U.S. patent application number 15/469249 was filed with the patent office on 2017-07-13 for subsea casing drilling system.
The applicant listed for this patent is Weatherford Technology Holdings, LLC. Invention is credited to Albert C. ODELL, II, Jose A. TREVINO, Eric M. TWARDOWSKI.
Application Number | 20170198526 15/469249 |
Document ID | / |
Family ID | 50552528 |
Filed Date | 2017-07-13 |
United States Patent
Application |
20170198526 |
Kind Code |
A1 |
TWARDOWSKI; Eric M. ; et
al. |
July 13, 2017 |
SUBSEA CASING DRILLING SYSTEM
Abstract
In one embodiment, a casing bit drive assembly may be used with
a casing drilling system. The casing bit drive assembly may include
one or more of the following: a retrievable drilling motor; a
decoupled casing sub; a releasable coupling between the motor and
casing bit; a releasable coupling between the motor and casing; a
cement diverter; and a casing bit.
Inventors: |
TWARDOWSKI; Eric M.;
(Spring, TX) ; ODELL, II; Albert C.; (Kingwood,
TX) ; TREVINO; Jose A.; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Weatherford Technology Holdings, LLC |
Houston |
TX |
US |
|
|
Family ID: |
50552528 |
Appl. No.: |
15/469249 |
Filed: |
March 24, 2017 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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15346544 |
Nov 8, 2016 |
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15469249 |
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13774989 |
Feb 22, 2013 |
9488004 |
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15346544 |
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61601676 |
Feb 22, 2012 |
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Current U.S.
Class: |
1/1 |
Current CPC
Class: |
E21B 17/03 20130101;
E21B 34/06 20130101; E21B 2200/05 20200501; E21B 7/208 20130101;
E21B 4/00 20130101; E21B 34/10 20130101; E21B 4/02 20130101; E21B
21/10 20130101; E21B 33/0422 20130101; E21B 2200/06 20200501; E21B
33/14 20130101; E21B 21/103 20130101 |
International
Class: |
E21B 7/20 20060101
E21B007/20; E21B 34/10 20060101 E21B034/10; E21B 4/02 20060101
E21B004/02; E21B 33/14 20060101 E21B033/14; E21B 17/03 20060101
E21B017/03 |
Claims
1. A casing drilling system, comprising: a casing; a drilling
member coupled to the casing; a retrievable motor releasably
coupled to the casing and includes a power section configured to
rotate the drilling member relative to the casing; and a releasable
coupling assembly for coupling an output shaft of the motor to the
drilling member, wherein the releasable coupling assembly includes:
a coupling attached to the drilling member; and a retractable dog
configured to couple or decouple the output shaft to the
coupling.
2. The system of claim 1, wherein the motor includes a rotating
portion and non-rotating housing, wherein the power section
comprises an annular area between the rotating portion and a
non-rotating portion.
3. The system of claim 2, wherein the motor includes an arcuate
recess formed in non-rotating housing, wherein a ball received at
an end of the arcuate recess prevents relative rotation between the
rotating portion and the non-rotating housing.
4. The system of claim 1, further comprising a cement diverter for
diverting cement from the power section of the drilling motor.
5. The system of claim 1, wherein the releasable coupling assembly
further comprising a biased sleeve configured to retain the dog in
a retracted position.
6. The system of claim 1, further comprising a locking mechanism to
prevent relative rotation between drilling member and the
casing.
7. The system of claim 6, wherein the locking mechanism includes: a
locking segment attached to the casing; a first set of teeth formed
on the locking segment; and a second set of teeth formed on the
drilling member, wherein the second set of teeth is engageable with
the first set of teeth to prevent relative rotation between the
casing and the drilling member.
8. The system of claim 6, wherein the locking mechanism includes an
arcuate recess formed between the casing and the drilling member, a
ball received at an end of the arcuate recess prevents relative
rotation between casing and the drilling member.
9. The system of claim 8, further comprising a fluid path between a
bore of the motor and the recess.
10. The system of claim 6, wherein the locking mechanism includes:
an upper sleeve attached to the casing, the upper sleeve having a
first set of teeth; and a lower sleeve releasably coupled the
motor, the lower sleeve having a second set of teeth configured to
mate with the first set of teeth, wherein upon release, the lower
sleeve is movable to engage the upper sleeve, thereby preventing
relative rotation between casing and the drilling member.
11. The system of claim 1, further comprising a second releasable
coupling assembly for coupling the motor to the casing.
12. A method of forming a wellbore in a formation, comprising:
coupling a first casing to a second casing, the first casing having
a motor for rotating the drilling member; lowering the first casing
and the second casing into the formation; releasing the first
casing from the second casing; rotating the drilling member
relative to the first casing to extend the wellbore; supplying
cement around the motor and into the wellbore; detaching the motor
from the drilling member by retracting a dog from engagement with
the drilling member; and retrieving the motor.
13. The method of claim 12, wherein retracting the dog includes
axially moving a mandrel coupled to the dog.
14. The method of claim 12, further comprising preventing the
retracted dog from re-extending.
15. The method of claim 12, wherein the motor includes a rotatable
member and a stationary member, and further comprising preventing
the rotatable member from rotation.
16. The method of claim 15, wherein prevention rotation of the
rotatable member comprises landing a ball in a recess between the
rotatable member and the stationary member.
17. The method of claim 12, wherein supplying cement around the
motor comprises diverting the cement through a bore in the
motor.
18. The method of claim 12, further comprising locking the drilling
member from rotating relative to the first casing.
19. The method of claim 18, wherein locking the drilling member
from rotation includes engaging a first set of teeth of the first
casing to a second set of teeth of the drilling member.
20. The method of claim 18, where locking the drilling member
includes moving a lower sleeve coupled to the motor toward an upper
sleeve coupled to the first casing; and engaging a first set of
teeth of the upper sleeve to a second set of teeth of the lower
sleeve.
Description
BACKGROUND OF THE INVENTION
Field of the Invention
[0001] The present invention generally relates to an apparatus and
method for casing drilling. More particularly, the invention
relates to a subsea casing drilling system and methods
therefor.
Description of the Related Art
[0002] In the oil and gas producing industry, the process of
cementing casing into the wellbore of an oil or gas well generally
comprises several steps. For example, a conductor pipe is
positioned in the hole or wellbore and may be supported by the
formation and/or cemented. Next, a section of a hole or wellbore is
drilled with a drill bit which is slightly larger than the outside
diameter of the casing which will be run into the well.
[0003] Thereafter, a string of casing is run into the wellbore to
the required depth where the casing lands in and is supported by a
well head in the conductor. Next, cement slurry is pumped into the
casing to fill the annulus between the casing and the wellbore. The
cement serves to secure the casing in position and prevent
migration of fluids between formations through which the casing has
passed. Once the cement hardens, a smaller drill bit is used to
drill through the cement in the shoe joint and further into the
formation.
[0004] Although the process of drilling with casing has improved,
there is still a need for further improvements in drilling with
casing techniques.
SUMMARY OF THE INVENTION
[0005] Embodiments of the present invention provide a casing bit
drive assembly suitable for use with a casing drilling system. The
casing bit drive assembly may include one or more of the following:
a retrievable drilling motor; a decoupled casing sub including a
drilling member such as a casing bit; a releasable coupling between
the motor and drilling member; a releasable coupling between the
motor and casing; a cement diverter; and a drilling member.
[0006] In one embodiment, a casing drilling system includes a
casing; a drilling member coupled to the casing; a retrievable
motor releasably coupled to the casing and includes a power section
configured to rotate the drilling member relative to the casing;
and a cement diverter for diverting cement from the power section
of the drilling motor.
[0007] In one embodiment, a casing drilling system includes a
casing; a drilling member coupled to the casing; a retrievable
motor releasably coupled to the casing and includes a power section
configured to rotate the drilling member relative to the casing;
and a releasable coupling assembly for coupling an output shaft of
the motor to the drilling member. The releasable coupling assembly
includes a coupling attached to the drilling member; and a
retractable dog configured to couple or decouple the output shaft
to the coupling.
