Pack-off well apparatus and method

A pack-off tubing hanger is shown for use in a tubing string extending from a well surface location to a downhole location within a well casing. The hanger body includes an external packing element and gripping slips which support the hanger body within the surrounding casing. A longitudinal passageway communicates hydraulic pressure from the lower end of the hanger to a setting chamber to hydraulically set the packing elements and actuate the gripping slips. A companion concentric tubing anchor is carried within the internal bore of the hanger and connects the hanger to the tubing string leading to the well surface.

BACKGROUND OF THE INVENTION 
1. Field of the Invention 
The present invention relates to well devices employed in the completion 
and production of oil and gas wells. More specifically, the invention 
relates to a well tubing hanger which is retrievably anchored in a 
subsurface location within a well casing or other well conduit and to a 
cooperating concentric tubing anchor used to anchor a tubing string 
extending from the well surface within the tubing hanger. 
2. Description of the Prior Art 
Anchor-seal assemblies of various types have been used in the past in well 
working operations, and in the production of a well. For instance, seal 
assemblies in the form of packers are known for isolating formations for 
treatment, or for isolating segments of liners or well casings. Packers 
are routinely used for sealing production strings to well liners or well 
casings to define flow paths from producing formations to the well 
surface. 
Particularly in the case of packers, the seal assembly is usually 
positioned within a well by means of a pipe string, and then set in 
sealing and anchoring engagement with the surrounding conduit. The setting 
operation usually involves the movement of multiple components of the 
packer to expand one or more resilient seal members, and to wedge 
anchoring slips against the surrounding well conduit or casing. 
In spite of advances in the art, a need exists for a pack-off well 
apparatus which is adapted for specific, demanding environments. For 
example, in gas injection operations, a tubing hanger is needed which is 
capable of anchoring and sealing a well tubing string in a borehole, the 
tubing hanger having an extremely high axial load capability. 
A need also exists for such a pack-off apparatus which can be used for gas 
injection operations where temperature changes subject the apparatus to 
large static loads. 
A need also exists for such an apparatus which can serve as a redundant 
wellhead when set at a shallow depth in a borehole. 
It is an object of the present invention to provide a tubing hanger with an 
axial load capability which is substantially equivalent to the load 
capability of the tubing string supported by the tubing hanger. 
Another object of the invention is to provide a tubing hanger adapted for 
gas injection processes which can be set at a shallow depth below the well 
surface and which can tolerate the large static loads encountered due to 
temperature requirements encountered during such operations. 
Another object of the invention is to provide such a tubing hanger which 
cannot be inadvertently pulled from the anchored location in the well 
casing by an impact to the upstream equipment located at the well surface 
such as might occur if an ocean vessel inadvertently rammed the surface 
structures. 
Another object is to provide a tubing hanger which eliminates flow ports in 
the production tubing or work string, or a component in direct fluid 
communication therewith, to provide actuating fluid from the bore of the 
production tubing to well tools to initiate desired operations, such as 
the setting of the packing element. Seals employed with such ports must be 
sealed in subsequent operations and are subject to deterioration and hence 
leakage. 
Additional objects, features and advantages will be apparent in the written 
description which follows. 
SUMMARY OF THE INVENTION 
The present pack-off apparatus is designed for extremely high axial load 
capability. In its preferred environment, the present apparatus is set at 
a shallow depth, e.g., 100-4,000 feet below the well surface and serves as 
a redundant wellhead with packers and other production equipment supported 
below. The apparatus is also designed to accept a cooperating Concentric 
Tubing Anchor (CTA). The CTA includes inner and outer concentric tubular 
bodies which allow gas injection through an annular flow path created 
between concentric tubing bodies, through the interior of the tubing 
hanger and out ports provided in the hanger body below the annular packing 
element. In this way, gas injected through the annular flow path and out 
the injection ports co-mingles with production fluids in the surrounding 
formation, thereby providing artificial lift for these fluids. The 
gas-fluid mixture is then returned through the inner concentric tubular 
body of the CTA and passes up the interior of the tubing string leading to 
the well surface. 
In its preferred form, the apparatus of the invention comprises a pack-off 
tubing hanger designed to support a tubing string extending from a well 
surface location to a downhole location within a surrounding subterranean 
formation lined with a well casing. The tubing hanger includes a generally 
cylindrical hanger body having an upper end and a lower end, the hanger 
body being adapted to be supported in the surrounding well casing. The 
hanger body has a longitudinal axis, cylindrical sidewall portions and an 
internal bore. 
An annular packing element is carried about the hanger body which is 
radially expandable under axial compression. A setting sleeve is carried 
about the hanger body. The setting sleeve is axially moveable with respect 
to the packing element for compressing the packing element. The setting 
sleeve has an upper end adapted to contact the packing element and has a 
lower end, the lower end of the setting sleeve being slidably received 
within the interior of a circumscribing member which defines a setting 
chamber on the exterior of the hanger body. An anti-preset piston is 
carried about the hanger body below the setting sleeve. The anti-preset 
piston has an engagement end which initially locks the setting sleeve in a 
running-in position. The anti-preset piston is axially moveable in an 
opposite direction from the setting sleeve to release the setting sleeve 
and set the packing element upon the application of hydraulic pressure to 
the setting chamber. 
