Note: Descriptions are shown in the official language in which they were submitted.
CABLE COMPATIBLE RIG-LESS OPERABLE ANNULI ENGAGABLE SYSTEM
FOR USING AND ABANDONING A SUBTERRANEAN WELL
SPECIFICATION
FIELD
[0001] The present invention relates, generally, to cable conveyable and rig-
less operable
systems and methods that can be usable to install well barrier element
isolations for
delaying or performing subterranean well abandonment operations, on at least a
portion of a substantially water or substantially hydrocarbon well.
BACKGROUND
[0002] Constructing a subterranean well for producing substantially water,
e.g. from
solution mined or water cut hydrocarbon wells, or for producing substantially
hydrocarbons, requires capital investment with an expectation of a return on
capital
repaid over the life of the well, followed by the permanent abandonment of all
or part
of the well to delay further cost, once storage or producing zones have
reached the
end of their economic life or the well's structural integrity becomes an
issue. For the
hydrocarbon extraction industry, the producing life of a well is, typically,
designed for
to 20 years of production. However, conventional practice is primarily to
extend
well life as long as possible, even after exceeding its original design life,
and, despite
any marginal economic losses incurred, to push the cost of final abandonment
into the
future. For the underground storage industry, wells may be designed for a 50
year life
span, but over time storage wells may also encounter integrity issues that
require
intervention, maintenance or abandonment.
[0003] Embodiments of the present invention are usable to delay abandonment by
placing well barrier element members to intervene in or maintain a well's
structural
integrity to allow additional marginal production or storage operations until
final
cessation of production or storage operations. Embodiments are further usable
to
permanently abandon all or part of produced subterranean or underground
storage
wells.
[0004] As the cost of placing acceptable abandonment barriers to permanently
isolate
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subterranean pressurized liquids and gases comprises an investment without a
return
on capital, the financially minded are continually seeking to reduce the net
present
cost of abandonment by either delaying it through marginal production
enhancement
or by minimising expenses associated with abandoning the lower portion of a
well,
sometimes referred to as suspension until final abandonment of a well.
[0005] Embodiments of the present invention are usable with rig-less
intervention
operations to minimize the cost of marginal production enhancement and the
abandonment of a portion of a well to suspend the well until a final
abandonment
campaign is used to further minimize costs, potentially using rig-less
embodiments.
[0006] The present invention relates, generally, to rig-less systems and
methods usable to
install well barrier element isolations to delay or perform subterranean well
abandonment operations on at least a portion of a substantially water or
substantially
hydrocarbon well. This allows and/or provides for the production or storage
from a
different portion of the well until the well has reached the end of its life
and is ready
for final rig-less abandonment, by using the installed conduits that are
engaged to the
wellhead, to place apparatuses or settable fluid mixtures at selected depths
to isolate at
least a portion of the well using rig-less operable annulus engagable members
and
methods of the present invention.
[0007] Various embodiments of the present invention may include the use of, or
be
usable with, other inventions of the present inventor, including the
inventions
disclosed in the United Kingdom Patent GB2471760B, entitled "Apparatus And
Methods For Sealing Subterranean Borehole And Performing Other Cable Downhole
Rotary Operations" published 1 February 2012; United States Patent Application
Serial Number 12/803,775, entitled "Through Tubing Cable Rotary System" filed
on
July 6, 2010 and published under US2011/0000668 Al on January 6th, 2011; PCT
Patent Application Serial Number GB2010/051108, entitled "Apparatus And
Methods
For Sealing Subterranean Borehole And Performing Other Cable Downhole Rotary
Operations" filed July 5, 2010 and published under W0201 1/004183A2 on January
31, 2011; and PCT Patent Application Serial Number PCT/US2011/000377, entitled
"Manifold String For Selectively Controlling Flowing Fluid Streams Of Varying
Velocities In Wells From A Single Main Bore" filed March 1, 2011 and published
under W02011/119198 Al on September 29, 2011.
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100081 The present invention significantly improves upon prior art with
methods and
apparatus embodiments for forming and using four (4) dimensional geologic time
well barrier elements necessary for the practice of cap rock restoration,
wherein the
provision of a operable space for logging the cement bonding of a three (3)
dimensional space prior to placing and supporting at least one cement
equivalent
barrier member within said operable space, using at least one annulus
engagable
member to access at least one annulus from an innermost passageway, by
displacing
at least one portion of a wall of at least one conduit surrounding the
innermost
passageway to provide said operable space, bridge across said operable space,
and
place said at least one cement equivalent well barrier member through said
operable
space to form at least one geologic time-frame space, which can be usable to
fluidly
isolate at least one portion of a subterranean well without removing installed
conduits
and associated debris from below one or more subterranean depths, to provide
or
enable cap rock restoration above a producible zone.
100091 For example, Patent GB2471760B of the present inventor is usable to
form a four
(4) dimensional space when the elements of a geologic time frame space happen
to be
present, for example, when an immovable production packer does not block an
annular passageway. The present invention provides significant improvements by
providing the elements of a geologic time frame in instances where said
elements may
otherwise be unachievable without the use of a drilling rig. The present
invention's
methods and apparatuses are usable to, for example, place and/or jar cement
equivalent sealing material about the annulus blockage, such as a production
packer,
to increase the probability of successfully forming a geologic fourth
dimensional
space at the specific depth defined by the cap rock, which previously
contained a
producible zone before it was penetrated by the well. Consequently, the
spectrum of
wells available for rig-less abandonment increases significantly by enabling
or
providing for the re-sealing of said cap rock at said specific depth according
to
conventional industry practices for sealing a well over the fourth dimension
of
geologic time.
[00010] Similarly, the present invention provides significant improvements
upon prior art,
for example W02004/016901 Al entitled "Well Abandonment Apparatus," which is
silent to industry cap rock replacement practice and lower cost rig-less cable
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conveyable practices, and teaches the use of higher cost drillpipe and coiled
tubing
conveyance and circulation methods, using electrical and hydraulic umbilical
lines for
power and control. In contrast, the present invention can use the circulatable
fluid
column, within the plurality of passageways formed by in-place tubing and
casing, to
operate an annulus engagable member and form and/or use a four (4) dimensional
operable space, which can be consistent with the practice of cap rock
restoration at the
geologic dictated depth necessary for providing or enabling said cap rock
restoration
over a geologic time frame.
I00011]The present invention provides a rig-less well annuli access and
abandonment
system of methods and members usable to solve the complex set of problems that
have forced industry to use expensive, over-specified, drilling rigs and/or
deployed
pipe circulation to meet minimum published well suspension, sidetracking and
abandonment best practice and standards. Conventional rig-less technology
generally
uses, for example (e.g.), perforating guns, abrasive cutters and severing
explosives to
crudely engage annuli or complex and relatively large and still expensive rig-
less
coiled tubing or pipe handling arrangements unsuitable for instances
constrained by
minimum space and infrastructure, such as normally unmanned minimum remote
onshore wells and offshore facilities.
[000121The present invention provides cable compatible embodiments, usable
with slick
line and braided coiled wire strings to provide selectively controllable
access to all
well annuli to: i) adequately clean the annuli to provide a wettable surface
for proper
bonding of cement and other suitable permanent well barrier elements, ii)
provide
logging access to confirm the presence of primary cement behind well casings,
iii)
provide stand-off between well conduits to ensure that conduits are embedded
in
cement and/or have cement inside and outside of the metal conduits to prevent
corrosion, iv) remove potential leak paths such as control lines and cables
from
annuli, and vi) place well barrier elements across from strong impermeable
formations
to meet published industry best practices for permanent abandonment, where no
comprehensive conventional rig-less abandonment system is available for
minimum
facilities with limited space and resources, e.g. power, and larger facilities
where the
cost of numerous complex system rig-ups and rig-downs over a plurality of
wells is
cost prohibitive.
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[00013]The methods and systems of the present invention are usable in various
combinations to provide, in whole, a rig-less well suspension, side-tracking
and
abandonment system to meet industry best practices described in various
publications,
including NORSOK D-010 revision 3, August 2004, which define the requirements
of
conventional well barrier elements used to form a plurality of pressure
bearing
envelops that resist subterranean pressurized liquids and gasses.
[00014] The methods and apparatus of the present invention differ from the
conventional
hydrocarbon and storage industry practices and apparatuses, which are designed
for a
significant life cycle, because the present embodiments are usable with a more
economic means of placing a permanent well barrier element. For example, where
a
conventional tubing patch is designed to repair breached tubing for a
significant
period of production, various embodiments of the present invention are usable
to
provide temporary and/or partial fluid pressure circulating capabilities to
place a
permanent cement plug, because the extra expenditure to repair the breached
tubing is
unnecessary, given that the well is being abandoned. Furthermore, the present
invention is usable to increase the number of wells, where lower cost rig-less
slickline
operations are usable to place permanent well barrier elements, like cement,
as
opposed to the conventional practice of using an extremely expensive and over
specified drilling rig to perform work on an asset that has no further value.
[00015] The present invention can be usable with rigs or conventional rig-less
arrangements, such as those described in U.S. Patent 7921918B2, published the
12th
of April 2011. However, the present invention can be further usable to
minimize the
required operational footprint and resources, because the systems and
apparatus of the
present invention may be used with, but do not require, pipe handling
arrangements
and are operable with tension of a coiled wireline or coiled tubing string and
pumping
arrangements, or optionally, with electric line, through the wellhead using
the well's
circulatable fluid column.