[0008] In another embodiment, a method of forming a wellbore in a
formation includes providing a first casing with a motor for
rotating a drilling member relative to the first casing; coupling
the first casing to a second casing; lowering the first casing and
the second casing into the formation; releasing the first casing
from the second casing; rotating the drilling member to extend the
wellbore; supplying cement around the motor and into the wellbore;
detaching the motor from the drilling member; and retrieving the
motor.
[0009] In one embodiment, a method of forming a wellbore in a
formation includes coupling a first casing to a second casing, the
first casing having a motor for rotating the drilling member;
lowering the first casing and the second casing into the formation;
releasing the first casing from the second casing; rotating the
drilling member relative to the first casing to extend the
wellbore; supplying cement around the motor and into the wellbore;
detaching the motor from the drilling member; and retrieving the
motor.
[0010] In one or more of the embodiments described herein, the
motor includes a rotating portion and non-rotating housing, wherein
the power section comprises an annular area between the rotating
portion and a non-rotating portion.
[0011] In one or more of the embodiments described herein, the
system may include a coupling for transferring load between the
non-rotating housing and the casing.
[0012] In one or more of the embodiments described herein, the
system may further include a bearing for transmitting load from an
output connected to the rotating portion to the non-rotating
housing.
[0013] In one or more of the embodiments described herein, the
motor includes an arcuate recess formed in non-rotating housing,
wherein a ball received at an end of the arcuate recess prevents
relative rotation between the rotating portion and the non-rotating
housing.
[0014] In one or more of the embodiments described herein, the
cement diverter includes a diverter sub coupled to the motor; a
cementing tube in selectively fluid communication with a bore of
the diverter sub; and a sleeve disposed in the bore, wherein the
sleeve is selectively actuatable to open fluid communication to the
cementing tube.
[0015] In one or more of the embodiments described herein, the
cement diverter includes a diverter sub coupled to the motor and
including a bore extending therethrough; a sleeve releasably
coupled to the bore; and a diverter piston releasably coupled to
the sleeve, wherein the sleeve is configured to release at a lower
force than the diverter piston.
[0016] In one or more of the embodiments described herein, the
system includes a locking mechanism to prevent relative rotation
between drilling member and the casing.
BRIEF DESCRIPTION OF THE DRAWINGS
[0017] So that the manner in which the above recited features of
the present invention can be understood in detail, a more
particular description of the invention, briefly summarized above,
may be had by reference to embodiments, some of which are
illustrated in the appended drawings. It is to be noted, however,
that the appended drawings illustrate only typical embodiments of
this invention and are therefore not to be considered limiting of
its scope, for the invention may admit to other equally effective
embodiments.
[0018] FIGS. 1A and 1B show an exemplary embodiment of a casing
drilling system.
[0019] FIG. 2 illustrates an embodiment of a casing drilling system
without the conductor casing.
[0020] FIGS. 3-7 are enlarged partial views of FIG. 1.
[0021] FIG. 8 shows a sequence view of the diverter mechanism in
operation.
[0022] FIG. 9 shows the motor removed from the casing drilling
system.
[0023] FIG. 10 illustrates an embodiment of a locking
mechanism.
[0024] FIG. 11 illustrate another embodiment of a casing bit drive
assembly.
[0025] FIGS. 12-18 illustrate enlarged partial views of FIG.
11.
[0026] FIGS. 15-18 are enlarged views of the motor.
[0027] FIGS. 19-23 are sequential views of the diverter mechanism
of FIG. 11 in operation.
[0028] FIG. 24 shows the motor removed from the bit drive assembly
of FIG. 11.
[0029] FIGS. 25-27 are sequential views of an embodiment of a
lock-out mechanism for the motor in operation.
[0030] FIG. 28 illustrate another embodiment of the casing bit
drive assembly.
[0031] FIGS. 29-31 are sequential views of the lock-out mechanism
for the casing bit of FIG. 28 in operation.
[0032] FIG. 32 illustrates another embodiment of a bit drive
assembly.
[0033] FIGS. 33 to 36 are sequential views of the releasable
coupling of FIG. 32 in operation.
[0034] FIGS. 37-38 show an embodiment of a releasable coupling for
coupling the motor to the casing.
[0035] FIG. 39 illustrates another embodiment of a drill out
locking mechanism.
[0036] FIGS. 40-45 are sequential views of the locking mechanism of
FIG. 39 in operation.
[0037] FIG. 46 illustrates another embodiment of a float valve.
[0038] FIG. 47 illustrates an embodiment of a mandrel for use with
the releasable coupling for coupling the motor to the casing.
DETAILED DESCRIPTION
[0039] Embodiments of the present invention generally relates to a
casing drilling system. In one embodiment, the system includes a
conductor casing coupled to a surface casing and the coupled
casings can be run concurrently. In one trip, the system will
jet-in the conductor casing and a low pressure wellhead housing,
unlatch the surface casing from the conductor casing, drill the
surface casing to target depth, land a high pressure wellhead
housing, cement, and release. The system includes a drill bit that
may be powered by a retrievable downhole motor which rotates the
drill bit independently of the surface casing string. In another
embodiment, the system may also include the option of rotating the
drilling bit from surface.
[0040] Exemplary drilling motors include positive displacement
motors (PDM) and downhole turbo-drills. The drilling motor is used
to rotate the casing bit. A releasable coupling is used to couple
the rotating output shaft of the drilling motor to the casing bit.
When this coupling is engaged, axial and torsion loads may be
transmitted between the motor output shaft and the casing bit.
[0041] A second releasable coupling is used to transfer axial and
torsional loads from the non-rotating motor housing to the surface
casing. The second coupling allows reactive forces to be
transmitted between the motor housing and the casing. The second
coupling may be positioned above the first coupling and thus may be
referred to as the upper coupling.
[0042] The motor may include bearings to transmit loads from the
rotating motor output shaft to the non-rotating motor housing.
These bearings are configured to carry the drilling loads.
Exemplary bearings include a sealed bearing pack and a mud
lubricated bearing pack.
[0043] The couplings and the bearings may provide a load path from
the casing bit, to the lower coupling, to the motor output shaft,
through the motor bearings, to the motor housing, to the upper
coupling, and to the surface casing.
[0044] The motor may also include features for cementing either
around or through the drilling motor. In one embodiment, a cement
diverter mechanism is used to alter the flow path for cementing
purposes. Separate flow paths are available for drilling fluid flow
during drilling mode and cement flow during cementing mode. This
mechanism limits the chances of inadvertently cementing the motor
in place. In another embodiment, the power section of the drilling
motor is sealed off prior to pumping cement, in order to prevent
damage to the power section from hardened cement.
[0045] In one embodiment, tandem drilling float valves are
installed in the bore of the drilling motor's output shaft. These
float valves provide a pressure barrier to prevent u-tubing of
drilling fluid or cement, when the pumps are not circulating fluid
down the drillstring.
[0046] The motor may optionally include a contingency lock-out
feature to prevent the motor from rotating in the event of motor
damage. If the power section experiences wear during drilling, this
feature would allow for continued drilling by rotating the entire
casing string and casing bit from surface.
[0047] The casing sub allows the casing bit to be rotated
independently, or relative to, the surface casing. The casing sub
may be decoupled from the casing bit. In one embodiment, the motor
bearings are used to carry the drilling loads. In another
embodiment, the bearings could also be positioned in the de-coupled
casing sub.
[0048] If the motor bearings are used, the decoupled casing sub
provides an interface between the non-rotating surface casing and
the rotating casing bit. The upper portion of the decoupled casing
sub is connected directly to the lower end of the surface casing.
The lower end of the decoupled casing sub is adjacent to the upper
end of the casing bit. The interface may optionally contain a
rotating "material seal" that helps prevent formation cuttings from
entering the casing bit. In one embodiment, the rotating material
seal does not provide a pressure-tight seal.
[0049] The decoupled casing sub may also provide a locking
mechanism that prevents rotation of the casing bit during
subsequent drill-out operations. In ideal conditions, a good cement
job at the casing shoe will prevent the casing bit from spinning
freely as it is drilled-out. If the casing bit is not rotationally
constrained, drill-out would be problematic. In the event of a poor
quality cement job, or "wet shoe", a mechanical locking mechanism
provides a contingency mechanism for rotationally locking the
casing bit and decoupled casing sub to the non-rotating surface
casing. This allows the casing bit to be drilled-out more
easily.
