Note: Descriptions are shown in the official language in which they were submitted.
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Drilling Rig Apparatus
and Downhole Tool
Assembly System and Method
FIELD OF THE INVENTION
The invention relates to oil and gas drilling rigs,
and in particular oil and gas drilling rigs used to drill using
both coiled tubing and jointed-pipe.
BACKGROUND OF THE INVENTION
The use of coiled tubing (CT) technology in oil and
gas drilling and servicing has become more and more common in
the last few years. In CT technology, a continuous pipe wound
on a spool is straightened and pushed down a well using a CT
injector. CT technology can be used for both drilling and
servicing.
The advantages offered by the use of CT technology,
including economy of time and cost are well-known. As compared
with jointed-pipe technology wherein typically 30-45 foot
straight sections of pipe are connected one section at a time
while drilling the well bore, CT technology allows the
continuous advancement of piping while drilling the well
significantly reducing the frequency with which such drilling
must be suspended to allow additional sections of pipe to be
connected. This results in less downtime, and as a result, an
efficiency of both cost and time.
However, the adoption of CT technology in drilling
has been less widespread than originally anticipated as a
result of certain problems inherent in using CT in a drilling
application. For example, because CT tends to be less robust
than jointed-pipe for surface-level drilling, it is often
necessary to drill a pilot hole using jointed-pipe, cement
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casing into the pilot hole, and then switch over to CT
drilling. Additionally, when difficult formations such as
boulders or gravel are encountered down-hole, it may be
necessary to switch from CT drilling to jointed-pipe drilling
until the formation is overcome, and then switch back to CT
drilling to continue drilling the well. Similarly, when it is
necessary to perform drill stem testing to assess conditions
downhole, it may again be necessary to switch from CT drilling
to jointed-pipe drilling and then back again. Finally, a
switch back to jointed-pipe operations may be necessary to run
casing into the drilled well. These types of situations
require the drilling manager to switch back and forth between
CT drilling rigs and jointed-pipe drilling rigs, a process
which results in significant down-time as one rig is moved out
of the way, and another rig put in place.
Another disadvantage of CT drilling is the time-
consuming process of assembling a BHA (bottom-hole-assembly -
the components at the end of the CT for drilling, testing,
etc.), and connecting the BHA to the end of the CT. Presently,
this step is performed manually through the use of rotary
tables and make/breaks. Not only does this process result in
costly down-time, but it can also present safety hazards to the
workers as they are required to manipulate heavy components
manually.
SUMMARY OF THE INVENTION
This invention provides an improved rig for drilling
oil and gas wells. The rig includes components which permit
both coiled tubing and jointed-pipe drilling with a minimum of
steps and time required to switch between the two. The setup
of the rig also allows the easy and time-efficient assembly of
bottom hole assemblies (BHA's), and their connection to coiled
tubing.
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In a broad aspect, the present invention provides a
rig for drilling a well, comprising a base, a mast mounted on
said base, a top drive operable to engage and rotate downhole
equipment slidably mounted on said mast for longitudinal
sliding along said mast, and a coiled tubing injector operable
to move coiled tubing in and out of said well mounted on said
mast such that the coiled tubing injector may be selectively
transposed between a first position in which the injector is in
line with the mast, to a second position in which the injector
is out of line with the mast to accommodate manipulation of
down-hole equipment by the top drive.
In another aspect, the present invention provides a
BHA (bottom hole assembly) assembling system for assembling a
BHA for use in coiled tubing drilling, said BHA assembling
system comprising a base, a mast mounted on said base, a top
drive operable to engage and rotate BHA elements slidably
mounted on said mast for longitudinal sliding along said mast,
a coiled tubing injector operable to move coiled tubing on to
and off of a BHA mounted on said mast such that the coiled
tubing injector may be selectively transposed between a first
position in which the injector is in line with the mast, to a
second position in which the injector is out of line with the
mast to accommodate manipulation of BHA elements by the top
drive, and a rotary table operable to engage and rotate BHA
elements, mounted on said base in line with the mast.