[00016] Various methods and fluid and apparatus member embodiments of the
present
invention's rig-less suspension, sidetracking and abandonment systems can be
combinable with conventional rig-less operable methods and apparatuses when
placing well barrier elements and forming branching passageways, from the
innermost passageway, to be used for accessing annuli and producible zones of
a well
CA 2841144 2019-02-12
and/or forming new well barrier elements, which can be rig-lessly placeable
with
jointed conduits, coiled strings and/or a well's circulatable fluid column.
[00017]Pumpable members of the systems of the present invention represent
significant
improvement over the teachings of EP0933414A1, published 4 August 1999, and
GB2429725A, published 7 March 2007 which describe swellable gravel packs; US
2003/0144374A1, published 31 July 2003, and EP1614669A1, published 29 June
2005, which describe organophillic clay and cement mixtures. Where
conventional
practice focuses on water production isolation, with swellable and reservoir
isolation
with clay and cement, the present invention provides methods for mixing
gradated
hard particles that can be combinable with swellable particles and clay based
cement
to form an annuli bridging matrix or pseudo packer within well annuli, forming
well
barriers and/or supporting placement of a permanent barrier, e.g., neat
cement. The
present invention further improves conventional or existing practices for rig-
less
abandonment by incorporating reagent mixing methods from the drilling
industry,
commonly referred to as gunk, usable to temporarily seal leaks downhole. The
present invention's combination of gradated hard and swellable particles mixed
with
organophillic clay, oils and cement provide a means for isolating well annuli
during
rig-less operations and providing permanent barriers within selected portions
of a
well.
[0001810ther existing methods and systems, for example, EP0933414A1 and
GB2429725A describe swellable particle packs used in water shut-off and gravel
packs, while US 2003/0144374A1 and EP1614669A1 describe an organophillic clay
cement mixture usable for sealing producible hydrocarbon formations,
historically
comparable to drilling practitioner's use of "gunk" for closing fractured
formations
during drilling operations. Conventional packing methods are silent as to the
present
embodiments comprising hard gradated particles mixed with gradated swellable
particles and clay mixtures to form a fluid deployable hard pressure bearing
matrix or
pseudo packer within an annulus, as specified within the present invention.
Thus, the
present invention provides significant improvement and benefit to rig-less
intervention and abandonment practitioners, with the use of theological
controllable
fluid members comprising, for example, hard size specific particles mixed with
size
specific gradated, swellable, particle packing mixes, wherein the pore spaces
are filled
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with a clay-based gunk or clay-based cement to form a pressure-bearing matrix.
The
pressure bearing capacity of theological controllable fluids of the present
invention
are further increasable with hydraulic packing methods and members, usable
with
intermixable gelatinous gunk or cement pumpable gradated swellable particle
mixes,
to form stress and pressure bearing matrices with the swellable particles, and
harder
intermediate gradations of particle sizes mixed with the low gravity solids
and particle
sizes of a clay-based gunk or cement to seal the pores spaces between the
packed
particles and a wall of a well, e.g. a conduit, permeable conduit and/or
strata wall,
such that a pseudo packer may be formed in annuli of a well for well
abandonment,
suspension and side tracking purposes. This pseudo packer is compatible with
the
setting nature of cement or oil-based gunk to provide support for sealing
materials,
forming an indefinite pressure bearing bridging of, e.g., cement across the
walls and
circumference of well annuli during the rig-less abandonment and/or temporary
suspension of subterranean wells. Additionally, the present invention
represents a
significant improvement over conventional clay cement mixes, with method
embodiments for segregating deployment of reagents of chemically reactive
fluid
mixes to control mixing and chemical gelling, at the point where a well
barrier
element is needed, wherein further chemical reaction of swellable material to,
e.g.,
hydrocarbons or water is also possible at said point.
[000191Boring and expandable conduit placement of the present invention
represents
significant improvement over such teachings as those disclosed in U.S. Patent
Application 2005/0252688, published Nov. 17, 2005, and U.S. Patent Application
2004/0069487A1, published 15 April 2004, which describe micro bore drilling
and
logging; and WO 2009/152532A1, published 17 December 2009, which describes
drilling a hole in a conduit and placing a sealable material within an
annulus. The
present invention improves upon such conventional practice by providing a
plurality
of sizes and placement means through which well barrier elements and logging
tools
may be placed to confirm primary cementation behind casing to meet published
minimum industry requirements, whereas similar conventional coiled wire string
compatible methods or apparatuses are not available for the economic
abandonment
of a well.
[00020]Axial screw and/or tractor embodiments of the present invention provide
more
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robust combinable pipe destruction and conveyance means for shredding and
milling
of well conduits, which do not require computer control as described in the
teachings
of U.S. Patent 6,868,906B1, published 22 March 2005. With regard to complex
computer systems, Greenfield hydrocarbon production has significant value, and
the
associated economics of using computer controlled systems is significant
during
construction of a well; however, abandoned wells have no future value with
well
conduits of no further use after deconstruction of a well, generally termed as
abandonment. Hence, the economics of abandonment are significantly different
and
require different tooling. The present invention provides significant
improvements in
the field of low cost rig-less intervention by providing a system of methods
and
apparatus to meet the lower cost needs of rig-less abandonment, which can be
usable
for suspension and side-tracking of marginal producible zones of a well that
may not
have warranted completion during initial well construction and/or do not
warrant the
use of a drilling rig or expensive computer operated systems, but are usable
to provide
marginal revenue to offset the cost of delaying final abandonment.
[00021]U.S. Patent Application 2005/0252688 describes methods for single micro-
bores
through strata immediately adjacent to cemented casings to place expandable
sand
screens for a producible formation. However, this reference is silent to, and
is
unsuitable for, simultaneously placing a plurality of bores and/or selectively
accessing
said bores with subsequent tools, such as conventional logging tools. Further,
this
conventional method does not teach the placing of integral passageways through
annuli, as described by the present invention. While U.S. Patent Application
2004/0069487 Al describes methods for providing strata measurements and fluid
traces within a micro bore, it does not teach the provision of sufficient
diameter,
angular offset or selective bore hole re-entry. Further, the invention taught
in
W02009/152532A1 is usable to make holes or cuts within an innermost conduit to
access a single annulus and place a well barrier element settable material in
the
annulus; however, this reference does not teach, nor is it usable to, access a
plurality
of annuli and/or placement of measurement devices needed for cap rock
restoration
using well barrier element members, such as settable sealing materials. Also,
W02009/152532A1 does not teach the provision of a conduit for production or
storage from a different part of the well to delay final abandonment with
marginal
production. Conversely, the present invention teaches a plurality of bores and
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expandable conduits that are not restricted to micro-boreholes and are usable
for fluid
communication, placement of conventional logging apparatuses and other
devices,
prior to placing cement according the published industry guidelines. Thus, the
present
invention provides significant improvements over conventional technology by
allowing for more and larger bore holes and conduit sizes through the
innermost bore
of a well. This then allows well operators to selectively guide, for example,
electric
motors and higher torque coiled string fluid motors to selectively place
larger boring
bits and selectively access a plurality of larger bit-carried-expandable-
conduits, usable
with higher flow rates, to fluidly communicate through annuli, which are
isolatable
from the carried expandable conduit passageway to, e.g., access producible
zones,
place devices, well barrier elements and/or rheological controllable fluid
members.
[000221The low torque centrifugally deployed disposable coiled cable string
compatible
milling embodiments of the present invention represent significant improvement
over
the existing technology, such as those of U.S. Patent 5101895A1, published 7
April
1997, and W02009/152532A1, published 17 December 2009. The present invention
provides a significant improvement for rig-less, low-cost milling with
balanced ball
joint mills deployable with centrifugal forces of rotation and arranges so as
to reduce
torque and be disposable downhole if the mill becomes stuck during use.
[00023]One of the primary objectives of rig-less abandonment of any portion of
a well is
its destruction at the lowest possible cost, wherein the present invention is
comprised
of low cost, simple and robust methods and members that can be more akin to
using a
sledge hammer than using the conventional computer controlled teachings of
U.S.
Patent 6,868,906 B1, involving complex computer controlled tractor conveyance
of
drilling assemblies for well services and deployable on wireline or
umbilicals, only.
The operational benefits of the present invention are numerous and
significant,
needing only fluid circulation, an electricity supply and/or line tension for
operation,
versus complex operations requiring computer control, wherein the simple
operations
of the present invention are generally easier to support and less expensive.
Additionally, if an assembly becomes stuck downhole, the value of retrieving
the
complex closed loop system operated apparatuses and tractors are significant,
given
the construction cost of complex apparatuses, thus limiting their utility for
risk of loss
within operations like abandonment where the well is a liability without
future value.
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Methods and members of the present invention are rig-lessly operable, with
cable
tension and the pressures of a circulated fluid column to drive a fluid motor
or an
electrical conductor to operate an electrical motor and/or disposable tractor,
using the
low cost disposable motor's reactive torque to drive the pushing or pulling of
various
disposable rotating or non-rotating apparatuses to penetrate walls within a
well that is
incapable of providing future return on investment. The hazards of destructing
said
well, e.g. the violent jarring, milling, shredding and tractor cutting wheel
destruction
of steel conduits, by crushing, cutting and rotating equipment suspended from
a non-
rotatable cable, represents a significant risk of becoming stuck downhole
and/or
breaking the cable. The present invention provides significant benefit over
more
complex systems, e.g. U.S. Patent 6,868,906B1, U.S. Patent Application
2005/0252688, U.S. Patent Application 2004/0069487A1 and W02009/152532A1,
because it requires a less complex system designed for operating under the
high
tension load of, e.g., a capstan cable pulling unit, wherein members may be
disposed
of downhole, if necessary, to avoid the more costly operation of more complex
systems, with an intrinsic re-usable value justifying said complex system's
retrieval.
