Note: Descriptions are shown in the official language in which they were submitted.
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LONG LATERAL COMPLETION SYSTEM AND METHOD FOR PIPE HANDLING
CROSS REFERENCE TO RELATED APPLICATIONS
TECHNICAL FIELD
[002] One possible embodiment of the present disclosure relates, generally, to
the field of
producing hydrocarbons from subsurface formations. Further, one possible
embodiment of the present disclosure relates, generally, to the field of
making a well
ready for production or injection. More particularly, one possible embodiment
of the
present disclosure relates to completion systems and methods adapted for use
in wells
having long lateral boreholes.
BACKGROUND
[003] In petroleum production, completion is the process of making a well
ready for
production or injection. This principally involves preparing the bottom of the
hole to
the required specifications, running the production tubing and associated
downhole
tools, as well as perforating and/or stimulating the well as required.
Sometimes, the
process of running and cementing the casing is also included.
[004] Lower completion refers to the portion of the well across the production
or injection
zone, beneath the production tubing. A well designer has many tools and
options
available to design the lower completion according to the conditions of the
reservoir.
Typically, the lower completion is set across the production zone using a
liner hanger
system, which anchors the lower completion equipment to the production casing
string.
[005] Upper completion refers to all components positioned above the bottom of
the
production tubing. Proper design of this "completion string" is essential to
ensure the
well can flow
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properly given the reservoir conditions and to permit any operations deemed
necessary
for enhancing production and safety.
[0061 In cased hole completions, which are performed in the majority of wells,
once the
completion string is in place, the final stage includes making a flow path or
connection
between the wellbore and the formation. The flow path or connection is created
by
running perforation guns into the casing or liner and actuating the
perforation guns to
create holes through the casing or liner to access the formation. Modern
perforations
can be made using shaped explosive charges.
10071 Sometimes, further stimulation is necessary to achieve viable
productivity after a well is
fully completed. There are a number of stimulation techniques which can be
employed
at such a time.
[0081 Fracturing is a common stimulation technique that includes creating and
extending
fractures from the perforation tunnels deeper into the formation, thereby
increasing the
surface area available for formation fluids to flow into the well and avoiding
damage
near the wellbore. This may be done by injecting fluids at high pressure
(hydraulic
fracturing), injecting fluids laced with round granular material (proppant
fracturing), or
using explosives to generate a high pressure and high speed gas flow (TNT or
FEIN,
and propellant stimulation).
10091 Hydraulic fracturing, often called fracking, fracing or hydrofracking,
is the process of
initiating and subsequently propagating a fracture in a rock layer, by means
of a
pressurized fluid, in order to release petroleum, natural gas, coal steam gas
or other
substances for extraction. The fracturing, known colloquially as a frack job
or frac job,
is performed from a wellbore drilled into reservoir rock formations. The
energy from
the injection of a highly pressurized fluid, such as water, creates new
channels in the
rock that can increase the extraction rates and recovery of fossil fuels.
[0010] The technique of fracturing is used to increase or restore the rate at
which fluids, such as
oil or water, or natural gas can be produced from subterranean natural
reservoirs,
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including unconventional reservoirs such as shale rod or coal beds. Fracturing
enables
the production of natural gas and oil from rock formations deep below the
earth's
surface, generally 5,000-20,000 feet or 1,500-6,100 meters. At such depths,
there may
not be sufficient porosity and permeability to allow natural gas and oil to
flow from the
=
rock into the wellbore at economic rates. Thus, creating conductive fractures
in the rock
, is essential to extract gas from shale reservoirs due to the
extremely low natural
permeability of shale. Fractures provide a conductive path connecting a larger
area of
the reservoir to the well, thereby increasing the area from which natural gas
and liquids
can be recovered from the targeted formation.
[0011] Pumping the fracturing fluid into the wellbore, at a rate sufficient to
increase pressure
downhole, until the pressure exceeds the fracture gradient of the rock and
forms a
fracture. As the rock cracks, the fracture fluid continues to flow farther
into the rock,
extending the crack farther. lb prevent the fracture(s) from closing after the
injection
process has stopped, a solid proppant, such as a sieved round sand, can be
added to the
fluid. The propped fracture remains sufficiently permeable to allow the flow
of
formation fluids to the well.
[0012] The location of fracturing along the length of the borehole can be
controlled by inserting
composite plugs, also known as bridge plugs, above and below the region to be
= fractured. This allows a borehole to be progressively fractured along the
length of the
bore while preventing leakage of fluid through previously fractured regions.
Fluid and
proppant are introduced to the working region through piping in the upper
plug. This
method is commonly referred to as "plug and perf."
[0013] Typically, hydraulic fracturing is performed in cased wellbores, and
the zones to be
fractured are accessed by perforating the casing at those locations.
[0014] While hydraulic fracturing can be performed in vertical wells, today it
is more often
performed in horizontal wells. Horizontal drilling involves wellbores where
the
terminal borehole is completed as a "lateral" that extends parallel with the
rock layer
containing the substance to be extracted. For example, laterals extend 1,500
to 5,000
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feet in the Barnett Shale basin. In contrast, a vertical well only accesses
the thickness
of the rock layer, typically 50--300 feet. Horizontal drilling also reduces
surface
disruptions, as fewer wells are required. Drilling a wellbore produces rock
chips and
fine rock particles that may enter cracks and pore spaces at the wellbore
wall, reducing
the porosity and/or permeability at and near the wellbore. The production of
rock chips,
fine rock particles and the like reduces flow into the borehole from the
surrounding
rock formation, and partially seals off the borehole from the surrounding
rock.
Hydraulic fracturing can be used to restore porosity and/or permeability.
[0015] Conventional lateral wells are completed by inserting coiled tubing or
a similar, generally
flexible conduit therein, until the flexible nature of the tubing prevents
further insertion.
While coil tubing does not require making up and/or breaking out each pipe
joint,
coiled tubing cannot be rotated, which increases the likelihood of sticking
and
significantly reduces the ability to extend the pipe laterally. Once a certain
depth is
reached in a highly angled and/or horizontal well, the pipe essentially acts
like soft
spaghetti and can no longer be pushed into the hole. Coiled tubing is also
more limited
in terms of pipe wall thickness to provide flexibility thereby limiting the
weight of the
= string.
[0016] Conventional completion rigs include a mast, which extends upward and
slightly outward
typically at approximately a 3 degree angle from a carrier or similar base
structure. The
angled mast provides that cables and/or other features that support a top
drive and/or
other equipment can hang downward from the mast, directly over a wellbore,
without
contacting the mast. For example, most top drives and/or power swivels require
a
"torque arm" to be attached thereto, the torque arm including a cable that is
secured to
the ground or another fixed structure to counteract excess torque and/or
rotation applied
to the top drive/power swivel. Additionally, a blowout preventer stack, having
sufficient components and a height that complies with required regulations,
must be
positioned directly above the wellbore. A mast having a slight angle
accommodates for
these and other features common to completion rigs. As a result, a rig must
often be
positioned at least four feet, or more, away from the wellbore depending on
the height
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=
of the mast. A need exists for systems and methods having A reduced footprint,
especially in lucrative regions where closer spacing of wells can
significantly affect
production and economic gain, and in marginal regions, where closer spacing of
wells
would be necessary to enable economically viable production.
[0017] Prior to common use of coiled tubing, completion operations often
involved the use of
workover/production rigs for insertion of successive joints of pipe, which
must be
threaded together and torqued, often by hand, creating a significant potential
for injury
or death of laborers involved in the completion operation, and requiring
significant time
to engage (e.g., "make up") each pipe joint. Drilling rigs could also be
utilized to run
production tubing but are more expensive although the individual joints of
pipes result
in the same types of problems.
[00181 A significant problem with prior art production/workover rigs or
drilling rigs as opposed
to coiled tubing units is that individual production tubing 'pipe connections
are often
considerably more difficult to make up and/or break out than the drilling pipe
connections. Drilling pipe connections are enlarged and are designed for quick
make
up and break out many times with very little concern about exact alignment of
the
connectors. Drill pipe is designed to be frequentry and quickly made up and
broken out
without being damaged even if the alignment is not particularly precise. On
the other
hand, production tubing is normally intended for long term use in the well and
requires
much more accurate alignment of the connectors to avoid damaging the threads.
Production tubing does not typically utilize the expensive enlarged conncctors
like drill
pipe and, in some completions, enlarged connectors simply are not feasible due
to
clearance problems within the wellbore. Thus, especially for production
tubing, prior
art workover/production rigs are much slower for inserting and/or removing
production
tubing pipe into or out of the well than coiled tubing units and are more
likely to result
in operator injuries and errors during pipe connection make up and break out
than
coiled tubing. There are also problems with human error in aligning the
individual
production tubing connectors whereby cross-threading could result in a damaged
or
leaking connection.
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[0019] Prior art insertion techniques of completion tubing into a lateral well
therefore suffers
from significant limitations including but not limited to: 1) the longer time
required to
run tubing into a well; 2) operator safety; and 3) the maximum horizontal
distance
across which the tubing can be inserted is limited by the nature of the tubing
used
and/or the force able to be applied from the surface. Generally, once the
frictional
forces between the lateral portion of the well and the length of tubing
therein exceed
=
the downward force applied by the weight of the tubing in the vertical portion
of the
well, further insertion becomes extremely difficult, if not impossible, thus
limiting the
maximum length of a lateral.
(0020] Due to the significant day rates and rental costs when performing
oilfield operations, a
need exists for systems and methods capable of faster, yet safer insertion of
pipe and/or
tubing into a well. Additionally, due to the costs associated with the
drilling,
completion, and production of a well, a need exists for systems and methods
capable of
extending the maximum length of a lateral, thereby increasing the productivity
of the
well.
[0021] Hydraulic fracturing is commonly applied to wells drilled in low
permeability reservoir
rock. An estimated 90 percent of the natural gas wells in the United States
use hydraulic
fracturing to produce gas at economic rates.
[0022] The fluid injected into the rock is typically a slurry of water,
proppants, and chemical
additives. Additionally, gels, foams, and/or compressed gases, including
nitrogen,
carbon dioxide and air can be injected. Various types of proppant include
silica sand,
resin-coated sand, and man-made ceramics. The type of proppant used may vary
depending on the type of permeability or grain strength needed. Sand
containing
naturally radioactive minerals is sometimes used so that the fracture trace
along the
wellbore can be measured. Chemical additives can be applied to tailor the
injected
material to the specific geological situation, protect the well, and improve
its operation,
though the injected fluid is approximately 99 percent water and 1 percent
proppant, this
composition varying slightly based on the type of well. The composition of
injected
" fluid can be changed during the operation of a well over time. Typically,
acid is
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initially used to increase permeability, then proppants are used with a
gradual increase
in size and/or density, and finally, the well is flushed with water under
pressure. At least
a portion of the injected fluid can be recovered and stored in pits or
containers; the fluid
can be toxic due to the chemical additives and material washed out from the
ground.
The recovered fluid is sometimes processed so that at least a portion thereof
can be
reused in fracking operations, released into the environment after treatment,
and/or left
in the geologic formation.
[0023] Advances in completion technology have led to the emergence of open
hole multi-stage
fracturing systems. These systems effectively place fractures in specific
places in the
wellbore, thus increasing the cumulative production in a shorter time frame.
[0024] Those of skill in the art will appreciate the present system which
addresses the above and
other problems.
BRIEF DESCRIPTION OF THE DRAWINGS
[0025] The accompanying drawings, which are incorporated in and constitute a
part of this
specification, illustrate an implementation of apparatus consistent with one
possible
embodiment of the present disclosure and, together with the detailed
description, serve
to explain advantages and principles consistent with the disclosure. In the
drawings,
100261 FIG. 1 illustrates an embodiment of a long lateral completion system
usable within the
scope of one possible embodiment of the present disclosure.
100271 FIG. 2 is a perspective view of the mast assembly, pipe arm, pipe tubs,
and the carrier of
the long lateral completion system of FIG. 1 in accord with one possible
embodiment
of the completion system of the present disclosure.
[0028] FIG. 3 is a plan view of the carrier, mast assembly, pipe arm, and pipe
tub of the long
lateral completion system of FIG. 1 in accord with one possible embodiment of
the
completion system of the present disclosure.
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. [0029] FIG. 4 is an illustration of the carrier of the long lateral
completion system of FIG. 1 in
accord with one possible embodiment of the completion system of the present
disclosure.
[0030] FIG. 4A-A is a cross sectional view of the carrier of FIG. 4 taken
along the section line
A-A in accord with one possible embodiment of the completion system of the
present
disclosure.
[0031] FIG. 4B-B is a cross sectional view of the carrier of FIG. 4 taken
along the section line B-
B in accord with one possible embodiment of the completion system of the
present
disclosure.
[0032] FIG. 5 is an elevation view of the carrier, the mast assembly, the pipe
arm and the pipe
tubs of the long lateral completion system of FIG. 1 in accord with one
possible
embodiment of the completion system of the present disclosure.
[0033] FIG. 5A is an enlarged or detailed view of the section identified in
FIG. 5 as "A" of the
rear portion of the carrier engaged with a skid of the depicted long lateral
completion
system in accord with one possible embodiment of the completion system of the
present disclosure.
[0034] FIG. 6 illustrates an elevation view of the completion system of FIG. 1
with the mast
assembly extended in a perpendicular relationship with the carrier and the
pipe tubs in
accord with one possible embodiment of the completion system of the present
disclosure.
[0035] FIG. 6A is an enlarged or detailed view of the portion of FIG. 6
indicated as section "A"
illustrating the relationship of the mast assembly, the deck and the base beam
in accord
with one possible embodiment of the completion system of the present
disclosure.
[0036] FIG. 7 is an elevation view of the carrier, the mast assembly, the pipe
arm, and the pipe
tub of FIG. 1, with the mast assembly shown in a perpendicular relationship
with the
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carrier, and the pipe aim engaged with the mast in accord with one possible
embodiment of the completion system of the present disclosure.
100371 FIG. 7A-A is a cross sectional view of FIG. 7 taken along the section
line A-A showing
the mast assembly and top drive of the depicted long lateral completion system
in
accord with one possible embodiment of the completion system of the present
disclosure.
100381 FIG. 7B is a perspective view of the portion of the mast assembly and
pipe arm illustrated
in FIG. 7A-A in accord with one possible embodiment of the completion system
of the
present disclosure.
(00391 FIG. 8 is an elevation view of. the completion system of FIG. 1
illustrating the mast
assembly in a perpendicular relationship with the carrier, including the use
of a
hydraulic pipe tong in accord with one possible embodiment of the completion
system
of the present disclosure.
100401 FIG. '8A-A is a cross sectional view of the system of FIG. 8 taken
along the section line
A-A, showing the pipe tong with respect to the mast assembly in accord with
one
possible embodiment of the completion system of the present disclosure.
100411 FIG. 8B-B is a cross sectional view of the system of FIG. 8 taken along
the section line
B-B, showing the mast assembly and top drive in accord with one possible
embodiment
of the completion system of the present disclosure.
100421 FIG. 8C is a perspective view of the portion of the system shown in
FIG. 8B in accord
with one possible embodiment of the completion system of the present
disclosure.
100431 FIG. 9 is an illustration of the long lateral completion system of FIG.
1, depicting the
relationship between the carrier, the mast assembly, the pipe arm, the pipe
tubs and a
blowout preventer in accord with one possible embodiment of the completion
system of
the present disclosure.
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[0044] FIG. 9A-A is a cross sectional view of the system of FIG. 9 taken along
the section line
AA, illustrating the upper portion of the mast assembly in accord with one
possible
embodiment of the completion system of the present disclosure.
[0045] FIG. 9B-B is a perspective view of the upper portion of the mast
assembly as illustrated
in FIG. 9A-A, showing the top drive and the pipe clam in accord with one
possible
embodiment of the completion system of the present disclosure.
100461 FIG. 9C-C is a cross sectional view of the system of FIG. 9 taken along
the section line
C-C, illustrating the relationship of the blowout preventer to the completion
system in
accord with one possible embodiment of the completion system of the present
disclosure.
=
[0047] FIG. 10A is an illustration of an embodiment of a pipe tong fixture
usable in accord with
one possible embodiment of the completion System of the present disclosure.
[0048] FIG. 10B is a perspective view of the pipe tong fixture of FIG. 10A.
[0049] FIG. 11A, FIG. 11B, FIG. 11C, and FIG. 11D illustrate an embodiment of
a compact
snubbing unit usable in accord with one possible embodiment of the completion
system
of the present disclosure.
[0050] FIG. 12A is a schematic view of an embodiment of a control cabin usable
in accord with
one possible embodiment of the completion system of the present disclosure.
100511 FIG. 12B is an elevation view of the control cabin of FIG. 12A in
accord with one
possible embodiment of the completion system of the 'present disclosure.
100521 FIG. 12C is a first end view (e.g., a left side view) of the control
cabin of FIG. 12A in
accord with one possible embodiment of the completion system of the present
disclosure.