In a further aspect, the present invention provides a
method of assembling a plurality of threaded BHA (bottom hole
assembly) elements into a BHA for use in coiled tubing
drilling, each of said BHA elements having an upper end and a
lower end. The method uses a BHA assembling system having a
base, a mast mounted on said base, a top drive operable to
engage and rotate BHA elements slidably mounted on said mast
for longitudinal sliding along said mast, a coiled tubing
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injector operable to move coiled tubing on to and off of a BHA
mounted on said mast such that the coiled tubing injector may
be selectively transposed between a first position in which the
injector is in line with the mast, to a second position in
which the injector is out of line with the mast to accommodate
manipulation of BHA elements by the top drive, and a rotary
table mounted on said base in line with the mast, operable to
engage and rotate BHA elements. This method comprises:
a) transposing the coiled tubing injector to its second
position in which the injector is out of line with the mast;
b) sliding the top drive to a position along the mast in
spaced relation to the rotary table;
c) placing a bottom element of the BHA into the rotary
table;
d) operating the rotary table to engage the bottom
element of the BHA;
e) placing a second element of the BHA such that its
upper end is adjacent to the top drive;
f) operating the top drive to engage the second element
of the BHA;
g) positioning the second element such that its lower
end is adjacent to the upper end of the bottom element of the
BHA;
h) operating said top drive and/or said rotary table to
rotate the second element and/or the bottom element relative to
each other so as to screw the two elements together;
i) operating the top drive to disengage the second
element of the BHA;
j) sliding the top drive along the mast to a position in
spaced relation to the second element;
k) repeating steps e) through j) for the remaining
elements of the BHA;
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1) sliding the top drive along the mast to a position
above the coiled tubing injector;
m) transposing said coiled tubing injector to its first
position in which the injector is in line with the mast;
n) operating said coiled tubing injector to move coiled
tubing having a threaded end, to a position adjacent the
assembled BHA;
o) operating said rotary table to rotate the BHA so as
to screw the BHA onto said threaded end of the coiled tubing;
and
p) operating said rotary table to disengage the BHA.
BRIEF DESCRIPTION OF THE DRAWINGS
Preferred embodiments of the invention will now be
described with reference to the attached drawings in which:
Figure 1 is a side view of a preferred embodiment of
the rig of the present invention shown in jointed-pipe drilling
mode;
Figure 2 is a top view of a trailer of the rig of
Figure 1;
Figure 3 is a front view of the rig of Figure 1;
Figure 4 is a rear view of the rig of Figure 1;
Figure 5 is a side view of the rig of Figure 1 shown
in jointed-pipe pick-up mode;
Figure 6 is a side view of the rig of Figure 1 shown
in CT drilling mode;
Figure 7 is a side view of the rig of Figure 1 shown
in transportation mode;
Figure 8 is a perspective view of an injector dolly
of the rig of Figure 1;
Figure 9 is a top view of a mast of the rig of Figure
1;
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Figure 10 is a bottom perspective view of the mast of
the rig of Figure 1;
Figure 11 is a top perspective view of a substructure
of the rig of Figure 1; and
Figure 12 is a perspective view of a spool of the rig
of Figure 1.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
A preferred embodiment of the rig of the present
invention is shown in the attached drawings. Its basic
features are shown in Figure 1.
In a broad sense, this rig includes a base, a mast,
and drilling components.
In this preferred embodiment, the base is a wheeled
carrier or trailer 20 which is adapted to be pulled by a
motorized vehicle. The trailer 20 has wheels 22 located near
its rear, and a hitch 24 located near its front for attachment
to a motorized vehicle (not shown). The trailer 20 also has a
lowered middle portion 26 so as to lower the center of gravity
of the components placed on this portion of the trailer 20.
While the wheeled carrier of the preferred embodiment rig has
been described and illustrated as being one which is adapted to
be pulled by a motorized vehicle, it is to be understood that
the wheeled carrier may itself be self-propelled.