[00024JAdditionally, conventional devices, such as those described in WO
2009/152532
Al, are generally unsuited for use with cable operations because erratic
rotation of its
unbalanced milling arm will occur when the conduits being milled shift, thus
placing
unacceptable tensional loads on a high-torque downhole motor, potentially
causing
damage or sticking and slipping issues for its milling assembly, which are
generally
unsuitable for cable operations where low torque and balanced rotation are
required to
prevent fouling of the cable. While U.S. Patent 5101895A1 provides a balanced
cutting and/or milling blade arrangement, the milling blades are driven by
supplied
torque and constrained within a rigid deployment arrangement that does not
automatically adjust to balance rotation, limit torque and prevent vibration,
that is
unacceptable for a cable deployed milling tool. Conversely, rotary cable tool
milling
embodiments of the present invention comprise balanced deployment mills that
intrinsically adjust to conduit eccentricity with ball joints and rotating
cutting
structures, which are suitable for lower torque motors on coiled string
applications to
prevent erratic rotation with the centrifugal forces of rotation adjusting
deployment of
the mills if conduits shift.
CA 2841144 2019-02-12
[000251The present invention provides significant improvements over the
teachings of
U.S. Patent 5,957,195, published 28 September 1999 describing an expandable
tubing
patch usable to repair a leak in production tubing. The present invention
provides a
swellable, expandable mesh-membrane fluid conduit that can be usable to place
cement and/or rheological controllable fluid members in any annulus and/or to
choke
fluid communication between the innermost passageway and one or more of the
annuli. Thus, the present invention provides a significant improvement over
conventional expanded tubing patches in the field of rig-less abandonment, due
to the
high probability that the condition of the tubing that caused the first breach
is the
result of age, corrosion and/or wear that will lead to further breaches or
tubing
collapse, which cannot be repaired with a single patch. In contrast, the
present
invention can include the ability for burst or collapse prevention as well as
an ability
to repair the tubing, due to the permeability of the mesh, which can provide
pressure
relief to prevent burst or collapse of the tubing, while placing and allowing
a cement
to harden, and whereby the mesh can allow removal of free water associated
with
cement setting, unlike a solid conventional tubing patch. Furthermore, an
expanded
mesh conduit can be placed through annuli of a well, and is usable to urge
heavier
viscous fluids, e.g. cement, through or about the mesh conduit, wherein the
pore
spaces of the mesh can provide a natural pressure relief system, which may
allow
limited leakage to prevent burst or collapse of a fluid conduit when fluids of
differing
densities exist inside and outside the conduit, unlike conventional expandable
solid
tubing technology. Additionally, the present invention represents a
significant
improvement over conventional expandable sand screens that are designed for
preventing sand production, by introducing swellable sleeves or gradated
packable
and swellable particles to an expandable mesh screen conduit, which provide
the
benefits of pressure relief to prevent conduit collapse while urging a
majority of fluids
communicated through the conduit to a selected location.
[00026] Various method and apparatus embodiments of the present invention's
system of
members are usable to form an enlarged passageway, including the milling and
shredding of well conduits and equipment and/or compression or compaction of
installed well conduits and equipment to, e.g., further form or enlarge
passageways
for placement of a permanent well barrier element. Other various embodiments
comprise small drilling and casing assemblies, usable to place small diameter
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boreholes and/or expandable casings, expandable seals or swellable materials
within
bores and annuli of a well, to form pressure bearing passageways usable to
place, e.g.,
logging equipment to determine any necessary remedial action within a bore or
annuli
of a well. The present invention is therefore usable for marginal production
enhancement or underground storage well integrity repairs to provide further
revenue
and to reduce overall net present cost of well abandonment by delaying it,
wherein the
present invention is also usable for final abandonment of the subterranean
portions of
a well.
100027] Well abandonment represents actions taken to ensure the permanent
isolation of
subterranean pressurized fluids from surface and/or other lower pressured
exposed
permeable zones, e.g. water tables, for various portions of a well where re-
entry is not
required, and wherein the portions, being selectively used and/or abandoned,
require
permanent fluid isolation, at depths specified by pressures within the strata,
and the
pressure bearing ability of the overlying strata to isolate lower strata fluid
pressures
from the surface or other upper permeable zones. Subterranean pressurized
permeable zones comprising strata formations accessed by a well having a
possibility
of fluid movement when a pressure differential exists, generally, must be
isolated to
prevent pollution of other subterranean horizons, such as water tables, or
surface and
ocean environments.
1000281 Various embodiments of the present invention are usable within a
pressure
controlled working envelope, using coiled strings, lubricators, grease heads
or other
conventional pressure control equipment, engaged to the upper end of a
wellhead and
valve tree to intervene within the passageways and annuli of a subterranean
well
extending downward from the wellhead to permanently isolate subterranean
pressurized fluids accessed by the passageways without the risk and cost of
placing
dense kill weight fluids in the well and breaking through surface pressure
barriers,
thus exposing personnel and the environment to a higher potential for
uncontrolled
fluid flow if the dense fluid column killing subterranean pressures is lost.
[00029]Performing well intervention and abandonment operations within a
pressure
contained environment is required for rig-less operations in a subsea
environment
where risers and lubricators must be engaged to the upper end of a subsea
valve tree
to remove plugs, for accessing the innermost well bore. However, access to
annuli
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within a subsea well is limited, with most wells opening the innermost annulus
to the
production stream during initial thermal expansion after which subsea annuli
are
closed. Many subsea configurations also provide fluid access to the innermost
annulus through a manifold placed on the subsea valve tree, which may also be
engaged with the supporting conduit pipelines, such as a methanol line. The
present
invention is usable from a boat and lubricator arrangements, within a pressure
controlled environment, e.g. a subsea lubricator and BOP, to rig-lessly access
and
abandon a well without a he need for a riser from mudline to or above sea-
level.
1000301 Permanent abandonment, generally, is considered to be the placement of
a series
of permanent barriers, often referred to as plugging and abandoning, in all or
part of a
well with the intention of never using or re-entering the abandoned portion.
Permanent well barriers arc, generally, considered well barrier envelopes
comprising
a series of well barrier elements that individually or in combination create
an
encompassing seal, which has the permanent or eternal characteristic of
isolating
deeper subterranean pressures from polluting shallower formations, e.g. ground
water
permeable zones, and/or above ground or ocean environments. Various
publications,
including Oil and Gas UK Issue 9, January 2009 Guidelines for Suspension and
Abandonment of Wells, define conventional best practice for permanent
abandonment
of a well and the associated acceptable well barrier elements used to form a
plurality
of pressure bearing envelops, resisting subterranean pressurized liquids and
gasses
over geologic time.
[000311Presently, there are no existing comprehensive systems for abandoning
wells,
other than the use of an over-specified and expensive drilling rig. The
present
invention provides an important and significant solution by specifying methods
and
apparatuses to rig-lessly suspend, sidetrack and abandon onshore and offshore,
surface and subsea, substantially hydrocarbon and substantially water wells,
which
also complies with the published conventional best practices for placement of
industry
acceptable permanent abandonment well barrier elements.
[00032]The cost of permanent abandonment can be expressed as a function of the
time
span required and the quantity and type of equipment needed to place permanent
barriers to contain subterranean fluid pressures for an indefinite period of
time. The
cost of abandonment is generally higher when using a drilling specification
rig,
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capable of constructing a well, with large capacity hoisting, pumping and
conduit
handling systems requiring a significant amount of supporting equipment and
personnel to operate. Conversely, the cost of abandonment is generally
significantly
lower when operating what are generally termed as "rig-less" systems, with
significantly less support equipment and personnel operating lower capacity
hoisting,
pumping and conduit handling systems.
[00033]Embodiments of the present invention are generally usable to meet
published
industry minimum requirements and best practices for placement of permanent
barriers using rig-less intervention and abandonment methods.
[000341 Drilling specification rigs are, generally, used to deconstruct a well
by cutting and
hoisting large and/or long strings of conduits from a well and potentially
mill casings
to place unobstructed cement plugs within the bores from which the conduits
were
removed. Conventional hazards exist, particularly when equipment within a well
must be removed to place acceptable eternal barriers, wherein the equipment
may be
coated with low specific activity (LSA) scale or normally occurring
radioactive
material (NORM) deposits, which accumulated over the well's productive life.
The
rig-less abandonment embodiments of the present invention are usable to
protect the
environment and personnel from these hazards, which, if achievable in existing
practices, would add additional costs and/or reduce the efficiency of the
abandonment
practice. The rig-less abandonment embodiments of the present invention
provide
acceptable methods and systems usable to leave the contaminated well equipment
within the strata.
[000351Embodiments of the present invention are usable with installed well
apparatuses
to avoid the need for completion equipment removal and exposure of personnel
and
the environment to various hazardous materials, which may have accumulated on
the
equipment over time.
[00036]In instances where insufficient cement exists behind casing and
production
equipment has been removed, a drilling rig may be conventionally required to
mill the
casing, so as to place a cement plug across the unobstructed strata bore. The
resources and associated costs required for casing milling operations may
often be
equivalent to the original conventional cost of constructing the well.