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[0053] FIG. 12D is an opposing end view (e.g., a right side view) of the
control cabin of FIG.
12A in accord with one possible embodiment of the completion system of the
present
disclosure.
100541 FIG. 13 is an illustration of an embodiment of a carrier adapted for
use in accord with one
possible embodiment of the completion system of the present disclosure.
[0055] FIG. 14 is an illustration of an embodiment of a pipe arm usable in
accord with one
possible embodiment of the completion system of the present disclosure.
[0056] FIG 14A depicts a detail view of an engagement between the pipe arm of
FIG. 14 and an
associated skid in accord with one possible embodiment of the completion
system of
the present disclosure.
[0057] FIG. 15A is an elevation view of the pipe ann of FIG. 14 in accord with
one possible
embodiment of the completion system of the present disclosure.
[0058] FIG. 15B is an exploded view of a portion of the pipe arm of FIG. 15A,
indicated as
section "B" in accord with one possible embodiment of the completion system of
the
present disclosure.
[0059] FIG. 15C is an enlarged or detailed view of a portion of the pipe arm
of FIG. 15A,
indicated as section "C" in accord with one possible embodiment of the
completion
system of the present disclosure.
-100601 FIG. 15D is an enlarged or detailed view of a portion of the pipe arm
of FIG. 15A,
indicated as section "D" in accord with one possible embodiment of the
completion
system of the present disclosure.
[0061] FIG. 15E is a plan view of the pipe arm of FIG. 14 in accord with one
possible
embodiment of the completion system of the present disclosure.
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100621 FIGs. 15F and 15G are end views of the pipe arm of FIG. 14 in accord
with one possible
embodiment of the completion system of the present disclosure.
000631 FIG. 16A is an elevation view of the pipe arm of FIG. 14 in accord with
one possible
embodiment of the completion system of the present disclosure.
10064] FIG. 16B is a plan view of the pipe arm of FIG. 14 in accord with one
possible
embodiment of the completion system of the piesent disclosure.
100651 FIG. 16C is an enlarged or detailed view of a portion of the pipe arm
of FIG. 16 A,
indicated as section "C" in accord with one possible embodiment of the
completion
system of the present disclosure.
[00661 FIG. 16D is an end view of the pipe arm of FIG. 14 in accord with one
possible
embodiment of the completion system of the present disclosure.
100671 FIG. 17 is a perspective view of an embodiment of a kickout arm usable
in accord with
one possible embodiment of the completion system of the present disclosure.
100681 FIG. 17A is an enlarged or detailed view of an embodiment of a clamp of
the kickout arm
of FIG. 17 in accord with one possible embodiment of the completion system of
the
present disclosure.
100691 FIG. 18A is an elevation view of the kickout arm of FIG. 17 in accord
with one possible
embodiment of the completion system of the present disclosure.
100701 FIG. 18B is a bottom view of the kickout arm of FIG. 17 in accord with
one possible
embodiment of the completion system of the present disclosure.
[0071J FIG. 18C is a top view of the kickout arm of FIG. 17 in accord with one
possible
embodiment of the completion system of the present disclosure.
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100721 FIG. 18B-B is a sectional view of the end taken along the section line
B-B in FIG. 18B in
accord with one possible embodiment of the completion system of the present
disclosure.
100731 FIG. 18C-C is a cross sectional view of the Idckout arm of FIG. 18C
taken along the
section line C-C in accord with one possible embodiment of the completion
system of
the present disclosure.
100741 FIG. 19A is an elevation view of an embodiment of a top drive fixture
usable with the
mast assembly of embodiments of the completion system in accord with one
possible
embodiment of the completion system of the present disclosure.
100751 FIG. 19B is a side view of the top drive fixture illustrated in FIG.
19A in accord with one
, possible embodiment of the completion system of the present
invention.
100761 FIG. 19C-C is a cross sectional view of the top drive fixture of FIG.
19B taken along the
section line C-C in accord with one possible embodiment of the completion
system of
the present disclosure.
100771 FIG. 19D is an enlarged or detailed view of a portion of the top drive
fixture of FIG. 19B
indicated as section "D" in accord with one possible embodiment of the
completion
system of the present disclosure.
100781 FIG. 19E-E is a cross sectional view of the top drive fixture of FIG.
19A taken along the
section line E-E in accord with one possible embodiment of the completion
system of
the present disclosure.
100791 FIG. 20A is an illustration of a top drive within the top drive fixture
of FIG. 19A in
accord with one possible embodiment of the completion system of the present
disclosure.
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[0080] FIG. 20 A-A is a cross sectional view of the top drive and fixture of
FIG. 20A taken along
section line A-A in accord with one possible embodiment of the completion
system of
the present disclosure.
=
[0081] FIG. 20B is a top view of the top drive and fixture of FIG. 20A in
accord with one
possible embodiment of the completion system of the present disclosure.
[0082] FIG. 21A is a perspective view of a pivotal pipe ann having a pipe
thereon with pipe
clamps retracted to allow a pipe to be received into receptacles of the pipe
arm in
accord with one possible embodiment of the completion system of the present
disclosure.
[0083] FIG. 21B is a perspective view of a pivotal pipe arm having a pipe
thereon with pipe
clamps engaged with the pipe whereby the pipe arm can be moved to an upright
position in accord with one possible embodiment of the completion system of
the
present disclosure:
[0084] FIG. 22A is an end perspective view of a walkway with pipe moving
elements whereby
the pipe moving elements are positioned to urge pipe into a pipe arm in accord
with one
possible embodiment of the completion system of the present disclosure.
[0085] FIG. 22B is an end perspective view of a walkway with pipe moving
elements whereby a
pipe has been urged into a pipe arm by pipe moving elements in accord with one
possible embodiment of the completion system of the present disclosure.
[0086] FIG. 23A is an end perspective view of a pipe feeding mechanism whereby
a pipe is
transferred from a pipe tub into a pipe arm in accord with one possible
embodiment of
the present disclosure.
[0087] FIG. 23B is another end perspective view of a pipe feeding mechanism
whereby a pipe is
transferred from a pipe tub into a pipe arm in accord with one possible
embodiment of
the present disclosure.
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[0088] FIG. 23C is a cross sectional view of a pipe feeding mechanism whereby
a pipe is
transferred from a pipe tub into a pipe arm in accord with one possible
embodiment of
the present disclosure.
[0089] FIG. 23D is a cross sectional view of a pipe feeding mechanism with the
pipes removed
in accord with one possible embodiment of the present disclosure.
[0090] FIG. 23E is a cross sectional view of a pipe feeding mechanism whereby
a pipe is
transferred from a pipe tub into a pipe arm in accord with one possible
embodiment of
the present disclosure.
[0091] FIG. 24A is a perspective view of an embodiment of a gripping apparatus
engageable
with a top drive of one possible embodiment of the present disclosure. "
[0092] FIG. 24B depicts a diagrammatic side view of the gripping apparatus of
FIG. 24A.
[0093] FIG. 25A is an exploded perspective view of a guide apparatus
engageable with a top
drive.
[0094] FIG. 25B is a diagrammatic side view of the guide apparatus of FIG.
25A.
[0095] FIG. 26 is a top view of a roller engaged with a guide rail in accord
with one possible
embodiment of the present disclosure.
[0096] FIG. 27A is a top view of a crown block sheave assembly showing an axis
of rotation in
accord with one possible embodiment of the present disclosure.
[0097] FIG. 27B is a top view of a traveling sheave block showing an axis of
rotation in accord
with one possible embodiment of the present disclosure.
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=
[00981 FIG. 28A is a perspective view of a system for conducting a long
lateral well completion
system of multiple wellheads in close proximity in accord with one possible
embodiment of the present invention.
= [00991 FIG. 28B is another perspective view of a system for conducting a
long lateral well
completion system of multiple wellheads in close proximity in accord with one
possible
embodiment of the present invention.
1001001 The above general description and the following detailed description
are merely
illustrative of the generic invention, and additional modes, advantages, and
particulars
of this invention will be readily suggested to those skilled in the art
without departing
from the spirit and scope of the invention.
DESCRIPTION OF, EMBODIMENTS
1001011 FIG. 1 illustrates an embodiment of a long lateral completion system
10 usable in
accord with one possible embodiment of the completion system of the present
disclosure. In this embodiment, the completion system 10 is shown having a
mast
assembly 100, which extends in a generally vertical direction (i.e.,
perpendicular to the
rig carrier 600 and/or the earth's surface), a pipe handling mechanism 200, a
catwalk -
pipe arm assembly 300, two pipe tubs 400, a pump pit combination skid 500, a
rig
= carrier 600 usable to transport the mast assembly 100 and various
hydraulic and/or
motorized pumps and power sources for raising and lowering the mast assembly
100
and operating other rig components, and a control van 700, used to control
operation of
= one or more of the components of long lateral completion system 10. Other
embodiments may comprise the desired completion system 10 components otherwise
arranged on skids as desired. For example, in another embodiment, separate
pump and
pit skids might be utilized. In another embodiment, catwalk pipe tubes with
tube
handling elements might be combined on one skid with pipe arm assembly 300
provided separately. It will be appreciated that many different embodiments
may be
utilized. Accordingly, FIG. 1 shows one possible arrangement of various
components
of the completion system 10 that can be implemented around a well (e.g., an
oil, natural
gas, or water well). Due to the construction, system 10 can work with wells
that are in
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close proximity to each other, e.g. within ten feet of each other. For
example, mast
assembly 100 may be located above a first well, as discussed hereinafter, and
rig floor
102 (if used) may be elevated above a second capped wellhead (not shown)
within ten
=
feet of the first well. Sensors, such as laser sights, guides mounted to the
rear of rig
earner 600, and the like may be utilized, e.g., mounted to and/or guided to
the well
head, to locate and orient the axis of drilling rig mast 100 precisely with
respect to the
wellbore, which in one embodiment may be utilized to align a top drive mounted
on
guide rails with the wellbore, as discussed hereinafter.
1001021 Control van 700 and automated features of system 10 can allow a single
operator in the
van to view and operate the truck mounted production rig by himself, including
raising
the derrick, picking up pipe, torqueing to the desired torque levels for
tubing, going in
the hole, coming out of the hole, performing workover functions, drilling out
plugs,
and/or other steps completing the well, which in the prior art required a rig
crew, some
problems of which were discussed above. In other embodiments, the control van
700
and/or other features can be configured for use and operation by multiple
operators.
Control van 700 may comprise a window arrangement with windows at the top,
front,
sides and rear (See e.g., FIG. 12B), so that once positioned in a desired
position on the
well site, all operations to the top of mast 100 are readily visible.
1001031 For example, embodiments of the system 10 can be positioned for real
time operation,
e.g., by a single individual operating the control van 700 and/or a similar
control
system, and further embodiments can be used to perform various functions
automatically, e.g., after calibrating the system 10 for certain movements of
the pipe
arm assembly 300, the top drive or a similar type of drive unit along the mast
assembly
100, etc. After providing the system 10 in association with a wellbore, e.g.,
by erecting
the mast assembly 100 vertically thereabove, a tubular segment can be
transferred from
one or more pipe tubs and/or similar vessels to the pipe arm assembly 300, and
the
control van 700 and/or a similar system can be used to engage the tubular
segment with
a pipe moving arm thereof. For example, as described hereinafter, hydraulic
members
of the pipe tubs and/or similar vessels can be used to urge a tubular member
over a stop
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into a position for engagement with a pipe moving arm, while hydraulic
grippers
thereof can be actuated to grip the tubular member. The control system can
then be
used to raise the pipe moving arm and align the tubular segment with the mast
assembly, which can include extension of a kick-out arm from the pipe moving
arm,
further described below. Alignment of the tubular segment with the mast
assembly
could further include engagement of the tubular segment by grippers (e.g.,
hydraulic
clamps and/or jaws) positioned along the mast. The control system is further
usable to
move the top drive along the mast assembly to engage the tubular segment
(e.g.,
through rotation thereof), to disengage the pipe moving arm from the tubular,
and to
further move the top drive to engage the tubular segment with a tubular string
associated with the wellbore. While the system is depicted having a pipe
moving arm
used to raise gripped segments of pipe into association and/or alignment with
the mast,
in other embodiments, a catwalk-type pipe handling system in which the front
end of
each pipe segment is pulled and/or lifted into a desired position, while the
remainder of
the pipe segment travels along a catwalk, can be used.
1001041 In an embodiment, any of the aforementioned operations can be
automated. For
example, the control system can be used to calibrate movement of the drive
unit along
the mast assembly, e.g., by determining a suitable vertical distance to travel
to engage a
top drive with a tubular segment positioned by the pipe moving arm, and a
suitable
vertical distance to travel to engage a tubular segment engaged by the top
drive with a
tubular string below, such that movement of a top drive between positions for
engagement with tubular members and engagement of tubular members with a
tubular
string can be performed automatically thereafter. Tne control system can also
be used
to calibrate movement of the pipe moving arm between raised and lowered
positions,
depending on, the position of the mast assembly 100 relative to the pipe arm
assembly
300 after positioning the system 10 relative to the wellbore. Then, future
movements of
the pipe moving arm, and the kick-out arm, if used, can be automated. In a
similar
manner, grippers on the mast assembly 100, if used, annular blowout preventers
and/or
ram/snubbing assemblies, and other components of the system 10 can be operated
using
the control system, and in an embodiment, in an automated fashion. After
assembly of
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a completion string, further operations, such as fracturing, production,
and/or other
operations that include injection of substances into or removal of substances
from the
wellbore can be controlled using the control system, and in an embodiment, can
be
automated. In embodiments where a catwalk-type pipe handling system is used,
operations of the catwalk-type pipe handling system can also be highly
automated,
including engagement of the front end of a pipe segment, lifting and/or
otherwise
moving the front end of the pipe segment, and the like.
[00105] FIG. 2 is a perspective view of the mast assembly 100, catwalk - pipe
arm assembly
300, pipe tubs 400, and the carrier 600 of the long lateral completion system
10 in
accord with one possible embodiment of the completion system of the. present
invention. The carrier 600 has the mast assembly 100 extending from the rear
portion
of the carrier 600. In one embodiment, the mast assembly 100 is essentially
perpendicular to the carrier 600. In another embodiment, mast assembly 100 is
aligned
either coaxially, within less than three inches, or two inches, or one inch to
an axis of
the bore through the wellhead, BOPs, or the like when the top drive is
positioned at a
lower portion of the mast and/or is parallel to the axis of the borehole
adjacent to the
surface of the well and/or the bore of the wellhead pressure equipment within
less than
.
.
five degrees, or less than three degrees, or less than one degree in another
embodiment,
For example, in one embodiment, mast rails 104, which guide top drive 150, may
be
aligned to be essentially parallel to the axis of the bore, within less than
five degrees in
one embodiment, or less than three degrees, or less than one degree in another
embodiment, whereby top drive 150 moves coaxially or concentric to the well
bore
within a desired tolerance. As used herein, a well completion system may be
essentially synonymous with a workover system, or drilling system, or rig, or
drilling
rig or the like. The system of the present invention may be utilized for
completions,
workovers, drilling, general operations, and the like and the term workover
rig,
completing rig, drilling rig, completion system, intervention system,
operating system,
and the like are used herein substantially interchangeably for the herein
described
system. Pipe, as used herein, may refer interchangeably to a pipe string, a
single pipe, a
single pipe that is connected to or removed from a pipe string, a stand of
pipe for
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connection or removal from a pipe string, or a pipe utilized to build a pipe
string,
tubular, tubulars, tubular string, oil county tubulars, or the like.
100106] The carrier 600 is illustrated with a power plant 650 and a winch or
drawworks
assembly 620. Winch or drawworks 620 can be utilized for lifting and lowering
the top
drive 150, in mast 100, utilizing pulley arrangements in crown 190 and blocks
associated with top drive 150. The mast positioning hydraulic actuators 630
provide
for lifting the mast assembly 100 into a desired essentially vertical
position, with
respect to the axis of the borehole at the surface of the well, within a
desired accuracy
alignment angle. In one embodiment, a laser sight may be mounted to the
wellbore
with a target positioned at an upper portion of the mast to provide the
desired accuracy
of alignment. In this embodiment, crown laser alignment target 192 is provided
adjacent crown 190. The mast assembly 100 is affixed to the rear portion of
the carrier
600. Also the mast assembly 100 is illustrated with a top drive 150 and a
crown 190.
The top drive allows rotation of the tubing, which results in significant
improvement
when inserting pipe into high angled and/or horizontal well portions. Further
associated with the mast assembly 100 and the carrier 600 is a mast support
base beam
120, for providing stability to the carrier 600 and the mast assembly 100,
e.g., by
increasing the surface area that contacts the ground.
