Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
215~97~
APPARATUS AND METHOD FOR INSTALLING
COILED TUBING IN A WELL
Ba~k~7ro~ln~9 of th~ :rnvention
1. Field of the Invention
The present invention pertains to methods and apparatus
for installing and suspending tubing in an oil and/or gas well.
More specifically, the present invention pertains to methods and
apparatus for installing and ~ p~nrlinq coiled tubing and
associated apparatus in an oil and/or gas well.
2. Description of the Prior Art
In the drilling and completion of an oil and/or gas well,
a hole is drilled through the earth to a subterranean formation
which comprises a reservoir for oil and/or gas. Typically, the
drilled hole is lined with a string of pipe, sometimes referred to
as a "casing string", and one or more smaller diameter strings of
pipe are lowered therein and supported at the surface of the well
by a wellhead. The smaller diameter pipe, sometimes referred to as
"tubing", is the pipe through which the oil and/or gas typically
rises to the surface of the well, by natural pressures or by
pumping, for production. The tubing string may also be used to run
safety valves, packers, plugs and other apparatus into the well.
Typically, such tubing is manufactured in rigid joints of
40 to 80 foot sections. The joints must be transported to the
2~ ~97~
well, stored on a pipe rack and vertically positioned in a derrick
or the like before installation in the well. Then they are
threadedly connected, joint by joint, as the string is lowered into
the well. If it becomes necessary to reposition or remove the
tubing, it must be ~l;cc--nn~ted, joint by joint, and removed from
the well. Obviously, these procedures are labor and time
intensive, resulting in relatively expensive operations.
In recent years, coiled tubing has been developed and
used in the oil field as an alternative to conventional jointed
tubing. Coiled tubing offers many advantages over conventional
~ointed tubing, including time and labor savings, pumping
flexibility, elimination of leakage and leak testings, reduced
formation damage, safety, etc. The coiled tubing may range in
sizes from 3/4" OD up to 3 1/2" OD. The operational concept of a
coiled tubing system involves running a continuous string of small
diameter tubing into a well to perform specific well servicing
operations without disturbing existing completion tubulars and
equipment. When servicing is complete, the small diameter tubing
and servicing equipment may be retrieved from the well and the
coiled tubing spooled onto a large reel for transport to and from
work locations.
Although coiled tubing has been in use since the early
1960's, it's use in production applications has only begun to gain
widespread acceptance in the last few years. Producers have for
several years successfully used concentric coiled tubing inside
larger conventional tubing to enable the wells to continuously
2~54976
unload liquids. For example, coiled tubing has been used to jet
sludge from wells as deep as 20, 000 feet prior to hanging the
string off and then unloading water through the "siphon" tubing to
increase gas production. In the past few years, coiled tubing has
5 begun to gain acceptance as a primary production string. Coiled
tubing can be run in llntl~-rh~l ~nc~ed well conditions to minimize
formation damage from completion of workover operations.
Installation and removal are generally faster than with jointed
pipe. Joint connections are reduced or eliminated, minimizing
10 potential for leaks and the need for testing connections. Cost is
competitive with jointed pipe in most sizes. Coiled tubing is
compatible with most artificial lift methods.
The typical procedure for hanging coiled tubing from the
surface as a production or an injection string may include the
15 following steps:
1. Rigging up a coiled tubing unit and killing the well if
necessary .
2. Installing a coiled tubing head. This may already be in
place or may be in addition to existing wellhead
equipment. ~any times the tubing head will be installed
on the lower master valve.
3. Nippling up or installing blowout preventers (BOP's) on
the tubing head. This usually also includes, above the
blowout preventers, an access window assembly.
4. Running coiled tubing with a shear out or pump out bottom
plug on the lower end to prevent possible well flow back
21 ~97~
through the coiled tubing. The BOP'6 nay be used for
annular well control.
5. When the end of the coiled tubing reaches the desired
depth, the lower set of BOP's are closed and the tubing
is checked for leaks.
6. The distance from the bottom flange of the access window
assembly to tubing head lock screws is measured to insure
that the annular hanger assembly sets completely in its
hanger profile.
~. A wrap around style annular hanger assembly (with slips
and seals) is placed around the coiled tubing and slowly
lowered to the top of the lower set of blowout preventer
rams .
8. The upper blowout preventers are closed and the lower
blowout preventers are opened, allowing pressure to
equalize across the spool.
