Note: Descriptions are shown in the official language in which they were submitted.
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1
CONTINUOUS CIRCULATION DRILLING METHOD
FIELD
This invention relates to drilling wells, and more particularly, to methods
and
apparatus for drilling wells much more efficiently and effectively so as to
substantially
reduce the mufti-million dollar cost of drilling a well.
BACKGROUND
~. o
It is well known in the drilling industry, and particularly in the field of
drilling for oil,
natural gas and other hydrocarbons, that drill strings comprise a large
plurality of
tubular sections, hereinafter "tubulars", which are connected by male threads
on the
pins and female threads in the boxes. It is also well known that such tubulars
must be
added to the drill string, one-by-one, or in "stands" of 2 or 3 connected
tubulars, as
the string carrying the drill bit drills into the ground; a mile more below
ground being
common in the oil drilling art. For various reasons during the drilling, and
after the
bore hole has been drilled, it is necessary to withdraw the drill string, in
whole or in
part. Again, each tubular or stand must be unscrewed, one-by-one, as the drill
string is
2 0 brought up to the extent required.
With prior art systems, each time that a tubular is added or removed it is
necessary to
stop the drilling process, and the circulation of drilling fluid. This
presents a costly
delay in the overall drilling operation. This is because the circulation of
drilling fluids
is extremely critical to maintaining a steady down hole pressure and a steady
and near
constant Equivalent Circulating Density (ECD) as is well known in the drilling
art.
Also, when tripping the drill string into or out of the well, the lack of
continuous
circulation of a drilling fluid causes pressure changes in the well which
increases the
probability of "kicks" as is well known.
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In addition to the drilling operation, the placement of casings in the bare
hole is also
necessary. As in the case of tubulars, the placement of casing sections in the
prior art
presents the same fundamental problems. That is, the flow of drilling fluids
must be
halted, and the drill string must be withdrawn in its entirety before the
casing can be
run into the well, which in some instances requires circulation of fluids and
rotation of
the casing.
STTIVINIARY
The present invention substantially reduces the time and cost of drilling
operations by
making it possible to continuously circulate drilling fluids while tubulars
are added or
removed, and also as casing strings are run into the bore hole. In addition,
the present
invention makes it possible to continue to rotate the drill string, if
desired, while adding
or removing tubulars. Bearing in mind that hundreds of tubulars are required
per mile
of drill string, the present invention eliminates hundreds of interruptions of
the
circulation of drilling fluids and a like number of breaks in the rotation of
the drill
string and the drilling operation per mile of drilling.
BRIEF DESCRIPTION OF DRAWINGS
FIGS. 1 - 3 are simplified, side elevational schematics of the structural
elements of
three embodiments of the present invention;
FIG. 3A is a simplified elevational view, partly in cross-section, further
illustrating one
embodiment of the invention;
2 5 FIGS. 4A - 6A are simplified, side elevational schematics of the
operational mode of
the embodiment of the invention shown in FIG. 3;
FIG. 7 is a schematic elevational view in cross-section of one preferred
embodiment of
the present invention;
FIGS. 8A-8H are schematic elevational views, in cross-section, showing the
3~ operational method of the FIG. 7 embodiment;
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FIG. 9 is a side elevational view, partly in cross section, showing one
embodiment of
the present invention in greater detail;
FIG. 9A is a cross-sectional view taken along view line 9A - 9A of FIG. 9;
FIG. 9B is a cross-sectional view taken along view line 9B - 9B of FIG. 9;
FIG. 9C is the same cross-sectional view with the grips extended;
FIG. 9D is an elevational plan view taken along view line 9D - D of FIG. 9B
with the
outer casing removed for clarity;
FIG. 10 is an enlarged view of the lower portion of FIG. 9;
FIG. 11 is. a cross-sectional view taken along view line 11- 11 of FIG. 1 1A
FIGS. 11A and 11B comprise a composite cross-sectional view taken along view
lines
llAand 11B ofFIG. 11;
FIGS. 12 to 19 are elevational views, partly in cross-section illustrating the
relative
positions of the components as a new tubular is connected to the string;
FIGS. 20, ZOA and 20B schematically illustrate the different positions in
which the
grips and slips may be located in the present invention; and
FIGS. 21 - 27 are elevational views, partly in cross-section, illustrating
another
embodiment of the present invention in which the grips are positioned outside
of the
coupler.
DETAILED DESCRIPTION
Referring first to FIG. 1, numeral 10 indicates a conventional power drive,
known in
the art as a "top drive", and the top drive is provided with an inlet 11 for
receiving
drilling fluid as is well known. Top drive carries a conventional "saver sub"
12, and
tubular 13 includes a threaded male pin 15 and a threaded female box 14 or
upset as is
conventional in oil drilling. Tubular 13 may be positioned vertically above
drill string
16 by known handler 5 17A-17B. Of course, instead of tubulars, it will be
understood
that casing sections may be similarly positioned by the handlers for insertion
into the
bore hole by the present invention.
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Surrounding string 16 is one example of a preferred coupler 18 according to
the
principles the present invention. Coupler I8 comprises a pressure resistant
hull or
casing 19, which may be integral With a stack 20 of conventional blow out
preventers
(BOP's) . In the embodiment of FIG. 1, coupler 18 includes a plurality of
elements in
vertical arrangement as follows. Numerals 22A and 22B indicate upper and lower
high
pressure fluid seals. In this regard it will be understood that such seals may
be
conventional BOP's or RBOP's or annular preventers as known, or may be any
other
type of seal capable of withstanding the particular fluid pressure in a given
drilling
operation. Below seal 22A is a valve 23 which is illustrated as having
horizontally
movable valve portions 23A and 23B. These portions may be moved from the open
position as shown to a closed position in which the valve portions engage each
other to
form a fluid tight seal. Thus, valve 23 divides coupler 1.8 into upper and
lower
chambers 21A and 21B which may be fluid sealed from each other. For example,
it will
I5 be understood that valve 23 may comprise a slide valve, or a ram preventer,
or blind
preventer, as these terms are known in the drilling art, or other structures
which may
be opened and closed such as to form a fluid tight seal between the upper and
lower
chambers of the coupler; valve 23 being hereinafter referred to as a "valve"
or "blind
preventer".
