on an intermediate portion thereof, and a lower annular

recess separated from the lower landing surface by a lower annular restriction,

the said liner including a tubular body having a recess formed thereabout

with an annular groove formed in its lower end,

a hanger comprising a circumferentially expandible and contractible C-ring

disposed within and closely about the hanger recess when in the retracted

portion,

said ring having teeth formed thereabout for landing on the landing

surfaces of the casing joint when in its expanded portion, and a lower end fitting

within the groove when in its retracted portion to permit the liner to be lowered

through the outer casing,

said ring being expandable, upon relative vertical movement with respect

to the liner, so as to release its lower end from the groove and thereby permit the

ring to expand outwardly against the outer casing,

whereby, upon continued relative movement of the liner and ring, the

teeth will move into a position in which they expand outwardly into landed

positions on the landing surfaces to permit the liner to be suspended therefrom,

said liner having a downwardly facing shoulder for landing on the upper end of the expanded ring and an outward enlargement beneath the shoulder to

fit within the upper end of the ring so as to hold the ring expanded.

81. As in claim 80, including

a tie bar guidably reciprocable within the liner recess radially inwardly of

the ring and having its upper end connected to a part surrounding and vertically

moveable with respect to the liner,

said tie bar and ring having radially extending parts which connect the tie

bar to the ring to raise the ring out of the groove and, when the ring is so raised,

are released from one other to permit the liner to be lowered with respect to the

ring,

82. As in claim 81 , wherein

the liner recess has a vertical slot to receive the tie bar and a stop surface

on its lower end to be engaged with the lower end of this tie bar prior to its being

raised to lift the lower end of the ring from the groove in liner recess.

83. As in claim 80, wherein

the bore of the casing joint also has an upper annular recess separated

from the upper landing surface by an upper annular restriction.

84. As in claim 80, wherein

the liner also has a lower outward enlargement thereabout above the groove for disposal within the lower end of the expanded ring.

85. As in claim 80, wherein

the bore of the casing joint has a polished bore above the landing surface.

86. Well apparatus comprising

an elongate member having an outwardly facing frusto conical surface

and adapted to be lowered into and suspended within a wellbore, and

a slip comprising a circumferentially expandible and contractible c-ring

having slip teeth about its outer side and a frusto conical surface on its inner side

disposed about the frusto conical surface of the member so that the c-ring may

be moved vertically between a contracted position in which the teeth are spaced

from the wellbore and an expanded portion in which the teeth engage the wellbore,

the member also having a recess to receive an end of the c-ring to retain

the c-ring contracted about the member, as it is lowered, whereby, upon

removal of the one end from the recess, the c-ring is free to expand toward its

fully expanded position to cause its slip teeth to grip the wellbore, so that the

weight of the member may be hung from the casing upon relative vertical

movement of the conical surfaces of the c-ring and member.

87. As in claim 86, wherein

the frusto conical surface of the member extends downwardly and

inwardly and the frusto conical surface of the c-ring is slidable upwardly over the surface of the member as the member is lowered to cause its teeth to move

outwardly to engage the wellbore.

88. Well apparatus as defined in claim 86, including

a part carried by the member for guided reciprocation with respect thereto

and engageable with the end of the c-ring or in order to remove the end of the c-

ring from the recess and thus release it for expansion.

89. As in claim 88, wherein

the part for releasing the c-slip comprises a tie bar extending guidably

within the member, with the c-ring and the tie bar have interfitting parts, when the

end of the c-ring is in the recess, so as to permit the c-slip to be removed from

the recess by the tie bar and then released therefrom to permit the c-ring to

expand into engagement with the bore of the casing.

90. A tool for use in a subterranean well to seal with a generally

cylindrical interior surface of a tubular or another downhole tool, the tool

comprising:

a conveyance tubular for positioning the tool at a selected location below

the surface of the well;

an annular seal assembly disposed about the conveyance tubular, the

seal assembly having a reduced diameter run-in position and an expanded

sealing position;

a wedge ring having a substantially conical outer surface configured to

radially expand the annular seal assembly upon axial movement of the annular

seal assembly relative to the wedge ring such that the seal assembly is expanded from its run-in position to its expanded sealing position wherein the

seal assembly is in sealing engagement with the generally cylindrical interior

surface; and

the annular seal assembly including a metal framework having a radially

inward annular base and a plurality of metal ribs each extending radially outward

from the base, the metal framework including an upper downwardly angled

primary seal metal rib for sealing pressure below the seal assembly, a lower

upwardly angled primary seal metal rib for sealing pressure above the seal

assembly, a primary elastomeric seal in a cavity radially outward from the base

and axially between the upper primary seal metal rib and the lower primary seal

metal rib, an upper downwardly angled secondary seal metal rib spaced axially

above the upper primary seal metal rib, and a lower upwardly angled secondary

seal metal rib spaced axially below the lower primary seal metal rib.