A plurality of circumferentially spaced slips are carried on the exterior 
of the hanger body. The slips have outer gripping surfaces adapted to grip 
the surrounding well casing. The slips are actuable by axial movement of 
the anti-preset piston to grip the well casing and support the hanger body 
within the well casing. The hanger body has a longitudinal passageway for 
communicating hydraulic pressure to the setting chamber, the longitudinal 
passageway extending from a point adjacent the lower end of the device 
upwardly along the longitudinal axis of the hanger body to the setting 
chamber. 
Preferably, the longitudinal passageway is a gun drilled hole which extends 
from the lower end of the device to the setting chamber used to set the 
packing element. 
A cooperating Concentric Tubing Anchor (CTA) can be located within the 
internal bore of the hanger body. The CTA has an external latch profile 
adapted to be engaged with an internal thread profile of the hanger body. 
The preferred CTA has an upper extent which carries a latch assembly for 
engaging the mating thread profile of the interior of the hanger body and 
a lower, tubular extent which extends within the interior of the hanger 
body to a point below the gripping slips. The CTA has upper and lower seal 
regions which are located above and below the packing element within the 
interior of the hanger body when the latch assembly engages the interior 
of the hanger body. The CTA has an outer tubing body and a concentrically 
located inner tubing body at the upper extent thereof. The outer an inner 
tubular bodies define an annular flow path which extends from the upper 
extent of the CTA to the lower extent thereof. Flow ports are located in 
the hanger body below the packing element. The flow ports are arranged in 
communication with the annular flow path defined by the inner and outer 
concentric tubular bodies of the CTA. Fluid pumped down the annular flow 
path passes to the exterior of the pack-off tubing hanger to an annular 
area of the borehole located below the packing element when the packing 
element is set in engagement with the surrounding well casing. 
An axially slidable closing sleeve is carried within the interior bore of 
the hanger body. The closing sleeve has an engagement region which is 
engageable by the tubular portion of the CTA as the CTA is inserted and 
withdrawn from the internal bore of the hanger body. The closing sleeve is 
provided with axially-spaced seal regions which alternately close the flow 
ports to the exterior of the tubing hanger as the CTA is withdrawn and 
open the flow ports as the CTA is inserted within the internal bore of the 
tubing hanger. 
The CTA is preferably provided with a downwardly extending latch collet 
supported on the outer tubular body thereof. The latch collet has a 
plurality of externally threaded collet fingers which are adapted to 
matingly engage an internal thread profile provided in the internal bore 
of the surrounding hanger body to thereby latch the CTA in a latched 
position within the hanger body. The inner tubular body has alternating 
external support lands which underlie the externally threaded collet 
fingers in the latched position. The alternating support lands of the 
inner tubular body are axially shiftable from beneath the externally 
threaded collet fingers in a release position. The inner tubular body has 
a cylindrical fixed portion and an axially aligned actuating portion which 
is axially shiftable to move the alternating support lands to the release 
position and actuate the release of the concentric tubing anchor from 
within the hanger body. Preferably, the inner tubular body is initially 
connected to the axially aligned, actuating portion by a severable joint 
which can be severed upon the application of a predetermined tension load 
by a suitable release tool. 
In certain operational sequences, stop means can be provided in the 
exterior of the outer tubular body for initially preventing downward 
movement of the outer tubular body relative to the hanger body and for 
preventing the externally threaded collet fingers from engaging the 
internally threaded profile provided in the internal bore of the hanger 
body. In the preferred embodiment, the stop means includes a stop ring 
which is located in a recess provided on the exterior of the outer tubular 
body. The recess includes a ramp region which allows downward movement of 
the stop ring as the outer tubular body is moved upwardly within the 
surrounding hanger body but which initially prohibits downward movement of 
the outer tubular body within the surrounding hanger body. 
Connecting means, located on the exterior of the outer tubular body, 
initially connect the CTA to the surrounding hanger body in order to 
deactivate the stop means. The connecting means is preferably formed as a 
double lobed C-ring having oppositely arranged lobes which extend radially 
outward from the exterior of the outer tubular body. One of the lobes is 
adapted to engage a mating groove provided within the internal bore of the 
hanger body and the opposite lobe is engaged within an internal recess of 
a triggering ring provided on the exterior of the outer tubular body. The 
triggering ring has an internal shoulder which is adapted to engage the 
stop ring located on the exterior of the outer tubular body for moving the 
stop ring up the ramp region. 
An indexing groove is provided on the exterior of the outer tubular body 
for receiving the stop ring. After the stop ring passes over the ramp 
region, the depth of the indexing groove increases. The stop ring is now 
removed from contact with the internal shoulder of the triggering ring. 
This allows the CTA to move downwardly relative to the hanger body to 
thereby latch the latch collet within the mating internal thread profile 
provided within the internal bore of the surrounding hanger body.