[0050] In one embodiment, an optional secondary flapper float valve
may be held in the open position by the motor housing. The motor is
positioned such that it passes through the bore of the float valve,
thus preventing the spring loaded flapper from pivoting into the
closed position. This secondary flapper remains in the open
position during the drilling and cementing processes. After
drilling and cementing operations are completed, the motor is
retrieved up through the secondary flapper float valve. Once the
motor is no longer effectively holding the float valve in the open
position, the spring loaded flapper is free to pivot into the
closed position. This secondary flapper float valve remains in
place after the motor is retrieved, and acts as a secondary
pressure barrier. This barrier feature may act as a safety feature,
especially in the event of a poor quality cement job at the
shoe.
[0051] The releasable couplings and the secondary flapper float
valve remain in the drill-out path after the motor is retrieved may
be manufactured from a drillable material. Aluminum is a suitable
material, but other drillable materials with sufficient strength
may also be used (i.e. composite, polymer, copper, brass, bronze,
zinc, tin, or alloys thereof). The nose and cutting structure of
the casing bit are also designed to be readily drillable. This
allows the next drill-out BHA to easily drill though the remaining
components in the shoe track, before proceeding to drill new
formation.
[0052] An exemplary casing drilling method is disclosed in U.S.
patent application Ser. No. 12/620,581, which application is
incorporated herein in its entirety.
[0053] Embodiments of the present invention include a casing bit
drive assembly suitable for use in a casing drilling system and
method. The casing bit drive assembly includes one or more of the
following: a retrievable drilling motor; a decoupled casing sub; a
releasable coupling between the motor and casing bit; a releasable
coupling between the motor and casing; a cement diverter; and a
casing bit.
[0054] FIGS. 1A and 1B show an exemplary embodiment of a casing
drilling system 100. The casing drilling system 100 includes a
conductor casing 10 coupled to a surface casing 20 and the coupled
casings 10, 20 may be run concurrently. The casings 10, 20 may be
coupled using a releasable latch 30. A high pressure wellhead 12
connected to the surface casing 20 is configured to land in the low
pressure wellhead 11 of the conductor casing 10. The drill string 5
and the inner string 22 are coupled to the surface casing 20 using
a running tool 60. A motor 50 is provided at the lower end of the
inner string 22 to rotate the casing bit 40. In another embodiment,
the casing bit 40 may be rotated using torque transmitted from the
surface casing 20. An optional swivel 55 may be included to allow
relative rotation between the casing bit 40 and the surface casing
20. In operation, the casing drilling system 100 is run-in on the
drillstring 5 until it reaches the sea floor. The system 100 is
then "jetted" into the soft sea floor until the majority of the
length of the conductor casing 10 is below the mudline, with the
low pressure wellhead housing 11 protruding a few feet above the
mudline. The system 100 is then held in place for a time, such as a
few hours, to allow the formation to "soak" or re-settle around the
conductor casing 10. After "soaking", skin friction between the
formation and the conductor casing 10 will support the weight of
the conductor casing 10.
[0055] The releasable latch 30 is then deactivated to decouple the
surface casing 20 from the conductor casing 10. In one embodiment,
the surface casing 20 has a 22 inch diameter and the conductor
casing 10 has a 36 inch diameter. After unlatching from the
conductor casing 10, the surface casing 20 is drilled or urged
ahead. The casing bit 40 is rotated by the downhole drilling motor
50 to extend the wellbore. The decoupled drilling swivel 55 allows
the casing bit 40 to rotate independently of the casing string 20
(although the casing string may also be rotated from surface). Upon
reaching target depth ("TD"), the high pressure wellhead 12 is
landed in the low pressure wellhead housing 11. Since the casing
string 20 and high pressure wellhead 11 do not necessarily need to
rotate, drilling may continue as the high pressure wellhead 12 is
landed, without risking damage to the wellhead's sealing
surfaces.
[0056] After landing the wellhead 12, it is likely that the
formation alone will not be able to support the weight of the
surface casing 20. If the running tool 60 was released at this
point, it is possible that the entire casing string 20 and wellhead
112 could sink or subside below the mudline. For this reason, the
running tool 60 must remain engaged with the surface casing 20 and
weight must be held at surface while cementing operations are
performed. After cementing, the running tool 60 continues holding
weight from surface until the cement has cured sufficiently to
support the weight of the surface casing 20.
[0057] After the cement has cured sufficiently, the running tool 60
is released from the surface casing 20. The running tool 60, inner
string 22, and drilling motor 50 are then retrieved to surface.
[0058] A second bottom hole assembly ("BHA") is then run in the
hole to drill out the cement shoe track and the drillable casing
bit 40. This drilling BHA may continue drilling ahead into new
formation.
[0059] The embodiments described below illustrate several concepts
for the bit drive assembly. Some of the features are common to
multiple concepts. It is contemplated that features described in
one concept is not limited for use with that concept, but may be
used with another concept.
[0060] FIG. 2 illustrates an embodiment of a casing drilling system
100 without the conductor casing 10. FIGS. 3-7 are enlarged partial
views of FIG. 1. The surface casing 20 (e.g., 22 inch casing)
includes an inner string 22 disposed therein. Connected below the
inner string 22 are a diverter sub 56, a drilling motor 50, and a
motor output shaft 62. The motor output shaft 62 is configured to
rotate a casing bit 40 relative to the surface casing 20.
[0061] In one embodiment, a drilling motor 50 includes features to
flow cement around the motor 50, as opposed to through the motor
50. This limits the possibility of inadvertently cementing the
motor 50 in place. Since no cement is pumped through the motor 50,
it is unlikely that the expensive motor 50 components will be
damaged as a result of hardened cement remaining inside the motor
50. The bypass around the motor 50 may cause the cement to enter
the annulus at a short distance such as a few feet above the casing
bit 40.
[0062] Referring to FIGS. 3 and 4, the lower end of the bit drive
assembly contains a drillable casing bit 40. An exemplary casing
bit 40 suitable for use with this and other concepts described
herein or illustrated in the Figures is Weatherford's Defyer DPA
casing bit. The casing bit 40 is coupled to the motor output shaft
62 by a threaded aluminum (or other drillable material) coupling
42. Threads on the outer diameter ("OD") of the coupling 42 are
secured to the casing bit 40. The threads on the inner diameter
("ID") of the coupling 42 are secured to the motor output shaft 62.
These threaded connections allow for transmission of axial and
torsional drilling loads. The ID threads on the coupling 42 are
designed to be weaker than the threads on the OD of the coupling
42. For example, the ID threads may have a shorter length than the
OD threads. In another example, the ID threads may have a smaller
diameter. In this respect, the weaker ID threads will shear before
the OD threads. Since the threads are made from aluminum, the motor
50 may be retrieved by pulling it upward with overpull force and
shearing the aluminum threads. The motor 50 can be retrieved, while
the coupling 42 remains behind.
[0063] A spacer ring 43 is used to facilitate assembly of the bit
drive assembly. The height of this spacer 43 can be selected to
easily adjust the axial space-out distance between the casing bit
40 and the motor output shaft 62.
[0064] A threaded locking ring 44 is positioned above the aluminum
coupling 42. It may be used as a jam-nut to effectively prevent the
OD threads on the coupling 42 from loosening during the drilling
process.
[0065] Drilling float valves 45 are installed in the bore of the
motor output shaft 62. As shown, a tandem set of float valves 45
are used, although one or three or more float valves may be used.
The float valves 45 provide a pressure barrier to prevent u-tubing
of drilling fluid or cement, when the pumps are not circulating
fluid down the drillstring. A stop sub 146 is threaded into the
bottom of the output shaft 62. This sub 146 prevents the float
valve(s) 45 from falling out.
[0066] The upper end of the casing bit 40 does not come into direct
contact with the casing sub 25. A small clearance gap 47 is present
between these two components 25, 40. An optional rotating sealing
element could be positioned in this gap 47. In one embodiment, the
gap 47 may include a "leaking trash barrier". This trash barrier
includes a tortuous path or labyrinth geometry. The trash barrier
will allow fluid to leak through it, but larger particles such as
formation cuttings, cannot freely cross through this barrier.