1001071 In one possible embodiment, a catwalk - pipe arm assembly 300 may be
located
proximate to the mast assembly 100, which, in one possible embodiment, may be
utilized to automatically insert and/or remove pipe from the wellbore. In one
embodiment, the pipe is not stacked in the rig but instead is stored in one or
more
moveable pipe tubs 400. Catwalk - pipe arm assembly 300 may be configured so
that
components are provided in different skids, as discussed hereinbefore, and as
discussed
hereinafter to some extent. In this example, catwalk - pipe arm assembly 300
has
associated on either side thereof a pipe tub 400. However, pipe tubes 400 may
be used
on only one side, two on one side, or any configuration may be utilized that
fits with
the well site. While more than two pipe tubes can be utilized, usually not
more than
four pipe tubs are utilized. However, pipe racks or other means to hold and/or
feed
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=
pipe may be utilized. It can be appreciated that multiple pipe tubs 400 are
provided for
supplying multiple pipes to the catwalk - pipe arm assembly 300. Pipe tubs 400
may or
may not comprise feed elements, which guide each pipe as needed to roll across
catwalk 302 to pivotal pipe arm 320. Conceivably, means (not shown) may be
provided which allow torqueing two or more pipes from associated pipe tubes
for
simultaneously handling stands of pipes utilizing pivotal pipe arm 300 for
faster
insertion into the well bore. However, in the presently shown embodiment, only
one
pipe at a time is typically handled by pipe arm 300. When handling stands of
pipe, then
the correspondingly lengthened mast 100 may be carried in multiple carrier
trucks 600.
[00108] The pipe tubs are preferably capable of holding multiple joints of
pipe for delivery to
the pipe ann. The pipe tubs are further preferably capable of continuously
lifting and
feeding a section of pipe to the pipe arm. The pipe tubs in some embodiments
can be
positioned in an orientation substantially parallel to the pipe arm, so that
the sections of
pipe are in a length-wise orientation parallel to the pipe arm. A pipe tub may
further
comprise a hydraulic lifting system for raising the floor or bottom shelf of
the pipe tub
in an upwards direction away from the ground and additionally may be used to
tilt the
pipe tub, so as to lift and roll one or more sections of pipe into a position
to be received
by the pipe arm. The pipe tubs could additionally include a series of pins
along the edge
of the pipe tub closest to the pipe arm, which feeds the sections of pipe to
the pipe arm.
However, preferably the series of pins are disposed on the pipe arm skid at a
location
proximate to the adjacent edge of the pipe tubs. These pins serve the purpose
of
stopping or preventing a joint of pipe from rolling onto the pipe arm or pipe
arm skid
prematurely. Each pipe tub used in the pipe handling system can further
incorporate one
or more flipper arms, which are hydraulically actuated arms or plates to push
or bump a
section of pipe over the above mentioned pins when the pipe handling skid and
pipe
arm are in a position to receive the said section of pipe. Preferably, the
pipe arm skid
includes one or more flipper arms which pivotally rotate in an upward
direction and
which engage the joints of pipe to lift the joints of pipe over the pins
retaining the
joint(s) of pipe, whether the pins are disposed along the edge of the pipe arm
skid or on
the edge of the pipe tub. It can be appreciated that as an alternative to the
pipe tubs 400,
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pipe ramps, saw horses, or tables can be used. The selection of the apparatus
(e.g. pipe
tubs, ramps, saw horses, or tables) for delivery of pipe joints to the pipe
arm .depends
on the physical layout of the surrounding area and if there are any
obstructions or
hazards that need to be avoided or overcome.
[00109] Various types of scanners, such as laser scanners for bar codes,
RFIDs, and the like,
may be utilized to monitor each pipe, whereby the amount of usage, the length,
torque
history and other applied stresses, testing history of wall thickness, wear,
and the like
may be recorded, retrieved, and viewed. If desired, the pipe tub and/or
catwalk may
comprise sensors to automatically measure the length of each pipe. Thus, the
operator
in the van can automatically keep a pipe tally to determine accurate
depths/lengths of
the pipe string in the well bore. Torque sensors may be utilized and recorded
so that the
torque record shows that each connection was accurately aligned and properly
torqued,
and/or immediately detect/warn of any incorrectly made up connection.
[00110] FIG. 3 is a plan view of one possible embodiment of carrier 600, mast
assembly 100,
catwalk - pipe arm assembly 300 and pipe tub 400 of the long lateral
completion
system 10 pursuant to one possible embodiment of the present invention. The
carrier
600 is illustrated with the power plant 650 and the winch or drawworks
assembly 620.
The mast assembly 100 is disposed at a rear extremity of the carrier 600 and
adjacent to
the winch or drawworks assembly 620. In this embodiment, base beam 120 is
disposed
beneath and/or adjacent to the mast assembly 100 for providing
security/stability for the
mast assembly 100. Base beam 120 may comprise wide flat mats 122 (also shown
in *
Fig. 2), which are pushed downwardly by base beam hydraulic actuators 612
(shown in
Fig. 2, and better shown in FIG. 8A-A). In one possible embodiment, wide flat
mats
122 may be 50 percent to 200 percent as wide as mast 100. Wide flat mats 122
may
' fold upon each other and/or extend telescopingly or slidingly
outwardly from carrier
600 and/or hydraulically. Wide flat mats 122 may be slidingly supported on
beam
runner 124 and may be transported on carrier 600 or provided separately with
other
trucks.
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1001111 In this embodiment, catwalk - pipe arm assembly 300 is affixed to mast
assembly 100
and carrier 600 by rig to arm connectors 305 (also shown in Fig. 2). In this
embodiment, catwalk - pipe arm assembly 300 is shown with a pipe tub 400 on
both
sides of the catwalk - pipe arm assembly 300. The pipe tubs 400 are shown with
the
side supports 402, the end support 404 and a cavity 420. A plurality of pipes
(not
illustrated) is placed in the pipe tubs 400. Pipes are displaced on to the
catwalk - pipe
, arm assembly 300 and lifted up to the mast assembly 100. Catwalk 302 may be
somewhat V-shaped or channeled to urge pipes to roll into the center for
receipt and
clamping, utilizing catwalk - pipe arm assembly 300. Catwalk 302 provides a
walkway
surface for workers and the like. Additional pipe tubs 400 can be slid into
place to
provide for a continuum of pipe lengths for use by the completion system 10.
Acoustic
and/or laser and/or sensors or RFID transceivers 408 and 410 may be positioned
on
ends 404 and sides 402 of pipe tubs 400, or elsewhere usdesired, to measure
and/or
detect the lengths of the pipes, and to detect RFIDs, bar codes, and/or other
indicators
which may be mounted to the pipes. Alternatively, pipe length sensors 412, 414
may
each comprise one or more sensors, which may be mounted to pipe arm 320. In
one
embodiment, sensors 412,414 may comprise acoustic, electromagnetic, or light
sensors
which may be utilized to detect features such as length of the pipe. Pipe
connection
cleaning/ grease injectors 416,418 may be provided for wire brushing, grease
injecting,
thread protector removal and other automated functions, if desired.
[001121 In one embodiment, sensors 412, 414 may comprise thread protector
sensors provided
to ensure that the thread protectors have been removed from both ends of a
pipe.
Thread protectors are generally plastic, or steel and used during
transportation to
= prevent any damage to the threading of pipe. Damage as a result of faulty
or damaged
threads could jeopardize a well site and the safety of the workers therein.
However,
, failing to remove a thread protector can cause the same
potential dangers if not found
before inserted into the pipe string. The pipe will not mate properly with the
threads of
the pipe string, comprising the integrity of the entire pipe string and well
site. The
thread protector sensors 412, 414 may be acoustic sensors or lasers used to
determine
whether the thread protectors have been removed and communicate this data with
the
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control system. If the thread protectors are present, an acoustic or light
signal
transmitted by sensors 412 may be reflected rather than received at 414.
Alternatively,
sensors 412 and 414 may be transceivers that will not receive a signal unless
the thread
protector is present. In another embodiment, a light detector will detect a
different
profile. In another embodiment, sensors 412 and 414 may comprise a camera in
addition to other thread protector sensors. If the thread protectors have not
been
removed, an operator will be informed before attempting to make up the pipe
connection so that the problem can be fixed.
1001131 In one possible embodiment, inner portion adjacent catwalk 302 and/or
catwalk edges
301 and 307 may comprise gated feed compartments whereby pipes are fed into a
compartment or funnel large enough for only single pipes or stands of pipes,
and then
gated to allow individual pipes or stands of pipes to be automatically rolled
onto either
side of catwalk 302.
1001141 FIG. 4 is an illustration of the carrier 600 of the long lateral
completion system 10 in
accord with one possible embodiment of the completion system of the present
disclosure. The carrier 600 is illustrated with the power plant 650 and the
winch or
drawworks assembly 620. Also, the mast assembly 100 is illustrated in a
lowered or
horizontal position, which is essentially parallel relationship with the
carrier 600. Mast
100 is clamped into the generally horizontal position with carrier front
clamp/support
633 above cab 605. Mast 100 is hinged at mast to carrier pivot 634 so that the
mast is
secured from any forward/reverse/side-to-side movement with respect to carrier
600
during transport after being clamped at the front and/or elsewhere. In this
embodiment,
mast positioning hydraulic actuators 630 are pivotally mounted with respect to
carrier
walkway 602 so that when extended, the hydraulic actuators 630 are angled
toward the
rear instead of toward the front of carrier 600 as in FIG. 4 (See for example
FIG. 2). In
one embodiment, mast positioning hydraulic actuators 630 may comprise multiple
telescopingly connected sections as shown in FIG. 6A. The horizontally
disposed mast
assembly 100 is illustrated for moving on the highway and for arrangement in
the
proximate location with respect to a wellbore. It will be noted that hydraulic
pipe tongs
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170 are mounted to mast 100 so that when the mast 100 is lowered, pipe tongs
170 are
in a position generally perpendicular to the operational position. Movements
and
actuation of the pipe tongs can be fully automated, for forming and/or
breaking both
shoulder connections and collared connections. The mast assembly 100 has the
crown
690 extending in front of the carrier 600. In one embodiment, rig carrier is
less than 20
feet high, or less than 15 feet high, while still allowing the rig to work
with well head
equipment having a height of about 20 feet. This is due to the construction of
the mast
with the Y-frame connection as discussed herein. The rig floor can be adjusted
to a
convenient height and is not necessarily fixed in height. In an embodiment,
the rig
floor could be connected to snubbing jacks.
[00115] FIG. 4A-A is a top view taken along the line A-A in FIG. 4 of the mast
assembly 100 of
the long lateral completion system pursuant to one possible embodiment of the
present
invention. FIG. 4A-A illustrates a downward view of the mast assembly 100. The
mast
assembly 100 shows the top drive assembly or fixture 150 (also shown in Fig.
4)
affixed to the portion of the mast assembly 100 over the winch or drawworks
assembly
620 over the carrier 600. The top drive assembly or fixture 150 is provided at
the
location associated with the carrier 600 for distributing the load associated
with the
carrier 600 for easy transportation on the highway. Top drive or fixture 150
may be
clamped or pinned into position with clamps or pins 162 or the like that are
inserted
into holes within mast 100 at the desired axial position along the length of
mast 100.,
Angled struts 134 (also shown in Fig. 4) on Y-section 132, which may be
utilized in one
possible embodiment of mast 100, are illustrated in the plan view. Top drive
150 is
shown with end 163, which may comprise a threaded connector and/or tubular
guide
= member and/or pipe clamping elements and/or torque sensors and/or
alignment sensors.
[00116] FIG. 4B-B is an end elevational view taken along the line B-B in FIG.
4 of the carrier
600 and the mast assembly 100 of the long lateral completion system 10 of in
accord
with one possible embodiment of the completion system of the present
disclosure. FIG.
4B-B illustrates the carrier 600, the winch or drawworks assembly 620 and the
top
drive 150. In this view, vertical top drive guide rails 104 are shown, upon
which top
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drive 150 is guided, as discussed hereinafter. In this embodiment, it will
also be noted
that top drive threaded connector and/or guide member and/or clamp portion 163
is
positioned in the plane defined between vertical top drive guide rails 104. In
this ,
embodiment, the view also shows one or more angled struts 134, which may
comprise
Y section 132 of one possible embodiment of mast 100, which is discussed in
more
detail with respect to FIG. 6A.
[00117] FIG. 5 is an elevation view of the carrier 600, the mast assembly 100,
and the catwalk -
pipe arm assembly 300 of the long lateral completion system 10 with respect to
one
possible embodiment of the present invention. The carrier 600 is illustrated
with the
power plant 650 and the winch or drawworks assembly 620. The cable from
drawworks
620 to crown 190 is not shown but may remain connected during transportation
and
raising of mast 100. The drawworks cable may be pulled from drawworks 620 as
mast
100 is raised. The mast assembly is illustrated engaged at the rear extremity
of the
carrier 600. The mast assembly 100 is in a vertical arrangement such that it
is at an
essentially perpendicular relationship with the carrier 600. The mast assembly
100 is
illustrated with the top drive 150 in an upper position near the crown 190.
The pivotal
= pipe arm 320 is shown in an angled disposition slightly above catwalk 302
for clarity of
view. Pivotal pipe arm 320 is shown with pipe 321 clamped thereto. The catwalk
-
pipe arm assembly 300 is engaged or connected via rig to arm assembly
connectors 305
= with the carrier 600 and the mast assembly 100. Rig to arm assembly
connectors 305
provide that the spacing arrangement between pivotal pipe arm 320 and mast 100
and/or carrier 600 is affixed so the spacing does not change during operation.
Rig to
arm assembly connectors 305 may comprise hydraulic operators for precise
positioning
of the spacing between mast 100 and pivotal pipe arm 320, if desired.
[00118] FIG. 5A is an enlarged or detailed view of the section shown in FIG. 5
as the rear
portion of the carrier 600 engaged with a skid or mast support base beam 120
of the
long lateral completion system 10 with respect to one possible embodiment of
the
= present invention. Mast positioning hydraulic actuators 630 are provided
for lowering
and raising the mast assembly 100 with respect to the carrier 600, about mast
to carrier
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pivot connection 634. Brace 632 for Y-base or support section 130 provides
additional
support for mast 100.
[00119] FIG. 6 illustrates the completion system 10 in a side elevational view
with the mast
assembly 100 extended in a perpendicular relationship with the carrier 600 and
the pipe
tubs 400 of the long lateral completion system 10 with respect to one possible
embodiment of the present invention. The pivotal pipe arm 320 is angularly
disposed
with respect to the catwalk 302. The mast assembly 100 is illustrated with the
top drive
150 slightly below the crown 190. Alternately, and not required in practicing
the
present disclosure, guy wires 101 can be engaged between the crown 190 of the
mast
assembly 100 and the carrier 600 on one extreme and the remote portion of a
pipe tube
400 on the other extreme. However, one or more guy wires could be anchored to
the
ground and/or may not be utilized. One or more guy wires can also be secured
to the
ends of base beam 120. It can be appreciated that the rigidity of the mast
assembly 100
with respect to the carrier 600 and the base beam 120 does not require guy
wires 101.
However, it may be appropriate in a particular situation or in severe weather
conditions
to adapt the present disclosure for use with such guy wires 101. The carrier
is
illustrated with the power plant 650 and the winch or drawworks assembly 620
on the
carrier deck 602.
1001201 FIG. 6A is an enlarged or detailed view of the portion of FIG. 6
illustrating the
relationship of the mast assembly 100, the deck 602 and the base beam 120 of
the long
lateral completion system 10 with respect to one possible embodiment of the
present
invention. FIG. 6A shows the relationship of the mast assembly 100, the deck
602 of
the carrier 600 and the base beam 120. It will be noted that base beam
widening
sections 121 may extend or slide outwardly from base beam 120 and be pinned
into
position with pin 123. Also illustrated is what may comprise multiple segments
of mast
= positioning hydraulic actuators 630 for angularly disposing the mast
assembly 100 in a
proximately perpendicular relationship with the carrier 600, and aligned with
respect to
the well bore, as discussed hereinbefore. Above the deck 602 of the carrier
and affixed
with the mast assembly 100 is a hydraulic pipe tong 170. The hydraulic pipe
tong 170
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is usable for handling the pipe as it is placed into a well, e.g., by
receiving joints of pipe
from the pipe arm and/or the top drive. The lower extremity of the mast
assembly 100
includes a y-base 130, which defines a recessed region above the wellbore at
the base
of the mast assembly 100, for accommodating a blowout preventer stack,
snubbing
equipment, and/or other wellhead components. The recessed region enables the
generally vertical mast assembly 100 to be positioned directly over a wellbore
without
causing undesirable contact between blowout preventers and/or other wellhead
components and the mast assembly 100.
[00121] The lower extremity of the mast assembly 100 is defined by the y-base
130. The y-base
130 provides a disposed arrangement for making and inserting pipe using the
completion system 10 in accord with one possible embodiment of the completion
system of the present invention. Y-base 130 supports Y section 132, which
extends
angularly with angled strut 134 out to support one side of mast 100. This
construction
provides an opening or space 136 for the BOP assembly, such as BOP (see FIG.