Below valve 23 are lower rotary grips 24, and below them are slips 25. In this
regard it
will be understood that the grips may be motorized roller grips, or of other
conventional designs motorized to rotate about their vertical axes, and the
slips are
support elements which have a central aperture smaller than the diameter of
box or
upset 14. While the grips 24 and slips 25 are shown as being separate elements
in some
Figures, the grips and slips may be integrated into a single unit and
motorized so that
both may be rotated and moved radially inwardly and outwardly as one element.
It will
also be noted that a plurality of inlets/outlets are provided, such as 29A, B
and C for
example, for the flow of drilling fluids and other fluids as will be further
explained.
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The embodiment of FIG. 2 is the same as that in FIG. 1 except that an
additional set of
upper rotary grips 26 is provided for the reason to be more fully explained
hereinafter.
Similarly, the embodiment of FIG. 3 is similar to the FIG. 2 embodiment except
that
upper grips 26, lower grips 24 and lower slips 25 may be one, single,
integrated unit.
5 Also, arrows 27 in FIGS. 2 and 3 indicate that lower and/or upper grips may
be moved
vertically, along the longitudinal axis of the drill string, as will be more
fully described
hereafter. It will also be noted that, instead of coupler 16 and BOP stack 20
being
integrated with the coupler on top of the stack, the coupler and BOP stack may
be
separate units with the coupler supported by the rig floor 39.
~. o
With respect to the motorized grips 24 and 26, it will be apparent that one or
both of
the conventional rotary grips may be motorized as shown schematically in FIG.
3A.
For example, the upper and lower grips may be provided with ring gears 32 and
33
which may by driven by drive gears 36 and 38 through shafts 35 and 37 by
motors M-1
and M - 2. Thus, each of the grips 24 and 26 may be held stationary or rotated
about
the longitudinal axis of the string and tubular as will be more fully
described hereafter.
FIGS. 4A - 6A illustrate, and Table I describes in detail, one mode of steps
whereby
the FIG. 2 and 3 embodiments may continuously maintain the flow of drilling
fluid into
and out of the bore hole while tubulars are added to the drill string. In
these FIGS.,
arrows 30 indicate rotation of the top drive and arrows 31 represent the
rotation of the
grips within casing 19. The bold arrows indicate the driving element, and the
lighter
arrows indicate that the element is idling and being driven by the other
element. With
respect to the FIG. 1 embodiment, it will be understood that the operation is
the same,
except that, without upper grips 26, top drive 10 is used to rotate the
tubular relative
to the string in order to make or break the threaded connection therebetween.
It wilt
also be understood by those skilled in the drilling art that upper slips may
be provided
in the FIG. 1-3 embodiments.
While the steps of the new method of the present invention are apparent from
Table I
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and FIGS. 4A - 6A, the following highlights should be noted. This method
utilizes the
top drive to provide the downward force necessary to push the tubular into the
coupler
against the pressure therein. Accordingly this method is more applicable to
adding
individual tubulars, rather than stands, and it will be understood that
conventional top
drives may be modified to produce greater downward force than usual depending
upon
the degree of pressure in a particular application. For example, conventional
top drives
can only be used for pressures in the bore hole and in the coupler up to about
500 psi.
Above this pressure, and particularly in the range of 1,000 to 5,000 psi which
are
frequently encountered, conventional top drives must be modified with,
stronger
structural support and bearings in order to counteract the higher pressures.
At these
very high pressures it will also be understood that the handlers guide the
tubulars and,
if necessary, prevent any buckling of the tubulars.