[0067] To further aid in preventing formation cuttings from
entering this gap 47, a positive pressure port may be used. This
port directs a small portion of the drilling fluid into the cavity
48 above the aluminum coupling 42. In this manner, pressure and
fluid flow is constantly directed to travel from inside the cavity
to the borehole annulus. This positive pressure and flow makes it
less likely that formation cuttings can enter from the borehole
annulus.
[0068] As shown in FIG. 5, a second drillable coupling 52 is used
to releaseably connect the motor housing 53 to the non-rotating
casing sub 25. Similar to the first, lower coupling 42, this upper
coupling 52 has threads on the OD and ID for transmitting axial and
torsional loads. Threads on the OD of the coupling 52 are secured
to the non-rotating casing sub 25. The threads on the ID of the
coupling 52 are secured to the motor housing 53. The ID threads on
the coupling 52 are designed to be weaker than the threads on the
OD of the coupling 52, as discussed above. Since the threads are
made from aluminum, the motor 50 may be retrieved by pulling it
upward with overpull force and shearing-out the aluminum threads.
The motor 50 can be retrieved, while the coupling 52 remains
behind.
[0069] A secondary flapper float valve 55 is positioned above the
upper coupling 53. The flapper float valve 55 may be similar in
form to a downhole deployment valve. The float valve 55 may be
integral to the upper coupling 52 via an extension sleeve 76 as
shown below to facilitate assembly. However, this flapper float
valve 55 may also be completely separate from the upper coupling
52.
[0070] The flapper of the float valve 55 is held in the open
position while the motor 50 is installed. The motor 50 is
positioned such that it passes through the bore of the float valve
55, thus preventing the spring loaded flapper from pivoting to the
closed position. The secondary float valve 55 remains in the open
position during the drilling and cementing processes.
[0071] After drilling to target depth ("TD") and landing the high
pressure wellhead 12, the cementing process can begin. Prior to
pumping cement, the flow path in the bit drive assembly is changed,
so that cement flow will be directed around the drilling motor 50
as opposed to through the drilling motor 50. In one embodiment, a
diverter mechanism is installed on the top of the motor 50, as
shown in FIG. 6. The diverter mechanism includes a diverter sub 56
that is connected to the inner string 22. The diverter sub 56 has
cementing side port 57 that is in selective communication with the
bore of the diverter sub 56, as shown in FIG. 6. A cementing tube
58 is connected to the side port 57 and extends downward around the
motor 50. In drilling mode, the side port 57 and the cementing tube
58 are blocked by a sleeve 59. The sleeve 59 is held in position
using a shearable member such as a screw 54. In this manner, the
fluid flow is directed through the bore of the diverter sub 56 to
the motor 50.
[0072] When ready to cement, a ball 61 is dropped from surface.
FIG. 8 shows the ball 61 landing in the ball seat of the sleeve 59.
Increasing pressure shears the shear screw 54, thereby allowing the
sleeve 59 to move downward. Movement of the sleeve 59 opens the
cementing port 57 and allows cement to enter the cementing tube 58.
While at the same time, the ball 61 prevents cement from entering
the motor 50.
[0073] Cement is then pumped down the drillstring 5, through the
inner string 22, and into the cementing tube 58. The cementing tube
58 extends downward and exits the casing sub 25 near the lower end
of the motor 50, as shown in FIG. 7. The cementing tube 58 provides
a path for cement to bypass the motor 50 and enter the annulus
between the casing 20 and the borehole.
[0074] To prevent u-tubing of the cement, an optional small flapper
float 64 is positioned near the outlet of the cementing tube 58, as
shown in FIG. 7. An optional rupture disc (not shown) may be
positioned between the flapper 64 and the OD of the surface casing
20 in order to prevent cuttings debris from accumulating in this
space, which might hinder opening of the flapper 64.
[0075] It should be noted that the cementing tube 58 may be
constructed of a rigid material (such as metal tubing) or a
flexible material (such as a high pressure hose).
[0076] After cementing, it is desirable that the majority of the
cementing tube 58 is retrieved to surface along with the drilling
motor 50. In one embodiment, the lower end of the cementing tube 58
is designed to have a releasable "weak point" 66 above the flapper
float 64 to facilitate shearing of the cementing tube 58 from at
the lower end. As the motor 50 is retrieved, the cementing tube 58
will detach at this weak point 66. The upper end of the cementing
tube 58 is retrieved with the motor 50, while the small flapper
float 64 is left behind. FIG. 9 shows the motor 50 removed from the
casing drilling system 100.
[0077] After drilling and cementing operations are completed, the
motor 50 is retrieved up through the secondary flapper float valve
55. Once the motor 50 is no longer holding the float valve 55 in
the open position, the spring loaded flapper is free to pivot to
the closed position. The secondary flapper float valve 55 remains
in place after the motor 50 is retrieved and acts as a secondary
pressure barrier. This barrier feature may act as a safety feature
such as in the event of a poor quality cement job at the casing
shoe.
[0078] After the motor 50 is retrieved, the casing bit 40 is no
longer coupled to the casing sub 25. In ideal conditions, a good
cement job at the casing shoe will prevent the casing bit 40 from
spinning freely as it is drilled-out in subsequent operations. If
the casing bit 40 is not rotationally constrained, the drill-out
process may be problematic. In the event of a poor quality cement
job, or "wet shoe", the casing drilling system includes a
mechanical feature that provides a contingency mechanism for
rotationally locking the casing bit 40 to the casing sub 25.
Locking these two components allows the casing bit 40 to be
drilled-out more easily, since rotation of the casing bit 40 is
prevented.
[0079] Referring now to FIG. 10 the mechanical feature includes a
lock 66 having mating teeth 67, 68. One set of teeth 67 is provided
in the OD of the casing bit 40, such as by machining the teeth 67
into the OD. Mating teeth 68 are provided on locking segments 69
that are preferably attached to the non-rotating casing sub 25. For
example, the locking segments 69 may be welded to the non-rotating
casing sub 25. As shown, three locking segments 69 are used,
however, any suitable number, such as two or four, of segments may
be used. The mating teeth 68 may be machined onto the locking
segments 69.
[0080] The teeth 67 on the casing bit 40 and the teeth 68 on the
locking segment 69 are arranged such that an axial gap is present
between the two sets of teeth 67, 68 when the motor 50 is
installed. The gap prevents the two sets of teeth 67, 68 from
coming in contact (and locking the casing bit 40) as the surface
casing 20 is drilled in place. After the motor 50 is retrieved, the
casing bit 40 can move downward so that the locking teeth 67 on the
casing bit 40 move toward the locking teeth 68 on the locking
segment 69. After closing the gap, the two sets of teeth 67, 68
come in contact, thereby rotationally locking the casing bit 40 for
drill-out.
[0081] In instances where the cutting structure of the casing bit
40 is resting on firm formation, an axial gap between the teeth 67,
68 may still be present, even after the motor 50 is retrieved. It
is anticipated that during the subsequent drill-out operation, the
drill-out bit would contact the internal face of the drillable
casing bit 40. As weight on bit is applied to the drill-out bit, it
would urge the casing bit 40 deeper, possibly causing the casing
bit 40 to drill a small amount of new formation, perhaps only a
fraction of one inch. This would allow the casing bit 40 to move
downward slightly, so that the locking teeth 67, 68 would
eventually come in contact and prevent further rotation of the
casing bit 40. After rotational locking is achieved, the casing bit
40 can be easily drilled out with the drill-out bit.
[0082] FIG. 11 illustrate another embodiment of a casing bit drive
assembly. This embodiment contains many similarities to the
embodiment shown in FIG. 2. Therefore, for sake of clarity, only
the differences will be discussed below. In must be noted that
features taught in one or more embodiment described herein may be
suitably used with another other embodiment described herein. FIGS.
12-18 illustrate enlarged partial views of FIG. 11. The casing bit
drive assembly contains features that allow for cementing through
the drilling motor 50 as opposed to cementing around the motor 50.
In one embodiment, the cement travels through the motor 50 and into
the cavity below the motor 50. The cement then exits the nozzles in
the casing bit 40 and enters the annulus between the casing 20 and
the borehole.