91. The downhole tool as defined in Claim 90, further comprising:

an upper biasing member between the upper primary seal metal rib and

the upper secondary seal metal rib for exerting a downward biasing force on the

upper primary seal metal rib in response to high fluid pressure below the seal

assembly, and a lower biasing member spaced between the lower primary seal

metal rib and the lower secondary seal metal rib for exerting an upward force on

the lower primary seal metal rib in response to high fluid pressure above the seal

assembly.

92. The downhole tool as defined in Claim 90, wherein an outer

surface of each of the upper primary seal metal rib, the lower primary seal metal

rib, the upper secondary seal metal rib, and the lower secondary metal rib is

configured for forming an annular metal-to-metal seal with a generally cylindrical

interior surface.

93. The downhole tool as defined in Claim 90, wherein said

conveyance tubular supports the wedge ring generally stationary while the seal

assembly moves axially with respect to the stationary wedge ring.

94. The downhole tool as defined in Claim 90, wherein the conveyance

tubular supports the seal assembly generally stationary while the wedge ring

moves axially with respect to the stationary seal assembly.

95. The downhole tool as defined in Claim 90, wherein the seal

assembly seals with an interior surface of a downhole tubular.

96. The downhole tool as defined in Claim 90, wherein the primary

elastomeric seal includes a void area when the primary elastomeric seal is

moved into sealing engagement with the cylindrical surface, such that the

primary elastomeric seal may thermally expand to fill at least part of the void

area in response to elevated downhole temperatures.

97. The downhole tool as defined in Claim 90, wherein each of the

downwardly angled primary seal metal rib and the upwardly angled primary seal

metal rib is inclined while in the run-in position at an angle of at least 15° with

respect to a plane perpendicular to a central axis of the cylindrical interior

surface.

98. The downhole tool as defined in Claim 97, wherein each of the

downwardly angled secondary metal rib and the upwardly angled secondary

metal rib is inclined while in the run-in position at an angle of at least 15° with

respect to a plane perpendicular to a central axis of the cylindrical interior

surface.

99. The downhole tool as defined in Claim 90, further comprising:

one or more axially spaced protrusions on a radially inner surface of the

annular base of the metal framework each for metal-to-metal sealing

engagement with the conical outer surface of the wedge ring.

100. The downhole tool as defined in Claim 99, further comprising:

one or more annular elastomeric sealing members for sealing between

the base of the metal framework and the conical outer surface of the wedge ring.

101. The downhole tool as defined in Claim 99, further comprising:

one or more annular metal protrusions on one of an outer surface of a conveyance tubular and an inner surface of the wedge ring to form a metal-to-

metal seal between the wedge ring and the conveyance tubular.

102 The downhole tool as defined in Claim 101 , further comprising:

one or more annular elastomeric sealing members carried by one of the

conical wedge ring and the conveyance tubular for forming an elastomeric seal

between the conveyance tubular and the wedge ring.

103. A tool for use in a subterranean well to seal with a generally cylindrical interior surface of a tubular or another downhole tool, the tool

comprising:

a wedge ring having a substantially conical outer surface configured to

radially expand the annular seal assembly upon axial movement of the annular seal assembly relative to the wedge ring such that the seal assembly is

expanded from its run-in position to its expanded sealing position wherein the

seal assembly is in sealing engagement with the generally cylindrical interior

surface; and

an annular seal assembly having a reduced diameter run-in position and

an expanded sealing position, the seal assembly including a metal framework

having a radially inward annular base and a plurality of metal ribs each extending

radially outward from the base, the metal framework including an upper

downwardly angled primary seal metal rib for sealing pressure below the seal

assembly, a lower upwardly angled primary seal metal rib for sealing pressure

above the seal assembly, a primary elastomeric seal in a cavity radially outward from the base and axially between the upper primary seal metal rib and the lower

primary seal metal rib, an upper downwardly angled secondary seal metal rib

spaced axially above the upper primary seal metal rib, and a lower upwardly

angled secondary seal metal rib spaced axially below the lower primary seal

metal rib.

104. The downhole tool as defined in Claim 103, further comprising:

an upper secondary elastomeric seal between the upper primary seal

metal rib and the upper secondary seal metal rib, and a lower secondary

elastomeric seal spaced between the lower primary seal metal rib and the lower

secondary seal metal rib.

105. A downhole tool as defined in Claim 103, wherein an outer surface

of each of the upper primary seal metal rib, the lower primary seal metal rib, the

upper secondary seal metal rib, and the lower secondary metal rib is configured

for forming an annular metal-to-metal seal with a generally cylindrical interior

surface.