9),
snubbing unit (see FIG. 11A), Christmas tree, well head, and/or other pressure
control
equipment. Mast 100 is supported by carrier to mast pivot connection 634 and
at the
carrier 600 rearmost position by mast support plate 636 (also shown in Fig.
4). Mast
support plate 636 may be shimmed, if desired. In another embodiment, mast
support
plate may be mounted to be slightly moveable upwardly or downwardly with
hydraulic
controls to support the desired angle of mast 100, which as discussed above
may be
oriented to ,a desired angle (e.g. less than five degrees or in another
embodiment less
than one degree) with respect to the axis of the bore of the well bore and/or
bore of
BOP 900, shown in FIG. 9. In this embodiment, mast support plate 636 does not
extend horizontally and rearwardly from carrier 600, as far as the other mast
100
horizontal supports, e.g., horizontal mast supports or struts 140. This
construction
allows the opening or space 136 for the BOP (see FIG. 9), snubbing unit (see
FIG.
11A), Christmas tree, well head, and/or other pressure control equipment.
However,
- the mast construction is not intended to be limited to this
arrangement.
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[001221 In other words, Y-base 130 back most rail 138 is horizontally offset
closer to carrier
600 than back most vertical mast supports 105 (also shown in Fig. 4b-B) with
respect to
carrier 600. Y-base 130 is sufficiently tall to allow BOP stacks to fit within
opening or
space 136. However, Y-base 130 is replaceable and may be replaced with a
higher or
shorter Y-base as desired, to accommodate the desired height of any pressure
control
and/or well head equipment. In this example, the bottoms of Y-base 130 may be
replaceably inserted/removed from Y-base receptacles 142 to allow for easy
removal/replacement of Y-base 130 from carrier 600.
(00123] As discussed hereinafter, vertical mast supports 105 support vertical
top drive guide
rails 104 (see FIG. 4 B-B and FIG. 8 B-B), which guide top drive 150. An
optional
raiseable/lowerable rig floor, such as rig floor 102 (See FIG. 1) is not shown
for
viewing convenience.
[00124] FIG. 7 is a side elevational view of the carrier 600, the mast
assembly 100, the catwalk
- pipe arm assembly 300, and the pipe tub 400 with the mast assembly 100
(e.g.,
transporting a joint of pipe to the mast assembly 100 for engagement by the
top drive)
= in a perpendicular relationship with the carrier 600, and an arm to mast
engagement
element 325 of the pivotal pipe arm 320 engaged with optional upper mast
fixture .135
on mast assembly 100 of the long lateral completion system 10 with respect to
one
possible embodiment of the present disclosure. The engagement of elements 325
and
135 may be utilized to provide an initial alignment of the pivotal connection
of kick out
arm 360 (also shown in Fig. 5) to pivotal pipe arm 320. Kick out arm 360 is
shown
pivotally rotated to a vertical position so that pipe 321 is aligned for
connection with
top drive 150, as discussed hereinafter. The carrier 600 is illustrated with
the winch
assembly 620 on the deck 602. The depicted hydraulic actuator 630 has raised
the mast
assembly 100 into its vertical position, as discussed hereinbefore. The mast
assembly
100 is illustrated with the top drive 150 near the crown 190. The kickout arm
360 of
the catwalk - pipe arm assembly 300 may be more accurately vertically placed
in the
extended position adjacent to the mast assembly 100, having a lcickout arm 360
in
association therewith. As such, when the pipe arm 320 pivoted into the
position shown
. 29
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in FIG. 7 (e.g., using the hydraulic cylinder 304), the pipe arm 320 is not
parallel with
the mast assembly 100, thus a joint of pipe engaged with the pipe arm 320
would not be
positioned suitably for engagement with the top drive 150. The kickout arm 360
is
extendable from the pivotal pipe arm 320 into a position that is generally
parallel with =
= the mast assembly 100, e.g., by use of a hydraulic actuator 362. Using
the kickout arm
360, the pipe (321) is placed in the position which is essentially parallel
with the mast
assembly 100, and in this embodiment is positioned in the plane defined by
mast rails
104 (See FIG. 4B-B), which guide top drive 150, by use of the hydraulic
actuator 362.
The movement of the pivotal pipe arm 320 is provided by the hydraulic actuator
304.
[00125] In one possible embodiment, the upright position of pivotal pipe arm
320 is controlled
by angular sensors 325 and/or shaft position sensors 326 (See Fig. 16A) to
account for
any variations in hydraulic operator 304 operation.
[00126] Alternatively, or in addition, upper mast fixture 135 may comprise a
receptacle and
guide structure. In this embodiment, which may be provided to guide the top of
pivotal
pipe arm 320 into contact with mast 100, whereby the same vertical/side-to-
side
positioning of kick out arm 360 is assured in the horizontal and vertical
directions. The
guide elements may, if desired, comprise a funnel structure that guides aim to
mast
engagement element 325 into a relatively close fitting arrangement. If
desired, a clamp
and/or moveable pin element (with mating hole in pivotal pipe arm) may be
utilized to
pin and/or clamp pivotal pipe arm 320 into the same position for each
operation. In
another embodiment upper mast fixture may comprise a hydraulically operated
clamp
with moveable elements that clamp the pipe in a desired position for aligned
engagement with top drive threaded connector and/or guide member and/or clamp
portion 163. As shown in FIG. 7A-A, upper fixture 135 may also comprise one or
more pipe alignment guide members/clamps/ supports as indicated at 139 to
position
pipe 321 and/or kickout arm 360 to thereby align pipe 321 and pipe connector
323 with
respect to top drive threaded connector and/or guide member and/or clamp
portion 163.
Element 139 may comprise a moveable hydraulic clamp or guide to affix and
align the
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pipe in a particular position. Element 139 may instead comprise a fixed groove
or slot
or guide and may be hydraulically moveable to a laser aligned position.
(00127) As a result, top connector 323 on tubing pipe 321 is aligned to top
drive threaded
connector and/or guide member and/or clamp portion 163, as discussed in more
detail
hereinafter, by consistent positioning of kick out arm 360. It will be
appreciated that rig
to arm connectors 305 further aid alignment by insuring that the distance
between
catwalk - pipe arm assembly 300 and mast 100 remains constant.
=
1001281 FIG. 7A-A is a rear elevational view of FIG. 7 taken along the section
line A-A in
FIG. 7, showing the mast assembly 100 and top drive 150 of the long lateral
completion
system 10 with respect to one possible embodiment of the present disclosure.
FIG. 7A-
A illustrates the portion of the mast assembly 100, which includes the top
drive 150,
and the upper portion of the pivotal pipe arm 320. Also illustrated are the
lattice
structural support elements 112 of the mast assembly 100. The top drive 150 is
shown
secured within a top drive fixture/carrier 151, which can be moved vertically
along the
mast assembly 100, e.g., via a rail/track-in-channel engagement using rollers,
bearings,
etc. Due to the generally vertical orientation of the mast assembly 100, and
the
positioning of the mast assembly 100 directly over the wellbore, the top drive
150 can
be directly engaged with the mast assembly 100, via the top drive fixture 151,
as
shown, rather than requiring use of conventional cables, traveling blocks, and
other
features required when an angled mast is used. Engagement between the top
drive 150
and the mast assembly 100 via the top drive fixture 151 eliminates the need
for a
conventional cable-based torque arm. Contact between the top drive 150 and the
fixture 151 prevents undesired rotation and/or torqueing of the top drive 150
entirely,
using the structure of the mast assembly 100 to resist the torque forces
normally
imparted to the top drive 150 during operation.
1001291 FIG. 7B is a perspective view of the portion of the mast assembly 100
and pivotal pipe
arm 320 engaged with upper fixture 135 as illustrated in FIG. 7A-A of the long
lateral
completion system 10 with respect to one possible embodiment of the present
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invention. The mast assembly 100 is illustrated with the top drive 150
positioned a
selected distance the pipe arm 300.
[00130] FIG. 8 is a side elevational view of the completion system 10 in
accord with another
embodiment of the present disclosure illustrating the mast assembly 100 in a
perpendicular relationship with the carrier 600 and/or aligned with an axis of
the upper
portion of the wellbore. The carrier 600 is shown with the deck 602 and the
mast
positioning hydraulic actuators 630 providing movement for the mast assembly
100
mast to carrier pivot connection 634. The mast assembly 100 has the top drive
150
disposed proximate to the crown 190. As discussed hereinafter, crown 190 may
comprise multiple pulleys that are utilized to raise and lower the blocks
associated with
top drive 150 utilizing drawworks 620. The pipe arm 320 is extended in an
upward
position using the pipe arm hydraulic actuator 304. Further, the kickout arm
360 is
disposed in a parallel relationship with the mast assembly 100 using the kick
out arm
hydraulic alignment actuator 362 to align pipe 321 appropriately with respect
to the
mast assembly 100, e.g., in one embodiment position the pipe in the plane
defined
between mast top drive rails 104. Mast top drive rails 104 (shown in FIG. 8B-
B) are
secured to an inner portion of the two rearmost (with respect to carrier 600)
vertical
supports 105 of mast 100.
[00131] FIG. 8A-A shows another view of Y section 132, which comprises one or
more angled
struts 134 on each side of mast 100 utilized to support vertical mast supports
105. Pipe
tong 170 is aligned within the plane between guide rails 104 to thereby be
aligned with
top drive threaded connector and/or guide member and/or clamp portion 163 (see
FIG.
8B-B and FIG. 4B-B) of top drive 150
[00132] FIG. 8B-B is a rear elevational view taken along the line B-B in FIG.
8 of the mast
assembly 100 and top drive 150 of the long lateral completion system 10 with
respect
=to one possible embodiment of the present invention. FIG. 8B-B illustrates
the
= relationship of pivotal pipe arm 320, the top drive 150 and the mast
assembly 100.
Further, the lattice support structure 112 is illustrated for providing
superior rigidity to
and for the mast assembly 100.
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[00133] FIG. 8C is a perspective view of FIG. 8B-B of the relationship between
the pivotal pipe
arm 320 and the top drive 150 relative to the mast assembly 100 of the long
lateral
completion system with respect to one possible embodiment of the present
invention.
Also illustrated is the pipe clamp 370 associated with the pivotal pipe arm
300 for
holding a joint of pipe. In an embodiment, a joint of pipe raised by the pipe
arm 300
then extended using the kickout arm 360 may require additional stabilization
prior to
threading the pipe joint to the top drive. Additional pipe clamps along the
mast
assembly 100 can be used to receive and engage the joint of pipe while the
pipe clamp
370 of the pipe arm 300 is released, and to Maintain the pipe directly beneath
the top
drive 150 for engagement therewith.
[00134] Referring again to FIG. 8A-A, is the figure depicts a sectional view
of FIG. 8 showing
the pipe tong 170 with respect to the mast assembly 100 of the long lateral
completion
system with respect to one possible embodiment of the present invention. FIG.
8A-A
illustrates the relationship of the hydraulic pipe tong 170 with respect to
the mast
assembly 100 and the base beam 120. The mast assembly 100 is supported by
braces
112. The braces 112 can be at various locations about the system 10 as one
skilled in
the art would appreciate.
[00135] FIG. 9 is an illustration of the long lateral completion system 10 of
the present
enclosure that depicts an embodied relationship of the carrier 600, the mast
assembly
100, catwalk - pipe arm assembly 300, the catwalk 302 and a blowout preventer
and
snubbing stack 900 of the long lateral completion system 10 with respect to
one
== possible embodiment of the present disclosure. As described
previously, the mast
assembly 100 is disposed in a generally vertical orientation (e.g.,
perpendicular to the
earth's surface and/or the deck 602), such that the mast assembly 100 is
directly above
the blowout prevent and snubbing stack 900 with the wellbore therebelow. The
recessed
region at the base of the mast assembly 100 accommodates the blowout preventer
and
= snubbing stack 900, while the top drive 150 disposed near the crown 190
of the mast
assembly 100 can move vertically along the mast assembly 100 while remaining
directly over the well.
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[00136] The mast assembly 100 can be moved and maintained in position by the
hydraulic
actuators 630 and/or other supports. The pipe arm 300 can be moved and
maintained in
the depicted raised position via extension of the hydraulic actuator 304. The
Idckout
arm 360 pivots from the top of pivotal pipe arm using the hydraulic system 362
for
aligning a joint of pipe in alignment with the well and BOP 900, which may
utilize
sensors (902, 904, 906, 908), for example, laser alignment sensors 902 mounted
on
BOP 900,904 on kickout arm 360, and/or laser alignment sensors 906 on top
drive 150.
It should be appreciated that the kick-out arm can be extended or retracted
through the
use of hydraulic system 362 and may be connected through_ manual actuation of
hydraulic/pneumatics or through an electronic control system, which maybe be
operated through a control van or remotely through an Internet connection.
This
particular embodiment implements the use of a kick-out arm 360 to provide a
substantially vertical joint of pipe for reception by the mast assembly 100,
which may
include a top drive of some configuration. It is important that the joint of
pipe be
substantially vertical so that the threads on each joint are not cross-
threaded when the
connection to the top drive is made. Cross-threading can lead to catastrophic
failure of
the connected joints of pipe or damage the threads of the joint of pipe and
render the
joint of pipe unusable without extensive and costly repair. As mentioned
above, the
pipe arm 300 can further include a centering guide, which is capable of mating
with a
centering receiver located on the mast assembly 100. This centering guide and
centering receiver, when used provides an additional point of contact between
the pipe
arm 300 and the mast assembly 100 providing additional stability to the system
and
more precise placement and orientation of the pipe arm and joints of pipe.
(00137) FIG. 9A-A is a sectional view of FIG. 9 illustrating the upper portion
of the mast
assembly 100 of the long lateral completion system 10 with respect to one
possible
embodiment of the present invention. One possible embodiment of the
relationship of
the pipe arm 300 and the clamp 370 is shown. Also, the lattice support 112 for
providing rigidity for the mast assembly 100 is illustrated. The top drive 150
is retained
by the fixture 151, which is moveably disposed along the mast assembly 100.
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100138] FIG. 9B-B is a perspective view of the upper portion of the mast
assembly 100 as
illustrated in FIG. 9A-A, showing the top drive 150 and the upper mast fixture
135 of
the long lateral completion system with respect to one possible embodiment of
the
present invention. The pipe arm 300 is shown below the top drive 150. The pipe
clamp
370 enables removable engagement between pipe arm 300, and a joint of pipe,
which
said joint of pipe is engaged by the top drive 150, and alternately one or
more clamps or
similar means of engagement along the mast assembly 100, or other engagement
systems associated with the mast assembly 100 and/or the top drive 150, can be
used to
assist with the transfer of the joint of pipe from the pipe arm 300 to the top
drive 150.
= 1001391 FIG. 9C-C is a sectional view of FIG. 9 illustrating the
relationship of the blowout
preventer and snubbing stack 900 with respect to the completion system 10 of
one
possible embodiment of the present invention. The blowout preventer and
snubbing
stack 900 is shown directly underneath the mast assembly 100, and thus
directly
adjacent to the rig carrier, such that the hydraulic pipe tong 170 can be
operatively
associated with joints of pipe added to or removed from a string within the
wellbore.
The mast assembly 100 can be secured using the adjustable braces 612 attached
to the
base plate 120. As another example, mast top drive guide rails 104, which
guide top
drive 150 may be aligned to be essentially parallel to the axis of the bore of
BOP,
within less than five degrees in one embodiment, or less than three degrees,
or less than
one degree in another embodiment. Accordingly, top drive threaded connector
and/or
guide member and/or clamp portion 163 (See FIG. 4B-B) is also aligned to move
up
and down mast 100 essentially parallel or coaxial to the axis of the bore of
BOP, within
less than five degrees in one embodiment, or less than three degrees, or less
than one
degree in another embodiment. The blowout preventor and/or other
pressure
equipment may comprise pipe clamps and seals to clamp and/or seal around pipe
as is
well known in the art. As discussed hereinafter, a snubbing jack may comprise
additional clamps and hydraulic arms for moving pipe into and out of a well
under
pressure, which is especially important when the pipe string in the hole
weighs less
than the force of the well pressure acting on the pipe, which would otherwise
cause the
pipe to be blown out of the well.
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[00140] Specifically, the blowout preventer 900 is shown having a first set of
rams 1012
positioned beneath a second set of rains 1014, the rams 1012, 1014 usable to
shear
and/or close about a tubular string, and/or to close the wellbore below, such
as during
emergent situations (e.g,., blowouts or other instances of inere,ased pressure
in the
wellbore). Above the first and second set of rams 1012, 1014, a snubbing
assembly can
be positioned, which is shown including a lower ram assembly 1016 positioned
above
the rams 1014, a spool 1018 positioned above the lower ram assembly 1014, an
upper
ram assembly 1020 positioned above the spool 1018, and an annular blowout
preventer
1022 positioned above the upper ram assembly 1020. In an embodiment, the upper
and
lower ram assemblies 1020, 1016 and/or the annular blowout preventer 1022 can
be
actuated using hydraulic power from the mobile rig, while the first and second
set of
rams 1012, 1014 of the blowout preventer can be actuated via a separate
hydraulic
power source. In further embodiments, multiple controllers for actuating any
of the =
rams 1012, 1014, 1016, 1020 and/or the annular blowout preventer 1022 can be
=
provided, such as a first controller disposed on the blowout preventer and/or
snubbing
assembly and a second controller disposed at a remote location (e.g.,
elsewhere on the
mobile rig and/or in a control cabin). During snubbing operations, the upper
and lower
ram assemblies1020, 1016 and/or the annular blowout preventer 1022 can be used
to
prevent upward movement of tubular strings and joints, while during non-
snubbing
operations, the upper and lower ram assemblies1020, 1016 and blowout preventer
1022
can permit unimpeded upward and downward movement of tubular strings and
joints.