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Adding one pipe, or stand of pipes, to the drill string
Activity sequence for one cycle
'Top drive' 'Coupler 'Handlers'
Activities:
1. Drilling or 'trippingDisengaged
in'
2_ - Rotate & close slips -
3. Lower 'upset' onto - -
slips
4. _ Rotate & close grips and
close annular preventers -
5. Rotate tubular passivelyRotate lower grips actively (drive)
(idle) -
g. _ Flushing mud in & air out -
7. Raise tubular passivelySreak tool joint 8' back off -
8. Hold position Release upper grips -
9. Raise to clear blind- -
preventer
10_ Stop circulation Close blind preventer - -
11. Flushing mud out - -
& air in
12_ _ Open upper annular preventer -
13. Rise up to accept - -
new pipe
14. - - Handlers offer up new
pipe to top drive
18. Lower & make up tool-
joint
1g. _ - Top handlerreteases
17. Lower pipe to blind - . tower handler guides
preventer
18. - Close upper annular preventer -
19. Flushing mud in & - Lower handler restrains
air out
20. - Open blind preventer -
21. Lower pipe to upper - -
grips
22_ - Close upper grips -
23. Rotate passively Rotate upper grips actively (drive)-
(idle)
24. Lower passively Make up tool joint -
23, - Flushing mud out & air in -
26_ Rotate tubular activelyRotate tower grips passively (idle)Handlers
(drive) disengage
27. - Upen & stop rotating both grips
& open annular preventers
28. Raise drill string - -
off slips
2g. - Open & stop rotating slips
30 1 Carry on drilling Disengaged -
= or 'tripping in'
and repeat cycle_
Notes:
'Flushing mud in & air out' includes bringing the space up to ful( mud pump
pressure
'Flushing mud out & air in' includes de-pressuring the space to atmospheric
pressure
TABLE ~i
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In activity 1, the string is drilling in the conventional mode and is driven
by top drive
10, although other forms of drive will become apparent hereinafter. In
activities 2 and
3, lower slips 25 have closed about the string, and box 14 has been lowered
onto the
slips while mud or other drilling fluid continues to be supplied through the
top drive to
the string. In activity 4, the upper and lower grips engage the tubular and
the string,
respectively, and rotate with them. In activity 5, the lower grips take over
while the top
drive begins to idle in its rotation. In activity 6, mud or other drilling
fluid is flushed
through the coupler and the coupler is pressurized. In activity 7, the saver
sub is
unscrewed from the string such as by slower rotation of the upper grips
relative to the
lower grips. In activity 8, valve 23 remains open as the top drive rises and
upper grips
26 open and release the saver sub. The top drive and saver sub continue to
rise as
shown in activity 9 while mud continues to be supplied to and through the top
drive, as
well as through passage 29B. In activity 10, valve 23 closes and circulation
of the mud
or other drilling fluid through the top drive is stopped. However, a continued
flow of
fluid is effected through passage 29B, the lower chamber of the coupler and
down
through the string. In activity 11, the mud or other drilling fluid is flushed
through inlet
passage 29B and outlet passage 29A, and the fluid is replaced by air at
atmospheric
pressure. Also, lower grips 24 may continue to rotate the drill string through
activities
2 D 5 to 25 if continuous rotation of the string is desired with or without
continuous
drilling. Activity 12 shows that the flushing has been completed and the
supply of mud
or other drilling fluid to the top drive and through the saver sub has
stopped. In activity
13, the saver sub has been fully retracted and valve 23 remains closed.
Drilling fluid
continues to be supplied through passage 29B and down through the string, and
it will
be noted that this supply of drilling fluid continues through all of
activities 13 to 24. In
activity 14, the handlers 17A and 17B deliver a new tubular, which is
connected to the
saver sub in activity 15. In activities 16 to 18, the lower end of the new
tubular is
lowered into the upper chamber by handler 17B and the upper annular preventers
or
seals 22A are closed and sealed about the new tubular. Of course, the mud or
other
3D drilling fluid continues to be supplied to the bore hole by supply to and
through the
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lower chamber as previously described, and valve 23 remains closed and sealed.
In
activity 19, the upper chamber is flushed and depressurized through passage
29A prior
to opening of the valve as shown in activity 20. In activity 21 the new
tubular is
lowered and guided by handler 17B, and in activity 22 the new tubular is
gripped by
upper grips 26. Throughout these activities, drilling fluid is resumed through
the top
drive, saver sub and the new tubular to the drill string; the flow of drilling
fluids
through the top drive and through passage 29B being overlapping and mixed
within the
lower chamber. In activities 23 - 24, upper grips 26 rotate the new tubular
relative to
the string and thereby make the connection. In this regard, it will be
understood that
the required relative rotation and torquing may be accomplished by rotation of
the new
tubular while the string is held stationary, or by rotation of both the
tubular and the
string in the same direction but at different rotational speeds. Thus, the
connection, or
disconnection, of a tubular may be accomplished with the string held
stationary, or
while continuing to rotate the string as desired.
In activities 24 to 30, the supply of drilling fluid to and through the top
drive is
continued while both chambers are flushed in activity 25, and the rotational
driving of
the new tubular is resumed by the top drive With the grips idling as shown in
activity
26. In activity 27 the upper and lower seals 22A and 22B are opened, as are
valve 23
and grips 24 and 26. These conditions are continued in activities 27 to 30
while lower
slips 25 are opened in activity 29 and the top drive begins to lower the drill
string in the
normal drilling operation as described in activity 1. Of course, the removal
of a tubular
or stand is accomplished by performing the above-described activities in
reverse order,
while continuing to supply the necessary fluids to the bore hole, and while
continuing
2 5 to rotate the drill string with or without further drilling.
Referring to FIG. 7, another preferred embodiment of the invention is
illustrated with
the same elements numbered with the same numerals as in FIGS. 1 - 3. In
addition,
numeral 34A indicates the carrier for vertical and rotary movement of the
upper grips
and slips and numeral 34B indicates the carrier for rotary movement of the
lower grips
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24 and slips 25; both of the upper and lower slips and grips being illustrated
as being
integral. As shown most clearly shown in FIGS. 8C to SF, the mating portions
23A and
B of valve 23 are designed of a size and shape so as to be able to open to a
diameter
greater than that of the upper grips and carrier 34A. Thus, the lower end of
each
5 tubular may be lowered below valve 23, and coupled with the upper tubular of
the
string in the lower portion of coupler 18. In this schematic, the
inlet/outlets axe shown
for the flow of drilling fluids such as mud and for hydraulic fluid to move
carrier 34A
vertically as will be further explained hereinafter.
10 FIGS. 8A - 8H illustrate the detailed steps of the method of this
embodiment to
connect a new tubular. In FIG. 8A, a new tubular 13 is to be added to string
16. The
top of the string is gripped by the lower grips and slips, and valve 23 is
closed. Upper
grips and slips and upper seal 22A are open, and lower seal 22B is closed. At
this time,
pressurized drilling fluid is supplied through inlet 29D and flows down the
drill string
so as to continue the circulation of fluid in the bore hole. Also, the lower
grips may
continue to be rotated, by a drive motor such as M2 shown in FIG. 3A and
rotate the
drill string so that the drilling operation may also be continuous if desired.