106. The downhole tool as defined in Claim 103, wherein each of the

downwardly angled primary seal metal rib, the upwardly angled primary seal

metal rib, the downwardly angled secondary seal metal rib and the upwardly

angled secondary seal metal rib is inclined while in the run-in position at an angle

of at least 15° with respect to a plane perpendicular to a central axis of the cylindrical interior surface.

107. A method of forming a downhole seal with a generally cylindrical

interior surface of a tubular or another downhole tool, the method comprising:

providing an annular seal assembly disposed about a conveyance tubular,

the seal assembly having a reduced diameter run-in position and an expanded

position, the seal assembly including a metal framework having a radially inward

annular base and a plurality of metal ribs each extending radially outward from

the base, the metal framework including an upper downwardly angled primary

seal metal rib for sealing pressure below the seal assembly, a lower upwardly

angled primary seal metal rib for sealing pressure above the seal assembly, a

primary elastomeric seal in a cavity radially outward from the base and axially

between the upper primary seal metal rib and the lower primary seal metal rib,

an upper downwardly angled secondary seal metal rib spaced axially above the

upper primary seal metal rib, and a lower upwardly angled secondary seal metal

rib spaced axially below the lower primary seal metal rib;

providing a wedge ring having a substantially conical outer surface; and

axially moving the annular seal assembly relative to the wedge ring such

that the seal assembly is expanded from its run-in position to its expanded

position wherein the seal assembly is in sealing engagement with the generally

cylindrical interior surface.

108. The method as defined in Claim 107, further comprising:

providing an upper biasing member between the upper primary seal metal rib and the upper secondary seal metal rib for exerting a downward biasing force

on the upper primary seal metal rib in response to high fluid pressure below the

seal assembly; and

providing a lower biasing member spaced between the lower primary seal

metal rib and the lower secondary seal metal rib for exerting an upward force on

the lower primary seal metal rib in response to high fluid pressure above the seal

assembly.

109. The method as defined in Claim 108, wherein an outer surface of

each of the upper primary seal metal rib, the lower primary seal metal rib, the

upper secondary seal metal rib, and the lower secondary metal rib is configured

for forming an annular metal-to-metal seal with a generally cylindrical interior

surface.

110. The method as defined in Claim 108, wherein the wedge ring is

generally stationary while the seal assembly moves axially with respect to the

stationary wedge ring.

111. The method as defined in Claim 110, wherein a set down weight

transmitted to the seal assembly through the conveyance tubular moves the seal

assembly axially with respect to the stationary wedge ring.

112. The method as defined in Claim 108, further comprising: providing one or more axially spaced protrusions on a radially inner

surface of the annular base of the metal framework each for metal-to-metal

sealing engagement with the conical outer surface of the wedge ring.

113. The method as defined in Claim 112, further comprising:

providing one or more annular elastomeric sealing members for sealing

between the base of the metal framework and the conical outer surface of the wedge ring.

114. The method tool as defined in Claim 108, further comprising:

providing one or more annular metal protrusions on one of an outer

surface of the conveyance tubular and an inner surface of the wedge ring to form

a metal-to-metal seal between the wedge ring and the conveyance tubular.

115. For use with a downhole cementing tool, comprising

a tubular member having an upper end connected to a well pipe for

lowering into a well bore to permit it to be cemented therein, and having a bore

with a relatively large diameter upper portion enabling one or more balls and

pump down plugs to be lowered therein and a smaller lower portion including a

liner wiper plug whose bore is smaller than the balls but permits passage of the

pump down plugs therethrough,

a diverter including a sub forming a part of the tubular member

intermediate the upper and lower portions and having a side pocket to one side of the bore to receive a ball prior to passage of a pump down plug therethrough,

and

a ramp extending diagonally across the sub and slanted downwardly to

guide the ball into the side pocket and having a U-shaped opening facing the

pocket to prevent passage of the ball, but permit a plug to pass between the ball

and pocket into the liner wiper plug.

116. A plug holder sub for being supported on a conveyance tubular for

temporarily supporting a wiper plug and for releasing the wiper plug in response

to an increase in fluid pressure within the conveyance tubular, the plug holder

sub comprising:

a generally tubular body adapted for connection with the conveyance

tubular and having a throughbore in fluid communication with the conveyance tubular;

a retainer member for attaching the wiper plug to the tubular body, the

retainer member movable from a retaining position to a release position for

releasing the wiper plug from the tubular body;

a piston movable within the tubular body in response to fluid pressure

within the throughbore from a retaining position for preventing the releasing

member from moving to the release position, the piston acting against a fluid

within a chamber within the tubular body when moving to the release position;

and

a metering jet along a fluid flow path from the fluid chamber to an annulus

about the tubular body, such that fluid pressure within the throughbore restrains movement of the piston to the release position until fluid is forced through the

metering jet, thereby preventing release of the liner wiper plug until the piston

moves to the release position.