Typically, the annular blowout preventer 1022 can be used to limit or
eliminate upward
Movement of tubular strings and/or joints caused by pressure in the wellbore,
though if
the annular blowout preventer 1022 fails or becomes damaged, or under non-
ideal or
extremely volatile circumstances, the upper and lower ram assemblies1020, 1016
can
be used, e.g., in alternating fashion, to prevent upward movement of tubulars.
As such,
the depicted snubbing assembly (the ram assemblies 1016, 1020and annular
blowout
preventer1022) can remain in place, above the blowout preventer, such that
snubbing
operations can be performed at any time, as immediately as necessary, without
requiring rental and installation of third party snubbing equipment, which can
be
limited by equipment availability, cost, etc. In an embodiment, the upper and
lower
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ram assemblies1020, 1016 can be used as stripping blowout preventers during
snubbing
operations. Additionally, while the figures depict a single blowout preventer
900
having two sets of rams 1012, 1014, and a single snubbing assembly, in various
embodiments, additional blowout preventers could be used as safety blowout
preventers, which can include pipe blowout preventers, blind blowout
preventers, or
combinations thereof.
1001411 Due to the clearance provided in the recessed region defined by the Y-
base 132 and
= support section 130, the snubbing assembly can remain in place
continuously, beneath
the vertical mast, without interfering with operations and/or undesirably
contacting the
= top drive or other portions of the mobile rig. Further, the clearance
provided in the
recessed region can enable a compact snubbing unit (e.g., snubbing jacks
and/or jaws)
to be positioned above the annular blowout preventer 1022, such as the
embodiment of
the compact snubbing unit 800, described below, and depicted in FIGs. 11A
through
= 11D.
[00142] FIG. 9C-C also shows a first hydraulic jack I 024A positioned at the
lower end of the Y-
base 132, on a first side of the rig, and a second hydraulic jack I024B
positioned at the
lower end of the Y-base 132, on a second side of the rig. The hydraulic jacks
1024A,
1024B are usable to raise and/or lower a respective side of the rig to provide
the rig
with a generally horizontal orientation. For example, while Figure 1 depicts
an
embodiment the long lateral completion system 10 having a mast assembly 100
and a
pipe handling system (e.g., skid 200, system 300, and tubs 400) positioned at
ground
level, each component having a lower surface contacting the upper surface of
the well
(e.g., the earth's surface), the hydraulic jacks 1024A, 1024B can be used to
maintain a
ground level rig in an operable, horizontal orientation, independent of the
grade of the
surface upon which the rig is operated.
[00143] FIG. 10A and FIG. 10B provide an illustration of one possible
embodiment for
mounting pipe tong 170 utilizing the pipe tong fixture 172 to support pipe
tong 170 at a
desired vertical distance in mast 100 from BOPs, such as the blowout preventer
900
shown in FIG. 9C-C, and with respect to a co-axial orientation with respect to
the bore
= 37
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of the BOPs.. Pipe tongs 170 may be moved in/out and up/down. The pipe tong
fixture
comprises one or more pipe tong vertical support rails 176, two pipe tong
horizontal
movement hydraulic actuators 178 in association with a horizontal pipe support
174 for
displacing the pipe tong 170. It will be appreciated that fewer or more than
two pipe
tong horizontal movement hydraulic actuators 178 could be utilized. In this
embodiment, horizontal support 174 may comprise telescoping and/or sliding
portions,
which engagingly slide with respect to each other, namely square outer tubular
component 175 and square inner tubular component 177, which move slidingly
and/or
telescoping,ly with respect to each other. In this embodiment, components 175
and 177
are concentrically mounted with respect to each other for strength but this
does not
have to be the case. Accordingly, pipe tong 170 is moved slidiney or
telescopically
horizontally back and forth as shown by comparison of FIG. 10A and 10B. In
FIG.
10A, pipe tong 170 is shown in a first horizontal position moved laterally
away from
pipe tong vertical support rails 176. In FIG 10B, pipe tong 170 is shown in a
second
horizontal position moved laterally or horizontally toward pipe tong vertical
support
rails 176. In this way, pipe tong 170 can be moved in the desired direction to
position
pipe tong 170 concentrically around the pipe from the bore through' BOP 900.
It will
be noted that here as elsewhere in this specification, terms such as
horizontal, vertical,
and the like are relevant only in the sense that they are shown this way in
the drawings
and that for other purposes, e.g. transportation purposes as shown in FIG. 4
with the rig
collapsed and hydraulic tongs oriented vertically as compared to their normal
horizontal operation, hydraulic actuators 178 would then move pipe tong 170
vertically.
It will also be understood that multiple tongs may be utilized on such
mountings, if
desired, in other embodiments of the invention, e.g. where a rotary drilling
rig were
utilized with the pipe tong mounting on a moveable carrier. If desired,
additional
centering means may be utilized to move pipe tong horizontally between
vertical
supports 176 to provide positioning in three dimensions
[00144] FIG. 10B is a perspective view of the pipe tong fixture 172 as
illustrated in FIG. 10A of
the blowout preventer with respect to the completion system of one possible
embodiment of the present invention whereby pipe tong 170 is moved vertically
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downwardly along pipe tong vertical support rails 176. Vertical sliding
supports 179
permit pipe tong frame 181, which comprise various struts and the like, to be
moved
upwardly and downwardly. Extensions 183 may be utilized in mounting support
rails
176 to mast 100 and/or may be utilized with clamps associated with vertical
sliding
supports 179 for affixing pipe tong frame 181 to a particular vertical
position. Pipe
tong frame 181 may be lifted utilizing lifting lines within mast 100 and/or by
connection with the blocks and/or top drive 150 and/or by hydraulic actuators
(not
shown).
[001451 FIG. 11A, FIG. 11B, FIG. 11C, and FIG. 11D illustrate one possible
embodiment for a
compact snubbing unit 800, usable with the completion system 10 of the present
disclosure, e.g., by securing the snubbing unit 800 .above the blowout
preventer and
snubbing stack 900 (shown in FIG. 9). However, snubbing unit 800 is simply
shown as
an example of a snubbing jack and other types of snubbing jacks may be
utilized in
accord with the present invention. Generally, a snubbing jack will have a
movable
gripper, which may be mounted on a plate that is movable with respect to a
stationary
= gripper. At least one gripper will hold the pipe at all times. The
grippers are
alternately released and engaged to move pipe into and out of the wellbore
under
pressure. If not for this type of arrangement, when the sting is lighter than
the force
applied by the well, the string would shoot uncontrollably out of the well.
When the
= string is lighter than the force applied by the well, this example of
snubbing jack 800
can be utilized to move pipe into or out of the well in a highly controlled
manner, as is
=
known by those of skill in the art. In another embodiment, an additional set
of pulleys
(not shown) might be utilized to pull top drive downwardly (while the existing
cables
remain in tension but slip at the desired tension to prevent the cables from
swanning).
Once the pipe is heavier than the force of the Well, then the normal operation
of top
drive may be utilized for insertion and removal of pipe so long as the pipe
string is
preferably significantly heavier than the force acting on the pipe string. In
this
example, the grippers of snubbing jack 800 also provide a backup in case of a
sudden
increase in pressure in the well. The compact (but extendable) snubbing unit
800 can be
sized to fit within the recessed region of the mast assembly 100, to prevent
undesired
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contact with the mast assembly 100 even when the snubbing jack is in an
extended
position. In this example, the depicted snubbing unit 800 includes a first
horizontally
disposed plate member 802, which is a vertically moveable plate, and a second
horizontally disposed plate member 804, which is a fixed plate with respect to
the
wellhead, displaced by vertical columns or stanchions 806 and 808. The lower
and/or
possibly upper portion of columns or stanchions 806 and 808 may comprise
hydraulic
jacks members which can be ufilized for hydraulically moving plate member 802
upwardly and downwardly with respect to plate member 804 and may be referred
to
herein as hydraulic jacks 806 and 808. Also, in this example, between the
first member
802 and the second member 804 is an intermediate member 803. In this example,
between the first member 802 and the intermediate member 803 is a first
engaging
= mechanism 820 for engaging and/or clamping and/or advancing or
withdrawing pipe.
Between the intermediate member 803 and the second member. 804 is a second
engaging mechanism 830 for engaging and advancing, or withdrawing pipe. In one
embodiment, both plates 802 and 803 are vertically moveable with respect to
plate 804
whereby both clamps (i.e., engaging mechanisms) 820 and 830 are used at the
same
time. Accordingly, in one embodiment, both plates 802 and 803 move together.
In
another embodiment, grippers (i.e. engaging mechanisms) 820 and 830 may be
moveable with respect to each other. In one possible mode of operation, the
clamping
mechanisms 820, 830 can be used to grip a joint of pipe and exert a downhole
force or
upward force thereto, counteracting a force applied to the string due to
pressure in the
wellbore. Because the force of the snubbing jack unit 800 is selected to
exceed the
pressure from the wellbore, joints can be added or removed from a completion
string
even under adverse, high pressure conditions. The BOPs or other control
equipment,
positioned below the snubbing jack 800, can seal around the pipe as it is
moved into
and out of the wellbore by snubbing jack 800. Thus, grippers 820 and 830 may
be
engaged and hydraulic jacks within stanchions 806 and 808 may be expanded to
remove pipe from the well or force pipe into the well. 'The hydraulic jacks
may be
contracted to move pipe into the well or pull pipe out of the well in a
controlled
manner. Other grippers within the BOPs may be utilized to hold the pipe, when
grippers 820 and 830 are released and moveable plates 802 and/or 803 are moved
to a
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new position for grasping the pipe to move the pipe into or out of the
borehole as is
known to those of skill in the art. In one embodiment of the present
invention, the
computer control of the control van is utilized to control the grippers 820,
830, and the
hydraulic jacks 806 and 808, and other grippers and seals in the BOPs to
provide
automated movement of the pipe into or out of the wellbore. This movement may
be
coordinated with that of the top drive and tongs for adding pipe or removing
pipe.
Thus, the entire process or portions of the process of going into the hole
with snubbing
units may be automated. However, it will be understood that at least two
separate
grippers or sets of grippers are required for a snubbing unit. If the top
drive is
connected to be able to apply a downward force then another stationary set of
grippers
is required. In addition, multiple sealing mechanisms such as rams, inflatable
seals,
grease injectors, and the like, may be utilized to open and close around
sections of
pipes so that larger joints and the like may be moved past the sealing
mechanisms in a
manner where at least one seal or set of seals is always sealed around the
pipe string in
a manner than allows sliding movement of the pipe string. The control system
of the
present invention is programmed to operate the entire system in a coordinated
manner.
In addition to or in lieu of the snubbing unit 800 and/or the snubbing
assembly depicted
and described above, various embodiments of the present system can include a
full-
sized snubbing unit, e.g., similar to a rig assist unit.
[00146] FIG. 12A depicts a schematic view of an embodiment of a control cabin
702 of the long
lateral completion system 10 with respect to the present disclosure. The
control cabin
702 comprises a command station 710. The command station 710 comprises a seat
712, control 714, monitor 716 and related control devices. Further, the
control cabin
702 provides for a second seat 715 in association with a monitor and,
optionally, a
structure for supporting other related monitoring and/or control devices (724,
722), and
a third seat 718 in association with yet another monitor. The control cabin
702 has
doors for exiting the cabin area and accessing a walkway 720 disposed around
the
perimeter of the control cabin 702.
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[00147] In one embodiment, command station 710 is positioned so that once
control van 700 is
oriented or positioned with respect to mast 100 (See FIG. 1), carrier 600,
catwalk and
pipe handling assembly 300, and/or pump/pit 500, then all mast operations can
be
observed through command station front windows 730 as well as command station
top
windows 732. Front windows 730, for example, allow a close view of rig
operations at
=
the rig floor. Top windows 732 allow a view all the way to the top of mast
100. In one
embodiment, additional command station side and rear windows 740, side windows
742 (shown in Fig. I2C), 744 (shown in Fig. 12D) will allow easy observation
of other
actions around mast 100. If desired, control van 700 may be positioned as
shown in
FIG. 1 and/or adjacent pump/pit combination skid 500. If desired, additional
cameras .
may be positioned around the rig to allow direct observation of other
components of the
rig, e.g., pump/pit return line flow or the like.
[00148] The control van 700 may include a scissor lift mechanism to lift and
adjust the yaw of
command station 710. A scissor lift mechanism is a device used to extend or
position a
platform by mechanical means. The term "scissor" is derived from the mechanism
used, which is configured with linked, folding supports in a crisscrossed "X"
pattern.
An extension motion or displacement motion is achieved by applying a force to
one of
the supports resulting in an elongation of the crossing pattern supports.
Typically, the
force applied to extend the scissor mechanism is hydraulic, pneumatic or
mechanical.
The force can be applied by various mechanisms such as by way of example and
without limitation a lead screw, a rack and pinion system, etc.
[00149] For example with loading applied at the bottom, it is readily
determined that the force
required to lift a scissor mechanism is equal to the sum of the weights of the
payload,
its support, and the scissor arms themselves divided by twice the tangent of
the angle
between the scissor arms and the horizontal. This relationship applies to a
scissor lift
mechanism that has straight, equal-length arms, i.e., the distance from an
actuator point
to the scissors-joint is the same as the distance from that scissor-joint to
the top load
platform attachment. The actuator point can be, by way of examples, a
horizontal-
jack-screw attachment point, a horizontal hydraulic-ram attachment point or
the like.
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For loading applied at the bottom, the equation would be F = (W+Wa)/2Tan(1).
The
terms are F=the force provided by the hydraulic ram or jack-screw, W=the
combined
weights of the payload and the load platform, Wa=the combined weight of the
two
scissor arms themselves, and is the angle between the scissor arm and the
horizontal.
[00150] And for loading applied at the center pin of the crisscross pattern,
the equation would
be F = W+(Wa/2)rTan(1). The terms are F=-the force provided by the hydraulic
ram or
jack-screw, W=the combined weights of the payload and the load platform,
Wa=the
combined weight of the two scissor arms themselves, and is the angle between
the
=
scissor arm and the horizontal.
[00151] FIG. 12B is an elevation view of the control cabin 702 of the
completion system 10 of
one possible embodiment of the present invention. The command station 710 the
walkway 720 and exterior controls 726.
[00152] FIG. 12C is an end view of the control cabin 702 of the completion
system 10 of one
possible embodiment of the present invention. FIG. 12C illustrates the command
station 710 in association with the control cabin 702. The walkway 720 is also
illustrated.
[00153] FIG. 12D is an end view of the control cabin 702 taken from the
alternate perspective
as that of FIG. 12C of the completion system of one possible embodiment of the
present invention. The outer controls 726 are illustrated.
[00154] FIG. 13 is an illustration of the carrier 600 adapted for use with the
completion
system 10 of one possible embodiment of the present invention. The carrier
comprises
a cabin 605, a power plant 650, and a deck 610. Foldable walkway 602 folds up
for
transportation and then when unfolded extends the walkway space laterally to
the side
of carrier 600. Winch assembly 620 can be mounted along slot 622 at a desired
axial
position at any desired axial position along the length of carrier 600. Winch
or
drawworks assembly 620 may or may not be mounted to a mounting such as
mounting
624, which is securable to slot 620. Mounting 624 may be utilized for mounting
an
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electrical power generator or other desired equipment. Recess 626 may be
utilized to
support mast positioning hydraulic actuators 630, which are not shown in FIG.
13. One
or more stanchions 614 (e.g., a Y-base) are illustrated for engaging the mast
assembly
= 100 with the carrier 600, wherein the mast 100 can be supported by
carrier to mast
pivot connection 634 and at the carrier 600 rearmost position by mast support
plate 363
(also shown in Fig. 4 as feature (636)).
1001551 FIG. 14 is an illustration of the catwalk - pipe arm assembly 300 of
the completion
system 10 of one possible embodiment of the present invention. The catwalk -
pipe
arm assembly 300 is illustrated with a ground skid 310, pipe arm hydraulic
actuators
304 for lifting the pivotal pipe arm 320 and the Idckout arm 360 attached
thereto. The
kickout arm 360 can subsequently be extended the central pipe arm 320 using
additional hydraulic cylinders disposed therebetween.