14
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[000371Various embodiments of the present invention are usable to access
annuli so as to
measure the presence of cement behind casing, or the lack thereof, while other
various
embodiments are usable to shred production conduits and mill casing to provide
an
unobstructed space for placement of cement across a bore.
[00038]Operating a drilling rig requires a significant amount of space
surrounding the
wellhead of the well being constructed or deconstructed for the placement and
operation of large capacity hoisting, pumping and conduit handling systems,
regardless of whether the work occurs onshore or offshore. Drilling rigs are,
generally, the primary controllable expensive driving return on capital and
offshore
drilling specification rigs are, generally, significantly more expensive than
onshore
drilling rigs, because they comprise living habitats capable of supporting a
significant
number of people, often exceeding a hundred persons, within a potentially
hazardous
environment. While the
requirements for coiled tubing well operations are
significantly less than those for a drilling rig, they are considerably
greater than those
of a wireline operation comprising electric line or slickline intervention.
[00039] The present invention is usable to provide smaller rig-less
operational footprints,
similar to electric line and slickline operations, usable, e.g. on small
normally
unmanned platforms, with methods and apparatus requiring a minimum of
resources
and associated space to perform necessary suspension, side-tracking and,
ultimately,
abandonment operations.
1000401Large hoisting capacity rigs usable for the removal of downhole
equipment are
not generally required, provided that annuli can be accessed and permanent
isolations
can be placed within annuli. Generally, rig-less abandonment operations use
through
tubing or through conduit operations to minimise equipment and personnel
requirements, using the installed completion and casing strings to circulate
cement,
and, ultimately, leave equipment downhole.
[00041]Providing annulus control and permanent isolation barriers with rig-
less
operations is challenging with no universally accepted conventional rig-less
means of
both verifying and placing permanent barriers within annuli, as required by
the
published industry best practices, because of the many potential leak paths
that exist
when completion equipment is left within a well, wherein conventional logging
can
CA 2841144 2019-02-12
only occur after the completion equipment has been removed. For example,
leaving
cables and control lines downhole within a cement barrier can represent a
significant
leak path because capillary or frictional forces may prevent viscous cement
from
entering the small diameter of a control line or sheath of a cable.
Additionally, while
records of originally installed primary cementation may exist, over time the
primary
cementation bond may have failed from the pressures and thermal cycling of the
casings during production, and a leak path may exist between casings and the
strata
rendering properly placed conventional rig-less abandonments ineffective.
[00042] Additionally, when well completion tubulars or conduits and completion
equipment are left downhole during through conventional tubing rig-less well
abandonment, leak paths may form around the installed apparatuses if they are
not
offset from other equipment so as to be embedded in, e.g., cement, including
verification of the position and placement of the permanent barriers inside
bores and
annuli of a well to determine if further remedial action is required.
[00043] Various embodiments of the present invention are usable to compress
severed
well equipment within a surrounding bore to remove obstructions and potential
leak
paths while providing space for logging behind casing, to determine whether an
acceptable cement bond exists.
[00044] The main characteristics that a permanent barrier must have to prevent
flow of
pressured fluids through the barrier are: i) long term isolation integrity
that ii) bonds
to completion equipment and iii) does not deteriorate over time or iv) shrink,
thus
allowing flow around the barrier, which must be of a v) ductile or non-brittle
nature to
accommodate mechanical loads and changes in the pressure and temperature
regime,
wherein the ductile or non-brittle material must also vi) resist ingress of
downhole
fluids and/or gases, such as hydrocarbon gas, CO2 and H2S into or through its
mass.
While cement is currently the primary oil and gas industry material used for
permanent well barriers, other suitable materials may also be usable, provided
they
meet these necessary conventional requirements.
[00045] Embodiments of the present invention are usable with cement and other
suitable
rig-lessly deployable permanent abandonment materials, with various
embodiments
usable to clean bores and annuli of hazardous or benign debris that could
potentially
16
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interfere with the placement of permanent impermeable barriers, e.g. cement,
to
further provide wettable surfaces for cement bonding, wherein portions of the
well
may be opened to dispose of hazardous material, such as LSA scale, during
abandonment.
[000461 The most prevalent permanent barrier for well abandonment is a cement
column
of a depth sufficient to ensure good quality and bonding of the cement to
completion
equipment. The surface of the completion equipment must be both wettable and
accessible during cement slurry placement. If equipment, such as completion
equipment or casing, is left within the strata bore, the cement must also be
placed on
both sides, embedding the equipment or casing in bonded cement, since over
time the
metal equipment may corrode if poor cement bonding or the lack of cement
bonding
exposes corrodible equipment to subterranean fluids, subsequently providing a
leak
path. Cemented casing is not considered a permanent barrier to lateral flow,
into or
out of the wellbore, unless the inner and outer diameters of the casing and
contained
conduits are sealed with good quality cement, which is bonded to the casing.
It is
noted that fluids may migrate through poor quality cement or axially along the
casing's inner or outer surface through micro annuli if poor bonding exists,
to
eventually corrode the casing when an incomplete localised cement sheath is
present
in the internal bore or annulus.
L000471 Various other embodiments of the present invention are usable to
provide both
space and offset of eccentric conduits to allow cleaning of downhole
completion
equipment and casings, both fluidly and mechanically, to provide cleaner
spaces and
wettable surfaces and to provide sufficient good quality cement bonding, thus
preventing axial or lateral pressurized fluid flow.
[00048]Because the lifespan of an installed permanent well barrier can be
measured in
geologic time, i.e. over millions of years, and as nature abhors a vacuum,
well barriers
must also be designed to resist the re-pressurization of a depleted reservoir
as it seeks
to return to its original state over time. In many subsurface reservoirs, this
requires
placing barriers at specific depths to replace the original cap rock holding
the
pressurized subterranean fluids, before it was penetrated by a well. The lack
of
foresight in the original well design is often a primary reason for using
drilling
specification rigs to abandon wells, because completion equipment, e.g.
production
17
CA 2841144 2019-02-12
packers, are incorrectly placed for conventional rig-less abandonment and/or
marginal
production enhancement when such packers either fail to isolate or prevent
access to
isolated marginal producible formations.
[00049]Other embodiments of the present invention are usable to access all
surrounding
annuli, replacing and/or bypassing production packer isolation of an annulus,
while
still other embodiments are usable to access isolated marginal producible
formations
or access injectable strata formations for disposal of hazardous materials,
during
suspension and/or side-tracking of a well and placement of annuli isolations
and to
access conduits to delay or perform final abandonment of a well, to
potentially reduce
the net present cost of abandonment.
[00050]Preventing exposure of the environment and personnel to hazardous
materials,
e.g., hydrocarbons from marginal producible formations, brines, H2S occurring
naturally or as a result of water injection, and/or LSA scale or NORM, with a
reasonable probability of success both during well operations and for the
indefinite
period thereafter, requires redundancy, i.e. a plurality of tested barriers
that can be
verified. The integrity of a well is generally measured both during operations
and
abandonment, by the existence of at least two verified barriers.
1000511Various embodiments of the present invention are usable to provide
supported
annuli cement placement for a plurality of annuli barriers that are verifiable
with the
conventional methods of logging and tagging, but which are unavailable to
conventional rig-less applications due to their inability to selectively
access annuli or
conduct pressure testing through the annuli access passageways, wherein the
present
invention is usable to access all annuli to abandon all or part of a
subterranean well.
1000521Well operators face a series of challenges at each stage of a well's
lifecycle as
they seek to balance the need to maximise economic recovery and reduce the net
present value of an abandonment liability to meet their obligations for safe
and
environmentally sensitive operations and abandonment. When wells lose
structural
integrity, which may be defined as an apparent present or probable future loss
of
pressure or fluid bearing capacity and/or general inoperability, all or
portions of a well
may be shut-in for maintenance or suspension until final abandonment or may
require
immediate plugging and abandonment, potentially leaving reserves within the
strata
18
CA 2841144 2019-02-12
that cannot justify the cost of intervention or a new well.
[00053] Some of the more frequently reported structural integrity problems are
a lack of
centralization leading to conduit erosion from thermal cycled movement,
corrosion
within the well conduit system; e.g., from biological organisms or 112S
forming leaks
through or destroying conduits or equipment and/or valve failures associated
with
subsurface safety valves, gas lift valves, annuli valves and other such
equipment.
Other common issues include unexplained annulus pressure, connector failures,
scale,
wear of casings from drilling operations, wellhead growth or shrinkage and
Xmas or
valve tree malfunctions or leaks at surface or subsea. Such issues comprise
areas
where operators are able to, or chose to, test and there are others (such as
the internals
of a conductor) which they cannot, or do not test, and which may represent a
serious
risk to economic viability and the environment. Problems within various
portions of a
well, in particular the annuli, cannot be conventionally accessed without
significant
intervention or breaking of well barriers, e.g., with a drilling rig, and
thus, are a
significant cost and safety risk to operators that are unsuitable for
conventional rig-
less operations mitigation.
[00054]A primary advantage of using drilling specification rigs for well
intervention is
the removal of conduits and access to annuli during well intervention and
abandonment, wherein the ability to access and determine the condition of the
annuli
casing and primary cement behind the production conduit or tubing is used to
make
key decisions regarding the future production and/or abandonment. If well
casings
are corroded or lack an outer cement sheath, remedial action, e.g., casing
milling, may
be undertaken to provide a permanent barrier. Conversely, the problem may be
exacerbated by conventional rig-less well abandonment when blind decisions are
made without cement logging access to annuli and attempts to place cement
fail,
thereby placing another barrier over potentially serious and worsening well
integrity
issues, which can represent a significant future challenge, both technically
and
economically, even for a drilling rig.