9. The hanger assembly is lowered to the depth of a hanger
bowl and the weight of the tubing is landed on the
hanger Lock down screws are engaged and the hanger ' s
seals are ~La~uLe tested.
lO. The coiled tubing is rough cut through the window of the
access window assembly and the blowout preventers and
access window assembly are removed.
11. A final or smooth cut is made on the coiled tubing and it
is beveled to f it an adapter and to avoid damaging
adapter seals. The L~ ining wellhead equipment is then
~ 2~4~76
installed and flow lines connected.
12. The coiled tubing is pressured up to shear out the bottom
plug .
13. The well is placed in service.
In the typical coiled tubing installation of the prior
art just described, it is, as indicated, necessary to provide an
access window assembly above the blowout preventers to provide
access to the coiled tubing and the annular space surrounding the
coiled tubing in the tubing head. It is necessary to open the
l O access window assembly f or placement of the hanger assembly around
the coiled tubing so that it may be lowered into the tubing head.
Even though pressure control may be maintained by blowout
preventers, this potentially opens the annular space suLL~Ju~l~ing
the coiled tubing to ~ S~ULe in the well. As is well known in the
industry, an oil and/or gas well that is not under total pressure
control can result in dangerous situations . The f act that the
hanger assembly must be lowered around the coiled tubing from a
point near the bottom of the access window assembly to the seating
area in the tubing head, without being seen, also provides a
potential for improper seating of the hanger seal and actuation of
it's slips. Wrap-around slip and sealing assemblies of such
hangers are inherently more likely to create sealing or slip
engagement problems.
Even though coiled tubing installations, particularly
production applications thereof, have become widely accepted in the
last few years, apparatus and methods for completing and producing
~ 2~97~
wells with coiled tubing continue to be developed. For exanple,
the method and apparatus of co-pending application Ser. No.
08/308, 407 provides substantial i ~,v ~ts ~or installing coiled
tubing in an oil and/or gas well, particularly for production of
hydrocarbon fluids therefrom. It provides a tubing head and hanger
which, unlike the prior art, is designed so that the tubing unit
stripper or blowout preventers do not have to be disconnected to
hang the coiled tubing string in the well. Furthermore, all
components of the hanger apparatus are internal, eliminating the
need to install access window assemblies to set the tubing in the
hanger and thus eliminating the pres6ure control problems
associated with such.
The hanger apparatus of Ser. No. 08/308,407 includes a
tubing head, having a vertical flow passage therethrough, for
~UL ting on the wellhead of the well. An annular sealing
assembly i8 carried in a counterbored portion of the f low passage
and a 81ip assembly is carried in a second counterbored portion
above the first mentioned counterbored portion. The sealing and
slip assemblies make up the hanger assembly. Also carried by the
tubing head are slip activation devices which engage the slip
assembly within the second counterbored portion of the flow passage
and which are manipulatable externally of the tubing head to move
the slip assembly from passive positions to active positions.
In the method of installing coiled tubing with the
apparatus of Ser. No . 08/308, 407, the coiled tubing hanger
apparatus, which includes the tubing head, annular seal assembly
,~ 2 ~ 7 6
and slip as6embly are all installed on the wellhead, completely
assembled, prior to lowering the coiled tubing into the well. A
blowout preventer stack and the coiled tubing injector apparatus
are installed thereabove. The coiled tubing is run through the
5 blowout preventer stack and the coiled tubing head until the string
of coiled tubing reaches its desired depth in the well. This is
done while the slip assembly is in an PYr~n-7Pd passive position.
After the coiled tubing has reached the proper depth, the slip
assembly is activated externally of the tubing head, the slips
10 thereof moving to a contracted active position grippingly ~n~ging
a portion of the coiled tubing which it surrounds. Then the coiled
tubing is slightly lowered to allow the weight of the tubing string
to be totally supported by the slip assembly, the weight of the
coiled tubing also ~YrzlnAinq the sealing assembly to seal around
the coiled tubing. After the coiled tubing is so hung and sealed,
it is cut off at a point above the hanger apparatus, the injection
a~aLc.Lus and the blowout preventer stack are removed and 1 ining
wellhead equipment installed.
Thus, the apparatus and method of Ser. No. 08/308,407
allows the use of coiled tubing for production applications without
having to disconnect the tubing in jector apparatus or blowout
preventers and without having to use an access window assembly.