DETAILED DESCRIPTION OF THE INVENTION 
FIG. 1 shows the upper most end of a pack-off tubing hanger of the 
invention designated generally as 11. The tubing hanger 11 is used for 
supporting a tubing string extending from a well surface location to a 
downhole location within a surrounding subterranean formation lined with a 
well casing (not shown). The tubing hanger 11 includes a generally 
cylindrical hanger body 13 which has an upper end 15 and a lower end 17 
(FIG. 11). As will be described, the hanger body 13 includes a plurality 
of tubular portions which are threadedly engaged between the upper end 15 
and lower end 17. The lower end 17 has an externally threaded pin end 19 
which is adapted to engage a mating box connection on a production string 
leading to a packer and additional production equipment supported below 
the tubing hanger in the well bore in conventional fashion. 
The hanger body 13 (FIG. 1) has a longitudinal axis 21, cylindrical 
sidewall portions 23 and an internal bore 25. As shown in FIG. 1, the 
internal bore includes a mating groove 27 provided within the internal 
bore 25 of the hanger body for engaging a connecting means for connecting 
a Concentric Tubing Anchor (CTA) to the surrounding hanger body. The 
internal bore 25 of the hanger body 13 also includes a locating shoulder 
29 for locating the CTA within the internal bore, as will be described. 
As shown in FIG. 3, the upper most extent of the hanger body 13 includes an 
internally threaded surface 33 for engaging an externally threaded surface 
35 of a downwardly extending cylindrical body portion 37 of the hanger 
body 13. The downwardly extending body portion 37 includes a region of 
reduced external diameter 39 for receiving an annular packing element 41. 
The annular packing element 41 will be familiar to those skilled in the 
art and includes one or more elastomeric regions which are radially 
expandable under axial compression. The packing element 41 is expanded 
outwardly between an upper shoulder ring 43 fixed in position by the lower 
extent 45 of the body portion and the lower shoulder region 47 of a 
setting sleeve 49 which is carried about the external diameter 39 of the 
downwardly extending body portion 37 of the hanger body 13. 
The setting sleeve 49 includes an upper region 51 of relatively greater 
external diameter and a lower region 53 of lesser relative external 
diameter which circumscribes the downwardly extending body portion 37. The 
setting sleeve 49 thus has an upper end which includes the lower shoulder 
region 47 which contacts the packing element 41 and has a lower end region 
53 which is slidably received within the interior of a circumscribing 
member 55 which defines a setting chamber 57 on the exterior of the hanger 
body. As shown in FIG. 4, O-ring seals 59, 61 are provided in mating 
grooves on the interior and exterior, respectively, of the setting sleeve 
lower end region 53 for sealingly engaging the internal diameter 63 of the 
circumscribing member 55 and the external diameter 65 of the body portion 
37, respectively. The lower end region 53 of the setting sleeve 49 also 
has a ratchet region 67 on the exterior thereof for engaging a body lock 
ring 69 which allows upward movement of the setting sleeve 49, as viewed 
in FIG. 4 but which prohibits downward movement of the setting sleeve 49 
after the rachet region 67 has engaged the teeth of the body lock ring 69. 
An anti-preset piston 71 is carried about the hanger body portion 37 below 
the setting sleeve 49, the anti-preset piston 71 having an engagement end 
73 which initially locks the setting sleeve in a running-in position. The 
anti-preset piston is axially moveable in an opposite direction from the 
setting sleeve 49 to release the setting setting sleeve and set the 
packing element upon the application of hydraulic pressure to the setting 
chamber 57. 
Preferably, the setting sleeve lower end region 53 is provided with a 
plurality of downwardly extending fingers 75 which define 
circumferentially spaced end slots (77a, 77b in FIG. 16) between each 
finger 75. The engagement end 73 of the anti-preset piston 71 is provided 
with upwardly extending fingers (79a, 79b in FIG. 16) which are received 
within the setting sleeve end slots when the setting sleeve is locked in 
the running-in position (see FIG. 15). The setting sleeve fingers 75 have 
a circumferential groove 81 (FIG. 14) cut therein which contains a snap 
ring 83. The circumscribing member 55 has an internal shoulder 85 which 
engages the snap ring 83 when the engagement end 73 of the anti-preset 
piston 71 locks the setting sleeve 49 in the running-in position. 
As shown in FIGS. 13 and 14, the upwardly extending fingers 79 of the 
anti-preset piston 71 initially underlie the snap ring 83 of the setting 
sleeve 49 when in the running-in position, whereby the snap ring 83 
engages the internal shoulder 85 of the circumscribing member 55. The 
upwardly extending fingers 79 are axially moveable from beneath the snap 
ring to a release position which frees the snap ring 83 from the internal 
shoulder 85 upon the application of hydraulic pressure to the setting 
chamber 57. 
The anti-preset piston 71 has inner and outer O-rings 87, 89 for forming a 
sliding seal between the circumscribing member 55 and the exterior of the 
downwardly extending body portion 37 of the hanger body 13. Shear means, 
such as shear pins 91 (FIG. 13) initially fix the position of the 
anti-preset piston 71 relative to the setting sleeve 49, the shear means 
being shearable by the application of a predetermined hydraulic pressure 
to the setting chamber 57 to thereby allow the anti-preset piston 71 to 
move to the release position shown in FIG. 14. 