The trailer 20 has mounted thereon retractable
outriggers or stabilizer legs 28 for stabilizing and levelling
the rig for drilling. Three stabilizer legs 28 are located on
each side of the rig, at the front of the lowered middle
portion 26, the rear of the lowered middle portion 26 and at
the rear of the trailer 20. The stabilizer legs 28 have
pontoons (not shown) mounted at their ends to ensure positive
contact with the ground. In the preferred embodiment rig, a
single long pontoon is attached to the front two legs 28 on
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each side of the rig, while a shorter pontoon is attached to
the rear leg 28 on each side.
Near the rear of the trailer is mounted a drilling
substructure 30, essentially a raised platform supporting a
rotary table 32, as seen in Figure 11, and a mast 34. Stairs
36 are attached to the substructure 30 to allow workers to
ascend to the substructure 30.
The rotary table 32 is a collar adapted to engage
down-hole equipment including tubing (coiled tubing or jointed-
pipe for example) through the use of slips or wedges (not
shown), and which is hydraulically powered for rotation. The
rotary table 32 is used to engage and rotate (or prevent
rotation of) equipment inserted therein. The substructure 30
also has mounted thereon BOP hangers (not shown) below the
rotary table 32 to allow raising and lowering of BOP's (blow-
out preventers) off of, and onto a wellhead.
The mast 34 is pivotally attached to the substructure
30 at mast mounting pins 38 for pivotal movement between a
horizontal transportation position as shown in Figure 7, and a
vertical operating position as shown in Figure 1. Although not
illustrated, the rig could be modified such that the mast 34
could also operate at any operating angle in between the
horizontal and vertical position to permit off-vertical
drilling. Such modifications would include providing a support
for the mast at off-vertical angles, and modifying the
placement of the rotary table 32 and BOP hangers to
accommodating tilting of these elements with the mast. The
vertical / horizontal orientation of the mast is controlled by
a hydraulic cylinder 40 connected at its ends to the trailer 20
and the mast 34.
A coiled tubing injector platform 42 is mounted on
the front of the mast 34 near the point at which the mast 34 is
pivotally attached to the substructure 30, in the preferred
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embodiment at about 12 feet up the mast 34. Forming part of
the injector platform 42 are two sets of v-rails 44 (one set
shown in Figure 10) extending substantially perpendicularly
from the mast 34. These v-rails 44 are located on either side
of the interior of the injector platform 42.
Riding on these v-rails 44 is an injector dolly 46
(shown in detail in Figure 8). The injector dolly is a box-
shaped component having mounts for receiving a coiled tubing
injector 48, and four v-groove rollers 50 located on either
side for riding on the v-rails 44 of the injector platform 42.
Located below the injector dolly 46 is a lubricator winch 52
whose purpose is discussed in greater detail below. The
movement of the injector dolly 46 on the v-rails 44 is
controlled by injector hydraulic cylinders (not shown)
connected at their ends to the injector dolly 46 and the
injector platform 42. The injector hydraulic cylinders are
used to selectively move the injector dolly 46 and the coiled
tubing injector 48 mounted thereon between a first position in
which the injector is in line with the mast 34, and a second
position in which the injector 48 is out of line with the mast
34 so as to allow other componentry to use the mast 34, as
discussed further below.
The coiled tubing injector 48 is mounted atop the
injector dolly 46 and consists of a series of rollers and
guides (not shown in detail) used to push, pull and guide
coiled tubing 54 into and out of the well. The structure and
functionality of coiled tubing injectors are well known and
will not be discussed in detail herein. Extending from the top
of the injector 48 is an injector arch 56 used to guide the
coiled tubing 54 in a gentle arch prior to entry into the
injector 48. Extending below the injector 48 is a telescoping
lubricator 58 which serves to guide the coiled tubing 54 as it
exits the injector 48. The lubricator 58 is telescoping to
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permit access to the coiled tubing 54 during connection /
disconnection with a bottom hole assembly as further discussed
below. The lubricator 58 is extended or contracted by the
lubricator winch 52 located below the injector dolly 46.