[001561 In yet another embodiment, a pivotal clamp could be utilized at 312 in
place of the
entire kick arm 360 whereby orientation of the pipe for connection with top
drive 150
may utilize upper mast fixture 135 and/or mast mounted grippers and/or guide
elements.
=
1001571 In one embodiment, catwalk 302 may be provided in two elongate catwalk
sections 309
and 311 on either side of pivotal pipe arm 320 for guiding pipe to and/or away
from
pivotal pipe arm 320. However, only one elongate section 309 or 311 might be
utilized.
Catwalk 302 provides a walkway and a catwalk is often part of a rig, along
with a V-
door, for lifting pipes using a cat line. To the extent desired, catwalk 302
may continue
provide this typical function although in one possible embodiment of the
present
invention, pivotal pipe arm 320 is now preferably utilized, perhaps or perhaps
not
exclusively, for the insertion and removal of tubing from the wellbore.
1001581 In one possible embodiment of catwalk 302, each catwalk section 309
and 311 may
comprise multiple catwalk pipe moving elements 314 which move the pipe toward
or
away from pivotal pipe arm 320 and otherwise are in a stowed position,
resulting in a
relatively smooth catwalk walkway. Referring to FIG. 15F and FIG. 15G, FIG.
21A,
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and FIG. 21B, catwalk pipe moving hydraulic controls 333 may be utilized to
independently tilt catwalk pipe moving elements 314 upwardly or downwardly, as
indicated. On the left of FIG. 15F, catwalk pipe moving element 314 is in the
stowed
= position flat with catwalk 309. On the right of FIG. 15F, catwalk pipe
moving element
= 314 is tilted inwardly to urge pipes toward pivotal pipe arm 320. In FIG.
15G, catwalk
pipe moving elements are both tilted away from pipe moving element 314 to urge
pipes
away from pivotal pipe arm 320. However, each prep of catwalk pipe moving
elements 314 on each of catwalks 309 and 311 operate independently. In one
embodiment, by tilting pipe moving elements 314 away from pivotal pipe arm
320, the
pipe moving elements 314 operate in synchronized fashion with pipe ejector
direction
control which directs pipe away from pipe arm 320 in a desired direction as
indicated
by arrows 377A and 377B (see FIG. 17), as discussed hereinafter.
1001591 In another embodiment, each entire elongate catwalk section 309 and
311 could be
pivotally mounted on skid edges 301 and 307. Accordingly, due to the pivotal
mounting discussed previously or in accord with this alternate embodiment,
catwalk
sections 309 may be 'selectively utilized to urge pipes toward or away from
pivotal pipe
arm 320. However, in yet another embodiment the catwalks may also be fixed
structures so as to either slope towards or away from pivotal arm 320 or may
simply be
relatively flat.
1001601 In yet another embodiment, at least one side of catwalk 302 (catwalk
sections 309
and/or 311) may be slightly sloped inwardly or downwardly toward pivotal pipe
arm
320 to urge pipe toward guide pipe for engagement with pivotal pipe arm 320.
In one
embodiment, pipe tubs 400 and/or one or both sides of catwalk 302 (and/or
catwalk
pipe moving elements 314) include means for automatically feeding pipes onto
catwalk
302 for insertion into the wellbore, which operation may be synchronized for
feeding
pipe to or ejecting pipe from pivotal pipe arm 320. In another embodiment, at
least one
side of catwalk 302 and/or catwalk pipe moving elements 314, may also be
slightly
sloped slightly downwardly towards at least one of pipe tubs 400 to urge pipes
toward
the respective pipe tub when pipe is removed from the well. In one embodiment,
one
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pipe tub may be utilized for receiving pipe while another is used for feeding
pipe. In
another embodiment, catwalk 302 may simply provide a surface with elements
(not
shown) built thereon for urging the pipe to or from the desired pipe tub 400.
[00161] In yet another embodiment, catwalk 302, which may or may not be
pivotally mounted
and/or comprise catwalk pipe moving elements 314, may be provided as part of
the
pipe tub and may not be integral or built onto the same skid as pivotal pipe
arm 320. In
yet another embodiment, the pipes may be manually fed to and from the pipe
tubs or
pipe racks to pivotal pipe arm 320 via catwalk 302.
[00162] FIG. 14A is a blowup view of the lower pipe arm pivot connection 313,
shown in Fig.
14, upon which the pivotal pipe arm 320 is lifted for the catwalk - pipe arm
assembly
300. The lower pipe arm pivot connection 313 comprises a bearing 306 and a
shaft or
pin 308 which provides a pivot point for the pivotal pipe arm 320 ,with
respect to the
pipe arm ground skid 310.
[00163] FIG. 15A is an elevation view of the catwalk - pipe ann assembly 300
of the
=
completion system 10 of one possible embodiment of the present invention. The
catwalk - pipe aim assembly 300 comprises the central arm 320, a kickout arm
360 and
one or more clamps 370A, 370B, 370C for engaging a pipe "P." The catwalk -
pipe
arm assembly 300 is rotationally moved or pivoted with respect to lower pipe
arm pivot
connection 313 using the hydraulic, actuators 304. In this embodiment, pivotal
pipe
" arm 320 comprises a grid comprising plurality of pipe arm
struts 364.
[00164] FIG. 15B is an enlarged or detailed view of the section "B" of pivot
connection 313 as
illustrated in FIG. 15A of the completion system of one possible embodiment of
the
present invention. The pivotal pipe arm 320 is pivotally moved using a bearing
306 in
association with a shaft or pin 308. Control arm 315, to which pivot arm
struts 317
(See also FIG. 15A) are affixed, pivots about lower pipe arm pivot connection
313.
100165] FIG. 15C is an enlarged or detailed view of section "C" illustrated in
FIG. 15A of the
completion system of one possible embodiment of the present invention, which
shows
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control arm to hydraulic arm pivot connection 319. Piston 323 of the hydraulic
cylinder of hydraulic actuator 304 is pivotally engaged with control arm 315
using the
pin 327.
[001661 FIG. 15D is an enlarged or detailed view of the section indicated by
"D" in FIG. 15A of
the completion system of one possible embodiment of the present invention,
which
shows the hydraulic cylinder of hydraulic actuator. 304 pivotal connection
329. FIG.
15D shows the engagement of the hydraulic cylinder with the skid using the pin
331.
[00167] FIG. 15E is a plan view of the catwalk - pipe arm assembly 300 of the
completion
system 10 of one possible embodiment of the present invention. The catwalk -
pipe
arm assembly 300 comprises the pivotal pipe arm 320 in association with the
skid 310.
The arm has engaged with it a kickout arm 360 which is pivotally moved with
the
hydraulic actuator 362. The pivotal pipe arm 320 is pivotally moved with the
hydraulic
actuator 304. The kickout arm has clamps 370A, 370B for engaging a piece of
pipe
[00168] FIG. 16A is an elevation view of the pivotal pipe arm 320 of the
completion system 10
of one possible embodiment of the present invention, without the catwalk 302
for easier
viewing. Pivotal pipe arm 320 comprises an elongate lower pipe arm, section
322
which is pivoted using the hydraulic actuators 304. Lower pipe arm section 322
is
secured to y-joint connector 324, which in turn connects to pivot arm Y arm
strut
components 326A and 326B (shown in Fig. 16B). The Y arm strut components 326A
and 326B are connected to control arms 315, which are in moveable engagement
with
the hydraulic actuators 304. An extension (not shown) may be utilized to
engage upper
mast fixture 135, if desired, to provide a preset starting position from which
kickout
arm 360 pivots outwardly to align with the top drive 150.
[00169] The elongate kickout arm 360 secures a piece of pipe "P" using a
plurality of pipe
clamps 370, which are labeled 370A and 370B at the bottom and top (when
upright) of
kickout arm 360. Pipe ejector direction control 371 acts to eject the pipe
from pivotal
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arm 320 in a desired direction when the pipe is laid down adjacent catwalk
302, as
discussed hereinafter.
1001701 FIG. 168 is a plan view of the pivotal pipe arm 320, as illustrated in
FIG. 16A for the
completion system 10 of one possible embodiment of the present invention,
showing
only the pipe arm components for convenience. In one possible embodiment,
upper
pipe arm section 340 may also incorporate kickout arm 360. In this embodiment,
kickout arm 360 remains generally parallel to pivotal pipe arm 320 except when
pivotal
pipe arm 320 is moved into the upright position shown in FIG. 7, FIG. 8, and
FIG.9.
Upon reaching the upright position, kickout arm 360 is pivoted using the
hydraulic
actuators 362, which cause kickout arm 360 to pivot away from pipe arm 320
about
kickout arm pivot connection 312 (FIG. 16C) at the top of pivotal pipe arm
360. The
kickout arm 360 is shown with the clamps 370A and 370B at the bottom and top
(when
Vertically raised) of kickout arm 360 as well as pipe ejector direction
control 371,
which may be positioned more centrally, if desired.
1001711 FIG. 16C is an enlarged or detailed view of the section "C" as
illustrated in FIG. 16A
for the completion system 10 of one possible embodiment of the present
invention,
which shows kick arm pivot connection 312 (FIG. 16C) at the top of pivotal
pipe arm
360. FIG. 16C shows the pivotal pipe ann 320 in association with an upper
portion of
kickout arm 360 (when vertically raised) and the clamp 370B.
1001721 FIG. 16D is an end view of the pivotal pipe arrn 320 and kickout arm
360 of the
completion system 10 of one possible embodiment of the present invention for
the
completion system 10, which shows an end view kickout arm pivot connection 312
(FIG. 16C) at the top of pivotal pipe arm 320 and clamp 370B. Pivot beam 366
connects pipe kickout arm 360 to the top of pivotal pipe arm 320. kickout arm
base
375 may comprise a rectangular cross-section in this embodiment. The pipe is
received
into pipe reception groove 378.
[00173j FIG. 17 is a perspective view of a portion of the kickout arm 360 of
the completion
system 10 in accord with one possible embodiment of the present invention. The
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kickout arm 360 is illustrated with the components attached to &kick out arm
base 375,
which in this embodiment may have a relatively rectangular or square profile.
The kick
out arm base 375 is used for supporting one possible embodiment of the pipe
clamps
370A and 370B (See also FIG. 18A) and pipe ejector directional control 371.
Torsional
arms 372, which are also referred to as torsional arms 372A and 372B, are
utilized to
selectively activate eject arms 374A and 374B. The eject arms 374A connect to
torsional arms 372A. The eject arms 374B connect to torsional arms 372B,
respectively. When torsional 'arms 372A are rotated utilizing hydraulic
actuator 382A,
which rotates plates 384A, (see FIG. 17A and FIG. 18 C-C), then eject arms
374A will
lift the pipe to eject the pipe from kickout arm 360 in the direction shown by
pipe
ejection direction arrow 377A to the pipe tub or the like. Similarly, when
torsional
arms 372B are rotated, then eject arms 374B eject the pipe in the direction
indicated by
pipe ejection direction arrow 377B to the other side. Prior to ejection or
clamping, the
pipe will align with the pipe reception grooves 378 in the clamps 370 and
ejector
mechanism 380. Plates 375 comprise a relatively square receptacle 385 (see
FIG. 17A)
that mates to kick out arm base 375 for secure mounting to resist torsional
forces
created during pipe ejection and/or pipe clamping.
1001741 FIG. 17A and FIG. 18C-C provide an enlarged or detailed view of the
pipe ejector
direction control 371 illustrated in FIG. 17 for the completion system of one
possible
embodiment of the present invention. The pipe ejector direction control 371 is
illustrated using the plates 376, which can be connected by a connector or
bracket
(386), and are in association with the torsional ejection rods 372A and 372B.
The
ejection mechanisms 380A and 380B (see FIG. 18 C-C) are between the plates 376
and
= provide for rotational movement of the torsional ejection rods 372A and
372B.
= Ejection mechanism 380A operates to eject pipe as indicated by pipe
ejection direction
arrow 377A (see FIG. 17). Ejection mechanism 380B operates to eject pipe in
the
direction indicated by arrow 377B. The pipe reception groove 378 is for
accepting the =
joint of pipe during clamping or prior to ejection. In this embodiment,
ejector hydraulic
actuators 382A and 382B are pivotally connected to pivotal plates 384A and
384B,
respectively, which are fastened to respective torsional ejection rods 372A
and 372B for
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selectively ejecting the pipe from kickout arm 360 in the desired direction as
indicated
by pipe ejection arrows 377A and 377B. As shown in FIG. 17, torsional ejection
rods
372A and 372B are rotationally mounted to plates on clamps 370A and 370B for
support at the ends thereof.
[001751 Referring to FIG. 17, FIG. 18C, FIG. 21A, and FIG. 21B, clamps 370A
and 370B are
similar and in this embodiment, each comprises two sets of clamping members,
including a lower clamp set 387A,B and an upper clamp set 389 A,B. Each clamp
set is
activated by respective pairs of clamp hydraulic actuators, such as 392A and
392B,
perhaps best shown in FIG. 18A. In this embodiment, after the pipe is rolled
into the
pipe reception grooves, then the clamp sets 387A, 389A and 387B, 389B are
pivotally
mounted on clamp arms 394A and 394B to rotate upwardly around pivot
connections to
clamp the pipes. When not in use clamp sets 387A, 389A and 387B, 389B are
rotated
downwardly to be out of the way (as shown in FIG. 17 and 21A) as the pipes are
rolled
into the pipe reception grooves 378.
[00176] It will be appreciated that other types of clamps, arms, ejection
mechanisms and the
like may be hydraulically operated to clamp and/or eject the pipe onto or away
from
kickout arm 360.
[00177] FIG. 18A is an elevation view of the kickout arm 360 of the completion
system 10 in
accord with one possible embodiment of the present invention. The kickout arm
360 is
shown with the lower and upper pipe clamps 370A and 370B, pipe ejector
direction
=
control 37], the base 375 with torsional ejection rod 372A (shown in Fig.
18B), ejector
hydraulic actuator 382A, and pipe clamp hydraulic actuators 392A.
[00178] FIG. 18B is a bottom view of the kickout arm 360 as illustrated in
FIG. 18A for the
completion system of one possible embodiment of the present invention. FIG.
18B
illustrates the base 375 in association with the torsional ejection rods 372A
and 372B,
which in this embodiment are rotationally secured to each of clamps 370A and
370B as
well as to pipe ejector direction control 371. The clamps 370A and 370B are
dispersed
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at the remote ends of the kickout arm 360. There may be fewer or more clamps,
as
desired.
[00179] FIG. 18C is a top view of the kickout arm 360 of the completion system
10 of the
present invention. The kickout arm 360 is illustrated with the clamps 370A and
370B
secured with the base 375 and operatively associated with the torsional
ejection rods
372A and 372B.
[001801 FIG. 18B-B is a sectional view of FIG. 18B for the -completion system
of one possible
embodiment of the present invention. The end 390 is illustrated with kickout
arm pivot
connection 312 at the top (when pivotal pipe arm is upright) of pivotal pipe
ann 320.
[00181] FIG. 18C-C is a cross section of FIG. 18C illustrating pipe ejector
direction control
371. The ejector mechanism 380A and 389B comprise ejector hydraulic actuators
382A, 382B and pivotally mounted ejection control arms 384A and 384B, which
rotate
- torsional ejection rods 372A, and 372B in one possible embodiment of the
present
invention.
1001821 FIG. 19A is an elevation view of the top drive fixture 151, without
the top drive
mechanism 160, used in conjunction with the mast assembly 100 of the
completion
system 10 of one possible embodiment of the present invention. The top drive
fixture
151 is shown with the guide frame 152, separated designated as 152A, 152B.
Guide
frames 152A, 152B are connected at top drive fixture flanges 141A, 141B to
extensions
143A, 143B downwardly projecting from side plates 156A, 156B of a traveling
block
frame 154. Traveling block fixture 154 is part of a traveling block assembly
153
comprising frame 154 and a cluster of sheaves 155 (155A, 155B, 155C, 155D)
supported in such frame. Guide frames 152A, 152B slidingly engage mast top
drive
guide rails 104, as discussed hereinbefore.
[001831 FIG. 19B is a side view of the top drive fixture 151 and frame 154 of
the traveling
block assembly 153 illustrated in FIG. 19A. FIG. 19B illustrates the guide
frame 152B
in relation to the traveling block frame 154B using the block side plate 156B.
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[00184] FIG. 19C-C is a cross sectional view taken along the section line C-C
in FIG. 19B
illustrating the mechanism associated with the top drive fixture 151 of the
completion
system of one possible embodiment of the present invention. The mechanism
provides
= for the slide supports 152 having at its extremities a first and second
rollers 158A, 158B
on a respective roller axles 159A, 159B of guide frame 152B, which may be
utilized to
provide a rolling interaction with mast top drive guide rails 104 maintaining
the top
drive in a relatively fixed vertical position. FIG. 19C-C also depicts flange
141B
connected to extension 143B.
[00185] FIG. 19D is an enlarged or detailed view of the roller 158A as
illustrated in FIG. 19B.