Returning to FIG. 4, the circumscribing member 55 is connected to an 
axially slidable tubular portion 93 of a slip setting body 95. The slip 
setting body 95 circumscribes the downwardly extending body portion 37 of 
the hanger body 13 and includes an internal groove 97 which contains a 
support ring 99. The support ring 99 includes a support shoulder 101 which 
engages the mating shoulder 103 provided on the external diameter of the 
downwardly extending body portion 37. The slip setting body 95 also 
includes an internal wicker surface 105 which engages a body lock ring 
107. The body lock ring 107 has an external wicker surface which engages 
the serrated exterior 109 of the hanger body downwardly extending portion 
37. The body lock ring 107 allows downward axial movement of the slip 
setting body 95 relative to the serrated exterior 109 of the hanger body 
but prohibits upward axial movement thereof. Vent port 111 communicates 
with the annular space between the hanger body portion 37 and the exterior 
of the slip setting body 95. 
As shown in FIGS. 4-8, the hanger body has a longitudinal passageway 113 
for communicating hydraulic pressure to the setting chamber 57. The 
longitudinal passageway extends from a point below the slip setting body 
95 along the longitudinal axis 21 of the hanger body 13 to the setting 
chamber 57. Preferably, the longitudinal passageway is a gun drilled hole 
which extends from the lower end of the hanger body to the setting chamber 
57. 
As shown in FIGS. 5 and 6, a plurality of circumferentially spaced slips 
115 are carried on the exterior of the hanger body 13. The slips have 
outer gripping surfaces 117 adapted to grip the surrounding well casing. 
The slips are actuable by axial movement of the anti-preset piston 71 to 
grip the well casing and support the hanger body 13 within the well 
casing. 
The slip mechanism shown in FIGS. 5 and 6 includes a plurality of 
circumferentially spaced upper gripping slips 119 which are connected by 
means of a solid ring 123 with an oppositely arranged set of 
circumferentially spaced lower slips 121. The particular slip arrangement 
shown in FIGS. 5 and 6 is described, e.g., in U.S. Pat. No. 4,711,326, 
issued Dec. 8, 1987, and assigned to the assignee of the present 
invention, the disclosure of which is hereby incorporated by reference. 
Such slip gripping mechanisms will be familiar to those skilled in the art 
and do not form a part of the present invention. Any suitable mechanism 
can be utilized which allows the gripping slips to move radially outward 
upon the downward axial movement of the anti-preset piston and slip 
setting body 95. 
The slip setting body includes a lower extent 125 (FIG. 6) which includes 
an internal wicker surface 127 carrying a body lock ring 129. The body 
lock ring 129 has an external wicker surface which engages a mating 
serrated surface 131 provided on the exterior of the downwardly extending 
body portion 37 of the hanger body 13. The body lock ring 129 allows the 
lower extent 125 to move downwardly relative to the body portion 37, but 
prohibits opposite relative movement. A vent portion 133 is provided in 
the cylindrical sidewall of a circumscribing member 135, the vent port 133 
providing communication between an annular space 137 and the exterior of 
the device. It will also be noted in FIG. 6 that a spaced serrated surface 
139 is provided on the exterior of the body portion 37 of the hanger body 
for engaging the body lock ring 129 during subsequent operations. 
As shown in FIG. 7, the downwardly extending body portion 37 of the hanger 
body has an externally threaded surface 141 which engages a hanger body 
portion 143, the hanger body portion 143 being received within the 
internal diameter of circumscribing member 135. The hanger body portion 
143 includes an angular passage 145 which communicates with the 
longitudinal passageway 113 and which communicates with an annular region 
151 within the circumscribing member 135. The hanger body portion 143 also 
includes a plurality of downwardly extending collet fingers 153 having 
external, left-hand threads 155. As shown in FIG. 7, the collet fingers 
153 are threadedly engaged with the internally threaded surface 157 of the 
circumscribing member 135. A release sleeve 159 having locking profile 161 
is initially fixed in position beneath the collet fingers 153 to thereby 
fix the position of the hanger body portion 143 relative to the 
circumscribing member 135, as by a plurality of shear pins 163. An 
internal recess 166 within the release sleeve 159 is provided to engage a 
release tool (not shown) during subsequent release operations for 
retrieving the tubing hanger to the well surface. 
The circumscribing member 135 (FIG. 7) has an internally threaded surface 
165 which matingly engages the externally threaded surface 167 of a lower 
body portion 169 of the hanger body. The lower body portion 169 includes a 
longitudinal passageway, such as gun drilled hole 171 which extends within 
the cylindrical sidewall portion thereof and which communicates with the 
annular region 151. 
As shown in FIG. 8, the lower body portion 169 includes a plurality of 
circumferentially spaced ports 173 which are located below the packing 
element 41 and which establish communication between the exterior of the 
device and an annular flow path 175 within the interior of the device. 
An axially slidable closing sleeve 177 is carried within the internal bore 
of the hanger body. The closing sleeve 177 has an engagement region such 
as collet lug 179 and has a downwardly depending cylindrical extent 181 
which includes axially spaced seal regions formed by O-rings 183, 185 
which alternately close the flow ports 173 to the exterior of the tubing 
hanger and open the flow ports as the closing sleeve 177 moves axially 
within the interior of the hanger body. 