In FIG. 8B the tubular has been lowered by the top drive into the upper
chamber of the
coupler and is gripped by upper grips. Upper seal 22A is closed, as is valve
23, so that
pressurized drilling fluid may be passed down the tubular from the top drive
and out of
the coupler through outlet 29A. The lower grips and slips may continue to
rotate the
drill string if desired, and drilling fluid continues to be supplied to the
bore hole
through inlet 29D and through the lower chamber and downwardly through the
drill
string. Valve 23 remains closed at this time so as to separate the upper and
lower
chambers of the coupler.
In FIG. 8C, upper and lower seals 22A - B remain closed while valve 23 has
been
opened so as to be able to lower tubular 13 and the upper grips and slips
below the
level of valve 23 and into engagement with upper end of the drill string.
During this
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time, the lower grips 24 may continue to rotate the drill string, and
pressurized drilling
fluid continues to be supplied through both the tubular and inlet 29D. In FIG.
8D, new
tubular 13 has moved down into threaded engagement with box 14 of the
uppermost
tubular of the drill string. This threaded engagement may be made by the upper
grips
and slips rotating tubular 13 at a differential speed in the same direction as
the drill
string. Alternatively, as in the FIG. 3 embodiment, the new tubular may be
rotated by
the top drive. In either case, the joint is made and torqued so that the new
tubular
becomes the uppermost tubular of the drill string. As in the previously
described steps, .
circulation of drilling fluid continues through new tubular 13 into the drill
string and
into the bore hole. In addition, the drill string may continue to be rotated
at all times by
the lower grips and slips if continuous drilling is desired. Thus, continuous
circulation
of the drilling fluid to the bore hole is achieved, as can Continuous string
rotation and
drilling, while each new tubular is added.
FIG. 8E shows that, having connected the new tubular, the mud within the
coupler
may be drained out via 29D and all of the seals and grips and slips retracted.
The top
drive continues drilling; or simply lowering the drill string when tripping
into the well.
FIG. 8F shows that, when the drill string has lowered sufficiently to need the
addition
of a new tubular, the saver sub of the top drive has reached the region of the
lower
grips, at which point the seals and grips and slips are all re-applied, the
coupler refilled
with mud and the saver sub is disconnected from the drill string as shown,
FIG. 8G shows the valve 23 closed to isolate the upper chamber from the lower
chamber and also shows that the mud circulation continues into the drill
string via inlet
2W and the mud can be drained from the saver sub and upper chamber via outlet
29A.
FIG. 8H shows that the upper seal 22A and upper grips and slips 26 and 28 can
be
retracted and allow the top drive and saver sub to rise up and accept a new
tubular.
so
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Referring to the simplified assembly drawing comprising FIG. 9, the elements
previously described are illustrated with the same numerals as in the prior
FIGS.
Coupler 18 comprises a high pressure casing 19 with tubular 13 positioned
above drill
string 16 and ready to be connected to the top of the string. At this time,
valve 23 is
closed, and box 14 is immediately below the center line of the valve. Valve
portions
23A and 23B carry resilient bumpers 23 C, D to be more fully described
hereafter. High
pressure seal 22A is closed and sealed against tubular 13, and lower high
pressure seal
22B is closed and sealed about string 16. It will also be noted that upper
grips 26 and
upper slips 28 are in engagement with tubular 13, and that lower grips 24 and
lower
slips 25 engage drill string 16. In this embodiment, both the upper and lower
slips and
grips are positioned within high pressure casing 19. However, it will be
understood
that these may be positioned above and below casing 19 as will be described
hereinafter. As further illustrated in FIG. 9, the sub-assembly of the upper
grips and
slips is contained within a cage 34A, and the complete assembly of the lower
grips and
slips is contained within a cage 34B. Upper cage 34A is mounted stationary
between
upper and lower casing portions 19A, and lower cage 34B is mounted stationary
between upper and lower casing portions 19A.
The bumpers may be composed of any firm but slightly resilient material which
can
2 0 withstand the pressures and drilling fluids such as, for example, hard
rubber. Bumpers
23 C and D may be of various shapes and are shown, for example, as segments
which
extend a few inches horizontally from the center line of the valve, and extend
upwardly
and downwardly a few inches from valve plates 23A and B with open passages
between the segments. Thus, the bumpers not only provide a centering and
cushioning
elect on the tubular and on the string, but also, they continuously allow
drilling fluids
to pass through the bumpers. That is, they pernut continuous flow of fluids
from the
tubular into the upper chamber, and from the lower chamber into the string, as
will be
more fully described in detail hereafter.
Referring to FIGS. 9, 9B - D and 10, lower cage 34B containing the sub-
assembly of
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lower slips and grips is illustrated most clearly. A carrier 40B is mounted
for rotational
movement within cage 34B, and also for axial movement if desired, Annular
seals 42A,
B and C are preferably provided between the carrier and the cage as shown most
clearly in FIG. 10. Carrier 40B includes a plurality of vertically extending
threaded
drive screws 44 which are positioned circumferentially about the carriage. As
shown
most clearly in FIGS. 9, 9D and 10, lower grips 24 are supported and moved
radially
inwardly and outwardly by pairs of links 45 and 46. One end of each of these
links is
pivotally connected to the grip, and the other end of each link is pivotally
connected to
a threaded follower 47, 48. Followers 47, 48 move vertically when drive screws
44 are
rotated. In this regard, it will be understood that the upper and lower
portions of the
drive screws are threaded in opposite directions. Thus, followers 47 and 48
move
vertically apart when the drive screw is rotated in one direction, and they
move
vertically toward each other when the drive screw is rotated in the reverse
direction.