[0083] In order to prevent the lower end of the motor 50 from
getting stuck in the cement, the casing bit drive assembly shown in
FIGS. 12-14 is provided with one or more of the following features:
tapered OD on the stop sub 146, tapered OD on the motor output
shaft 162, and a ring 144 around the neck of the motor output shaft
162. In addition, these surfaces may optionally be coated with a
non-stick surface treatment. Exemplary coating material includes
Teflon, Impreglon, quench polish quench, and combinations thereof.
The non-stick treatment will allow the outer portions of the motor
50 exposed to cement to be more easily retrieved.
[0084] The tandem drilling float valves in the bore of the output
shaft 162 have been changed from plunger-type float valves to
flapper-type float valves 145. The flapper float valves 145 will
allow balls, pistons, and other larger components to pass through
and exit the hollow bore motor 50, before getting trapped in the
stop sub 146 at the lower end of the motor 50.
[0085] A marine-type radial bearing 143 may be provided on the ID
of the non-rotating locking sleeve segments 169, as shown in FIG.
13. This bearing 143 rides against the OD of the rotating casing
bit 40. In one embodiment, the bearing 143 may be molded into the
locking sleeve segments 169. The bearing 143 provides added radial
support to the casing bit 40 during the drilling process. Although
the marine bearing 143 does not provide a true sealing surface, it
will help prevent formation cuttings in the borehole from entering
the assembly.
[0086] FIGS. 15-18 are enlarged views of the motor 50. The top of
the motor 50 connects to the inner string 22. The upper portion of
the rotor 153 is coupled to the stator 154 using axial and radial
bearings 151, 152. An optional upper flex shaft 156 couples the
bearing section to the power section 158 of the rotor 153. The
power section 158 of the rotor 153 has a hollow bore extending
therethrough. Referring to FIG. 17, a flow tube 170 and a diverter
piston 175 are disposed in the bore. The diverter piston 175 is
held in the flow tube 170 using a first shearable member 171 and
blocks fluid flow through the flow tube 170. The flow tube 170 is
held in the bore using a second shearable member 172. The second
shearable member 172 is configured to shear at a lower force than
the first shearable member 171. In drilling mode, the drilling
fluid enters the top of the drilling motor 50. Ports 173 in the
tube 170 are aligned with entry ports 174 in the rotor 153. When
these ports 173, 174 are aligned, the ports 173, 174 are in the
open position to allow flow to enter the top portion of the power
section 158 between the OD of the rotor 153 and the ID of the
stator 154. This provides power to cause rotation of the rotor 153.
The diverter piston 175 prevents fluid from travelling down through
the bore of the flow tube 170.
[0087] As shown in FIGS. 16 and 18, at the lower end of the power
section 158, fluid flow can exit the power section 158 and re-enter
the bore via port 177 to continue flowing downward to the motor
output shaft 162. The lower end of the rotor 153 also includes an
optional lower flex shaft 176 to facilitate transfer of torque to
the output shaft 162 and includes axial and radial bearings.
[0088] Referring to FIG. 19, after drilling is completed, a ball
178 can be dropped to alter the flow path through the motor 50 for
cementing purposes. The ball 178 seats in the entry port 174 of the
power section 158 and effectively blocks the fluid path to the
power section 158. As pressure is increased in FIG. 20, the
"weaker" shear screws 172 connecting the flow tube 170 to the rotor
153 are sheared out, thereby shifting the tube 170 downward. This
downward movement causes the flow tube 170 to seal off the entry
ports 174 to the power section 158. This downward movement also
causes the flow tube 170 to seal off the exit ports 177 from the
power section 158, as shown in FIG. 21. As a result, fluid and
cement can no longer enter the power section 158. This blockage
protects the expensive power section 158 from being damaged as a
result of hardened cement.
[0089] After the tube 170 has shifted downward, the pressure can be
further increased in order to shear out the "stronger" shear
screw(s) 171 that retains the diverter piston 175 against the flow
tube 170, as shown in FIG. 22. The diverter piston 175 is then
forced though the tube 170, and out of the motor 50. The stop sub
146 below the motor 50 traps the diverter piston 175 as it exits
the motor 50, shown in FIG. 23. One or more holes 179 in the stop
sub 146 allow fluid and cement to pass through while keeping the
diverter piston 175 trapped. An open circulation path is now
available for cementing, while the power section 158 remains sealed
from fluid flow. FIG. 24 shows the casing bit assembly after
cementing. The motor 50 has been removed by pulling up and shearing
from the thread couplings 42, 52. Also, the flapper float valve 55
has closed after removal of the motor 50.
[0090] In some instances, although unlikely, while drilling-in the
surface casing 20, the motor's power section 158 could become worn
out. If this were to happen, the motor 50 would no longer be able
to provide sufficient rotation and torque to continue drilling. In
the event of a worn power section 158, it may be desirable to
continue drilling ahead. A contingency motor lock-out feature is
provided so that drilling can continue by rotating the entire
casing string 20 and casing bit 40 together from surface. The motor
lock-out must be done prior to dropping the cementing ball and
shifting the cementing tube 170.
[0091] Referring to FIG. 25, to rotationally lock the motor 50, one
or more lockout balls 181 are dropped from surface. The lockout
balls 181 are smaller is size than the ball 178 dropped to begin
the cementing process. The lockout balls 181 travel though the
drillstring 5 and enter the top of the motor 50. When the balls 181
contact the diverter piston 175, they are directed through the
entry port 174 of the power section 158. The balls 181 are seated
in a space formed between a recess 182 of the OD of the rotor 153
and a recess 183 in the ID of the stator housing 154. The recess
183 may be machined into the ID of the stator housing 154 and is
not a full 360.degree. recess 183. Rather, the machined recess 183
is an arc of less than 360.degree.. This results in a shoulder 185
that remains in the circular path.
[0092] Referring to FIGS. 26A-B and 27, after the balls 181 have
been seated, pump pressure will cause the rotor 153 to begin
turning. Because the balls 181 are trapped in the rotor 153, they
will rotate together with the rotor 153. During rotation, the balls
181 will eventually come in contact with the shoulder 185 in the
recess arc of the stator housing 154. At this point, the motor 50
is effectively locked and can no longer rotate.
[0093] It should be noted that the rotation of the rotor 153 in
relation to the stator housing 154 is eccentric. The degree of
eccentricity or nutation is dependent upon several factors,
including the lobe configuration of the drilling motor 50.
Depending on the amount of eccentricity or nutation, it may require
several revolutions before the balls 181 come in contact with the
shoulder 185 of the stator housing's recess 183, as shown in FIG.
27.
[0094] FIG. 28 illustrate another embodiment of the casing bit
drive assembly. This embodiment contains many similarities to the
embodiments shown in FIGS. 2 and 11. Therefore, for sake of
clarity, only the differences will be discussed below. In must be
noted that features taught in one or more embodiment described
herein may be suitably used with another other embodiment described
herein.
[0095] In one embodiment, the casing bit drive assembly includes a
locking mechanism for rotationally locking the casing bit 40, for
example, immediately prior to pumping cement. The locking mechanism
may act as a contingency locking mechanism to prevent the casing
bit 40 from rotating during the drill-out process.
[0096] As shown in FIG. 28, a guide sleeve 205 and muleshoe tube
210 are installed in the bore of the motor output shaft 162. The
guide sleeve 205 abuts the stop sub 146 and prevents the float
valves 145 from falling out. The upper end of the guide sleeve 205
is tapered like a funnel to help direct the diverter piston 175
into the guide sleeve 205. The guide sleeve 205 also has a ball
seat 206 and angled port 207 which is aligned with complementary
ports 208 in the motor output shaft 162 and the recess 209 in the
lower aluminum coupling 42.
[0097] The muleshoe tube 210 is releaseably connected to the guide
sleeve 205 using a shear screw 211. The angled surface on the top
end of the muleshoe tube 210 is designed to mate with the lower end
of the diverter piston 175. This angled surface will be used to
rotationally align the diverter piston 175 with the angled port 207
and ball seat 206.