A pump-down sleeve 187 initially circumscribes the lower body portion 169 
and has spaced O-ring seals 189, 191 which span the flow ports 173. The 
pump down sleeve 187 is initially pinned in position by means of a 
plurality of circumferentially spaced shear-pins 193 which can be severed 
by the application of a predetermined fluid pressure within the annular 
flow path 175 to shift the sleeve 187 axially downward and uncover the 
ports 173. 
As shown in FIG. 9, the lower body portion 169 has an internally threaded 
lower extent 195 for matingly engaging the externally threaded upper 
extent 197 of the tubular sub which makes up the lower end 17 of the 
hanger body 13. As shown in FIG. 11, the pin end 19 of the lower end 17 is 
externally threaded to engage a mating connecting end of a production 
string (not shown) supported by the tubing hanger 11 within the cased well 
bore. The tubular sub 17, in the embodiment of the device shown in FIGS. 
9, 10 and 11, supports an actuating mechanism (199 in FIG. 10) which is 
used to supply a hydraulic setting force to the oil filled chamber 201 
arranged in communication with the longitudinal passageway (171 in FIG. 
9). The longitudinal passageway 171 communicates through the annular 
region 151 (FIG. 7) and passages 145, 147 and 149 with the longitudinal 
passageway 113 provided in the downwardly extending body portion 37 of the 
hanger body. Passageway 113 extends upwardly along the longitudinal axis 
of the device through the cylindrical sidewall of the hanger body portion 
and terminates at the setting chamber 57 (FIG. 4) for supplying hydraulic 
fluid to the setting chamber to set the packing element 41 and slips 115. 
The exact actuating mechanism (199 in FIG. 10) illustrated does not form a 
part of the present invention and is described, for instance, in the 
co-pending application entitled Subsurface Well Apparatus, Ser. No. 
07/549,803, filed July 9, 1990, the disclosure of which is hereby 
incorporated by reference. The actuating control (203 in FIG. 11) 
generates an activating voltage in response to external conditions, e.g., 
significant changes in the stresses existing in the conduit walls to which 
the device is attached. The activating voltage causes the propellant 205 
to be actuated, thereby forcing the piston 207 to shear the pins 209 and 
drive the piston 207 vertically upward to compress the hydraulic oil 
located in the oil filled chamber 201. This increase in hydraulic pressure 
is ultimately transmitted to the setting chamber 57, as previously 
described. 
Returning to FIG. 1, the pack-off tubing hanger 11 of the invention also 
has a Concentric Tubing Anchor (CTA) located within the internal bore 25 
of the hanger body 13. As will be described, the CTA has an external latch 
profile, designated generally as 213 in FIG. 2, which is adapted to be 
engaged within the internal thread profile 31 of the hanger body 13. In 
addition to the upper extent which carries the external latch profile 213, 
the CTA also has a lower, tubular extent 215 which extends downwardly 
along the longitudinal axis 21 of the device from the upper end of the 
hanger body to the lower body portion 169 (FIG. 9). The lower most extent 
217 (FIG. 9) of the CTA includes an external seal region 219 which 
slidingly engages the internal diameter of the lower body portion 169. 
As shown in FIG. 1, the CTA has an outer tubular body 221 and a 
concentrically spaced inner tubular body 223 at the upper extent thereof. 
The CTA is used to connect the tubing string leading from the well surface 
(not shown) to the tubing hanger 11. The concentric spacing of the inner 
and outer tubular bodies 221, 223 defines an annular flow path 225 which 
runs the length of the CTA from the upper extent thereof to the ports (173 
in FIG. 8) whereby a fluid such as natural gas can be injected along the 
annular flow path from a point above the set packing element 41 and out 
the ports 173 to the annular space in the surrounding borehole below the 
set packing element. As will be familiar to those skilled in the art, a 
pair of safety valves are customarily located above the device (not 
shown). A tubing safety valve seals off the production and internal tubing 
while an annular safety valve is used to seal off fluid which is injected 
down the annular flow path 225. As a result, the tubular bodies 221, 223 
are fixed relative to one another in the position shown in FIG. 1 and do 
not move relative to one another when the CTA is installed within the 
surrounding hanger body 13. 
As shown in FIGS. 1 and 2, the CTA preferably includes a downwardly 
extending latch collet 227 having a plurality of downwardly extending 
collet fingers 229. As shown in FIG. 2, the collet fingers 229 have 
external left-hand threads which engage the internal thread profile 31 of 
the hanger body 13, whereby the CTA can be released from the surrounding 
hanger body 13 by right-hand rotation of the tubing string leading to the 
well surface. 
The outer tubular body 221 (FIG. 1) carries an outer threaded ring 231 
which is used to locate the CTA within the hanger body and has an upper 
annular seal region 233 which passes circumferentially about the external 
diameter of the outer tubular body 221. The lower extent of the outer 
tubular body 221 also has an externally threaded region 235 which engages 
the mating internally threaded region 237 of a connecting member 239. The 
connecting member 239 has an internally threaded lower extent 241 which 
matingly engages a downwardly extending member 243, the member 243 having 
a stepped external diameter which forms a shoulder 245 for contacting a 
mating internal shoulder 247 provided on the latch collet upper end 227. 
The downwardly extending member 243 has an externally threaded lower extent 
249 which engages a mating lock ring 251. The lock ring 251 has an 
internal locking profile 253 for engaging the mating external surface of a 
body lock ring 255. 