In the preferred embodiment rig of the present
invention, the coiled tubing injector 48 is fixed along the
mast, rather than slidable along said mast. A fixed injector
48 results in a reduction in cost, simplicity of design and
operation, reduction in weight, ease of collapsibility of the
mast 34 into transportation position, and safety during
transportation. It is to be understood however, that a sliding
injector 48 may also be used in accordance with other
embodiments of the present invention.
The mast 34 of the preferred embodiment rig is
composed in part of square tubing (not shown) running along a
substantial portion of the length of the mast 34. Riding
along, and slidable on this square tubing is a top drive 60
operable to engage and rotate downhole equipment (which
equipment may or may not be in the well when engaged or rotated
by the top drive 60) such as jointed-pipe, bottom hole assembly
(BHA) elements, etc. As with the coiled tubing injector 48,
the structure and functionality of top drives 60 are well known
in the field and will not be discussed in detail herein. The
top drive 60 of the preferred embodiment rig has on its
underside, in line with the mast, a threaded engagement element
(not shown) for threaded engagement with downhole equipment.
As shown in Figure 5, the top drive 60 also has pivotally
connected to its underside, a pivotal engagement element
consisting of links 62 extending downward, at the ends of which
are mounted elevators 64. The links 62 are elongated arms
which are pivotally connected to the underside of the top drive
60 by a pin-and-bolt connection. The angle at which the links
62 are situated at a given time is controlled by hydraulic
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cylinders (not shown) connected to the links 62 and to the body
of the top drive 60. The elevators 64 are adapted to engage
down-hole equipment such as jointed-pipe, casing, or BHA
elements, but to also allow down-hole equipment to pass
therethrough when upward force is exerted on the down-hole
equipment, so as to engage the threaded engagement element.
Typically, such down-hole equipment have a bulge or "tool
joint" at their upper ends to accommodate engagement by tools
such as elevators 64. The function of the links 62, the
elevators 64 and the hydraulic cylinders controlling the angle
of the links is to allow the top drive 60 to engage downhole
equipment which are not necessarily in line with the mast.
This feature allows the top drive 60 to pick up downhole
equipment from a transport truck, for example, for placement
into the well, as discussed further below.
The vertical movement of the top drive 60 along the
mast 34 is controlled by a top drive winch 66 mounted on a
winch platform 68 (shown in Figure 10) which itself is mounted
on the mast 34 above the injector platform 42. The winch 66
is motorized and winds or unwinds cabling in a controlled
manner. This cabling extends from the top drive winch 66 up to
the crown 70 of the mast 34, over pulleys 72, and down along
the mast to the top drive 60. Thus, by operating the top drive
winch 66, the movement of the top drive 60 along the mast 34 is
controlled.
Near the forward end of the lowered middle portion 26
of the trailer 20 is a spindle 74 for mounting a coiled tubing
spool 76. The spindle 74 (shown in detail in Figure 12)
consists of a pair of geared U-shaped brackets supported above
the bed of the trailer 20. The spindle 74 also has a pair of
closures (not shown) to fully engage the coiled tubing spool 76
once it is in place. The coiled tubing spool 76 is a spool
having wound thereon coiled tubing 54. The coiled tubing spool
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76 is rotated during drilling operations by a spool drive motor
78 connected to the spindle 74 by chains or belts 80. As
coiled tubing 54 exits the coiled tubing spool 76 during
drilling operations, it is guided and straightened by a coiled
tubing guidance system, in this case a level wind 82 projected
above the spindle 74. From the level wind 82, the coiled
tubing 54 extends up to the injector arch 56. The coiled
tubing guidance system also serves to wind the coiled tubing 54
evenly across the coiled tubing spool 76 when the coiled tubing
54 is being rewound back onto the spool 76. In the alternative
to a level wind 82 which guides incoming coiled tubing 54 back
and forth across the coiled tubing spool 76, the guidance
system may also be for example a traversing system which moves
the coiled tubing spool 76 itself back and forth.