Followers 47 and 48 are shown in FIG. 10 as having moved to the position
closest to
each other. In this position, links 45, 46 are in their most radially inward
position such
that grips 24, and their friction and/or wear pads 24', have been forced
radially
inwardly into their clamping position about box 14. Conversely, when drive
screws 44
are rotated in the opposite direction, followers 47, 48 are moved vertically
away from
each other such that the radial length of the links is shortened and the grips
move
2 0 radially outwardly to their retracted and non-engagement position.
In FIG. 10, lower slips 25 are shown in their radially inwardly extended
position in
engagement with string 16 and the lower chamfered or conical surface 14' of
box 14.
In this position, a positive lock is made at the bottom of the box such that
the extreme
weight of the string cannot pull the string downwardly, even if grips 24 are
retracted or
are not capable of supporting the weight by frictional engagement. Preferably,
slips 25
include friction or wear liners 25' . Each slip is connected to and moved
radially
inwardly and outwardly by a pair of links 51, 52. The radially inner end of
each thrust
link 51 is pivotally connected to a slip 25 and the opposite end of each link
51 is
pivotally connected to a threaded follower 54 which is carried on a drive
screw 58. At
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the same time, the mid-portion of each of thrust links 51 is pivotally
connected to an
actuator link 52, and the opposite end of each link 52 is pivotally connected
to a
follower 56. Followers 56 are carried by drive screws 44, which also drive
followers
47, 48. Preferably, four to eight drive screws 44 are positioned
circumferentially
around the string as shown in FIGS. 98, 9C and 11. As drive screws 44 are
rotated in
one direction, by means to be described hereafter, followers 56 are moved
upwardly.
As the followers move upwardly, links 52 pull the upper portions of links 51
and slips
25 radially outwardly and out of engagement with string 16 and box 14.
Conversely,
rotation of drive screws 44 in the reverse direction drives followers 56
downwardly
and links 51 and 52 force slips 25 inwardly so as to positively lock string 16
against
any downward movement regardless of the position of grips 24.
It will also be understood that, once slips 25 engage string 16 and the
chamfered
surface 14' of box 14, continued rotation of drive screws 58 will cause
followers 54 to
move further upward while slips 25 are locked against the chamfered edge of
the box.
This provides for accommodating different vertical sizes of boxes in common
use. It
will also be understood that continued upward movement of followers 54 must be
accommodated by making the upper portions of drive screws 44 and/or the
threads on
followers 56 to be a slip-thread or otherwise flexible connection. That is,
the threads
on screws 44 and followers 56 may be of such dimensions, or of such materials,
such
as resilient materials, such that followers 56 move upwardly on screws 44
under
relatively light load or pressure, as previously described, but under the
substantially
greater toad and pressure of the heavy drill string, the threads of followers
56 may slip
over the threads of drive screws 44 without further clamping the already
clamped slips
2 5 25.
In order to rotate string 16, if continued rotation of the string is desired
while tubulars
are added, or removed, carrier 40B is surrounded by and connected to an
annular gear
60. Gear 60 is in engagement with driving gear 62 carried by shaft 64. Thus,
when
shaft 64 is rotated, by drive means to be described, earner 40B is rotated
about the
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vertical axis of string 16. Rotation of carrier 40B causes slips 25, and
particularly grips
24, to rotate about the vertical axis, and this rotation causes string 16 to
be rotated
even though it may be a mile or more in length in the bore hole.
5 The drive assemblies for rotating drive screws 44 and 58 will now be
described with
reference to FIGS. 3D and 10. Drive screws 44, which actuate the grips and the
slips,
are connected at their lower ends to gears 80. A ring gear 78 is provided
which has
teeth on its inner annular surface which engage drive gear 80. The ring gear
also has
teeth on its outer annular surface which engage drive gear 76 driven by shaft
74.
~.o
The drive assembly for rotating drive screws 58 to raise and lower slips 25 is
essentially similar, and it comprises a drive shaft 72 which rotates drive
gear 70. Drive
gear 70 engages the outer annular teeth of a ring gear 73 while the inner
annular teeth
of the ring gear engage gear 66 connected to rotate drive screws 56.
It will be readily understood that each of the vertically extending drive
shafts such as
64, 72 and 74 are driven by conventional reversible motors, not shown, which
may be
of either the known electric or hydraulic types. It will also be understood
that each of
these drive shafts are designed such as to be able to be vertically elongated
or
Shortened as carriers 40A and B are moved vertically within cages 34A and B as
will
be further described. For example, the drive shafts may be of the splined or
telescoping
type as is known in the art of conventional drive shafts. Also, while only
lower cage
34B and carrier 40B have been described in detail, it is apparent from FIG. 9
that the
same structural elements are provided with respect to upper cage 34A and
carrier 40A.
In addition to the rotational movement of carrier 40B by ring gear 60 and
drive gears
62 and 64 as described, carriage 40B may also be moved vertically so as to
raise and
lower drill string 16. That is, as shown most clearly in FIG. 9, there is a
first vertical
distance between the bottom of pin 15 and the top of box 14, and also a second
distance for the pin to thread into the box in order to make the threaded
connection.
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16
Accordingly, carrier 40A must be able to move downwardly by such distance, or
carrier 40B must be able to move upwardly by such distance, or each carrier
must
move one-half of the required distance. The present invention provides the
capability to
perform each of these modes a~ will now be described with reference to FIGS.
11,
11A and 11B.