117. The plug holder as defined in Claim 116, wherein the wiper plug

includes an internal seat, such that a pump down plug landed on the wiper plug

allows for the increase in fluid pressure within the tubular body.

118. The plug holder as defined in Claim 116, wherein the retainer

member is a C-shape ring which is radially expanded when the piston is in the

release position to release the wiper plug.

119. The plug holder as defined in Claim 116, wherein the C-shaped

ring has internal gripping members for gripping engagement with the wiper plug.

120. The plug holder sub as defined in Claim 116, wherein the piston

moves axially from the retaining position to the release position.

121. The plug holder sub as defined in Claim 120, wherein a radially

interior surface of the piston engages the retainer member to prevent the retainer

member from moving to the release position, and axial movement of the piston

releases the retainer member to the release position.

122. The plug holder sub as defined in Claim 116, wherein the metered

jet has external threads for threaded engagement with the tubular body.

123. The plug holder sub as defined in Claim 116, wherein the metering

jet is secured to the tubular body by a swage connection.

124. A plug holder sub for being supported on a conveyance tubular for

temporarily supporting a wiper plug and for releasing the wiper plug in response

to an increase in fluid pressure within the conveyance tubular, the plug holder

sub comprising:

a generally tubular body adapted for connection with the conveyance

tubular and having a throughbore in fluid communication with the conveyance tubular;

a retainer member for attaching the liner wiper plug to the tubular body,

the retainer member movable from a retaining position to a release position for

releasing the wiper plug from the tubular body;

a piston axially movable within the tubular body in response to fluid

pressure within the throughbore from a retaining position for preventing the

releasing member from moving to the release position, a radially interior surface

of the piston engaging the retainer member to prevent the retainer member from

moving to the release position, and axial movement of the piston releases the

retainer member to the release position, thepiston acting against a fluid within a

chamber within the tubular body when moving to the release position; and a metering jet along a fluid flow path from the fluid chamber to an annulus

about the tubular body, such that fluid pressure within the throughbore restrains

movement of the piston to the release position until fluid is forced through the

metering jet, thereby preventing release of the liner wiper plug until the piston

moves to the release position.

125. The plug holder sub as defined in Claim 124, wherein the plug

holder sub is positioned on a lower end of a liner hanger running tool, and the

wiper plug is a liner wiper plug.

126. The plug holder as defined in Claim 125, wherein the liner wiper

plug includes an internal seat, such that a pump down plug landed on the liner

wiper plug allows for the increase in fluid pressure within the tubular body.

127. The plug holder sub as defined in Claim 124, wherein the fluid in

the chamber has a known viscosity.

128. The plug holder as defined in Claim 124, herein the retainer

member is a C-shape ring which is radially expanded when the piston is in the

release position to release the wiper plug, and the C-shaped ring has internal

gripping members for gripping engagement with the liner wiper plug.

129. A method of supporting a liner wiper plug on a conveyance tubular

and for releasing the liner wiper plug in response to an increase in fluid pressure within the conveyance tubular, the method comprising:

providing a generally tubular body adapted for connection with the

conveyance tubular and having a throughbore in fluid communication with the

conveyance tubular;

providing a retainer member for attaching the liner wiper plug to the

tubular body, the retainer member movable from a retaining position to a release

position for releasing the liner wiper plug from the tubular body;

moving a piston within the tubular body in response to fluid pressure

within the throughbore from a retaining position for preventing the releasing member from moving to the release position, the piston acting against a fluid

within a chamber within the tubular body when moving to the release position;

metering discharge of fluid along a fluid flow path from the fluid chamber

to an annulus about the tubular body, such that fluid pressure within the

throughbore restrains movement of the piston to the release position until fluid is

forced through a metering jet, thereby preventing release of the liner wiper plug

until the piston moves to the release position;

allowing the retainer member to move to the release position when the

piston is in the release position, thereby releasing the liner wiper plug from the

tubular body; and

monitoring a drop in fluid pressure in response to the release of the liner

wiper plug.

130. The method as defined in Claim 129, wherein the retainer member includes providing a C-shape ring which is radially expanded when the piston is

in the release position to release the liner wiper plug.

131. The method as defined in Claim 130, further comprising:

providing internal gripping members on the C-shaped ring for gripping

engagement with the liner wiper plug.

132. The method as defined in Claim 129, wherein a piston moves

axially from the retaining position to the release position.

133. The method as defined in Claim 129, wherein the piston moves

axially from the retaining position to the release position.

134. The method as defined in Claim 133, wherein a radially interior

surface of the piston engages the retainer member to prevent the retainer

member from moving to the release position, and axial movement of the piston

releases the retainer member to the release position.

135. The method as defined in Claim 129, further comprising:

providing an internal seat on the liner wiper plug, such that a pump down

plug landed on the liner wiper plug allows for the increase in fluid pressure within

the tubular body.