Note: Descriptions are shown in the official language in which they were submitted.
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MOBILE RIG AND METHOD
CROSS REFERENCE TO RELATED APPLICATIONS
[001] The present application is a patent cooperation treaty (PCT) application
that claims priority to
United States Patent Application Serial Number 13/507,343, entitled "Mobile
Rig And Method," filed
on June 21, 2012.
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 properly given
the reservoir conditions. and to permit any operations deemed necessary for
enhancing production and
safety.
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[006] 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.
[007] 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.
[008] 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 PETN, and propellant stimulation).
[009] 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,
including unconventional
reservoirs such as shale rock 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.
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[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. To
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 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 posterity 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
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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 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 involved
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.
[0018] 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 thc 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 frequently 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
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alignment of the connectors to avoid damaging the threads. Production tubing
does not typically
utilize the expensive enlarged connectors 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.
[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) thc 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
CA 02877530 2016-08-04
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 perceht 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 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 he 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 wifh the disclosure. In the drawings,
[0026] FIG. 1 illustrates an embodiment of a long lateral completion system
usable within the scope of
one possible embodiment of the present disclosure.
[0027] 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.
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[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.
[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
carrier, and the pipe
arm engaged with the mast in accord with one possible embodiment of the
completion system of the
present disclosure.
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[0037] 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.
[0038] FIG. 7B is a perspective view of the portion of the mast assembly and
pipe arm illustrated in
FIG. 7 A-A in accord with one possible embodiment of the completion system of
the present
disclosure.
[0039] 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.
[0040] 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.
[0041] 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.
[0042] 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.
[0043] 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.
[0044] FIG. 9A-A is a cross sectional view of the system of FIG. 9 taken along
the section line A-A,
illustrating the upper portion of the mast assembly in accord with one
possible embodiment of the
completion system of the present disclosure.
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[0045J 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.
[0046] 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.
[0051] 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.
[0052] 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.
[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.
[0054] 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.
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[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 arm 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.
[0060] 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.
[0062] 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.
[0063] 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.
[0064] 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 present disclosure.
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[0065] 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.
[0066] 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.
[0067] 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.
[0068] 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.
[0069] 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.
[0070] 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.
[0071] 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.
[0072] 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.
[0073] FIG. 18C-C is a cross sectional view of the kickout 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.
[0074] 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.
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[0075] 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.
[0076] 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.
[0077] 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.
[0078] 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. =
[0079] 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.
[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 arm having a pipe
thereon with pipe clamps
retracted to allow a pipo 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.
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[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.
[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.
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[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.
[0098] 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.
[0099] 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. [0098]
[00100]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
[00101] 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
=
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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
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 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 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 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.
[00102] 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.
[00103] For example, etnbodiments 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
CA 02877530 2016-08-04
be used to urge a tubular member over a stop 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.
[00104] 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. The 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
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
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.
16
CA 02877530 2016-08-04
[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 connection or removal from a pipe string, or
a pipe utilized to build a
pipe string, tubular, tubulars, tubular string, oil country tubulars, or the
like.
[00106] 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 croVa 190. The top drive allows rotation of the tubing,
which results in significant
17
=
CA 02877530 2016-08-04
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.
[00107] 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 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
arm. 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 grbund 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
18
CA 02877530 2016-08-04
=
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,
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
19
CA 02877530 2016-08-04
supported on beam runner 124 and may be transported on carrier 600 or provided
separately with other
trucks.
[00111] 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 arc 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 as desired
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.
[00112] 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 tile 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 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
=
CA 02877530 2016-08-04
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.
[00113] In one possible embodiment, inner portion 406 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.
[00114] 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 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 10 snubbing jacks.
CA 02877530 2016-08-04
[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. 4
A-A illustrates a downward view of the mast assembly 100. The mast assembly
100 shows the top
drive assembly or fixture 150 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 (also shown in
Fig. 4) 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
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 463, which may comprise a threaded connector arid/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 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
22
CA 02877530 2016-08-04
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. 5 A 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 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 clrawworks
assembly 620 on the carrier
deck 602.
[00120] FIG. 6 A 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
with respect to one possible embodiment of the present invention. FIG. 6 A
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
23
CA 02877530 2016-08-04
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 thc 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 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. 11 A), 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 he 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. 11 A), Christmas tree, well head, and/or other
pressure control equipment.
However, the mast construction is not intended to be limited to this
arrangement.
[00122] 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
24
CA 02877530 2016-08-04
130 is sufficiently tall to allow BOP stacks to fit within opening or space
136. However, Y- base 130
is replaceable and maybe 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 kickout arm 360 in association
therewith. As such, when
the pivotal pipe arm 320 pivots into the position shown in FIG. 7 (e.g., using
the hydraulic cylinder
304), the pivotal pipe arm 320 is not parallel with the mast assembly 100,
thus a joint of pipe engaged
with the pivotal 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.