1001861 FIG. 19E-E is a cross sectional view taken along the section line E-E
in FIG. 19A.
19E-E is in the same orientation as FIG 19B, but is sectional. Referring to
FIGS 19A,
19B and 19E-E, traveling block frame 154 further comprises a front plate 144A,
a rear
= plate 144B (shown in FIG. 19B), and side plates 156A, 156B including the
downwardly
projecting extensions 143A, 143B. A frame cross member spans side plates 156A,
156B above traveling block sheaves 155A, 155B, 155C, 155D sufficiently within
parallel planes tangent to peripheries of flanges of such sheaves that a
drilling line
reeved around the sheaves as described below does not contact cross member
145.
within parallel planes tangent to peripheries of flanges of such sheaves that
a drilling
line reeved around the sheaves as described below does not contact cross
member.
Cross member mounts inferiorly a plurality of rigid spaced apart parallel
hangers 146A,
146B, 146C, 146D and 146 E (shown in FIG. 19A), each in a plane perpendicular
to an
axis of front sheaves of a crown block assembly described below. Hangers 146A,
146B
support between them an axle 147A for traveling block sheave 155A; hangers
146B,
146B support between them an axle 147B for traveling block sheave 155B;
hangers
146C, 1461) support between them an axle 147C for traveling block sheave 155C;
and
hangers 146D, 146E support between them an axle 147D for traveling block
sheave
155D. Each sheave axle 147A, 147B, 147C and 14713 is parallel to the plane of
the axis
of the front sheaves of the crown block assembly. Traveling block sheaves
155A, 155B,
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155C, 155D rotate in traveling block frame respectively on axles 147A, 147B,
147C
and 147D.
1001871 FIG. 20A is an illustration of the top drive 150 in the top drive
fixture 151 of the
completion system of one possible embodiment of the present invention. The top
drive
comprises the top drive fixture 151 in conjunction with the drive mechanism
160. The
drive mechanism 160 is moveably engaged with the guide frames 152A, 152B and
moves in a vertical direction using traveling block assembly 153. A top drive
shaft 165
provides rotational movement of the pipe using the drive mechanism 160. Top
drive
shaft 165 connects to item 163,, which may comprise a top drive threaded
connector
and/or pipe connection guide member. Item 163 may also be adapted to hold the
pipe.
A torque sensor may also be included therein.
1001881 FIG. 20B is an upper view of traveling block assembly 153 and top
drive 150 as
illustrated in FIG. 20A. FIG. 20B illustrates the guide frames 152A, 152B with
the
frame 154 there between.
=
1001891 Referring to FIGS 19A, 19B, 19E-E, 20A and 20B, traveling block
sheaves 155 are
seen to be horizontally canted in frame 154. The purpose and angle of this
canting and
the operation of the traveling block assembly to raise and lower top drive 150
is now
explained.
1001901 Referring to FIGS 4, 7B, 9, 27A, and 27B, carrier 600 pivotally mounts
mast 100 on the =
carrier for rotation upward to an erect drilling position, as has been
described. Mast 100
comprises front and rear vertical support members 105, and a mast top or crown
190
supported atop front and rear vertical support members 105. Drawworks 620 is
mounted on carrier 600 to the rear of an erect mast 100. Drawworks 620 has a
drum
621 with a drum rotation axis perpendicular to the drilling axis for winding
and
unwinding a drilling line on drum 621. A crown block assembly 191 is mounted
in mast
top or crown 190 for engaging the drilling line. The crown block assembly
comprises a
cluster 193 of front sheaves mounted at the front of mast top 190 facing the
drilling
axis. This cluster 193 comprises first and second outermost sheaves and at
least one
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inboard sheave, all aligned on an axis in a plane perpendicular to the
drilling axis and
having a predetermined distance between grooves of adjacent front sheaves. A
fast line
sheave 194 is mounted on the drawworks side of the mast top behind the first
outermost
front sheave of cluster 193 and on an axis substantially parallel to the axis
of the front
sheaves of cluster 193, for reeving the drilling line to the first outermost
front sheave of
cluster 193. A deadline sheave 195 (blocked from view by the front sheaves of
cluster
193) is mounted on the dmwworks side of mast top 190 behind a second laterally
outermost front sheave (blocked from view by fast line sheave 194) and on an
axis
substantially parallel to the axis of the front sheaves of cluster 193, for
reeving the
drilling line from the second outermost front sheave to an anchorage.
1001911 Traveling block assembly 153 hangs by the drilling line from the front
sheaves of the
crown block assembly, and comprising, as has been described, fixture 154 and
the
cluster of sheaves 155 supported in the fixture. The cluster is one less in
number than
the number of front sheaves in the crown block assembly and includes at least
first and
second outermost traveling block sheaves 155A, 155D (in the illustrated
embodiment
there are two traveling block sheaves, 155B, 155C inboard of outermost
traveling block
sheaves 155A, 155D. Traveling block sheaves 155A, 155B, 155C, 155D have a
predetermined distance between grooves of adjacent traveling sheaves and
rotate on a
common horizontal axis in a plane perpendicular to the drilling axis. The axis
of the
traveling sheaves 155A, 155B, 155C, 155D is angled in the latter plane
relative to the
axis of the front sheaves of the crown block assembly such that the drilling
line reeves
downwardly from the groove in a first front sheave parallel to the drilling
axis to
engage the groove in a first traveling block sheave and reeves upwardly from
the
groove in a first traveling block sheave toward the second front sheave next
adjacent
such first front sheave at an up-going drilling line angle to the drilling
axis effective
according to the distance between the grooves of the first and second front
sheaves to
move the drilling line laterally relative to the front sheave axis and engage
the groove
of the second front sheave, each the traveling block sheaves receiving the
drilling line
parallel to the drilling axis and reeving the drilling line to each following
front sheave
at an up-going angle.
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[00192] Accordingly, first outermost traveling block sheave 155A receives the
drilling fine
reeved downward from the first laterally outermost front sheave of the crown
block
assembly parallel to the drilling axis and reeves the drilling line at an up-
going angle to
a next adjacent inboard front sheave. The latter inboard front sheave reeves
the drilling
line downward to traveling block sheave 155B next adjacent first laterally
outermost
traveling block sheave 155A parallel to the drilling axis. The latter
traveling block
sheave 155B reeves the drilling line at an up-going angle to a front sheave
next
adjacent the front sheave next adjacent the first laterally outermost front
sheave, and so
forth, for each successive traveling block sheave (respectively sheaves 155C,
155D in
the illustrated embodiment of FIGS 19A, 19B, 19E-E, 20A and 20B), until the
second
outmost traveling block sheave (155D in the illustrated embodiment) reeves the
drilling
line at an the up-going angle to the second outmost front sheave. The second
outmost
front sheave reeves the drilling line to the deadline sheave, and the deadline
sheave
reeves the line to the anchorage.
[00193] In an embodiment, an up-going angle from a traveling block sheave to a
crown block
front sheave is not more than about 15 degrees. In an embodiment, an up-going
angle
from a traveling block sheave to a crown block front sheave is about 12
degrees.
[00194] In an embodiment, the predetermined distances between grooves of the
front sheaves
are equal from sheave to sheave. In an embodiment in which the front sheaves
comprise a plurality of inboard sheaves, the predetermined distance between at
least
one pair of inboard front sheaves may be the same or different than the
distance
separating an outermost front sheave from a next adjacent inboard front
sheave.
[00195] FIG. 20A-A is a cross sectional view taken along the section line A-A
in FIG. 20A
illustrating the relationship of the drive mechanism 160 in the top drive
frame 151. The
guide frames 152 provide structural support for the drive mechanism 160.
[00196] FIG. 21A is a perspective view of the pipe arm assembly with the pipe
clamps recessed
allowing the pipe arm to receive pipe, as also previously discussed with
respect to FIG.
17, and FIG. 18C. In this embodiment, pipe ejector direction control 371 is
omitted for
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clarity of the other elements in the figure. However, in another possible
embodiment,
the pipe ejector mechanism may not be utilized or may be replaced by other
pipe
ejector means. Kickout arm 360 is secured to pivotal pipe arm 320 at kickout
arm pivot
connection 312 located at the top of pivotal pipe arm 320. Kickout arm
hydraulic
actuators 362 provide pivotal movement when pipe arm 320 is in an upright
position. In
this embodiment, pipe clamps 370A and 370B are mounted to kickout arm 360,
although in other embodiments pipe clamps 370A and 370B can be mounted
directly to
pivotal pipe arm 320. Catwalk segments 309 and 311 contain one possible
embodiment
of catwalk pipe moving elements 314 to urge pipe onto pipe arm 320 which are
guided
or rolled into pipe reception grooves 378 along pipe guides 379 (See FIG.
16D). Pipe
clamp sets 387A, 389A and 387B, 389B are recessed below an outer surface of
pipe
guides 379 within pipe clamp mechanisms 370A and 370B to allow pipe "P" to be
accepted in pipe reception grooves 378, such as pipe "P" which is shown in
position in
the pipe reception grooves. Pipe clamp sets 387A, 389A and 387B, 389B are
mounted
to pivotal pipe clamp arms 394A and 394B.
1001971 FIG. 21B is a perspective view of the pipe arm assembly with the pipe
clamps engaged
around the pipe, which allows the pipe arm to move the pipe "P" to an upright
position
in mast 100. In this embodiment, pipe clamp 370A is located at a lower point
on
kickout arm 360, while pipe clamp 370B is located on an upper part of kickout
arm
360. In another embodiment, pipe clamps 370A and 370B could be mounted to pipe
arm 320. As discussed hereinbefore, pipe clamp sets 387A, 389A and 387B, 389B
are
mounted to pivotal pipe clamp arms 394A and 394B. In this embodiment, once
pipe
"P" is urged into pipe receptacle grooves 378 by catwalk moving elements 314
on
either catwalk section 309 or 311, pipe clamp hydraulic actuators 392A and
392B (See
FIG. 18C) urge pipe clamp sets 387A, 389A and 387B, 389B around clamp pivots
391A and 391B to engage pipe "P".
[001981 FIG. 22A is a perspective end view of one possible embodiment of
walkway 309 and
311 with one possible example moving elements, illustrating how pipe is moved
from
the walkway to the pipe arm. In FIG. 22A, catwalk segment 311 contains catwalk
pipe
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moving elements 314 in a sloped position for urging pipe "P" into pipe clamp
mechanisms 370A and 370B utilizing pipe reception grooves 378. In another
embodiment, catwalk pipe moving elements .314 can move into a second sloped
position for moving pipe away from kickout arm 360 towards a pipe tub. In this
embodiment, corresponding pipe moving element hydraulic controls 333 can be
utilized for selectively operating pipe moving elements 314 on catwalk
segments 309
and 311(See FIG. 15F). For example, the moving elements can be retracted below
the
surface of walkway 311 or raised to provide a gradual slope that urges the
pipes into
pipe reception grooves 378.
[00199] In one possible embodiment, pipe barrier posts 31,6 may be utilized to
prevent
additional pipes from entering catwalk segment 311 while pipe is being moved
with
pipe moving elements 314 towards pipe clamp mechanisms 370A and 370B located
on
kickout arm 360. Pipe bather posts 316 may keep the pipe outside of the
catwalk
segment 311 after pipe moving elements 314 are lowered, whereby an operator
may
walk along the catwalk without impediments and/or utilize the catwalk for
other
purposes such as making up tools or the like. Catwalk segment 309 illustrates
pipe
moving elements 314 in a flat position flush with the surface of catwalk
segment 309.
In one possible embodiment, pipe barrier posts 316 may be hydraulically raised
and
lowered. In another embodiment pipe barrier posts 316 may mechanically
inserted,
removed, or replaced (such as with sockets in the catwalk). In another
embodiment,
pipe bather posts may not be utilized. In another embodiment, other means for
separating the pipe may be utilized to urge a single pipe on pipe moving
elements
whereupon catwalk moving elements 314 are raised to gently urge one or more
pipes
into pipe reception grooves 378. Catwalk pipe moving elements may be larger or
wider
if desired. In another embodiment, catwalk pipe moving elements may comprise a
groove that holds the next pipe until raised whereupon the pipes are urged
toward pipe
guides 379 and pipe reception grooves 379.
[00200] FIG. 22B is a perspective end view of the walkway with movable
elements in accord
with one possible embodiment of the invention. Catwalk segment 309 contains
pipe
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moving elements 314 in a recessed position with pipe barrier posts 316 to
prevent pipe
from entering catwalk segment 309 while pipe "P" is engaged with pivotal pipe
arm
320. In this embodiment, catwalk segment 311 illustrates pipe moving elements
314 in
a raised position that work with pipe barrier posts 316 to prevent pipe from
entering
catwalk segment 311. In other embodiments, pipe barrier posts 316 may be
hydraulically actuated or manually removable. In another embodiment, pipe
barrier
posts may be omitted and pipe moving elements 314 may contain a groove for
holding
back pipe from pipe tub 400. Kickout arm 360 is secured to pivotal pipe arm
320 at
kickout arm pivot connection 312 located at the top of pivotal pipe arm 320.
Pipe "P"
has rolled into pipe reception grooves 378 located in pipe clamp mechanisms
370A and
370B where pipe clamp sets 387A, 389A and 387B, 389B will pivot about pivotal
pipe
clamp arms 394A and 394B to engage pipe "P".
1002011 FIG 23A is an end perspective view of a pipe feeding mechanism 422 in
accord with
one possible embodiment of the invention. In this embodiment, pipe tub 400
comprises
a rack or support, at least a portion of which is sloped downward towards
catwalk
segment 311 which urges pipe towards pipe feed receptacle 424. Pipe feed
receptacle
424 is movably mounted to support arms 434 for transporting pipe between pipe
tub
400 and catwalk segment 311. Accordingly, in one embodiment, pipe receptacle
424
lifts pipe one at a time out of pipe tub 400 onto catwalk 311 and/or catwalk
moving
elements 314. As used herein pipe tube 400 may comprise a volume in which
multiple
layers of pipe may be conveniently carried or may simply be a pipe rack with a
single
layer of pipe.
1002021 FIG. 23B is another end perspective view of a pipe feeding mechanism
422 in accord
with one possible embodiment of the present invention. Pipe feed mechanism 422
comprises support arms 434 which, if desired, may be fastened to catwalk
segment 311.
In one possible embodiment, pipe feed receptacle may comprise a wall, rods,
brace 425
at edge 427 of pipe feed receptacle adjacent the incoming pipe that contains
the
remaining pipe on the rack when pipe feed receptacle 424 moves, in this
embodiment,
upwardly. Thus, the wall or rods act as a gate. Once pipe receptacle 424 is
lowered,
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then another pipe drops into pipe receptacle 424. In this embodiment, pipe
feed
receptacle 424 is slidingly mounted to support arms 434 for movement between
pipe =
tub 400 and catwalk segment 311. Once pipe "P" is moved towards catwalk
segment
311, catwalk moving elements 314 urge pipe "P" towards pipe rum 320 with
kickout
ami 360. Pipe feed receptacle 424 could also be pivotally mounted to urge pipe
out of
pipe tub 400. In another embodiment, the tub or rack of pipes may be higher
than the
surface of catwalk 311 and the catwalk moving elements act as the pipe feed to
control
the flow of pipe from the pipe tub or rack 400 of pipe. Accordingly, the pipe
feed may
or may not be mounted within pipe tube 400.
=
1002031 In yet another embodiment, as shown in FIG. 23C, pipe tub 400 may
comprise means
for moving pipe from the bottom to the top of the pipe tub 400, such as a
hydraulic
floor or a spring loaded floor. In one embodiment, pipe tub 400 may also
contain pipe
gate 426 at an upper edge of pipe tub 400 for efficiently moving pipe from
pipe tub 400
to pipe feed receptacle 424.
1002041 FIG. 23C is a cross sectional view of another possible embodiment of a
pipe feeding
mechanism 422 with the pipes present. The embodiment of pipe tub 400 shown in
FIG.
23C may also be utilized for receiving pipe as the pipe is removed from the
well in
conjunction with pipe ejection mechanisms and/or catwalk pipe, moving elements
discussed hereinbefore. As discussed hereinbefore, pipe tub 400 contains
sloped bottom
428 and optional pipe rungs 432 for controlling movement of pipes towards pipe
gate
426. The downward sloped angle of pipe rungs 432 and their placement inside
pipe tub
cavity 420 continually move pipe as pipe gate 426 opens to allow pipe "P" to
be
received by pipe feed receptacle 424. Pipe feed receptacle 424 lifts pipe "P"
to an upper
position adjacent a surface of catwalk segment 311 for movement unto kickout
arm
360. Various types of lifting mechanisms may be utilized for pipe feed
receptacle
including hydraulic, electric, or the like. Pipe gate 426 controls movement of
pipe onto
pipe feed receptacle 424 which is supported by vertical support member 430 and
support base 440 to prevent movement during operation. -
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[00205] FIG. 23D is a cross sectional view of a pipe feeding mechanism 422
with the pipes
removed in accord with one possible embodiment of the present invention. Pipe
feed
mechanism 422 is positioned between pipe tub 400 and catwalk segment 311. Pipe
tub
400 contains pipe gate 426 at a lower end of pipe tub 400 facing catwalk
segment 311.