As seen in FIG. 2, the downwardly extending member 243 is adapted to engage 
an upwardly extending portion of a latch retainer 259 at a clutch area 
257. The clutch area constitutes a rotational clutch which allows the 
latch retainer 259 to move axially with respect to the downwardly 
extending member 243, while at the same time allowing the member 243 to 
supply rotational torque to the latch retainer 259. It should also be 
noted that the body lock ring 255 has an internal lock profile 261 adapted 
to matingly engage the external profile 263 provided on the outer diameter 
of the latch retainer 259. The mating profiles 261, 263 allow the latch 
retainer 259 to move downwardly with respect to the body lock ring 255, 
but thereafter prohibits upward relative movement between the two parts. 
As will be explained, the latch retainer portion 259 of the inner tubular 
body includes alternating external support lands 265 which underlie the 
externally threaded collet fingers 229 in the latched position and which 
are axially shiftable from beneath the externally threaded collet fingers 
in a release position to allow retrieval of the CTA from the internal bore 
of the surrounding hanger body 13. 
As shown in FIG. 1, the inner tubular body 223 has a cylindrical fixed 
portion 267 and an axially aligned, actuating portion 269. The actuating 
portion 269 is also a cylindrical member which forms the bottom portion of 
the cylindrical fixed portion 267 in the fixed position shown in FIG. 1. 
The fixed portion 267 and actuating portion 269 are initially connected by 
means of a severable joint 271 which can be, e.g., a welded connection 
with is severable upon the application of a predetermined tension load 
between the fixed portion 267 and the actuating portion 269 of the inner 
tubular body 223. As will be explained more fully, the actuating portion 
is axially shiftable to move the external latch profile (265 in FIG. 2) to 
the release position to actuate the release of the CTA from within the 
hanger body 13. The tension load can be supplied between the fixed portion 
267 and actuating portion 269 in a number of fashions. For instance, a 
conventional wireline release tool (not shown) can be lowered within the 
interior of the inner tubular body 223 to engage the upper recess 273 and 
lower recess 275 shown in FIG. 1 and 2. The release tool would then be 
actuated from the well surface to cause relative downward movement of the 
actuating portion 269 relative to the fixed portion 267 to sever the 
welded connection 271. 
The outer tubular body 221 of the CTA can also be provided with stop means 
on the exterior of the outer tubular body 221 for initially preventing 
downward movement of the outer tubular body 221 relative to the hanger 
body 13 and for preventing the externally threaded collet fingers 229 from 
engaging the internally threaded profile 31 provided in the internal bore 
of the hanger body 13, as during recompletion operations. 
FIGS. 18 and 19 show the CTA in a spaced-out position, as would occur 
during recompletion upon initially locating the CTA within the bore of the 
previously set tubing hanger. The stop means includes a stop ring 277 
located in a recess 279 provided on the exterior of the outer tubular body 
221. The recess 279 also includes a ramp region 281 which allows downward 
movement of the stop ring 277 as the outer tubular body 221 is moved 
upwardly within the surrounding hanger body 13 but which initially 
prohibits downward movement of the outer tubular body 221 within the 
surrounding hanger body 13. 
An indexing groove 283 is located axially below the recess 279 on the 
exterior of the outer tubular body 221 for receiving the stop ring 277 
after the stop ring passes over the ramp region 281. The depth of the 
indexing groove 283 is slightly greater than the depth of the recess 279 
whereby movement of the stop ring 277 to the indexing groove 283 causes 
the stop ring 277 to move from a greater relative radial position to a 
lesser relative radial position. 
Connecting means are also located on the exterior of the outer tubular body 
221 for initially connecting the CTA to the surrounding hanger body 13, in 
the position shown in FIGS. 18-21. 
As shown in FIG. 19, the preferred connecting means includes a double lobed 
C-ring 285 having oppositely arranged lobes 287, 289 which extend radially 
outward from the exterior of the outer tubular body 221. The lower lobe 
289 is adapted to engage a mating groove 291 provided within the internal 
bore of the hanger body. The upper lobe 287 is engaged within an internal 
recess 293 of a triggering ring 295 provided on the exterior of the outer 
tubular body 221. The triggering ring 295 has an internal shoulder 297 
which is adapted to engage the stop ring 277 for moving the stop ring up 
the ramp region 281. As previously discussed, the depth of the indexing 
groove 283 is selected to remove the stop ring 277 from contact with the 
internal shoulder 297 of the triggering ring 295 to allow the CTA to move 
downward relative to the hanger body 13 to thereby latch the latch collet 
227 within the mating internal thread profile 31 provided within the 
internal bore of the surrounding hanger body 13. 
Shear release means, such as collar 299 are located below the C-ring 285 
for maintaining the C-ring in the position shown in FIG. 19 until the CTA 
is moved upwardly relative to the surrounding hanger body. Upper movement 
of the CTA shears the shear-pins 301 and allow downward movement of the 
collar 299 within the annular space 303, as will be more fully described 
in the operational description of the invention. 
The operation of the device of the invention will now be described. In the 
case of an initial completion operation, the pack-off tubing hanger 11 is 
run into position within the surrounding well casing with the packing 
element 41 and gripping slips 115 in the relaxed positions shown in FIGS. 