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[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 arm 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. 7 A- 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 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.
[00128] FIG. 7A-A is a rear elevational view of 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
26
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=
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.
[00129] FIG. 7B is a perspective view of the portion of the mast assembly 100
and pivotal pipe arm
320, with clamps (370B) for engaging pipe, engaged with upper fixture 135 as
illustrated in FIG. 7 A-
A of the long lateral completion system 10 with respect to one possible
embodiment of the present
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, the pipe are
positioned 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
27
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CA 02877530 2016-08-04
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 of the mast assembly 100 and top
drive 150 of the long
lateral completion system 10 shown in Fig. 8, 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.
[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, 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 systein
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
=
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CA 02877530 2016-08-04
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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.
=
[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 kickout 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.
[00138] FIG. 9B-B is a.perspective view of the upper portion of the mast
assembly 100 as illustrated
in FIG. 9 A-A, showing the top drive 150 and the upper mast fixture 135 of the
long lateral completion
29
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CA 02877530 2016-08-04
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.
[00139] 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 I30P, 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.
[00140] Specifically, the blowout preventer 900 is shown having a first set of
rams 1012 positioned
beneath a second set of rams 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 increased 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
CA 02877530 2016-08-04
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 1020 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 assemblies 1020,
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 assemblies 1020,
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 of extremely
volatile circumstances, the
upper and lower ram assemblies 1020, 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,
1020 and annular blowout preventer 1022) 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 ram assemblies
1020, 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.
[00141] 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.
31
CA 02877530 2016-08-04
[00142] FIG. 9C-C also shows a first hydraulic jack 1024A positioned at the
lower end of the Y- base
132, on a first side of the rig, and a second hydraulic jack 1024B 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 1024 A, 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 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 telescopically 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 slidingly 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
32
CA 02877530 2016-08-04
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 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).
[00145]FIG. 11 A, FIG. 11B, FIG. 11C, and FIG. 11D illustrate one possible
embodiment for a
compact snubbing unit SOO, 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 string 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 swarming). Once the pipe is heavier
than the force of the
well, then the normally 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
33
CA 02877530 2016-08-04
recessed region of the mast assembly 100, to prevent undesired 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 utilized 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 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
34
CA 02877530 2016-08-04
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.
[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. 12C), 744 (shown in Fig. 12 D) 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.
CA 02877530 2016-08-04
[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. For
loading applied at the bottom, the equation would be F = (W+Wa)/2Tan<D. 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 thc 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)/Tan< . 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.
36
CA 02877530 2016-08-04
[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
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 carrier 600 rearmost
position by mast support
plate 363 (also shown in Fig. 4 as feature (636)).
[00155] 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 kickout arm 360 attached thereto. The kickout arm 360 can
subsequently be extended the
central pipe arm 320 using additional hydraulic cylinders disposed
therebetween.
[00156] 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.
[00157] 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
37
CA 02877530 2016-08-04
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.
[00158] 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, 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
group 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.
[00159] In another emb.odiment, 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.
[00160] 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
38
= CA 02877530 2016-08-04
pipe is removed from the well. In one embodiment, one 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 arm assembly 300
of the completion
system 10 of one possible embodiment of the present invention. The catwalk -
pipe arm assembly 300
comprises the central arm 320, a kickout arm 360 and onc 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. 15 A) are
affixed, pivots about lower
pipe arm pivot connection 313.
[00165] 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 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.
39
CA 02877530 2016-08-04
[00166] 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 "P."
[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 326 A 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 arm 320 in a
desired direction when the
pipe is laid down adjacent catwalk 302, as discussed hereinafter.
[00170] FIG. 16B 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
CA 02877530 2016-08-04
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.
[00171] 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
arm 320 in association with an upper portion of kickout arm 360 (when
vertically raised) and the
clamp 370B.
[00172] FIG. 16D is an end view of the pivotal pipe arm 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.
[00173] FIG. 17 is a perspective view of a portion of the kickout arm 360 of
the completion system 10
of in accord with one possible embodiment of the present invention. The
kickout arm 360 is illustrated
with the components attached to a 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. 18 A) 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 374 A and 374B. The eject arms 374
A 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
41
CA 02877530 2016-08-04
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.
[00174] 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) arc between
the plates 376 and
provides 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 384 A and 384B,
respectively, which are.fastened to respective torsional ejection rods 372A
and 372B for 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 370 A and 370B for support at the ends thereof.
[00175] 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 392 A and 392B, perhaps best shown in FIG. 18 A.
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 21 A) 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
42
CA 02877530 2016-08-04
and upper pipe clamps 370A and 370B, pipe ejector direction control 371, the
base 375 with torsional
ejection rod 372A (shown in Fig. 18B), 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 370 A and 370B as well as to pipe
ejector direction control 371
. The clamps 370A and 370B are dispersed at the remote ends of the kickout arm
360. There may be
fewer or more clamps, as desired.