[00055] Various embodiments of the present invention are usable to gather
information
that conventional rig-less operations cannot, by providing access and/or space
for both
measurement devices and sealing materials. Once such information is gathered,
still
other embodiments are usable to rig-lessly place barriers, and/or mill or
shred
19
CA 2841144 2019-02-12
conduits and casings to expose and bridge across hard impermeable strata or
cap rock
formations for placement of permanent barriers without imbedded equipment to
ensure structural integrity.
[00056]In general, age is believed to be the primary cause of structural well
integrity
problems. The combination of erosion, corrosion and general fatigue failures
associated with prolonged field life, particularly within wells exceeding
their design
lives, together with the poor design, installation and integrity assurance and
maintenance standards, associated with the aging well stock, is generally
responsible
for increased frequency of problems over time. These problems can be further
exacerbated by, e.g., increasing levels of water cut, production stimulation,
and gas
lift later in field life.
[00057]However, the prevalent conventional consensus is that although age is
undoubtedly a significant issue, if it is managed correctly, it should not be
a cause of
structural integrity problems that may cause premature cessation of
production.
Additionally, fully depleting producing zones through further production prior
to
abandonment provides an environment of subterranean pressure depletion that is
better suited for placing permanent barriers, by lowering the propensity of
lighter
fluids to enter, e.g., cement during placement.
[00058)A need exists for delaying abandonment with low cost rig-less
operations for
placement of well barrier elements to increase the return on invested capital,
for both
substantially hydrocarbon and substantially water wells, through rig-less side-
tracking, for marginal production enhancement, suspending and/or abandoning
portions of a well, to re-establish or prolong well structural integrity for
aging
production and storage well assets; and thus, prevent pollution of
subterranean
horizons, such as water tables or surface and ocean environments.
[00059] A need exists for small operating foot-print rig-less well barrier
element
placement operations that can be usable to control cost and/or perform
operations in a
limited space, e.g. electric line or slickline operations, on normally
unmanned
platforms, from boats over subsea wells or in environmentally sensitive area,
e.g.
permafrost areas, where a hostile environment and environmental impact are
concerns. A related need also exists for working within a closed pressure
controlled
CA 2841144 2019-02-12
envelope to prevent exposing both operating personnel and the environment to
the
risk of losing control of subterranean pressures, particularly if a well
intervention kill
weight fluid column is lost to, e.g., subterranean fractures.
[00060] A need exists for avoiding the high cost of drilling rigs with a rig-
less system
capable of suspending, side-tracking and/or abandoning onshore and offshore,
surface
and subsea, substantially hydrocarbon and substantially water wells using
and/or
complying with the published conventional best practices for placement of
industry
acceptable permanent abandonment well barrier elements.
[000611A need exists for preventing risks and removing the cost of protecting
personnel
and the environment from well equipment contaminated with radioactive
materials
and scale by rig-lessly placing abandonment barriers and leaving equipment
downhole. A further need exists to rig-lessly side-track or fracture portions
of a well
to dispose of hazardous materials resulting from circulation of the wells
fluid column
during suspension, sidetracking and abandonment operations.
100062]A need exists for rig-lessly accessing annuli to measure whether
acceptable
sealing cementation exists behind casing and to rig-lessly mill the casing and
place
cement if acceptable cementation does not exist. A further need exists to
verify the
placement of well barrier elements during rig-less operation to ensure the
successful
settable material bonding and sealing of a well's passageways has occurred or
whether
further remedial work is required.
[00063] A need exists for rig-lessly accessing annuli presently inaccessible
with minimal
foot-print conventional slickline rig-less operations, including bypassing
annulus
blockages, created, e.g., by production packers, during placement of permanent
well
barrier elements within selected portions of a well across from cap rock and
other
impermeable formations needed to isolate subterranean pressures over geologic
time.
[00064]A need exists for a plurality of permanent well barriers that are
verifiable through
selectively accessed annuli passageways with rig-less operations usable with
conventional logging tools to maintain the structural integrity of a well
prior to final
abandonment, which also provide access for placing permanent barriers to
ensure
structural integrity of the strata bore hole thereafter.
21
CA 2841144 2019-02-12
[00065]A need exists for marginal production enhancement usable to offset
operating
costs until final abandonment occurs, including rig-lessly providing well
integrity
while waiting until an abandonment campaign across a plurality of wells can be
used
to further reduce costs.
100066]A need exists to reduce the abandonment liability for operators while
meeting
their obligations of structural well integrity for safe and environmentally
sensitive
well operations, suspension and abandonment in an economic manner that is
consistent with providing more capital for exploration of new reserves to meet
our
world's growing demand for hydrocarbons by minimising the cost of operations,
suspension and abandonment with lower cost rig-less suspension, side-tracking
and
abandonment technologies.
[00067ffinally, verifiable rig-less well abandonments are needed to facilitate
a market
where the reduction of well abandonment liability allows larger operating
overhead
companies to sell marginal well assets to smaller lower overhead operating
companies, i.e. by lowering the risk of a residual abandonment liability, to
prevent
marginal recoverable reserves from being left within the strata because higher
operating overhead requirements made such recoverable reserves uneconomic.
[00068]Various aspects of the present invention address these needs.
SUMMARY
[00069] The present invention relates, generally, to cable conveyable and rig-
less operable
systems and methods that can be usable to install well barrier element
isolations for
delaying or performing subterranean well abandonment operations, on at least a
portion of a substantially water or substantially hydrocarbon well.
[00070] The embodiments of the present invention include rig-less operable
annulus
engagable members and systems, comprising fluids and apparatuses, to
selectively
form new and/or to block existing well passageways for placement of logging
measurement devices and well barrier elements to, in use, access at least a
portion of a
subterranean well's producible zones and annuli, prior to abandoning all of
the well's
plurality of passageways, without using a drilling rig. Rig-less method and
system
embodiments eliminate the need to remove installed conduits, thus allowing
installed
well equipment, and any associated scale or naturally occurring radioactive
material,
22
CA 2841144 2019-02-12
to be left in place while also meeting published industry best practices for
confirming
primary well barrier element integrity through logging with centralized
concentric
conduits and removal of potential leak paths for placement of cements,
polymers, size
graded particles, or any other suitable material that can be usable within the
supported
annular spaces to form permanent well barrier elements and indefinite
abandoned well
integrity.
[00071]The present invention provides systems for annular access, that can be
usable
with rheological controllable fluid members, logging tool members, expandable
members, swellable members, placeable conduit members, motorized members,
boring members, tractor members, conduit shredding members, milling members
and/or rig-less members, which can include cable conveyable and rig-less
string
operable annulus engagable members that are usable to form or place well
barrier
elements for isolating at least a portion of a well. The present invention is
usable to
access annuli and producible zones of a well to perform or delay final well
abandonment by providing further marginal well production enhancement and/or
extending the longevity by rig-lessly placing additional underground well
barrier
elements. Furthermore, the present invention is usable for final rig-less well
abandonment on wells where annuli are conventionally inaccessible, thus saving
the
cost of using a drilling specification rig.
[00072]The present invention provides a lower cost rig-less means of accessing
annuli
and selectively placing pressure bearing conduits and well barrier elements at
required
subterranean depths between annuli when intervening in, maintaining, and/or
abandoning portions of a well to isolate portions affected by erosion and
corrosion,
which, in turn, can extend the well life to fully deplete a reservoir and to
further
reduce the risk associated with well barrier element placement and the
pollution
liability from an improperly abandoned well.
[00073]The level of maintenance, intervention and workover operations
necessary for
well maintenance is restricted by the substantial conventional costs involved.
The
limited production levels of aging assets often cannot justify the
conventional practice
of using higher cost drilling rigs and conventional rig-less technology is
generally
incapable of accessing various passageways or all annuli within the well.
23
CA 2841144 2019-02-12
[00074]Therefore, well operators generally place an emphasis on removing
troublesome
assets from their portfolio and seek to prevent future problems using improved
designs, rather than attempting to remedy a poorly designed well, which in
turn
precipitates a greater focus on asset disposal, well design, installation
and/or integrity
assurance. Passing the problem on to others with the sale of a well does not,
however,
solve the issue of abandoning existing and aging wells from a liability
viewpoint.
[00075]When intervention is required, risk adverse major oil and gas companies
generally prefer asset disposal and replacement rather than remediation,
favouring
sale of aging well assets to smaller companies with lower overheads and higher
risk
tolerances. Smaller companies, requiring a lower profit margin to cover
marginal
cost, are generally eager to acquire such marginal assets, but may in the
future be
unable to afford well abandonment, thus putting the liability back to the
original
owner and preventing sale or creating a false economy for the seller. Low cost
reliable
rig-less placements of well barrier elements to delay or perform abandonment
is
critical to major and small companies, if aging assets are to be bought and
sold and/or
to avoid such false economies. Thus, the rig-less methods and members of the
present
invention, usable to place and verify well barrier elements for reliable
abandonment,
are important to all companies operating, selling and/or buying aging wells.