There is complete ~l~s:,u~e control of the well at all times. The
internal slip and seal assemblies are contained within the coiled
tubing head but are activated externally thereof. Furth. ~, the
slip assembly may be moved or retracted to an inactive or passive
21~497~
po6ition to allow the coiled tubing to be repositioned, lower or
higher in the well, without pulling the tubing.
While the a~aL~Lu:, of Ser. No. 08/308,407 is a
substantial i ~ L~ v~3111ent over the prior art, particularly in
5 production applications, the related sealing and slip assemblies
may not provide enough clearance to allow lowering of packers,
safety valves or other tools through the tubing head. There are
many situations in which it would be desirable to use such
equipment while providing the other advantages of coiled tubing.
10 ,C~ ry o~ the Presf~nt ~nventiQn
The present invention provides methods and apparatus for
installing coiled tubing and related equipment in an oil and/or gas
well. The apparatus of the present invention includes a tubing
head and hanger which, like that of Ser. No . 08/308, 407 but unlike
the prior art, is designed so that the tubing unit stripper or
blowout preventers do not have to be ~ cnnne~-ted to hang the
coiled tubing string in the well. All cnmronl~nts of the hanger
a~aL~Lu~ are internal, eliminating the need to install access
window assemblies to set the tubing in the hanger and thus
2 0 eliminating the pressure control problems associated with such .
The hanger apparatus of the present invention includes a
tubing head, having a vertical flow passage therethrough, for
tiUL _~-ting on the wellhead of the well. The flow passage includes
at least one cylindrical bore and a coaxially aligned inverted
frusto-conical recess providing an upwardly and outwardly flaring
or tapered slip seating surface. A hanger assembly is carried in
2~g76
the frusto-conical recess and includes a plurality of segmented
slip and seal members moveable between upwardly and outwardly
expanded passive positions within the recess and downwardly and
inwardly contracted active positions in which the slip and seal
5 members are engageable with coiled tubing disposed in the flow
passage to sealingly support the coiled tubing with the tubing
head. In the outwardly, expanded passive positions, the slip and
seal members lie totally outside of the diameter of the cylindrical
bore of the flow passage, providing full bore access for passage of
10 the coiled tubing and related apparatus through the tubing head.
Also carried by the tubing head are slip activation
devices which engage the hanger assembly within the recessed
portion of the flow passage and which are manipulatable externally
of the tubing head to move the slip and seal members of the hanger
assembly from passive positions to active positions. In a
preferred: ~;r L of the invention, the slip activation devices
are a plurality of screws which nay be rotated externally of the
tubing head but which extend through threaded holes for engagement
with the hanger assenbly f or movement thereof .
In the method of installing coiled tubing with the
apparatus of the present invention, the coiled tubing hanger
apparatus, which includes the tubing head and the hanger assembly
are all installed on the wellhead, completely assembled, prior to
lowering the coiled tubing into the well. A blowout preventer
stack and the coiled tubing injector apparatus are installed
thereabove. The coiled tubing, and any other equipment attached
9 7 6
thereto, is run through the blowout preventer stack and the coiled
tubing head until the string of coiled tubing reaches its desired
depth in the well. This is done while the hanger assembly is in
its expanded passive position with all components thereof
5 completely without the diameter of the cylindrical bore of the
tubing head. After the coiled tubing has reached the proper depth,
the hanger asse~bly is activated externally of the tubing head, the
slip and seal members thereof moving to contracted active positions
grippingly engaging a portion of the coiled tubing which they
10 I~ULLVUlld. Then the coiled tubing is slightly lowered to allow the
weight of the tubing string to be totally supported by the hanger
assembly, the weight of the coiled tubing also ~'Yr~n~9; n~ the seal
members of the hanger assembly to seal around the coiled tubing.
After the coiled tubing is 80 hung and sealed, it is cut off at a
15 point above the hanger apparatus. The injection apparatus and the
blowout preventer stack are removed and 1l -;n;n~ wellhead
equipment installed.