[0098] In drilling mode of FIG. 28, drilling fluid can pass through
the ID of the muleshoe tube 210, through the holes 179 in the stop
sub 146, and into the nozzles 41 of the casing bit 40. A portion of
the drilling fluid is directed through the angled port 207 to
provide "positive pressure" to assist in keeping formation cuttings
from entering the assembly.
[0099] After drilling to TD, the bit drive assembly is prepared for
cementing mode by dropping a large ball into the top of the motor
50 and shifting the cementing tube 170, as was described previously
in FIGS. 17-22. The diverter piston 175 is released from its
initial position at the top of the drilling motor 50. The diverter
piston 175 travels downward, through the hollow bore motor 50, and
lands against the muleshoe tube 210, as shown in FIG. 29. The
geometry of the muleshoe angle will properly align the ramp on the
upper end of the piston 175 with the angled ball seat 206 and
angled port 207. The ramp will help guide the small locking balls
into the angled port 207.
[0100] To rotationally lock the motor 50, one or more small balls
212 are dropped from surface, as shown in FIG. 30. The balls 212
are sufficiently sized to pass through the angled port 207. The
balls 212 travel through the drillstring 5 and into the hollow bore
motor 50. When the balls 212 contact the diverter piston 175 in the
bottom of the motor 50, they are directed through the angled port
in the guide sleeve 205, then through the complementary port in the
output shaft 162 and lower aluminum coupling 42. The small balls
212 are seated in a recess 209 between the OD of the aluminum
coupling 42 and the ID of the casing bit 40. The recess 209 is
machined into the end of the casing sub 25, but is not a full
360.degree. recess. Rather, the machined recess is an arc of less
than 360.degree.. This results in a shoulder 213 on the lower end
of the casing sub bit 40. This shoulder 213 remains in the circular
path.
[0101] After the small balls 212 have been seated, a larger ball
214 is dropped from surface, as shown in FIG. 30. The large ball
214 is sized to land in a seat 206 in the guide sleeve 205 to block
the fluid flow path through the angled port 207. Pressure can then
be increased to shear out the screw 211 on the muleshoe tube
210.
[0102] After the muleshoe screw has been sheared, the muleshoe tube
210 and diverter piston 175 are forced through the guide sleeve
205, and out of the motor 50. The stop sub 146 below the motor 50
traps the diverter piston 175 and muleshoe tube 210 as they exit
the motor 50, as shown in FIG. 31. The guide sleeve 205 remains in
the motor 50. Holes in the stop sub 146 allow fluid and cement to
pass through while keeping the diverter piston 175 and muleshoe
tube 210 trapped. An open circulation path is now available for
cementing.
[0103] Because the balls 212 are trapped in the lower coupling 42,
they will rotate together with the lower coupling 42. With
sufficient rotation, for example, less than 360.degree., the balls
212 will come in contact with the shoulder 213 in the recess arc
209 of the casing bit 40. At this point, the casing bit 40 is
effectively locked and can no longer rotate. Locking the casing bit
40 will aid the subsequent drill-out process in the event of a poor
quality cement job at the shoe.
[0104] FIG. 32 illustrates another embodiment of a bit drive
assembly. This embodiment contains many similarities to the
embodiment shown in FIG. 11. For example, referring to FIG. 32, the
features for cementing through the drilling motor 50 and locking
the casing bit 40 during drill-out are similar to those shown in
FIG. 11. For sake of clarity, only the differences will be
discussed below. It is contemplated that one or more of differences
may be used with the embodiment shown in FIG. 11 or any other
suitable embodiment described herein. FIGS. 32 to 34 illustrate
another embodiment of a mechanism for releaseably coupling the
motor output shaft 162 to the casing bit 40 and releaseably
coupling the motor housing 154 to the non-rotating casing 20. In
this embodiment, the couplings use retractable dogs 220, as opposed
to shearable threads, to transmit axial and torsional loads. One
advantage of utilizing retractable dogs 220 is that relatively high
forces can be transmitted, without requiring excessive overpull
forces to release the motor 50 from the couplings. In another
embodiment, the releasable coupling between the motor housing 154
and the casing 20 has been moved to a position on top of the
drilling motor 50.
[0105] FIGS. 32 and 36 show a cross-section of the lower end of the
assembly. The positive pressure port 222 has been re-located to a
position in the drillable aluminum coupling 242, rather than
through the motor output shaft 162 as shown in prior Figures. This
new position allows for placement of a nozzle 223 in line with
positive pressure port 222. The nozzle 223 can be any suitable size
to achieve the desired proportion of fluid flow in relation to the
flow exiting the nozzles in the casing bit 40.
[0106] Retractable dogs 220 are used to transmit axial and torque
loads from the motor output shaft 162 to the lower aluminum
coupling 242. In drilling mode, the dogs 220 extend through the
output shaft 162 and into mating recesses 225 in the lower aluminum
coupling 242. This releasable connection is used to drive the
casing bit 40.
[0107] The dogs 220 are supported internally by the inner mandrel
228, which is installed in the bore of the motor output shaft 162.
In drilling mode, the mandrel 228 is held in position by a
shearable member such as shear screw(s) 227. The bore of the
mandrel includes a ball or piston seat 229 configured to receive
the diverter piston 175. As shown, four dogs 200 are used and
equally spaced apart. However, any suitable number of dogs may be
used.
[0108] The outer surface of the mandrel 228 contains a dovetail
ramp profile 231, as shown in FIGS. 33 and 34. The inner ends of
the dogs 220 include a mating dovetail ramp profile 237. When mated
together, the mandrel 228 effectively grips the dogs 220. As the
mandrel 228 shifts downward, the dogs 220 are positively retracted
along the dovetail profile 231, 237, which puts the dogs 220 in the
disengaged position.
[0109] Positioned above the mandrel 228 is a guide funnel 232,
which is held in position by a retainer clip 233. The guide funnel
232 helps direct the diverter piston 175 into the mandrel's ball
seat 229 as the diverter piston 175 passes through the floats 145.
The guide funnel 232 and retainer clip 233 also keep the floats 145
from falling out.
[0110] A spring-loaded locking sleeve 235 is held in the upward
position with the spring 236 compressed, when the dogs 220 are
extended, as shown in FIG. 32. Downward travel of the locking
sleeve 235 is prohibited by the extended dogs 220.
[0111] After drilling to target depth, the bit drive assembly is
prepared for cementing mode by dropping a large ball into the top
of the motor 50 and shifting the cementing tube 170, as was
described previously in FIG. 11. The diverter piston 175 is
released from its initial position at the top of the drilling motor
50. The diverter piston 175 travels downward, through the hollow
bore motor 50, and lands the ball seat 229 of the mandrel 228, as
shown in FIG. 35. Increasing pressure shears the mandrel shear
screw 227, which releases the mandrel 228 to travel downward. As
the mandrel 228 moves down, the dovetail profile 231, 237
positively retracts the dogs 220.
[0112] Once the dogs 220 have retracted, the spring-loaded locking
sleeve 235 shifts downward, as shown in FIG. 35. The locking sleeve
235 keeps the dogs 220 from re-engaging during the cementing
process. Pressure from pumping the cement cannot push the dogs 220
outward, because they are blocked by the locking sleeve 235.
[0113] The mandrel 228 and diverter piston 175 are forced downward
and out of the motor 50. The stop sub 146 below the motor 50 traps
the diverter piston 175 and mandrel 228 as they exit the motor 50.
The dogs 220 remain in the motor 50 and in the retracted position.
Holes 179 in the stop sub 146 allow fluid and cement to pass
through while keeping the diverter piston 175 and mandrel 228
trapped. An open circulation path is now available for
cementing.
[0114] The releasable coupling 250 between the motor housing 154
and casing 20 has been moved to a location on top of the drilling
motor 50, shown in FIG. 37. The releasable coupling 250 includes a
mandrel 254 attached to the inner string 22 and a coupling housing
253 releasably attached to the mandrel 254 using a shearable member
256 such as a shearable screw. Upper dogs 252 extend from the
coupling housing 253 and engage the coupling receiver 255 that is
attached to the casing 20. The dogs 252 on the upper coupling 250
are held in the engaged position by the inner mandrel 254. When the
mandrel 254 is in the down position, the upper locking dogs 252
cannot retract. The mandrel 254 is held in the down position by the
shearable member 256. The coupling housing 253 optionally includes
a tapered hole for receiving the dogs 252. The coupling 252 may be
made from a drillable material such as aluminum. In one embodiment,
the mandrel 254 may include a polygonal configuration to facilitate
transfer of torque, as shown in FIG. 47. For example, the mandrel
254 may have a hexagonal outer diameter and the housing 253 may
have a complementary shape to receive the mandrel. Other suitable
configurations include, but not limited to, triangle, rectangle,
pentagon, and octagon.