Also located on the trailer 20 are an engine 84 fox
providing the power required to operate the various drilling
components, a hydraulic tank 86 for storing hydraulic fluids
for use in operating the various hydraulic cylinders located on
the rig, a hydraulic cooler 88 for cooling the hydraulic fluid,
a fuel tank 90 for storage of fuel for the engine 84, and a
mast rest 92 located near the front of the trailer 20 extending
above the trailer for supporting the mast 34 when the mast 34
is in transportation position.
In the preferred embodiment rig, each of the winch
platform 68, the injector platform 42, the spindle 74, as well
as the engine 84, hydraulic tank 86, hydraulic cooler 88, fuel
tank 90 are located on the trailer 20 and on the mast 34 such
that when the mast 34 is lowered into its transportation
position such that the mast 34 is substantially horizontal,
none of these elements impinges on the other elements.
In operation, the rig is stored and transported with
the mast 34 in its transportation position, namely with the
mast 34 in a substantially horizontal position. Once a site
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for a well has been identified, the trailer 20 of the preferred
embodiment of the present invention is positioned such that the
mast 34 when erected will be in line with the axis of the well
to be drilled. When the trailer 20 is in position, the
stabilizer legs 28 are extended such that their pontoons engage
the ground. The stabilizer legs 28 are then adjusted so as to
level the trailer 20. The mast 34 is then erected from its
transportation position to its operating position wherein (in
the case of the preferred embodiment rig of the present
invention) the mast 34 is vertical. If a coiled tubing spool
76 is not already mounted on the spindle 74, one is put in
place, and then the coiled tubing 54 is threaded through the
level wind 82 up through the injector arch 19 and into the
coiled tubing injector 48.
In a typical drilling application, the top drive 60
will then be used to drill a pilot hole using jointed-pipe.
The process of jointed-pipe drilling is well known to those in
the relevant field and is not discussed in detail here. The
coiled tubing injector 48 is moved to its second position
during this procedure, using the injector cylinders (not
shown), such that the injector 48 is out of line with the mast
34 to allow the top drive 60 to drill using jointed-pipe.
Once a pilot hole has been drilled, casing (not
shown) will typically be run into the pilot hole using the top
drive 60 and cemented in place. Again, this process is well
known to those in the field. The well is then ready for coiled
tubing drilling.
The first step in the coiled tubing drilling stage
using the preferred embodiment rig of the present invention is
to assemble a bottom hole assembly (BHA) and connect it to the
end of the coiled tubing 54. As this preferred embodiment rig
is uniquely suited to perform this task in an efficient manner,
this procedure will be discussed in some detail.
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The BHA typically consists of the various elements to
be located at the end of the coiled tubing 54 to allow coiled
tubing 54 to be used for drilling. Of course the BHA may
additionally, or alternatively consist of other down-hole
equipment such as sensors or samplers used to determine
properties of a particular down-hole formation. Typical
drilling elements included in a drilling BHA include a bit, a
mud motor, drill collars, and survey tools. Each of the BHA
elements is typically threaded at its lower and upper ends so
as to permit threaded engagement with each other, as well as
with the threaded end of the coiled tubing 54.
During the first series of steps, it is necessary for
the coiled tubing injector 48 to be placed in its second
position in which the injector 48 is out of line with the mast.
The top drive 60 is moved to a position near the bottom of the
mast 34, but still some distance above the rotary table 32 so
as to allow the insertion of BHA elements therebetween.
A bottom element of the BHA is then positioned such
that it is in line with the mast 34 between the rotary table 32
and the top drive 60. Typically, the BHA elements are brought
to the well site on a transport truck, and the BHA elements are
placed into position using hydraulic lifting racks, a crane, an
auxiliary winch located near the top of the mast 34, or by
other suitable means. This bottom element is then moved
downward so as to be inserted into the rotary table 32. This
first step may also be accomplished using the top drive in a
manner similar to that described below for the remaining
elements of the BHA. The rotary table 32 is then operated to
engage the bottom element of the BHA.