Thus, the ~ aL~l~U:i and method of the present invention
allows the use of coiled tubing for service and production
0 applications without having to disconnect the tubing injector
a~u~ or blowout preventers and without having to use an access
window assembly. There is complete pressure control of the well at
all times. The internal slip and seal members of the hanger
assembly are contained within the coiled tubing head but are
activated externally thereof. FurfhF~ e, the hanger assembly IQay
be moved or retracted from an active position to a passive position
~ 21~g7~
to allow the coiled tubing and equipment attached thereto to be
repositioned, lower or higher in the well, without pulling the
tubing. One particular object of the invention is to provide full
bore access through the tubing head when the hanger assembly is in
5 its passive position. Many other objects and advantages of the
apparatus and method of the present invention will be apparent from
reading the description which f ollows in con junction with the
accompanying drawings.
Brief Descri~tion of f h.~ 12rawi n~
Fig. 1 is a vertical elevation view of the wellhead of an
oil and/or gas well and hanger apparatus for running and hanging a
string of coiled tubing therein according to a preferred embodiment
of the invention;
Fig. 2 is a vertical elevation view, in section, of a
tubing hanger head, with combination slip and sealing hanger
assembly, ~or lowering coiled tubing therein with apparatus such
as shown in Fig. 1, the right-hand part of the drawing illustrating
the hanger assembly in its non-~n~; nq or passive position and the
left-hand part of the drawing illustrating the hanger assembly in
2 0 its engaging or active position;
Fig. 3 is a cross-section view of the coiled tubing
hanger head of Fig. 2, taken along lines 3-3 thereof, showing the
hanger assembly in its non-engaging or passive position;
Fig. 4 is a cross-sectional view of the coiled tubing
hanger head of Fig. 2, taken along lines 4-4 thereof, showing the
hanger assembly in its engaging or active position; and
~ ~ r~ ~ 9 7 ~
Fig. 5 ls a vertical elevation view of a completed
wellhead utilizing the coiled tubing hanging apparatus of the
present invention, according to a preferred ~ L thereof.
Descri~tion of Preferre~ r ~ Qf th~ Tnv~nt~on
Referring first to Fig. 1, there is shown the wellhead 1
of an oil and/or gas well which i8 to produce from a subterranean
formation many feet below the surface S. The wellhead 1 is made up
of a number of components. For example, a casing head 2 may be
attached to the upper end of an outer casing and equipped with one
or more valves 3. Another casing or tubing head 4 equipped with
one or more valves ~ may be ~iUL u..Led on the casing head 2 and may
be attached to the upper end of a smaller production casing or
tubing string. One or more tubing strings may be supported in the
tubing head 4 from a tubing hanger (not shown) at the upper end
thereof. In fact, such a tubing string may actually be the
original production tubing through which the well produces. A
master control valve 6 may be attached to the upper end of the
tubing head 4. The casing and tubing strings (not shown) supported
from the casing head 2 and tubing head 4 and/or the tubing strings
supported therein might be strings previously placed in the well at
some prior time. In any event, for purposes of illustrating the
present invention, it is to be assumed that a string of coiled
tubing is to be run into the well, the coiled tubing being
concentrically disposed within the ; nnc~ L string of jointed
pipe, either a casing string or a tubing string.
To begin running coiled tubing, a coiled tubing unit
12
~ 21~4976
which includes a tubing injector 7 would need to be brought in
place. The injector 7 is typically provided with a protective
frame 8 and mounted on adjustable support legs 9 and 10. Prior to
connection of the injector 7 for running of the coiled tubing, it
may be n~ Ary to kill the well. A coiled tubing head 20 is
installed. The coiled tubing head 20 illustrated in Fig. 1 is a
specially designed coiled tubing head which includes hanger
apparatus, including internal slip and sealing apparatus for
supporting and sealing around coiled tubing in the well. This
coiled tubing head 20 will be described in greater detail
hereaf ter . For present purposes, it should be mentioned that the
coiled tubing head 20 could already be in place or may be an
addition to existing wellhead eo~uipment. Most times, the coiled
tubing head 20 would be installed directly above the lower master
valve 6. If other wellhead equipment previously existed above the
lower master valve 6, it might have to be removed.
Mounted directly above the coiled tubing head 20 is a
blowout preventer stack 21 which would typically include four ram
type blowout preventers, tubing rams 22, slip rams 23, cutter rams
24 and blind rams 25. The blowout preventers 21 are used, of
course, as a primary means of well control during the running of
coiled tubing.