1-5. The CTA, which is received within the internal bore 25 of the hanger 
body 13, would be in the position shown in FIGS. 1-2. Note that the CTA is 
supported within the hanger body 13 with the externally threaded fingers 
229 of the latch collet 227 engaged with the mating internal thread 
profile 31 provided in the hanger body. 
The combined CTA and hanger are lowered to the desired setting depth and 
the actuating control (203 in FIG. 11) is actuated to cause the actuating 
mechanism to sever pins 209 and force the piston 207 axially upward, 
thereby compressing the oil contained within the oil filled chamber 201. 
Hydraulic pressure is thus supplied through the longitudinal passageway 
171 (FIG. 9) to the annular region 151 (FIG. 7) and through the 
passageways 145, 147, 149 to the longitudinal passageway 113. The 
longitudinal passageway 113 continues upwardly through the downwardly 
extending body portion 37 of the hanger body and terminates at the setting 
chamber 57 (FIG. 4). 
As best shown in FIGS. 13-17, an increase in hydraulic pressure in the 
setting chamber 57 acts upon the anti-preset piston 71 causing the piston 
71 to shear the pins 91 and move downwardly. This action causes the 
upwardly extending fingers 79 to be pulled from beneath the snap ring 83, 
thereby allowing the snap ring 83 to move radially inward within the 
groove 81 to the release position shown in FIG. 14. In this position, the 
snap ring 83 no longer engages the internal shoulder 85, whereby the 
setting sleeve 49 is freed to move in an upward axial direction to 
compress the packing element 41. Body lock ring 69 (FIG. 4) prohibits the 
opposite axial travel of the setting sleeve 51 relative to the 
circumscribing member 55 and locks the setting force in the packing 
element. 
The downward movement of the anti-preset piston 71 and the opposite 
relative movement between the circumscribing member 55 and the setting 
sleeve 49 also causes the slip setting body 95 to move downwardly to 
effect the outward radial movement of the gripping slips 119, 121. During 
the setting operation, the upper slips 119 and ring 123 cause the lower 
slips 121 to move axially downward as a unit, whereby the lower slips 121 
ride up their respective ramp surfaces. This causes the gripping surfaces 
118 to travel radially outward and grip the surrounding well casing. After 
the lower slips 121 begin to grip the surrounding casing, upper slips 119 
are driven up the ramp surface 120, thereby causing outward radial 
movement of the upper slips to grip the surrounding casing. The exact 
setting mechanism of the gripping slips will be familiar to those skilled 
in the art and is described, for instance, in U.S. Pat. No. 4,711,326, 
previously referenced. 
Movement of the top body lock ring 69 traps the packing element in 
compression and maintains a fluid tight seal. Movement of the middle body 
lock ring 107 along the serrated exterior 109 of the hanger body portion 
37 causes the lock ring to act as a one-way ratchet device which prevents 
the hanger load from being transferred into the packing element after 
setting the device. The bottom body lock ring 129 similarly ratchets along 
the mating serrated surface 131 to maintain the slips in a retracted 
position during retrieval. 
The tubing hanger-CTA can be assembled at the surface in the configuration 
shown in FIGS. 1-2, run into the well bore as a unit and set at the 
desired depth within the casing. This would be the typical arrangement for 
long term production from the well. The CTA can be released from within 
the internal bore of the hanger body 13 by lowering a wireline release 
tool (not shown) which engages the upper and lower recesses 273, 275 for 
applying a tension load between the fixed portion 267 and actuating 
portion 269 of the CTA. The application of a predetermined tension load 
causes the welded connection 271 to sever, thereby allowing the actuating 
portion 269 to move vertically downward as viewed in FIGS. 1 and 2. FIGS. 
22-25 show the CTA in the release position in which the welded connection 
271 has been severed and the actuating portion 269 has shifted downwardly. 
This action causes the alternating support lands 265 of the latch retainer 
259 to move slightly downward from beneath the externally threaded collet 
fingers 229, whereby the external threaded can be freed from the thread 
profile 31 located within the bore of the hanger body. The body lock ring 
255 moves along the external profile 263 of the latch retainer 259 to 
thereby lock the latch profile 265 in the position shown in FIG. 24 so 
that the CTA can be retrieved to the well surface. 
In the case of a recompletion operation, the CTA would be reinserted within 
the internal bore 25 of the previously set hanger body 13. The CTA would 
be dressed at the surface so that the stop ring 277 is in the recess 279 
and the shear pins 301 are supporting the collar 285. The CTA would then 
be run downhole and inserted within the internal bore 25 of the tubing 
hanger body 13. FIGS. 18-21 show the CTA during this "locating" operation. 
Note that the lobe 289 of the collar 285 has engaged the mating groove 291 
in the hanger body 13. The collet latch fingers 229 do not engage the 
internal thread profile 31 of the hanger body, however. The operator at 
the well surface would then "mark" the tubing string in order to determine 
the length of pipe needed to extend from the surface to the tubing hanger. 