[0115] After disengaging the lower dogs 220, cementing is performed
through the hollow bore of the motor 50. The dogs 252 on the upper
coupling 250 are not retracted prior to cementing. The upper dogs
252 remain engaged to the coupling receiver 255 of the casing 20
throughout the cementing process, in order to resist u-tubing
forces as the cement is pumped. The engaged upper dogs 252 prevent
the motor 50 from being pushed or "pumped" upward during cementing,
and as the cement hardens.
[0116] After the cement has hardened sufficiently to support the
weight of the casing 20, the running tool 60, shown in FIG. 1 is
released from the casing adapter in the casing 20. After releasing
the running tool 60, the components including the drillstring 5,
the running tool 60, and the inner string 22 can be pulled upward.
With continued upward movement, the bumper subs (telescoping
portions of the inner string) will become fully extended. The lower
end of the inner string 22 is connected directly to the mandrel 254
of the upper coupling 250. Upward force is then applied to the
mandrel 254, thereby shearing the screw(s) 256. The mandrel 254 is
then pulled to the upward position, as shown in FIG. 38. Once the
mandrel 254 is pulled to the upward position, the recess 257 on the
outer diameter of the mandrel 254 is moved adjacent to the dogs
252. The dogs 252 are now free to move inward. Continued upward
movement will force the tapered ends of the dogs 252 against the
tapered holes in the coupling receiver 255. This will push the dogs
252 inward into the disengaged position. The drilling motor 50 is
now uncoupled and can be retrieved with the inner string.
[0117] FIG. 39 illustrates another embodiment of a drill out
locking mechanism. The casing bit drive assembly of FIGS. 39 and 40
contains many similarities to the embodiment shown in FIG. 32. For
sake of clarity, only the differences will be discussed below. One
difference is the drill-out locking mechanism for the casing bit
40.
[0118] After the motor 50 is retrieved, the casing bit 40 is no
longer directly coupled to the casing sub 25. In ideal conditions,
a good cement job at the casing shoe will prevent the casing bit 40
from spinning freely as it is drilled-out in subsequent operations.
If the casing bit 40 is not rotationally constrained, the drill-out
process may be problematic. In the event of a poor quality cement
job, or "wet shoe", the casing bit 40 system includes a mechanical
feature provides a contingency mechanism for rotationally locking
the casing bit 40 to the casing sub 25. Locking these two
components allows the casing bit 40 to be drilled-out more easily,
since rotation of the casing bit 40 is prevented.
[0119] Referring to FIG. 39, in one embodiment, the locking
mechanism 270 includes one set of teeth 273 machined into the end
of a sleeve 271 which is threaded and securely fastened to the
non-rotating casing sub 25. This upper locking sleeve 271 is
rotationally and axially affixed to the casing sub 25. A mating set
of teeth 274 is machined into a movable lower sleeve 272. The lower
locking sleeve 272 has tabs 276 which mate with slots 277 in the
lower aluminum base 280. These tabs 276 and slots 277 remain
aligned as the lower sleeve 272 moves axially upward toward upper
locking sleeve 271. The tabs 276 and slots 277 prevent relative
rotation between the lower locking sleeve 272 and the drillable
aluminum base 280.
[0120] The lower sleeve 272 includes a shoulder 278 connecting the
upper, larger diameter portion of the sleeve 272 containing the
teeth 274 and the lower, smaller diameter portion of the sleeve
272. The shoulder 278 is positioned above the aluminum base 280.
The lower sleeve 272 is held in the unengaged, down position by the
lower dogs 220 during drilling mode. The dogs 220 extend through
holes 279 in the lower locking sleeve 272 and also into holes 281
in the aluminum base 280. In drilling mode, the dogs 220 are
engaged with the aluminum base 280 to transmit axial and torsion
loads from the motor output shaft 162 to the casing bit 40. The
extended dogs 220 also prevent the lower locking sleeve 272 from
moving upward. While the dogs 220 are extended or engaged, the
lower sleeve 272 cannot move upward.
[0121] Spring loaded plungers 285 are positioned in the wall of the
casing bit 40. The plungers 285 are spring biased inward. In
drilling mode, the spring 285 is compressed as the plunger tip 286
is compressed against the OD of the lower locking sleeve 272. The
plungers 285 do not prevent upward movement of the lower locking
sleeve 272.
[0122] After drilling to TD, the bit drive assembly is prepared for
cementing mode by dropping a large ball into the top of the motor
50 and shifting the cementing tube 170, as was described previously
in FIGS. 18-22. The diverter piston 175 is released from its
initial position at the top of the drilling motor 50. The diverter
piston 175 travels downward, through the hollow bore motor 50, and
lands the ball seat of the mandrel 228, shown in FIG. 42. The
pressure is increased to shear the mandrel shear screw 227, and to
force the mandrel 228 to move downward, thereby positively
retracting the dogs 220.
[0123] In cementing mode as shown in FIG. 43, when the lower dogs
220 are retracted, the lower sleeve 272 is no longer constrained by
the dogs 220. Pressure from the positive pressure nozzle 223 will
urge the lower sleeve 272 to move upward. As the teeth 274 on the
lower sleeve 272 move toward to teeth 273 on the upper sleeve 271,
the casing bit 40 becomes rotationally locked for the subsequent
drill-out process. This locking mechanism 270 is activated prior to
pumping cement.
[0124] As the shoulder 278 of the lower locking sleeve 272 moves up
past the spring loaded plungers 285, the inwardly biased plunger
tips 286 extend inward and under the shoulder 278. The plunger 285
prevents the lower locking sleeve 272 from moving back down, even
if downward force is applied during the subsequent drill-out
process.
[0125] In the operation sequence shown in FIG. 44, the cement is
then pumped through the drillstring and inner string, into the
hollow bore motor 50, through the holes 179 in the stop sub 146,
out of the nozzles in the casing bit 40, and into the annulus
between the casing 20 and the borehole. Some cement 288 will enter
the cavities adjacent to the lower end of the drilling motor 50 as
seen in FIG. 44. After the cement has hardened sufficiently to
support the weight of the casing 20, the running tool 60 shown in
FIG. 1 is released from the casing adapter of the casing 20. The
upper coupling 250 between the motor 50 and the casing 20 is
released by pulling up on the inner string 22 as described in FIGS.
37-38. The running tool, inner string, and drilling motor 50 are
then pulled to surface.
[0126] As the drilling motor 50 is retrieved up through the
secondary flapper float valve 55, the flapper closes, as shown in
FIG. 45. Once the motor 50 is no longer holding the float 55 in the
open position, the spring loaded flapper is free to pivot to the
closed position. This secondary flapper float valve 55 remains in
place after the motor 50 is retrieved, and acts as a secondary
pressure barrier. This barrier feature may act as a safety feature,
especially in the event of a poor quality cement job at the
shoe.
[0127] After retrieving the motor 50, a second bottom hole assembly
(BHA) is then run in the hole to drill out the cement shoe track
and the drillable casing bit 40. This drilling BHA may continue
drilling ahead into new formation. The casing bit drive and
cementing components remaining in the drill-out path may be
manufactured from a drillable material (e.g., aluminum, composite,
polymer, copper, brass, bronze, zinc, tin, or alloys thereof).
[0128] The locking teeth 273, 274 and tabs 276, 277 on the locking
sleeve 271, 272 are positioned such that they remain outside the
drill-out path, as shown in FIG. 45. In this manner, the casing bit
40 is prevented from rotating throughout the drill-out process.
[0129] In another embodiment, a secondary flapper valve 292 is
positioned in the casing sub 25. In previous embodiments, for
example FIG. 11, the extension sleeve 76 is integral to the upper
coupling 52, which couples the motor housing 154 to the casing 20.