Mounted between the blowout preventer stack 21 and the
injector 7 is a stuffing box or "stripper rubber" 26 which normally
contains a split elastomeric element which is compressed against
the coiled tubing as it is in~ected into the well by the injector
13
21~4~6
7. The stripper 26 isolates the annulus wellbore ~lest,uLe from the
a i ~ re .
Tubing to be injected into the well is normally stored on
a coiled tubing reel (not shown) which may store 20,000 feet or
5 more of tubing ~ p~nAin~ upon its diameter. The tubing 28 would be
dispensed from the reel through a tubing guide 29 into the injector
7. The injector 7 does not form a part of the present invention.
There are several types of injectors which could be used. In one
design used in the industry today, the continuous coiled tubing
string is manipulated by utilizing two opposed sprocket-driven
traction chains which are powered by contra-rotating hydraulic
motors. The chains are fabricated with interlocking saddle blocks
mounted between chain links and machined to fit the particular
coiled tubing diameter with which they are to be used.
15 Hydraulically actuated compression rollers force the saddle blocks
onto the coiled tubing with enough force to establish frictional
drive. The tubing guide 29 essentially straightens the coiled
tubing as it is fed into the injector 7.
Referring now to Fig's 2, 3 and 4, the specially designed
20 tubing hanger apparatus of the present invention will be described
in detail. The coiled tubing head 20 comprises a lower body 51 and
an upper body 52 connected by a threaded pin and box connection 53
which is sealed by an annular seal 54. The upper and lower ends of
the tubing head 20 may be provided with pin and box type
c"nn~-~t;ons or with flanges 55 and 56, as shown in Fig. 2.
Radially disposed holes are provided in the flanges 55 and 56 for
14
~ 21~4~6
receiving bolts 57, 58 for connection to wellhead component6 such
as the blowout preventers 21 and the master control valve 6 of Fig.
1. The flanges 55, 56 are provided with annular grooves for
receiving seal rings 59, 60.
The body 51, 52 of the tubing hanger head 20 has a
vertical f low passage therethrough . The f low passage, in the
exemplary ~ nt of Fig. 2, comprises upper and lower
cylindrical bore sections 61, 62 joined by an intermediate section
63 formed by an inverted generally frusto-conical recess. An
outlet flow passage 65 may be provided for communication with the
annulus 66 of the lower bore 62 when a coiled tubing 28 is
concentrically positioned therein. Drilled and tapped holes 66 may
be provided on the lower body 51 around the outlet 65 to receive
the base of a valve or other component (not shown). An annular
recess 67 may be provided for an annular seal ring ~not shown).
The flow passage recess 63 formed in lower and upper
bodies 51, 52 receives a hanger assembly which comprises a
plurality, three in the exemplary embodiment, of composite slip and
seal segments 71, 72, 73. These composite slip and seal members
2 0 71, 72, 73 are moveable between upwardly and outwardly /~YrAnrl~d
passive positions, as illustrated by slip and seal members 72 in
Fig. 2, and downwardly and inwardly radially contracted active
positions, as illustrated by slip and seal members 71 in Fig. 2.
Each of the segmented slip and seal members 71, 72, 73 is
a composite of an upper slip 71a, 72a, 73a, a lower slip 71b, 72b,
73b and an intermediate seal 71c, 72c, 73c. The upper and lower
~ 2~ 76
slips would be of rigid materials such as steel. The intermediate
seal would be of an elastomeric material bonded or otherwise
sandwiched to and between the upper and lower slips. The outer
surfaces of at least the upper and lower slips 71a-c and 73a-c
substantially define, when in the contracted active positions of
Fig. 4, an inverted frustrum of a cone. This inverted ~Lu~LL.uLI of
a cone corresponds with and engages the upwardly and outwardly
tapered or flared frusto-conical slip seating surfaces 51 provided
on the lower tubing head body 51 and defining the lower limits of
recess 63.
As earlier stated, the slip and seal segments 71, 72, 73
are moveable between upwardly and radially outwardly expanded
passive positions within recess 63, as illustrated in Fig. 3 and in
the right hand half of Fig. 2 and downwardly and radially inwardly
contracted active positions, as illustrated in Fig. 4 and in the
left hand half of Fig. 2. In the radially ~Yr~n~erl passive
positions, the slip and seal members 71, 72 and 73 are separated by
spaces 74, 75 and 76 (See Fig. 3) and lie totally without the
diameter of cylindrical bores 61, 62. Thus, with the slip and seal
2 0 member 71, 73 and 73 in the passive position, the coiled tubing 28
and/or any other piece of equipment which can pass through the full
bores 61, 62 can be raised or lowered through the tubing hanger
head 2 0 .