[00076] Therefore, the structural integrity of producing and abandoning wells
is critical
because the liability of well abandonment cannot be passed on if a well
ultimately
leaks pollutants to surface, water tables or ocean environments, because most
governments hold all previous owners of a well liable for its abandonment and
environmental impacts associated with subsequent pollution. Hence the sale of
a well
liability does not necessarily end the risk when the asset is sold or
abandoned unless
the final abandonment provides permanent structural integrity.
[00077]Embodiments of the present invention are usable with rig-less well
intervention
and maintenance to extend the life of a well by placing well barrier elements
to isolate
or abandon a portion of a well then operating another, until no further
economic
production exists or well integrity prevents further extraction or storage
operations,
after which the well may be completely and permanently abandoned for an
indefinite
time using the present invention capability to rig-lessly selectively access
annuli for
both placement and verification of well barriers.
24
CA 2841144 2019-02-12
[00078]The preferred embodiments of the present invention provide methods (1A-
1BU)
and systems comprising rig-less operable members (2A-2BU and 3A-3BU), which
further comprise apparatus (2A-2BU) for accessing and placing well barrier
elements
(3A-3BU) to provide (220) or enable (211-219) cap rock restoration of at least
a
portion (4A-4BU) of a producible zone of a subterranean well.
[000791Embodiments of the present invention are usable for placing and
supporting at
least one cement equivalent well barrier member (3A-3BU, 20, 216) within an
operable usable space, formed by at least one cable operable and rig-less
string
operable, annulus engagable member (2A-2BU), comprising components that can be
cable and rig-less string conveyable through an innermost passageway (25, 25E,
25AE), which can be surrounded by at least one annulus of a plurality of
annuli
formed by installed conduits (11, 12, 14, 15, 15A, 19), extending downward
from a
wellhead (7) within subterranean strata (17) for forming a plurality of
passageways
(24, 24A, 24B, 24C, 25, 25E, 25AE) in fluid communication with said producible
zones through cap rock.
[00080] Embodiments of the present invention are operable using energy
conductible
through the movable fluids of a well's circulatable fluid column (31C) or a
deployment string's electrical conductors and/or the deployment string's
tension to
operate at least one annulus engagable member for accessing at least one
annulus
from the innermost passageway, to displace at least one portion of a wall of
at least
one conduit about said innermost passageway, to provide an operable space,
bridge
across said operable space, and place said at least one cement equivalent well
barrier
member through said operable space, adjacent to said cap rock, for forming at
least
one geologic time-frame space that can be usable to fluidly isolate said at
least one
portion of said subterranean well, without removing said installed conduits
and
associated debris from below one or more subterranean depths (218) of
associated
capping rock to provide or enable said cap rock restoration above said
producible
zone.
[00081] Various embodiments are usable to rig-lessly abandon and/or suspend a
portion
of the well, then side-track to one or more new producible zones.
[00082] Various other embodiments are usable to provide a permanent fluid
isolation and
CA 2841144 2019-02-12
cap rock restoration by using an operable space to measure or provide (214)
cement-
like (216) bonding (213) across a sufficient axial length (219) of conduits,
which can
be embedded in (215), or filled within and embedded in (217), cementation,
with
stand-off (211) between conduits, and support (212) of said cementation at
said
subterranean depth (218), adjacent to impermeable strata capping rock, prior
to
performing said placing of said at least one cement equivalent well barrier
member
through said operable geologic time-frame space for enabling said cap rock
restoration above said producible zone.
[00083]Still other embodiments can be usable to provide an abrasive,
explosive, or
cutting component for accessing of at least one annulus from the innermost
passageway, or displacing of at least one portion of the wall of a conduit to
provide an
operable space.
[00084]Various embodiments can be usable to provide a motorized member (2B1,
2AN,
2AM2, 2BN, 2B0, 2BP) comprising at least one downhole motor that is
suspendable
from a cable and operable with the energy from said rig-less string or said
circulatable
fluid column to drive at least one rotatable cutting component or a mechanical
linkage
component.
[00085] Various related embodiments can provide an axially tractor operable
member
(2AW3, 2BN, 2BP3-2BP4, 2BQ) comprising said mechanical linkage or at least one
cutting component that can be engagable to the wall of the conduit to axially
move
through the innermost passageway for displacing another well barrier member or
said
wall.
[00086] Various other related embodiments may provide a conduit shredding
member
(2E2, 2AW2, 2BP2, 2BR), which can comprise one or more peripheral cutting edge
components. The one or more peripheral cutting edge components can comprise
wheels, blades, or combinations thereof, and the conduit shredding member can
be
deployable axially and radially outward from the innermost passageway, with a
solid
or kelly pass-through cam to shred and displace said wall.
[00087] Still other related embodiments can provide an annulus milling member
(2E6,
2AV3. 2AW1, 2AY1, 2BP1, 2BT1-2BT3) comprising one or more rotatable
peripheral cutting edge components, wherein the one or more rotatable
peripheral
26
CA 2841144 2019-02-12
cutting edge components can comprise wheels, blades, or combinations thereof,
usable for axially, rotatably, and circumferentially penetrating and cutting
the wall of
the conduit.
1000881Various embodiments can also provide a guiding member (2C1, 2D3, 2E4,
2N6,
2Y1, 2Y2, 2Z1, 2AB3-2AB4, 2AC, 2AM2, 2A01, 2AP, 2AQ1, 2AQ2, 2AT1, 2BI2-
2B13, 2BJ, 2BI6, 2BK, 2BL, 2BM) comprising a selectively orientable guiding
whipstock (2Y2, 2AB1, 2AQ1, 2B16, 2BK, 2BL, 2BM, 47), a conduit (2D2, 2AE3,
2AF, 2AK, 2AL, 2A03, 2AS2, 2AT3, 2AV2, 2AV5, 2BI3, 2AB3, 2AC1, 2B15), an
annulus bridge (2X3, 2AH, 2AJ1-2A13, 2AU1, 2AY2, 2AZ, 2BB,2BC, 2BD, 2BM2),
or combinations thereof, that can be engagable and orientable within said
innermost
passageway, to urge a passage of another well barrier member or said movable
fluids
through said wall using an alignable bore selector between said innermost
passageway
and at least one penetration in said wall.
[00089]Other related embodiments may provide at least one portion of a
selectively
orientable guiding whipstock or a guiding conduit that can be rotatably
orientable and
selectable with said bore selector, between a plurality of penetrations in the
wall of
the conduit, from within said innermost passageway.
[00090] Various other related embodiments may provide a fluid communication
conduit
component that can be placeable within said operable space, through said
innermost
passageway or through said guiding member, with said movable fluid pressure
against
a wall of said fluid communication conduit component.
[00091]Still other related embodiments may involve the wall of the guiding
conduit
comprising a rigid material, a mechanically expandable material, a chemically
expandable material, or a rigid and expandable material, that is sealable
against said
wall of said installed conduit.
[0009210ther related embodiments can further comprise providing a motorized
annulus
boring access member (2B3, 2C1, 2E4, 2L3, 2Y3, 2Z1, 2Z2, 2AA1, 2AB I, 2AC,
2AD, 2AE1, 2AN, 2AM2, 2AQ2, 2AS1, 2AV4 and 2BI1) comprising at least one
rotatable cutting component having a flexible shaft and boring bit for
penetrating and
displacing a portion of said wall of said installed conduit.
27
CA 2841144 2019-02-12
[00093] Various related embodiments may comprise providing a motorized borable
mechanical linkage component for displacing at least one portion of the wall
of the
conduit to provide a stand-off displacement or to prevent further displacing
of at least
one portion of the wall of the installed conduit, from another portion.
[000941Still other related embodiments may comprise providing said fluid
communication conduit borable mechanical linkage component within the operable
space to bridge across, or through, at least two passageways of the plurality
of
passageways to access the operable space.
[00095]Still other various related embodiments may further comprise providing
a fluid
communication mesh wall conduit component with at least one portion of said
wall of
said fluid communication conduit comprising permeable pore spaces sized for
packing and unpacking of particles or compositions that are usable to
selectively
prevent or provide fluid communication through said pore spaces using a flow
orientation of said circulatable fluid column, said pore space sizing, or said
particles
or compositions.
[0009610ther related embodiments may provide a straddle member (2B4, 2C2, 2D1,
2E1,
2E5, 2L2, 2M, 2N2, 2R2) with said fluid communication conduit component for
bridging across at least two perforations in said wall of said conduit to
segregate flow
between said at least two perforations and another passageway of said
plurality of
passageways to fluidly connect an annulus above and below a blockage in the
annulus
to fluidly communicate around the annular blockage.
[00097] Various other related embodiments of the straddle member may comprise
a
slideable piston for displacing or impacting movable fluids or another well
barrier
member within said plurality of passageways, using pressure from the
circulatable
fluid column, wherein the slideable piston can form a valve for opening and
closing at
least one penetration in the wall of the conduit to selectively and fluidly
bypass a
portion of the circulatable fluid column in one circulation orientation,
through said at
least one penetration, or to fluidly communicate through a longer portion of
the
circulatable fluid column in the opposite circulation orientation.
[00098]Various embodiments can provide a mechanically or fluidly placeable
pressure
bearing packer member (2F-2K, 2N5, 2S2, 2T1, 2B7, 2D4, 2E7, 2N4, 202, 2P, 2Q,
28
CA 2841144 2019-02-12
2R1, 2S1, 2T3, 2U, 2V1-2V2, 2W2, 2X2, 2AE2, 2AG, 2A1, 2AK, 2AL, 2BF1,
2BF3, 2B14) that can be expandable within said operable space and can be
axially
fixable or movable within at least one of said plurality of passageways to
provide: the
displacing of at least one portion of the wall of the conduit to provide an
operable
space, the bridging across the operable space, or the placing of at least one
cement
equivalent well barrier member through the operable space to fluidly isolate
the at
least one portion of a subterranean well.