Referring first to FIG. 11, in addition to drive shafts 64, 72 and 74, one
preferred
embodiment of the present invention further provides additional vertical
screws 90 for
vertically moving carriers 40A and 40B upwardly and downwardly. For purposes
of
simplicity, the following description will be with respect to carrier 40B;
however, it
will be understood that carrier 40A may be moved vertically in the same
manner.
Screws 90 are positioned circumferentially apart as shown in FIG. 11 so as to
not
interfere with the previously described drive shafts 64, 72 and 74, or with
seals 22A
and B. Upon rotation of screws 90 in one direction, by conventional motors,
casing or
piston 100 moves carriage 40B upwardly or downwardly as desired for the
functions
or steps hereinafter described. Alternatively, casing or piston 100 may be
controlled as
to its vertical position by hydraulic means as shown in the break-away view of
FIG.
11B. That is, the bottom surface 102 of casing element 100 may be designed to
be a
piston, with suitable piston rings as desired. Thus, the high weld pressure
may act,
through the mud or other drilling fluid on the lowermost surface 102 of piston
100.
Against this pressure, the piston may be controlled by pressurized fluid
entering the
sealed chamber 94 through passage 104. Therefore, whether operated
mechanically or
hydraulically, carriers 40A and 40B may be controlled as to their vertical
positions,
which in turn, controls the vertical positions of string 16 and/or new tubular
13. In
both cases it will be understood that a key 106 and keyway 108 as shown in
FIG. 10,
or other anti-rotational element is provided in order to prevent the carriers
from
rotating relative to cages 34A and 34B.
FIG. 12 illustrates the relative positions of the elements when a new tubular
is to be
added to the string.
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17
At this time the string is gripped by lower grips 24 and 26 is positively
loclced against
downward movement by slips 25. Lower high pressure seal 22B is closed about
string
16, and valve 23 is closed thereby separating the coupler into upper and lower
chambers as previously described. Upper high pressure seal 22A is open, and
upper
grips 26 and slips 28 are in their retracted position thereby enabling a new
tubular to be
lowered into the upper chamber of the coupler. Also, it will be noted that
carriers 40A
and 40B are in their uppermost and lowermost positions, respectively.
In FIG. 13, a new tubular has been lowered into the upper chamber and has been
gripped by upper grips 26 and slips 28. In this position, it will be noted
that pin 15 has
engaged bumper 23C which sets the correct position of the new tubular without
shock
or damage to valve 23. It will also be noted that upper seal 22A has closed
and is
sealed around the new tubular, and that the vertical positions of carriers 40A
and 40B
~ 5 are the same as in prior FIG. 12. At this time, drilling mud or other
drilling fluid may
continue to pass down the tubular into the upper chamber from which it may
exit
through a passage such as 29A or 29B by virtue of the flow passages in bumper
23C as
previously described. In addition, drilling fluid may be admitted into the
lower chamber
27 through passage 29C or 29D from which it may.exit down the string through
the
lower bumper of similar construction. Accordingly, it will be apparent that
drilling fluid
may be circulated continuously through the upper and lower chambers of the
coupler,
and down the string into the bore hole while new tubulars are added to the
string, or
removed therefrom. In addition, it will be understood that if it is desired to
continue
drilling during the addition of tubulars, carrier 40B may continue to be
rotated such as
through ring gear 60 and drive gear 62 as previously described. At this time
the upper
end of the string remains secured in a fixed vertical position, but drilling
may continue
due to elongation; i.e., stretching of the string, or by use of a bumper sub
or similar
extension, such that the bit continues to drill downwardly if continuous
drilling is
desired.
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18
FIG. 14 illustrates the elements in the same positions as in FIG. 13, but also
illustrates
valve 23 as having been opened. Opening of valve 23 allows carrier 40A to pass
downwardly and carrier 40B to move upwardly. Also, the upper and lower
chambers
are in open communication such that the string may receive continuing flow of
drilling
fluid from both the new tubular and from that supplied to the coupler such as
through
passages 29A and/or B and/or 29C and D.
FIG. 15 illustrates the position of the elements after carrier 40A has moved
downwardly, and carrier 40B has moved upwardly, to make the connection of the
new
tubular to the string. That is, for example, by rotating the new tubular by
the upper
grips, or by the top driver while bringing the tubular down and the string
upwardly by
the respective vertical movements of carriers 40A and 40B. In this regard it
will be
understood that the string may be held stationary by the lower grips while
only the
tubular is rotated by the .upper grips in order to screw the pin into the box.
Alternatively, if the string is being rotated by lower grips 24 for down hole
operational
reasons or in order to continuously drill, the tubular may be rotated in the
same
direction but at a higher RPM. In either event, the connection is properly
torqued and
fluid flow to the coupler may be terminated since the flow of drilling fluids
down the
new tubular to the string is fully sufficient to continue continuous drilling
circulation of
2 0 drilling fluid, and drilling if desired. Thereafter, all of the slips and
grips are retracted as
shown in FIG. 16 and the drilling continues for the length of the new tubular
until the
next new tubular is added in the same manner. If the coupler is not mounted on
or
integral With the BOP Stack, the drilling fluid in the coupler is flushed out
and drained
through passage 29D before lower seal 22B is opened. Conversely, it will be
apparent
that the above-described steps may be performed in the reverse order when it
is desired
to remove tubulars.