It will be noted that the inner cylindrical surfaces of
at least the upper slips 71a, 72a and 73a are provided with
upwardly directed frictional engaging surfaces, such as teeth 77,
16
~ 9~6
78, 79. When the slip and seal members 71, 72 and 73 are in the
radially contracted active positions they essentially encircle the
coiled tubing 28, as best illustrated in Fig. 4. In this position,
teeth 77, 78 and 79 engage the coiled tubing 28. If the weight of
the tubing 28 is then supported by slip and seal members 71, 72,
73, the wedging action between the slip and seal members 71, 72, 73
and the fru6to-conical surface 51a will cause the seal members 71c,
72c, 73c to be squeezed and axially contracted between upper and
lower slips 71a, 72a, 73a and 71b, 72b and 73b, respectively. As
this occurs the seal members 71c, 72c and 73c also expand outwardly
against surface 51a and inwardly against coiled tubing 28 creating
a fluid tight annular seal between the coiled tubing 28 and the
hanger head body 51.
To provide for moving the slip and seal members 71, 72,
73 between the passive positions o~ Fig. 3 and the right hand half
of Fig. 2 and the active positions of Fig. 4 and the left hand half
of Fig. 2, slip activation iles~mhl ;es, one for each, are provided.
Although there are three in the exemplary ~ , only two slip
activation assemblies 101, 102 are visible in Fig. 2. The upper
slips 71a, 72a, 73a of the slip and seal members 71, 72, 73 are
provided with inclined cylindrical recesses 91, 92, 93 which are
engageable by the inner ends of slip activation assemblies 101,
102, 103, one for each slip member 71a, 72a, 73a, which are
manipulatable externally of the tubing head 20 to move the slip and
seal members 71, 72, 73 from the passive or inactive position of
Fig. 3 to an active position ( see Fig . 4 ) in which the gripping
17
2~ 76
means 77, 78, 79 on the upper slips 71a, 72a, 73a engage the coiled
tubing 28.
In the preferred ~ , the slip activation
assemblies 101, 102, 103 include slip activation screws 105, 106,
5 107, the upper ends of which are threaded to engage corresponding
threads of gland nuts 111, 112 in a threaded connection. The gland
nuts 111, 112 have reduced diameter threaded portions 113, 114
which engage corr~p~-n~l;ng threaded holes in the upper body 52
abutting annular packing 115, 116 which seals the interior of the
tubing head 20 from the exterior thereof. The lower ends of the
slip activation screws 105, 106, 107 are provided with enlarged
heads 105a, 106a, 107a which engage the corrPspon~lin~ cylindrical
recesses 91, 92, 93 of slips 71a, 72a, 73a and are maintained
therein by retainer plates 95, 96, 97 attached to the top of each
upper slip 71a, 72a, 73a. These retainer plates 95, 96, 97 are
provided with holes which allow reciprocation of the lower ends
105, 106, 107 of the slip activation screws but do not allow escape
of the enlarged heads 105a, 106a, 107a thereof. Rotation and
extension of the activation screws 105, 106, 107 toward the flow
passage 61, 62, 63 will force the slip and seal members 71, 72, 73
to move downwardly and inwardly toward the contracted active
position of Fig. 4. Rotation of the activation screws 105, 106,
107 ~n the opposite direction results in retraction of the
activation screws, effecting upward and outward v~ L of the
slip and seal members 71, 72, 73 to the f~Yr~nrl~fl, passive or
inactive positions of Fig. 4.
18
76
Referring now to Fig's 1 - 5, operation of the apparatus
of the present invention and the method of installing coiled tubing
in a well therewith will be described. As previously mentioned
with reference to Fig. 1, the coiled tubing head 20, with the slip
and seal assemblies 71, 72, 73 previously installed as in Fig. 2,
is mounted on one of the components of the wellhead 1 such as the
master valve 6. The blowout preventer stack 21 is mounted on the
coiled tubing head 20 and the coiled tubing injector apparatus,
i.e. stripper 26, injector head 7, etc. are attached to the blowout
preventers 21. Then the coiled tubing 28 and any other attached
equipment which can pass through bores 61 and 62 could be run
through the blowout preventer stack 21, the coiled tubing head 20
and the casing head 2 until the string of coiled tubing 28 and/or
other equipment reacnes the desired depth in the well.