[00179] FIG. 18C is a lop view of the kickout arm 360 of the completion system
10 of the present
invention. The kickout arm 360 is illustrated with the clamps 370 A and 370B
secured with the base
375 and operatively associated with the torsional ejection rods 372A and 372B.
[00180] FIG. 18B-B is a sectional view 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 arm 320.
[00181] FIG. 18C-C is a cross section of FIG. 18C illustrating pipe ejector
direction control 371. The
ejector mechanism 380A and 380B 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.
[00182] 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.
43
CA 02877530 2016-08-04
[00183] FIG. 19B is a .side view of the top drive fixture 151 and frame 154 of
the traveling block
assembly 153 illustrated in FIG. 19 A. FIG. 19B illustrates the guide frame
152B in relation to the
traveling block frame 154B using the block side plate 156B.
[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 158 A, 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.
[00186] 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 19 A, 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 145 spans side plates 156A, 156B above traveling block sheaves 155 A,
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.
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, 146D 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 147 A, 147B, 147C and 147D is parallel to the plane of the axis of
the front sheaves of the
crown block assembly. .Traveling block sheaves 155 A, 155B, 155C, 155D rotate
in traveling block
frame respectively on axles 147A, 147B, 147C and 147D.
[00187] 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
44
CA 02877530 2016-08-04
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.
[00188] 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.
[00189] 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.
[00190] 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 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 drawworks 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.
= CA 02877530 2016-08-04
[00191] 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 155 A,
155D (in the illustrated embodiment there are two traveling block sheaves,
155B, 155C inboard of
outermost traveling block sheaves 155 A, 155D. Traveling block sheaves 155 A,
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 apgled 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.
[00192] Accordingly, first outermost traveling block sheave 155 A receives the
drilling line 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 155 A 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, 20 A 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.
46
CA 02877530 2016-08-04
[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. 21 A 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
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 370 A 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 394 A and
394B.
[00197] 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
47
CA 02877530 2016-08-04
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 391 A and 391B to engage
pipe "P".
[00198] FIG. 22 A 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 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 316 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
barrier 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 barrier 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
48
CA 02877530 2016-08-04
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 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 394 A and 394B to engage pipe "P".
[00201] 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.
[00202] 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,
then another pipe drops into pipe receptacle 424. In this embodiment, pipe
feed receptacle 424 is
= 49
CA 02877530 2016-08-04
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 arm 320 with kickout arm 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.
[00203] 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.
[00204] 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.
[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
CA 02877530 2016-08-04
430 and support base 440 while in this position. Pivotal rungs may be
removable or pivotal to open for
filling the pipe tub more quickly.
[00206] FIG. 23 E 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
387 A, 389 A and/or 387 A, 389 A to clamp the pipes. During this time, the
length and other factors of
the pipe is sensed or read by RFID tags. Pivotal pipe arm 320 is then rotated
upwardly to the desired
position (which may bc determined by sensors and/or an upper mast fixture 315.
Kickout arm 360
Pivots outwardly to orient the pipe vertically.
[00208] 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
51
CA 02877530 2016-08-04
breaking the connection of this pipe and may utilize reverse rotation of the
top drive to undo the
connection. Using drawworks 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, kickout
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 simply comprise racks, checking mud measurements, checking
engines, and the like
as is well known.
[00210] 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.
[00211] 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.
[00212] 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.
[00213] 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
52
= CA 02877530 2016-08-04
1008. While Figures 24A and 24B 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.
[00214] 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 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.
[00215] 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. For example, Figure
25 A 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.
[00216] 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.
53
CA 02877530 2016-08-04
[00217] 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 1108 A, 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
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 frustroconical 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 25 A and 25B depict the upper member H02 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
frustoconical 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
54
CA 02877530 2016-08-04
the guide apparatus 1100. Likewise, rotational movement of the top drive
(e.g., to make or unmake a
threaded connection in a pipe 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
engaged with a portion of the top drive directly.
[00221] 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 152 A 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 grooves 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.
[00223] Turning 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 193 A, 193B, 193C, 193D have an
axis of rotation X
upon which the sheave clusters 193A, 193B, 193C, and 193D rotates. Traveling
sheave block
assembly 153 has sheaves 146A, 146B, 146C, 146D which are fastened to said
guide frame 152 of top
CA 02877530 2016-08-04
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, and 193D
rotates. 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 cluster 193 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.
[00224] Generally, sheave wheels have a minimxim 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.
[00225] 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
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.
[00226] 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 the 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.
56
CA 02877530 2016-08-04
[00227] 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.
[00228] 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 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 kickarm 360 to pivot away from pipe arm 320 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 he less than 10
feet apart in certain
embodiments.
[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.
57