[0009910ther related embodiments of a fluidly placeable pressure bearing
packer member
can comprise a mechanical packer with cylindrical, bag or umbrella components.
[000100] Other embodiments of a fluidly placeable pressure bearing packer
member of
the present invention can comprise a gelatinous packer with particles or
rheological
fluid components fluidly placeable and gelatinously fixable within at least
one of said
plurality of passageways.
[000101] Still other related embodiments can comprise gradated particles with
intermediate pore spaces that can be fillable by a chemical reagent mix for
forming
the gelatinous packer.
[000102] The embodiments of the present invention can include a packable
gradated
particle slurry that can have a chemical reagent mix comprise: a first fluid
mix of
organophillic clay of 5% to 60% by weight of composition mixed with a
hydratable
gelling agent that is sufficient to suspend the clay with weighting material
and
alkaline source components, placed within 15% to 60% water by weight of
composition, wherein the first fluid can be mixable and chemically reactable
with at
least a second fluid, which can comprise 15% to 60% water by weight of
composition,
and can be mixed with at least one of: i) a hydraulic cement of 15% to 75% by
weight
of composition, or ii) an oil based mud comprising 15% to 60% oil by weight of
composition mixed with weighting materials of 15% to 75% by weight of
composition. Although the above referenced embodiments include particular
ranges
of percentages by weight of composition materials, composing the packable
gradated
particle slurry, (i.e., chemical reagent mix, organophillic clay, water,
hydraulic
cement, oil based mud, and weighting materials), other combinations of ranges
of
percentages by weight of composition are possible for such materials.
29
CA 2841144 2019-02-12
[000103] Various other related embodiments may comprise axially compressing
adjacent well components, within axially adjacent operable spaces, with a
fluidly
placeable pressure bearing packer member for forming or enlarging the operable
space. In an embodiment, an axial piston component can be usable for axially
displacing at least a portion of a wall of a conduit, the movable fluids, or
combinations thereof, by axially compressing the axially adjacent components,
within
the axially adjacent space, to form or enlarge the operable space.
[000104] Still other embodiments can comprise laterally compressing well
components
within radially adjacent operable spaces, with a fluidly placeable pressure
bearing
packer member, for forming the operable space for the placing of the at least
one
cement equivalent well barrier member through the operable space to fluidly
isolate at
least one portion of the subterranean well. In an embodiment, a lateral piston
component can be used for laterally compressing well components, within
radially
adjacent operable spaces, with a packer member e.g., fluidly placeable
pressure
bearing packer member, for forming the operable space for the placing of the
well
barrier member to fluidly isolate the at least one portion of the subterranean
well,
without removing the plurality of installed conduits and associated debris
from below
one or more subterranean depths (218) and to provide or enable the cap rock
restoration above the producible zone.
[000105] Other embodiments of the present invention may provide a jarring
member
(2E3, 2S3, 2T2, 2U2, 2V1, 2W1, 2X5, 2BF3, 2BG6, 2BH1-2BH3), which can
comprise a latchable and releasable piston, sealable within said innermost
passageway
and fireable with energy released from compressing said circulatable fluid
column, to
travel along a dance pole or a re-latching rod and to deliver an explosive
hydraulic
jarring pulse, a mechanical impact, or combinations thereof, to objects below
said
releasable piston.
[000106] Finally, various other embodiments of the present invention provide
explosives or an abrasive particle severing member (2136, 2E8, 2AV7) to remove
the
wellhead and engaged conduits above the point of severance to complete the
abandoning of a well.
CA 2841144 2019-02-12
BRIEF DESCRIPTION OF THE DRAWINGS
[000107] Preferred embodiments of the invention are described below by way of
example only with reference to the accompanying drawings, in which:
[000108] Figures 1 to 3 depict prior art diagrams of different types of
drillings rig
operations and Figure 4 shows a prior art normally unmanned offshore platform.
Figures 5 to 7 illustrate different types of prior art rig-less operations.
[000109] Figures 8 to 9 illustrate prior art equipment usable to perform rig-
less
operations.
[000110] Figure 10 shows a typical prior art drilling rig well abandonment for
comparison to the rig-less abandonment issues and published conventional
minimum
industry requirements shown in Figures 11-15.
[000111] Figures 16 to 19 depict various embodiments of the present invention
for using
and/or abandoning substantially hydrocarbon or substantially water wells.
[000112] Figure 20 illustrates a prior art well configuration prior to
abandonment.
Figure 21 depicts the same well after abandonment using various embodiments of
the
present invention.
[000113] Figures 22 to 26 depict various rheology controllable and annuli
placeable
fluid member embodiments of the present invention. Figure 26A illustrates a
hard
and swellable material mixture, deployable using the fluid members of Figures
22 to
26.
[000114] Figures 27 to 34 illustrate various axially slideable annular
blockage bypass
member embodiments usable within the systems and methods of the present
invention.
[000115] Figures 31 to 34 depict various annular piston member embodiments
usable
within the systems and methods of the present invention.
[000116] Figure 34 shows a conduit pinning member embodiment usable within the
systems and methods of the present invention.
[000117] Figures 35 to 41 show various annular piston member embodiments while
31
CA 2841144 2019-02-12
Figures 42 to 46 illustrate jarring member embodiments, usable within the
system and
method embodiments of the present invention.
[000118] Figures 47 to 53 and Figures 62 to 66 depict various motorized
annulus access
embodiments, while Figures 54 to 61 illustrate various annulus piston
embodiments,
usable within the system and method embodiments of the present invention.
[000119] Figures 67 to 68 and 68A to 68B illustrate a swellable expandable
mesh
membrane member embodiment of the present invention.
[000120] Figures 69 to 71 show various annular boring, annular logging and
piston
packer annular access embodiments, usable within the system and method
embodiments of the present invention.
[000121] Figures 72 to 74 illustrate various milling embodiments, while
Figures 75 to
79 depict apparatuses usable in various embodiments of the present invention.
[000122] Figures 80 to 84 show various annulus separation embodiments of the
present
invention.
[000123] Figures 85 to 92 illustrate an axially slideable annular blockage
bypass
member embodiment, and Figures 94 to 104 depict various jarring member
embodiments, usable within the embodiments of the present invention.
[000124] Figures 105 to 116 show various motorized annular access embodiments,
of
the present invention.
[000125] Figures 117 to 122 illustrate various annular access guidance
embodiments of
the present invention.
[000126] Figures 123 to 147 depict various motorized annular access
embodiments of
the present invention.
[000127] Embodiments of the present invention are described below with
reference to
the listed Figures.
DETAILED DESCRIPTION OF THE EMBODIMENTS
[000128] Before explaining selected embodiments of the present invention in
detail, it is
32
CA 2841144 2019-02-12
to be understood that the present invention is not limited to the particular
embodiments described herein and that the present invention can be practiced
or
carried out in various ways.
[000129] Figure 1, is an isometric view of a prior art jack-up mobile offshore
drilling
unit (163) with a crane (195), helideck (194) and large scale derrick (193A)
over a
normally unmanned platform (170), usable to, e.g., support the day-to-day
needs of a
hundred people while drilling a well kilometres into the subterranean strata.
A
wellhead (7) would be situated on the normally unmanned platform (170),
immediately under the derrick (193A) that has been cantilevered over the
platform,
once the rig is jacked up. While constructing a well and conducting drilling
operations offshore or onshore requires a significant level of resources and
associated
cost, the abandonment of the same well can require significantly less
resources if
installed conduits are left within the strata, but because conventional rig-
less methods
for meeting various published industry standards for a majority of wells are
not
suitable, drilling rigs are often used to abandon wells despite their cost.
[000130] Figure 2 depicts an isometric view of prior art modular Drilling Rig
Derrick,
Rig Floor and Pipe Rack arrangement (165) without supporting equipment, such
as
mud pits, pumps, compressors and power generation, with a large hoisting
capacity
mast (193B) of comparable lifting capacity to a derrick (193A of Figure 1)
usable
offshore or onshore. Figure 2 shows another example of a drilling capable rig,
generally over specified for well abandonment, which is difficult to move,
erect and
operate, thus it is costly despite a significantly smaller foot print compared
to the full-
sized drilling rigs (e.g. 163 of Figure 1 and 164 of Figure 3).
[000131] Figure 3 is an elevation view of prior art Semi-submersible floating
Mobile
Offshore Drilling Unit (164), with a crane (195) and full size derrick (193A)
floating
at sea level (122A) over pressure control equipment (168), comprising a subsea
blow
out preventer (9A) engaged to a subsea tree and wellhead (7) at the sea bed
(122).
Subsea well operations, including abandonment, must account for the hazards
and
hydrostatic pressure of the ocean fluid column between the seabed (122) and
sea level
(122A). Rig-less subsea operations are possible with pressure control
equipment
(168A) significantly smaller than a drilling rig's subsea equipment (168), but
similar
to surface equipment (168C and 168D of Figures 7 and 9, respectively) that is
adapted
33
CA 2841144 2019-02-12
for use and deployment subsea, engaged to a subsea tree and wellhead (7),
wherein
lubricators and wireline are deployed from a boat (201 of Figure 6) and
engaged to
the subsea tree and wellhead (7). For rig-less abandonment operations, well
barrier
elements would be rig-lessly placed through the lubricator (8 of Figures 7 and
9) on
the boat, then lowered and engaged to the subsea tree to perform abandonment
operations. Thereafter, the wellhead (7) would be severed and recovered to the
boat,
once the ocean floor (122) was isolated from subterranean pressure sources
using
permanent well barrier elements, e.g. cement.