As indicated, the seal members 71c, 72c, 73c of the slip
and seal members 71, 72, 73 are in the inactive or passive
positions of Fig. 3 and the right hand half of Fig. 2 as the coiled
tubing is being run into the well. Once the coiled tubing 28
reaches the desired depth, the slip and seal members 71, 72, 73 are
activated externally of the coiled tubing head 20 by rotating the
slip activation screws 105, 106, 107 until the slip and seal
members 71, 72, 73 move downwardly and inwardly to the contracted
active positions, grippingly engaging a portion of the coiled
tubing 28 ,,u~L~ullded thereby. When this occurs, the coiled tubing
28 is slightly lowered to allow the weight thereof to be totally
supported by the slip and seal members 71, 72, 73. The upper slips
1~
9 7 6
71a, 72a, 73a transfer the weight of the coiled tubing 28 to the
seal members 71c, 72c, 73c. As this occurs, the seal members 71c,
72c, 73c are axially compressed and expand inwardly and outwardly
to sealingly engage the coiled tubing 28 and the ~,uLl~ul~ding
5 surface 51a of the frusto-conical recess 63 in which the slip and
seal assemblies 71, 72, 73 are disposed. See Fig. 4 and the left
hand half of Fig. 2.
If for any reason, it is determined that the coiled
tubing 28 needs to be repositioned, lower or higher, or removed,
lO the weight of the coiled tubing 28 is first released from the slip
and seal members 71, 72, 73 by picking it up with the injector
apparatus 7. Then the slip and seal members 71, 72, 73 are
deactivated e~ternally of the tubing head 20 by rotating the
activation screws 105, 106, 107 in the opposite direction,
retracting the activation screws 105, 106, 107 and moving the slip
and seal members 71, 72, 73 from their active contracted positions
back to the ~Y~;Indl~cl passive positions. Since the weight of the
coiled tubing 28 is then removed, the seal members 71c, 72c, 73c
will assume the relaxed or nonset position. The coiled tubing may
be repositioned, higher or lower in the well, and the slip and seal
members 71, 72, 73 reactivated externally of the tubing head 20 so
that they return to the contracted active positions grippingly
engaging a portion of the coiled tubing 28 ~ULL~UIIded thereby. The
coiled tubing 28 may then again be slightly lowered to allow the
weight thereof to again be supported by the upper and lower slips
71a, 72a, 73a and 71b, 72b, 73b and the seal members 71c, 72c, 73c,
215~976
.
the weight thereof causing the seals 71c, 72c, 73c to again seal
around the coiled tubing 28.
Once the coiled tubing is properly positioned in depth,
the 81ip and seal members 71, 72, 73 properly set and sealed, the
blowout preventer stack 21 and the injection apparatus 7 may be
removed. At some point in this process, the coiled tubing 28 is
cut at a point above the tubing head 20. Then additional wellhead
equipment such as an adapter 119, an upper master valve 120, and
other flow connections of a well manifold or Christmas tree 121 may
be installed. See Fig. 5.
Thus, the apparatus and method of the present invention
allows the running of coiled tubing into a well for production of
fluids from the well or the running of other equipment therein with
complete pressure control of the well at all times. The unique
coiled tubing head and hanger apparatus contained therein
eliminates the need for an access window assembly and the potential
pressure control problems associated therewith. The hanger slip
and seal members of the present invention are initially positioned,
prior to the running of the coiled tubing, so that there is no
2 0 possibility of them being improperly disposed as in the case of
prior art apparatus in which the hanger, ~ ~ts must be wrapped
around the coiled tubing through access windows and dropped down
into a tubing head, sight unseen, with potential setting problems.
The apparatus and method of utilizing the apparatus of the present
invention in running of coiled tubing and associated apparatus is
unique and is a substantial i ~ ov~ L over the prior art.
21
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A single embodiment of the apparatus of the present invention
and method of use thereof have been described herein. However, many
variations in the apparatus and methods of its use can be nade
without departing from the spirit of the invention. Accordingly, it
5 is intended that the scope of the invention be limited only by the
claims which follow.