Next, the hydraulic cylinders controlling the angle
of the links 62 are operated to push the links out at a
suitable angle, and a second element of the BHA is positioned
such that its upper end is adjacent to the elevators 64 of the
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top drive 60. Typically, the second element of the BHA would
be positioned at an angle to the mast 34 at this point. The
elevators 64 are then operated so as to engage this second
element of the BHA. Because the links 62 to which the
elevators 64 are mounted are connected to the remainder of the
top drive 60 through a pivotal connection, this process of
engaging the second element of the BHA can take place even when
the second element of the BHA is not parallel to the mast 34.
If necessary, the top drive 60 is then moved upward using the
top drive winch 66 to position the second element of the BHA
such that it is in line with the mast 34. The top drive 60 is
then lowered until the lower end of the second element of the
BHA is adjacent to the upper end of the bottom element. By
further lowering the top drive 60, the second element of the
BHA is pushed up through the elevators 64, between the links
62, to lie adjacent to the threaded engagement element of the
top drive 60. The top drive 60 and/or the rotary table 32 are
then operated to allow the top drive 62 to threadedly engage
the second element of the BHA, and then to rotate the second
element of the BHA and the bottom element of the BHA. relative
to each other so as to threadedly engage the second element of
the BHA with the bottom element of the BHA. Optionally, the
rotary table 32 may be operated at this point to release the
bottom element, the top drive 60 may be moved down the mast 34
such that the second element is inserted into the rotary table
32, and then the rotary table 32 may be operated to engage the
second element of the BHA. The top drive 60 is then operated
to disengage the second element of the BHA.
The steps in the above paragraph are then repeated
for the remaining elements of the BHA. When the final element
of the BHA has been screwed into the BHA, the rotary table 32
typically releases the BHA., and the top drive 60 moves the BHA
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partly into the well. The rotary table 32 then engages the BHA
again, and the top drive 60 disengages the BHA.
The top drive 60 is then moved to a location above
the coiled tubing injector 48 so as to move it out of the way.
The lubricator winch 52 is then operated to retract the
lubricator 58, and the coiled tubing injector 48 is moved to
its first position wherein the injector 48 is in line with the
mast 34. Next, the coiled tubing injector 48 is operated to
move coiled tubing 54 to a position such that its threaded end
is adjacent to the upper end of the BHA. The rotary table 32
is then operated to rotate the BHA relative to the coiled
tubing so as to connect the two in threaded engagement, and the
lubricator 58 is extended.
Finally, the rotary table 32 releases the BHA, and
the coiled tubing injector 48 is operated to drill the well.
When necessary to switch from coiled tubing
operations to jointed-pipe operations, the coiled tubing 54 is
extracted from the well such that the BHA is suspended below
the coiled tubing injector 48. The coiled tubing injector 48
is then moved to its second position in which the injector 48
is out of line with the mast, so as to allow the top drive 60
to perform jointed-pipe operations.
When necessary to switch from jointed-pipe operations
to coiled tubing operations, the jointed-pipe is extracted from
the well and moved out of the mast. The coiled tubing injector
48 is then moved to its first position in which the injector 48
is in line with the mast so as to be in a position to perform
coiled tubing operations.
It is to be understood that the precise steps and the
precise order of these steps do not need to be exactly as
described above for the operation of the preferred embodiment
rig of the present invention. Steps may be reordered, steps
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may be omitted, or other steps may be inserted without
necessarily departing from the method of the present invention.
It is further to be understood that the particular
configuration of the various components of the rig, and their
relative location need not necessarily be exactly as described
above.
It is also to be understood that the drilling rig of
the present invention may also be used to set casing using the
top drive once drilling has been completed. The rig can also
be used for drill stem testing using the top drive and jointed-
pipe.
Numerous modifications and variations of the present
invention are possible in light of the above teachings. It is
therefore to be understood that within the scope of the
appended claims, the invention may be practised otherwise than
as specifically described herein.