From the foregoing description of one preferred mode of operation, it will be
apparent
that upper carrier 40A may be held vertically stationary while string 16 is
raised the
required distance by upward movement of lower carrier 40B. However, in view of
the
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19
substantial weight of the string, it is preferred that lower carrier 40B be
designed to
remain stationary, and that the full distance of the required movement is
performed by
upper carrier 40A. This embodiment is illustrated in FIGS. I7 - 19 and it will
be
apparent from FIG. 17 that piston 100 of the lower assembly may be eliminated
thereby simplifying the overall design. As illustrated in FIG. 18, upper
carrier 40A and
keyway 106 are designed to be sufficiently Long such that carrier 40A may move
downwardly by the full distance required to make the connection. This is
further
illustrated in the assembly drawing of FIG. 19. In this illustration it will
be apparent
that the distance to be traveled downwardly by the new tubular is more than
sufficiently provided for by the downward vertical movement of carrier 40A
within
cage 34A.
With regard to the locations of the grips and slips relative to casing 19 and
valve 23,
FIG. 20 schematically illustrates eight relative locations which are possible
with the
I5 present invention. For example, FIG. 20A illustrates both the upper grips
26 and the
lower grips 24 as being outside of casing 19. FIG. 20B illustrates upper grips
26 as
being in the casing above valve 23, and the Lower grips outside and below the
casing.
FIG. 20C illustrates the upper grips as being in the lower chamber while the
lower
grips 24 are outside and below the chamber. In FIG. 20D, the upper grips are
2 0 illustrated above the casing with the lower grips in the lower chamber of
the casing.
FIG. 20E illustrates the embodiment shown in FIG. 9, as previously described,
in
which upper grips 26 are within the casing and above the valve, and lower
grips 24 are
in the lower chamber of the casing and below the valve. FIG. ZOF illustrates
the
positions of the grips as previously described with respect to the FIG. 2
embodiment in
25 which both of the upper arid lower grips are within the casing and below
the valve. In
FIG. 20G. the upper grips are outside and above the casing while the lower
grips are in
the upper chamber of the casing. Lastly, FIG. 20H illustrates the embodiment
in which
both of upper grips 26 and lower grips 24 are in the upper chamber of the
casing above
valve 23.
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In addition to the above, it has discovered that, for use in the present
invention, certain
positions and combinations of slips, grips and seals are substantially
preferred and lead
to unexpected advantages and results. For example, FIG. 20A illustrates the
multiple
positions which are possible, at least theoretically, for the positions of the
seal and
5 lower slips relative to each other and relative to chamber 19. Similarly,
FIG. 20B
illustrates the theoretically possible locations of the seal and upper slips
and grips
relative to each other and to chamber 19. While all of these locations are
physically
possible, some locations produce unexpectedly superior results. For example,
the
surfaces of the upsets are usually much rougher than that of the tubular body.
10 Therefore, the lower seal 22B would wear out unless it is more expensive
RBOP.
Therefore, embodiments g to 1 in FIG. 20A are preferred for substantially
longer and
more effective seal life without resorting to rotating seals.
At the same time, it has been noted that the grips should engage the upset,
and not the
15 tubular body, in order to prevent potentially serious damage to the surface
of the
tubular. Therefore, it has been discovered that the upset of the tubular
should be
gripped by the grips such as illustrated in FIGS. 20A a, b, c, g, h, i, m, n
and o.
The theoretical options for the upper seals and upper slips and grips are also
illustrated
24 in FIG. 20B. However, the principles described with reference to FIG. 20a
also apply.
Thus, the embodiments of FIGS. 20B b and h have been discovered to produce the
most unexpected results in combination with the other elements of the present
invention. As a result, it has been discovered that the preferred positioning
of the seals,
grips and slips, including the serious factor of minimizing the vertical
height of the
2 5 coupler which also is very important for achieving the optimum results of
the present
invention, is to position the elements as illustrated in FIGS. 20A b and 20A h
if the
slips and/or grips are located within the pressure casing 19. In the future,
as the
industry modifies its present equipment, the optimum results have been
discovered to
be with 20B h above and 20A n below.
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21
As previously stated, the advantages of the present invention may also be
accomplished
by positioning the grips, and slips if desired, outside of pressure casing I9.
This
embodiment is illustrated schematically in FIGS. 21 - 27. As shown in FIGS. 21
- 22,
in this embodiment the high pressure casing 119 is positioned between the
upper grips
assembly 100A and the lower grips assembly 100B. Upper grips assembly 100A
engages a tubular 113 and lower grips assembly engages a drill string 116.
High
pressure casing 119 encloses an upper seal 122A, a lower seal 122B, and a
valve 123.
It will be understood that these elements correspond to previously described
elements
19, 22A - B and 23, and that they operate in the same manner as their
previously
described counterparts. It will be apparent to those skilled in the art that
the lubricants
and drilling fluids may be supplied to and from casing 119 in various ways
similar to
that previously described. However, one preferred embodiment is illustrated in
FIG. 22
in which lubricant for the upper annular preventer or seal 122A may be
supplied
through port or passage 102. Passage 104 may be provided for supplying mud and
purge air to the upper chamber from which it may be discharged through
passages 106.
Mud or other drilling fluid may be supplied to the lower chamber through
passage 108
so as to flow down the drill string for continuous circulation as previously
described,
and excess drilling fluid and/or purge air may exit the lower chamber through
passages
110. An additional passage 107 is preferably provided for injecting a
lubricant or dope
in contact with the pin and box when valve 23 is open and the pin has been
lowered.
As further shown in FIG. 22, centering elements or rams 124, 126 and 128 are
preferably provided. The rams extend at a 90° angle relative to valve
23, and may be
moved radially inwardly to engage and center the lower end of tubular 113 and
the
upper end of drill string 116, by conventional electric or hydraulic motors
not shown,
as the tubular and string are about to be coupled. Centralizing ram 126 rnay
also be
used to centralize pin 115 relative to box 114 when valve 123 is open just
prior to the
coupling.