In FIG. 46, the extension sleeve 76 has been removed. The float
housing 290 is affixed directly to the casing sub 25, such as by a
threaded connection.
[0130] The secondary flapper valve 292 is held in the open position
while the motor 50 is installed. The motor 50 is positioned such
that is passes through the bore of the flapper valve 292, thus
preventing the spring loaded flapper from pivoting into the closed
position. This secondary flapper valve 292 remains in the open
position during the drilling and cementing processes.
[0131] After drilling and cementing operations are completed, the
motor 50 is retrieved up through the secondary flapper valve 292.
Once the motor 50 is no longer effectively holding the flapper
valve 292 in the open position, the spring loaded flapper is free
to pivot into the closed position. This secondary flapper valve 292
remains in place after the motor 50 is retrieved, and acts as a
secondary pressure barrier.
[0132] As shown in FIG. 46, the upper ends of the upper coupling 52
and the float housing 290 include a tapered or beveled profile 293.
This profile 293 may be used to guide the subsequent drill-out bit,
and help keep it centralized during the drill-out process.
[0133] During the drill-out process, a subsequent bit is used to
drill through the secondary flapper valve 292. In the float
geometry shown in FIG. 11, the lower portion of the float housing
290 and flapper may break free and fall downward. This piece of
unrestrained material may be problematic to drill through. The
geometry of the float housing 290 of FIG. 46 better restrains the
flapper during the drill-out process. Because a portion of the
float housing 290 remains outside of the drill-out path, the
flapper is constrained until the drill-out bit drills into the
hinge pin. This allows a larger percentage of the flapper to be
drilled, before breaking free.
[0134] The drill-out bit then continues drilling out the shoe
track, the casing bit 40, and into new formation.
[0135] In one embodiment, a method of forming a wellbore in a
formation includes providing a first casing with a motor for
rotating a drilling member relative to the first casing; coupling
the first casing to a second casing; lowering the first casing and
the second casing into the formation; releasing the first casing
from the second casing; rotating the drilling member to extend the
wellbore; supplying cement around the motor and into the wellbore;
detaching the motor from the drilling member; and retrieving the
motor.
[0136] In one embodiment, a method of forming a wellbore in a
formation includes coupling a first casing to a second casing, the
first casing having a motor for rotating the drilling member;
lowering the first casing and the second casing into the formation;
releasing the first casing from the second casing; rotating the
drilling member relative to the first casing to extend the
wellbore; supplying cement around the motor and into the wellbore;
detaching the motor from the drilling member; and retrieving the
motor.
[0137] In one or more of the embodiments described herein, the
motor is coupled to a non-rotating portion of the first casing and
to a rotating portion of the drilling member.
[0138] In one or more of the embodiments described herein, the
motor is releasably coupled to the first casing using a shearable
threaded connection.
[0139] In one or more of the embodiments described herein, the
motor includes a rotatable member and a stationary member, and
further comprising preventing the rotatable member from
rotation.
[0140] In one or more of the embodiments described herein, the
rotatable member is prevented from rotation by landing a ball in a
recess between the rotatable member and the stationary member.
[0141] In one or more of the embodiments described herein, the
cement is diverted to a cementing tube.
[0142] In one or more of the embodiments described herein, the
cement is diverted through a bore in the motor.
[0143] In one or more of the embodiments described herein, the bore
for diverting cement is located in a rotatable member of the
motor.
[0144] In one or more of the embodiments described herein, the
drilling member is locked from rotating relative to the first
casing.
[0145] In one or more of the embodiments described herein, locking
the drilling member from rotation includes engaging a first set of
teeth of the first casing to a second set of teeth of the drilling
member. In one or more of the embodiments described herein, the
first set of teeth is coupled to the first casing using a locking
segment.
[0146] In one or more of the embodiments described herein, locking
the drilling member includes moving a lower sleeve coupled to the
motor toward an upper sleeve coupled to the first casing; and
engaging a first set of teeth of the upper sleeve to a second set
of teeth of the lower sleeve.
[0147] In one or more of the embodiments described herein,
detaching the motor from the drilling member includes retracting a
dog from engagement with the drilling member. In one or more of the
embodiments described herein, the retracted dog is prevented from
re-extending.
[0148] In one or more of the embodiments described herein,
retracting the dog includes axially moving a mandrel coupled to the
dog.
[0149] In one embodiment, a casing drilling system includes a
casing; a drilling member coupled to the casing; a retrievable
motor releasably coupled to the casing and includes a power section
configured to rotate the drilling member relative to the casing;
and a releasable coupling assembly for coupling an output shaft of
the motor to the drilling member. The releasable coupling assembly
includes a coupling attached to the drilling member; and a
retractable dog configured to couple or decouple the output shaft
to the coupling.
[0150] In one or more of the embodiments described herein, the
motor includes a rotating portion and non-rotating housing, wherein
the power section comprises an annular area between the rotating
portion and a non-rotating portion.
[0151] In one or more of the embodiments described herein, the
system includes a coupling for transferring load between the
non-rotating housing and the casing.
[0152] In one or more of the embodiments described herein, the
system includes a bearing for transmitting load from an output
connected to the rotating portion to the non-rotating housing.
[0153] In one or more of the embodiments described herein, the
motor includes an arcuate recess formed in non-rotating housing,
wherein a ball received at an end of the arcuate recess prevents
relative rotation between the rotating portion and the non-rotating
housing.
[0154] In one or more of the embodiments described herein, the
system includes a cement diverter for diverting cement from the
power section of the drilling motor.
[0155] In one or more of the embodiments described herein, the
releasable coupling assembly further comprising a biased sleeve
configured to retain the dog in a retracted position.
[0156] In one or more of the embodiments described herein, the
system includes a locking mechanism to prevent relative rotation
between drilling member and the casing.
[0157] In one or more of the embodiments described herein, the
locking mechanism includes a locking segment attached to the
casing; a first set of teeth formed on the locking segment; and a
second set of teeth formed on the drilling member, wherein the
second set of teeth is engageable with the first set of teeth to
prevent relative rotation between the casing and the drilling
member.
[0158] In one or more of the embodiments described herein, the
locking mechanism includes an arcuate recess formed between the
casing and the drilling member, a ball received at an end of the
arcuate recess prevents relative rotation between casing and the
drilling member.
[0159] In one or more of the embodiments described herein, the
system includes a fluid path between a bore of the motor and the
recess.
[0160] In one or more of the embodiments described herein, the
locking mechanism includes an upper sleeve attached to the casing,
the upper sleeve having a first set of teeth; and a lower sleeve
releasably coupled the motor, the lower sleeve having a second set
of teeth configured to mate with the first set of teeth, wherein
upon release, the lower sleeve is movable to engage the upper
sleeve, thereby preventing relative rotation between casing and the
drilling member.
[0161] In one or more of the embodiments described herein, the
system includes a locking plunger for retaining the lower sleeve in
an engaged position with the upper sleeve.
[0162] In one or more of the embodiments described herein, the
system includes a second releasable coupling assembly for coupling
the motor to the casing.
[0163] In one or more of the embodiments described herein, the
system includes the second releasable coupling assembly includes a
first thread connecting a coupling to the casing and a second
thread for connecting the coupling to the motor, wherein the second
thread is configured to shear at a lower force than the first
thread.
[0164] In one or more of the embodiments described herein, the
system includes a third releasable coupling assembly having a third
thread connecting a second coupling to the drilling member and a
fourth thread for connecting the second coupling to the output
shaft, wherein the fourth thread is configured to shear at a lower
force than the third thread.
[0165] In one or more of the embodiments described herein, the
second releasable coupling assembly includes a coupling having a
locking dog for releasably connecting an upper end of the motor to
the casing; and a mandrel releasably connected to the coupling,
wherein axial movement of the mandrel retracts the locking dog,
thereby decoupling from the casing.
[0166] In one or more of the embodiments described herein, the
coupling attached to the drilling member is drillable.
[0167] While the foregoing is directed to embodiments of the
present invention, other and further embodiments of the invention
may be devised without departing from the basic scope thereof, and
the scope thereof is determined by the claims that follow.
* * * * *