The tubing string extending from the CTA to the well surface can now be 
lifted vertically upward. This action causes the shear-pins 301 to sever, 
freeing the collar 299 (FIG. 19) and allowing relative movement between 
the outer tubular body 21 of the CTA and the hanger body 13. As the outer 
tubular body 221 moves vertically upward, the stop ring 277 rides up the 
ramp 281 and is received within the indexing groove 283. This allows the 
tubing string to be lifted several feet or more so that, e.g., the length 
of the tubing string can be adjusted by adding or removing a spacing sub 
in the tubing string. 
The CTA can then again be lowered into the well bore and be reinserted 
within the surrounding hanger body 13 and moved to the latched position 
shown in FIGS. 1 and 2 of the drawings. In the latched position, the latch 
collet 227 is engaged with the internal thread profile 31 of the hanger 
body 13, the stop ring 277 is located within the indexing groove and the 
C-ring 285 no longer engages the upper end 15 or triggering ring 295. 
Approximately 3/8 inch play exists in the latch mechanism, as illustrated 
at 245 in FIG. 2, so that placing the tubing string under tension causes 
the latch profile 265 to move underneath the externally threaded fingers 
229 of the collet latch to maintain the latched position. It will also be 
noted in FIG. 19 that the cylindrical fixed portion 267 of the CTA is 
firmly connected to the actuating portion 269 and that the severable 
connection 271 is whole. 
In order to release the tubing hanger, a suitable retrieving tool (not 
shown) is lowered into the internal bore 25 of the hanger body 13 from the 
well surface. It will be understood, at this point, that the CTA has now 
been retrieved to the well surface and that only open casing exists above 
the tubing hanger. Thus, with reference to FIG. 7 and 8, it will be 
understood that the lower tubular extent 215 of the CTA has now been 
retrieved to the well surface. 
The retrieving tool can be of conventional design and is not described in 
detail since it does not form a part of the present invention. Since the 
retrieving tool will be required to support the weight of the tubing 
hanger and associated production string depending from the hanger body, it 
will typically be run on drill string from the well surface down the 
borehole. The retrieving tool will be designed to engage the release 
grooves 166, 168, shown in FIGS. 7 and 8. 
The release tool will be actuated from the well surface, as by supplying 
hydraulic pressure through the interior of the drill pipe string to cause 
the release sleeve 159 (FIG. 7) to move upwardly relative to the hanger 
body portion 143. This action causes the shearpins 163 to sever and causes 
the locking profile 161 to be moved upwardly from beneath the collet 
fingers 153 of the hanger body portion 143. Freeing the collet fingers 153 
disengages the threaded surfaces 155, 157, allowing opposite relative 
movement between the downwardly extending body portion 37 of the hanger 
body and the circumscribing member 135, as viewed in FIG. 7. 
As this action is occurring, the first pick up shoulder (305 in FIG. 4) 
engages the setting sleeve 49, stretching out the sleeve portion thereof. 
A second pick up shoulder (307 in FIG. 5) engages the internal shoulder 
(309 in FIG. 4) of the tubular portion 93 causing the upper cone 120 to be 
pulled from beneath the upper slips 119. This action allows the upper 
slips 119 and, in turn, lower slips 121 to relax and be retracted radially 
inward so that the unit is stretched from the top to release the setting 
mechanism. As shown in FIG. 6, the internal wicker surface 127 of the body 
lock ring 129 engages the spaced serrated surface 139 of the body portion 
37 as the body portion moves upwardly relative to the lower extent 125 to 
lock the setting components in the stretched-out position. The hanger can 
be retrieved on the drill pipe string to the well surface. 
An invention has been provided with several advantages. The pack-off tubing 
hanger of the invention is extremely sturdy in design and can withstand 
extremely high axial loads. It is especially useful when set at shallow 
depths and subjected to temperature variations such as are encountered 
during gas injection operations. The packing element and slips are set by 
means of a hydraulic passageway which runs from the lower extent of the 
device to the upper extent thereof. This setting arrangement provides 
great versatility in allowing a number of alternative setting mechanisms 
to be utilized to provide the needed hydraulic force. The novel 
anti-preset piston and setting sleeve for the packing element securely 
engage the setting sleeve during the running-in operation so that the 
packing element cannot be inadvertently set if parts of the device should 
drag on the surrounding casing. The companion CTA can be engaged with the 
tubing hanger to allow the overall device to be hung in a one-trip 
operation. 
The unique stop means and indexing ring carried on the CTA are especially 
useful in the case of recompletion operations. After locating the CTA with 
respect to the previously set tubing hanger, the CTA and tubing string can 
be lifted to allow the length of the tubing string to be adjusted. When 
the CTA is again inserted within the bore of the hanger body, the stop 
means and indexing ring are shifted in position to allow the engagement of 
the CTA latch collet within the hanger bore. 
The CTA can be released from within the latched position by using a 
suitable wireline retrieving tool or can be released by right-hand 
rotation of the unit from the surface which frees the left-hand threads of 
the collet latch. The hanger can be released and retrieved to the well 
surface by running a retrieving tool on a drill string which shifts a 
release sleeve in the lower portion of the hanger body to stretch-out the 
slip and packing element setting mechanisms from the top to relax these 
elements and allow the device to be retrieved to the well surface. 
While the invention has been shown in only one of its forms, it is not thus 
limited but is susceptible to various changes and modifications without 
departing from the spirit thereof.