Referring now to FIG. 23, the lower grip assembly lODB is schematically
illustrated
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22
one preferred embodiment, and it will be understood that the upper grip
assembly may
be the same but reversed so as to be upside down. Grip assembly 100B includes
an
outer casing or shell 130 within which a drum 132 is contained and mounted for
rotation between upper and lower thrust bearings 134A and 134B. Drum 132
includes
an annular ring gear 136 which may be driven by one or more drive gears 138
rotated
by one or more drive shafts 140 which are driven by conventional reversible
motors)
not shown. Thus, drum 132 may be rotated clockwise or counterclockwise in
order to
rotate grips 142 about the axis of string 116. Grips 142 are moved radially
inwardly
and outwardly by sets of links 143 and 144 are which moved vertically by
followers
1 D 147A and B carried by drive screws 146 in the same manner as previously
described.
Drive screws 146 are connected to and rotated by drive gears 148 supported by
thrust
bearings 1 S0. Drive gears 148 are rotated by an annular gear 152 having inner
teeth
which engage gears 148, and having outer teeth which engage one or more drive
gears
154. Drive gears 154 may be driven by conventional motors through shafts 156
extending through high pressure seals 158.
The operation of this embodiment will be readily understood from the prior
description
in that drive screws 146, having upper and lower reverse threads, move links
143 and
144 inwardly and outwardly depending upon the direction of rotation of drive
screws
2 0 146 and the direction and speed differential of drive shafts 140 and 156.
In addition, it
will be understood that grips 142 may also function as slips in that the
downward force
created by the weight of the string causes lower links 144 to increase the
gripping
force on the string. That is, the grips and lower links act as wedges which
prevent
downward axial movement of the string. Similarly, the upper set of linlcs 143'
in grip
assembly 100A act as wedges forcing grips 142' into tighter engagement with
the
tubular as the high pressure in the coupler chamber applies a substantial
upward force
on the tubular before the connection is made with the string. In addition, in
the
preferred embodiment, the axial length of the grips is made greater than that
of the
previously described grips. For example, instead of a common length in the
order of 6
to 10 inches, grips 142 and 142' are preferably in the order of 18 to 24
inches in axial
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23
length.
As previously discussed and as illustrated in FIGS. 21, 22 and 25, one or
other or both
of tubular 113 and string 116 must be moved vertically toward each other for
connecting or removing a tubular to or from the string. FIG. 25 illustrates
one
preferred embodiment in which coupler casing 119 and lower grip assembly 100B
may
remain stationary while upper grips assembly 100A and tubular 113 are moved
the
required vertical distance by a power system 170, although it will be apparent
that
lower grips assembly 100B may be moved on similar manner if desired, In the
embodiment as illustrated, upper grips assembly 100A includes an offset casing
portion
160 which carries an internally threaded power sleeve 162. Casing 119 of the
coupler
includes an offset housing 164 which carries a threaded power screw 166. Power
screw 166 is connected to and rotated by a gear 168 which .is driven by a
drive gear
and shaft 172. Gear 168 and power screw 166 are provided with a thrust bearing
174
7.5 at the lower end. Gear 168 and power screw 166 are provided with a thrust
bearing
174 at the lower end. Power sleeve 162 slides through high pressure seal 178
and seals
against the inside of casing 164 with high pressure seal 176. Therefore, as
power screw
I66 is rotated by shaft and gear 172, and gear 168, the power screw moves
power
sleeve 162 and upper grip assembly 100A downwardly or upwardly as desired to
make
2 0 or break the connection of the tubular. Alternatively, the power gear
assembly may be
replaced by a hydraulic power assembly. Additionally, hydraulic fluid at a
pressure
equal to or proportional to the mud pressure in the drill string may be
admitted through
passage 179 to pressure balance the forces and thereby reduce the force on the
threads
of the screw. Of course, it is preferred to provide two or more power systems
170
25 circumferentially spaced about the vertical axis of the grip assembly in
order to balance
the forces and apply the total force desired. In addition, the preferred
embodiment
includes a vertically extending stop or guide 180 which extends between the
grip
assembly 100A and the casing 119 so as to allow the vertical movement just
described
while acting against any torque forces therebetween.
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24
FIGS. 26 and 27 illustrate the application of the external grips to tubulars
which do not
have external upsets or boxes, and to tubulars having small diameters and
relatively
thicker walls. Without external upsets, the distance between upper and lower
seals
122A and 122B may be greatly reduced. Additionally, the grips may be shortened
due
to the greater thickness of the tubular wall. As a result, it has been
discovered that the
vertical height of the overall casing and external grips may be substantially
reduced. In
this embodiment, the vertical height of coupler casing 119' is reduced such
that it may
be in the order of the vertical height of the entire power system 170, and the
high
pressure casing 119 and the lower grips assembly 100B may be one, integrated
casing.
From the foregoing brief description of several embodiments of the present
invention,
it will be apparent that very substantial savings in the cost of drilling may
be achieved.
It is also to be understood that the present invention may be remote
controlled, such as
in off shore under sea drilling operations, by remotely controlling the drive
motors by
radio or sonar signals. It will also be understood that, instead of the
coupler being
supported by a rig floor, the coupler may be mounted on handlers for mobile
operation
so as to perform hand-to-hand or hand-over-hand drilling operations as more
fully
described in published PGT Applications WO 98/16716 and WO 00/22278 which are
hereby incorporated by reference. Of course, it is to be understood that the
foregoing
description of several preferred embodiments is intended to be purely
illustrative of the
principles of the invention, rather than exhaustive thereof, and that the
present
invention is not intended to be limited other than as expressly set forth in
the following
claims interpreted under the doctrine of equivalents.