Pipe rungs 432 may be utilized in connection with sloped bottom 428 within
pipe tub
400 for controlling the movement of pipe "P" towards pipe gate 426. As
discussed
hereinbefore, pipe feed receptacle 424 is stabilized by vertical support
member 430 and
support base 440 while in this position. Pivotal rungs may be removable or
pivotal to
open for filling the pipe tub more quiddy.
[00206] FIG. 23E is a cross sectional view of a pipe feeding mechanism 422 in
accord with one
possible embodiment of the present invention. In this embodiment, pipe rungs
432 are
omitted so that pipe tub cavity 420 only contains sloped bottom 428 and pipe
gate 426.
This arrangement allows a higher volume of pipe to be stored in pipe tub 400
for
= drilling operations. Sloped bottom 428 will urge pipe towards pipe gate
426 which
remotely opens and closes to allow pipe "P" to be received by pipe feed
receptacle 424.
After pipe "P" has cleared pipe gate 426, it will be hoisted along vertical
support
member 430 via pipe feed receptacle 424 until it reaches catwalk segment 311.
Once at
catwalk segment 311, pipe "P", will be further urged to pipe arm 320 by
catwalk
moving elements 314 (See FIG. 23B). In one embodiment, the pipe feeding
mechanism
of FIG. 23E May be utilized with the pipe tub 400 of FIG. 23C. When removing
pipe
from the well, the pipe may be positioned onto the rungs by catwalk moving
elements
and/or pipe ejection elements discussed hereinbefore.
[00207] During operation for insertion of pipes into the wellbore, pipes are
moved from pipe
tubs 400 to the catwalk (if desired by automatic operation) and in one
embodiment
catwalk pipe moving elements 314 are activated to urge the pipes into pipe
grooves 378
past retracted pipe clamps 387A, 389A and/or 387B, 389B. Once the pipe is in
the
grooves, then the pipe clamps are pivoted upwardly 387A, 389A and/or 387A,
389A to
clamp the pipes. During this time, the length and other factors of the pipe is
sensed or
read by REID tags. Pivotal pipe arm 320 is then rotated upwardly to the
desired
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position (which may be determined by sensors and/or an upper mast fixture 315.
Kickout arm 360 pivots outwardly to or the pipe vertically.
1002081 Top drive 150 is lowered using drawworks 620 to lower traveling block
assembly 153,
and top drive shaft 165 is rotated to threadably connect with the upper pipe
connector.
The pipe is then lowered utilizing traveling block assembly 153 and top drive
150 so
that the lower connection of the pipe is connected to the uppermost connection
of the
pipe string already in the wellbore and the pipe may be rotated to partially
make up the
connection. The pipe tongs 170 are moved around the pipe connection to torque
the
pipe with the desired torque and the torque sensor measures the make-up torque
curve
to verify the connection is made correctly. The pipe tongs are moved out of
the way.
The slips are disengaged and the pipe string is lowered so that the pipe upper
connection is adjacent the rig floor and the slips are applied again to hold
the pipe
string. The pipe tongs may be brought back in for breaking the connection of
this pipe
and may utilize reverse rotation of the top drive to undo the connection.
Using
drawwotks 620 to raise traveling block assembly 153, top drive 150 is moved
back
toward the mast top in readiness for the next pipe.
[00209] To remove pipe from the well bore, the top drive is raised so that the
lower connection
of the pipe for removal is available to be broken by pipe tongs. Once broken,
the top
drive may be used to undo the connection the remainder of the way. The pipe is
then
raised, lcickout arm 360 is pivoted outwardly, and clamps 370A and 370B clamp
the
pipe. The connection to the top drive is then broken by rotation of the top
drive shaft
165, whereupon the top drive is moved out of the way. Kickout arm 360 is then
pivoted back to be adjacent pivotal pipe arm 320. Pivotal pipe arm 320 is
lowered.
Clamps 370A and 370B are released and retracted. Either the eject arms 374A or
374B
are activated depending on which side the pipe tube is located. Accordingly, a
single
operator can run pipe into the well, perform services, and remove pipe from
the well.
Other personnel at the well site may be utilized for other functions such as
cleaning
pipe threads, removing thread protectors, moving pipe onto pipe tubs, which
may also
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simply comprise racks, checking mud measurements, checking engines, and the
like as
is well known.
1002101 For alignment purposes of the present application, a wellhead, BOP,
snubber stack,
pressure control equipment or other equipment with the well bore going through
is
considered equivalent because this equipment is aligned with the path of the
top drive.
1002111 Figure 24A depicts a perspective view of an embodiment of a gripping
apparatus 1000
engageable with a top drive, such that pipe segments can be gripped by the
apparatus
1000 to eliminate the need to thread each individual segment to the top drive
itself.
Figure 24B depicts a diagrammatic side view of the apparatus 1000.
1002121 The apparatus 1000 is shown having an upper connector 1002 (e.g., a
threaded
connection) usable for engagement with the top drive, though other means of
engagement can also be used (e.g., bolts or other fasteners, welding, a force
or
interference fit). Alternatively, the gripping apparatus 1000 could be formed
integrally
or otherwise fixedly attached to a top drive or similar drive mechanism.
1002131 The apparatus 1000 is shown having an upper member 1004 engaged to the
connector
1002, and a lower member 1006, engaged to the upper member 1004 via a
plurality of
spacing members 1008. While Figures 24A and 2413 depict the upper and lower
members 1004, 1006 as generally circular, disc-shaped members, separated by
generally elongate spacing members 1008, it should be understood that the
depicted
configuration of the body of the apparatus 1000 is an exemplary embodiment,
and that
any shape and/or dimensions of the described parts can be used. The lower
member
1006 is shown having a bore 1010 therein, through which pipe segments can
pass.
1002141 During operation, the apparatus 1000 can be threaded and/or otherwise
engaged with
the top drive, then after positioning of a pipe segment beneath the top drive
and
apparatus 1000, e.g., using a pipe handling system, the apparatus 1000 can be
lowered
by lowering the top drive. And end of the pipe segment thereby passes through
the
bore 1010, such that slips or similar gripping members disposed on the lower
member
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1006 can be actuated (e.g., through use of hydraulic cylinders or similar
means) to grip
and engage the pipe segment. Continued vertical movement of the top drive
along the
mast thereby moves the apparatus 1000, and the pipe segment, due to the
engagement
of the gripping members thereto. Likewise, rotational movement of the top
drive (e.g.,
to make or unmake a threaded connection in a pipe string) causes rotation of
the
apparatus 1000, and thus, rotation of the gripped pipe segment. The apparatus
1000 is
thereby usable as an extension of the top drive, such that pipe segments need
not be
threaded to the top drive itself, but can instead be efficiently gripped and
manipulated
using the apparatus 1000.
1002151 Other types of attachments for engagement with a top drive or other
drive system,
and/or for engaging and/or guiding a tubular joint are also usable. tor
example, Figure
25A depicts an exploded perspective view of an embodiment of a guide apparatus
1100
engageable with a top drive such that tubular joints brought into contact with
the guide
apparatus 1100 can be moved toward a position suitable for engagement with the
top
drive (e.g., in axial alignment therewith). Figure 25B depicts a diagrammatic
side view
of the guide apparatus 1100.
1002161 Specifically, the guide apparatus 1100 is shown having an upper member
1102 that
includes a connector (e.g., interior threads) configured to engage a top drive
and/or
other type of drive mechanism, though other means of engagement can also be
used
(e.g., bolts or other fasteners, welding, a force or interference fit).
Alternatively, the
guide apparatus 1100 could be formed integrally or otherwise fixedly attached
to a top
drive or similar drive mechanism.
= 1002171 The upper member 1102 is shown engaged to the remainder of the
guide apparatus
1100 via insertion through a central body 1106 having an internal bore, such
that a
= threaded lower portion 1104 of the upper member 1102 protrudes beyond the
lower end
of the central body 1106. A collar-type engagement, shown having two pieces
1108A,
1108B, connected via bolts 1110, nuts 1111, and washers 1113, can be used to
secure
the upper member 1102 to the remainder of the apparatus 1100, though it should
be
understood that the depicted configuration is exemplary, and that any manner
of
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removable or non-removable engagement can be used, or that the upper member
1102
could be formed as an integral portion of the guide apparatus 1100.
[00218] A lower member 1112 is shown below the upper member 1102, the lower
member 1112
having a generally frustxoconical shape with a bOre 1114 extending
therethrough. The
, shape of the lower member 1112 defines a sloped and/or angled
interior surface 1116.
A plurality of spacing members 1118 are shown extending between the lower
member
1112 and the central body 1106, thus providing a distance between the lower
member
1112 and the upper member 1102 and/or a top drive connected thereto. While
Figures
25A and 25B depict the upper member 1102 and central body 1106 as generally
tubular
and/or cylindrical structures, it should be understood that any shape and/or
configuration could be used. Similarly, while the lower member 1112 is shown
as a
generally frustroconical member, other shapes (e.g., pyramid, partially
spherical, and/or
curved shapes) could be used to present an angled and/or curved surface in the
direction
of a tubular.
[00219] During operation, the guide apparatus 1100 can be threaded and/or
otherwise engaged
with the top drive, then after positioning of a tubular joint beneath the top
drive and the
guide apparatus 1100 (e.g., using a pipe handling system), the guide apparatus
1100 can
be lowered by lowering the top drive. After the end of the tubular joint
passes through
the lower end of the bore 1114, the end of the tubular joint contacts the
angled interior
surface 1116. Continued movement of the guide apparatus 1100 causes the
tubular to
move along the angled interior surface 1116 until the end of the tubular exits
the upper
end of the bore 1114, where contact between the tubular and the upper portion
off the
lower member 1112, and/or between the tubular and the spacing members 1118
prevents further lateral movement of the tubular relative to the guide
apparatus 1100.
[00220] The end of the tubular joint can then be connected (e.g., threaded) to
the lower portion
1104 of the upper Member 1102. Continued vertical movement of the top drive
along
the mast thereby moves the guide apparatus 1100, and the tubular joint, due to
the
engagement between the joint and the guide apparatus 1100. Likewise,
rotational
movement of the top drive (e.g., to make or unmake a threaded connection in a
pipe
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string) causes rotation of the guide apparatus 1100, and thus, rotation of the
engaged
tubular joint. The guide apparatus 1100 is thereby usable as an extension of
the top
drive, such that tubular joints need not be threaded to the top drive itself
where
misalignment can occur, but can instead be presented in a misaligned position,
contacted against the angled interior surface 1116, and moved into alignment
for
engagement with the apparatus 1100. In alternate embodiments, the upper member
1102 and lower portion 1104 thereof could be omitted, and a tubular joint
could be
eny: ged with a portion of the top drive directly.
1002211 FIG. 26 is a top view of a roller and a support rail in accord with
one possible
embodiment of the present invention. Roller 158 is one of several rollers
connected to
both guide frames 152A and 152B (See FIGS. 19, 19B, and 19C-C). Roller 158 is
connected to guide frame 152 at roller axle 159 allowing roller 158 to spin
freely
around roller axle 159., Support rail 176 is sized to mate with groove 173 of
roller 178
to facilitate movement of top drive 150 along support rail 176. In another
embodiment,
support rail 176 could contain groove 173 whereby roller 158 is sized to
engage groove
173 to facilitate movement of top drive 150. In this way, rollers 158 may be
utilized to
prevent rotation of the top drive and to reduce back and forth movement as may
occur
in prior art systems.
[00222] It will be understood that grooves could be provided in the guide
frame whereby the
- rollers fit in the groove of the guide frame rather than the groove being
formed in the
rollers. The moves may be of any type including straight line grooves where
the grove
sides may be angled or perpendicular with respect to the axis of rotation of
the rollers.
As well, the grooves may be curved. The grooves may also have combination of
angled and perpendicular lines or any variation thereof. Mating surfaces in
the
opposing component, either the guides or the rollers are utilized. There may
be some
variation in size to reduce friction, e.g., the groove may have a bottom width
of two
inches and the inserted member may have a maximum width of 1 and three-
quarters
inches and so forth. As discussed above, the grooves may be V-shaped or
partially V-
shaped.
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1002231 Miming to FIG. 27A and 27B, a top view of a crown block assembly in
accord with one
possible embodiment of the present invention. Crown block assembly 193 has
cluster
of sheaves located on top of mast assembly 100. Sheaves 193A, 193B, 193C, 193D
have an axis of rotation X upon which the sheave clusters 193A, 193B, 193C,
193D
rotate. Traveling sheave block assembly 153 has sheaves 146A, 146B, 146C, 146D
which are fastened to said guide frame 152 of top drive fixture 150 (see FIG.
19).
Traveling sheave block assembly 153 has axis of rotation Y, which is offset in
relation
to axis of rotation X upon which sheave clusters 193A, 193B, 193C, 193D
rotate. In
one embodiment, the offset is less than ninety degrees. In another embodiment,
the
offset is less than forty five degrees. In another embodiment, the offset is
less than
twenty five degrees. It will be understood that these ranges would also apply
if any
multiple of ninety degrees were added to these ranges, e.g., between ninety
and one-
hundred eighty degrees. This orientation improves the ability of sheave
clusters 193A,
193B, 193C, 193D and traveling sheave block assembly to reeve a drilling line.
When
the traveling sheaves move closely to the crown sheaves, the offset aids in
providing a
smoother transition from one set of sheaves to the other in that sharp bends
of the
drilling line are avoided.
1002241 Generally, sheave wheels have a minimum diameter with respect to the
type of drilling
line to limit the amount of bending of the drilling line. Generally, the
minimum sheave
diameter will be between fifteen times and thirty time the diameter of the
drilling line.
However, this range may vary. Accordingly, in some embodiments, the ratio of
sheave
wheel diameter to drilling line diameter may be less than twenty.
1002251 Turning to Figs. 28A and 28B, one possible embodiment of long lateral
completion
system 10 is depicted. A well site with first wellhead 12 and second wellhead
14 is
shown. As discussed hereinbefore, long lateral completion system 10 can work
well
with wellheads in close proximity with each other on a well site, which can be
less than
a 10 foot distance between first wellhead 12 and second wellhead 14. Pipe arm
assembly 300 occupies a rear portion of skid 16 while rig floor 102 is
positioned at a
front end of skid 16 closest to second wellhead 14. In another embodiment, rig
floor
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102 and pipe arm assembly 300 are operable without skid 16. Skid 16 is
positioned so
that rig platform 102 is directly above second wellhead 14. Rig floor 102 may
or may
not be part of skid 16.
1002261 Fig. 28B depicts long lateral completion system 10 in accord with one
possible
embodiment of the present invention. Rig carrier 600 is shown with mast
assembly 100
in an upright position. Mast assembly 100 extends past a rear portion of rig
carrier 600
so that top drive unit mounted within mast assembly 100 is positioned directly
above
first wellhead 12 for drilling operations, as discussed hereinbefore. In other
embodiments, sensors such as laser sights or guides mounted to the rear of rig
carrier
= 600, and the like may be utilized, e.g., mounted to and/or guided to the
well head, to
= locate and orient the axis of mast assembly 100 precisely with respect to
the wellbore
of first wellhead 12.
1002271 Rig floor 102 is shown positioned above second wellhead 14 providing
operators
access to mast assembly 100 when conducting drilling operations on first
wellhead 12.
System 10 is configured so that pivotal pipe arm 320 of pipe handling system
300 can
move pipe to and away from mast assembly 100 without contacting rig floor 102
during
operation. Pivotal pipe arm 320 uses control arm 315 to pivot about pipe arm
pivotal
connection 313 creating an angle which avoids rig floor 102.
1002281 In another embodiment of the present invention, pivotal pipe arm 320
may contain
kickout arm 360. In this embodiment, kickout arm 360 remains generally
parallel to
pivotal pipe arm 30 except when pivotal pipe arm 360 is moved into the upright
position shown in FIG. 7, FIG. 8, and FIG. 9. Upon reaching the upright
position,
kickout arm 360 is pivoted using the hydraulic actuators 362, which cause
kickout arm
360 to pivot away from pipe arm 360 about kickout arm pivot connection 312
(See
FIG. 16B). This preferred configuration of long lateral completion system 10
allows
drilling operations on multiple wells in close proximity, which can be less
than 10 feet
apart in certain embodiments.
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[00229] While certain exemplary embodiments have been described in details and
shown in the
accompanying drawings, it is to be understood that such embodiments are merely
illustrative of and not devised without departing from the basic scope
thereof, which is
determined by the claims that follow. Moreover, it will be appreciated that
numerous
= inventions are disclosed herein which are taught in various embodiments
herein and
that the inventions may also be utilized within other types of equipment,
systems,
methods, and machines so that the invention is not intended to be limited to
the
specifically disclosed embodiments.
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