[000132] Figure 4, a plan view of a prior art normally unmanned offshore
platform
(170A), optionally with a helideck (194), shown with dashed lines, for
personnel
access and a crane (195) for lifting equipment off of a boat (201 of Figure
6),
illustrates the relatively small dimensions of the underlying platform jacket
of 8.5
metres by 12 metres. Once various operational production apparatuses (196) and
production manifolds and pipework (197) are placed on the platform, leaving
little
room for well intervention and abandonment equipment, hence drilling rigs,
despite
being over-specified for various required operations as described in Figure 1,
are
sometimes required to provide the necessary space for personnel and equipment.
Limited space on such facilities may also prevent the use of rig-less
arrangements,
such as that described in Figure 5, wherein only the lower space requirements
of rig-
less operations described in Figures 6, 8 and 9 may be possible.
[000133] Figure 5 depicts an isometric view of a prior art rig-less
arrangement (166A),
published in US Patent 7921918B2, with a jib crane (195), pressure control
(168B),
comprising, e.g., a packing element, and work string (199) or pipe handling
(198)
equipment. Figure 5 illustrates a rig-less arrangement designed for operating
below
ground level (121) or below sea level (122A) and mud line (122). While
embodiments of the present invention are usable with drilling rigs (163, 164
and 165
of Figures 1, 3 and 2, respectively) and this rig-less arrangement (166A), the
present
invention can be usable with rig-less arrangements (166B and 166C of Figures 6
and
7, respectively) that are placeable and operable in space-limited
environments,
wherein this arrangement (166A) may not be viable.
[000134] Figure 6, an isometric view of a prior art rig-less arrangement
(166B) and
offshore access system (200) from a boat (201) floating on the ocean surface
(122A),
34
CA 2841144 2019-02-12
illustrates a normally unmanned platform (170B) with a mast (169) for
deploying
wellhead (7) engaged pressure control equipment (168D of Figure 9) and cable
tool
operations, which can be usable with the methods and apparatuses of the
present
invention.
[000135] Figure 7 is an elevation view of an onshore prior art rig-less
arrangement
(166C) usable with the present invention to lower the cost and space
requirements of
abandonment. It depicts a truck (202) with a wireline winch (203) deploying a
coiled
string (187), comprised of, e.g., coiled wire or coiled tubing, passing
through various
sheaves and entering a lubricator (8) engaged to blow out preventers (9), and
further
engaged to a valve tree (10) and wellhead (7). A work string (199) is deployed
with
rotary (72) and/or snap (98) connections at its lower end, which can be usable
with
methods and apparatuses of the present invention.
[000136] Figures 8 and 9, isometric and elevation views of a prior art mobile
wireline
mast (169) wireline blow out preventers (BOPs) and lubricator arrangement
(168D),
respectively, illustrate telescoping mast sections (205) above a base with
sheaves
(204) at the upper end, for cables, from which a winch is usable to hoist
pressure
control equipment (168D) for engagement with a wellhead (7). The mast (169)
serves
a similar function to a derrick (193A of Figures 1 and 3, and 193B of Figure
2), albeit
with a significantly reduced lifting capacity suited primarily for lifting
pressure
control equipment and hoisting a lubricator (8), disconnected and reconnected
to a
blowout preventer (9) and valve tree (10), so as to engage apparatuses to a
coiled
string (187) threaded through the lubricator and operated with a winch (203).
The
pressure in a well is controlled, during intervention or abandonment, by
closing the
valve tree (10) and BOPs (9) when the lubricator is disconnected for placement
and
removal of apparatuses from within, after which the lubricator is reconnected
and the
valve tree and BOPs are opened for deployment on the coiled string (187),
sealed at a
stuffing box located at the upper end of the lubricator (8), whereby the
apparatus may
be deployed through the pressure controlled envelope of a well, through the
wellhead
(7) and plurality of installed conduits engaged to and extending downward from
the
we 1 lhead
[000137] Figure 10, a diagrammatic elevation cross section view through the
well and
subterranean strata of a prior art Drilling Rig Permanent Well Abandonment
(172A),
CA 2841144 2019-02-12
depicts the production tubing removed from the conductor (14), intermediate
(15),
production (12) and liner (19) well casings, that are shown cemented to the
various
diameter strata bores (17), between the lower casing shoes (16) and various
subterranean depths, within which cement (20) plugs are placed across the well
bore
to isolate hydrocarbon (95B) and water (95A) producible zones or formation
layers
within the strata, wherein a portion of the production casing (12) is cut and
removed
for placement of two of the plugs. As the gauge or diameter of the original
strata bore
(17) varies between and over casing sections, the top of cement behind casing
and
above a casing shoe (16) is often unknown, if during construction a casing
bond log
was not performed and circulating pressures were used to estimate the top of
cement.
Additionally, due to testing, thermal cycling, and overburden stresses and
pressures
within a well during its operating life cycle, the cement bond behind the
casing may
have been lost even if it was initially present, thus providing a leak path
for
subterranean pressurized fluids. Various milling, compressing and shredding
methods
of the present invention are usable to emulate this removal of the innermost
conduits
by cutting and compressing them for placement of well barrier elements above
their
compressed remains.
[000138] As later described in Figures 14 and 15, conduits may be left within
a well
during abandonment, provided a permanent barrier element, e.g., cement, is
placed
across the entire strata bore (17). In many cases, the subterranean depths
and/or
existence of a cement bond behind the various casings is unknown, and a
drilling rig
must be used to first remove the production tubing to access the production
annulus in
order to perform cement bond logging. Conversely, various methods and
apparatuses
of the present invention are usable to access these annuli in rig-less
operations so that
logging may occur to determine the extent of cement bonding behind installed
conduits, thus removing the need for a drilling rig.
[000139] Referring now to Figures 11 and 12, a diagrammatic elevation
subterranean
strata sliced view of before (171A) and after (172B) conventional rig-less
permanent
abandonment, respectively, wherein the left portion of Figure 11 shows a half
slice
through the subterranean strata and well casings, with a quarter section of
the
completion removed, and the right side is a simplified diagrammatical
depiction of the
left side, illustrating intermediate casing (15) cemented (20) to a casing
shoe (16) with
36
CA 2841144 2019-02-12
the production casing (12) cemented (20) and penetrated (129), by perforating
guns,
to expose a producible zone (95C). The production conduit or tubing (11), with
nipple profiles or receptacles (45) above and below a production packer (40)
engaged
to the casing (12), has a wireline entry guide (130) at its lower end. During
conventional abandonment, cement is bullheaded through the perforations, as
shown
in Figure 12, until the forces of injection were too high, and the cement
locked up,
leaving cement (20A1) within the tubing (11). Conventional rig-less
abandonment
operations, using installed conduits (11) for placement of cement (20A1-20A3)
within
the innermost passageway (25), production annulus (24) and intermediate casing
annulus (24A), suffer from an inability to effectively circulate or support
placed
cement, wherein cement contamination (20C) may occur. As shown in Figure 12, a
plug (25A) was then placed in the tubing (11), below the packer (40), and
penetrations
(129A) were made to place cement (20A2) in the innermost bore (25) and
production
annulus (24). A second plug (25B) was set using coiled string deployment, then
the
tubing (11) and production (12) conduits were penetrated (129B) to allow
cement
(20A3) to be placed in the innermost passageway (25), production annulus (24)
and
intermediate annulus (24A).
[000140] As logging of the cement bonds behind the casings (12, 15) is
generally not
conventionally possible, without removal of the tubing, neither the integrity
of the
cement behind casing nor the top of the cement (206) could be confirmed, as
required
by various published industry standards. While the bullheading of cement to
the
producible zone (95C) may have been effectively placed, lighter hydrocarbons
may
subsequently gravitate upwards and cause channels within the cement (20A1),
thus
preventing it from being considered a permanent barrier. Cement below the
packer
(40) and above the plug (25A) is likely to have been contaminated (20C),
albeit such
small volumes are unlikely to have caused pressure bearing integrity issues,
but
placement of cement (20A2) above the top of the cement (206) and behind the
production casing (12) does not constitute an industry acceptable permanent
barrier,
because the annuli (24A) are unsupported at that point (206). Also, cement
(20A3)
placed through penetrations (129) may not have entered the intermediate casing
annulus (24A) and/or the volumes of fluid below the unsupported cement (20A3)
may
be sufficient to cause contamination of the cement (20C) as it falls through a
lighter
fluid.
37
CA 2841144 2019-02-12
[000141] The inability to confirm the existence of cement in the locations
necessary to
form a permanent barrier capable of isolating subterranean pressures from the
above
ground, ocean environments and/or subterranean water tables for an indefinite
period
of time is a serious issue to which conventional rig-less abandonment often
does not
have answers. Even when conventional coiled tubing is used to form a
circulation
pathway for better placement of cement during prior art rig-less abandonment
operations, in conventional practice there is no means for rig-lessly placing
logging
tools to confirm the existence of a cement bond nor are there any cable
compatible
prior art conduit milling solutions, which are capable of removing conduits
and poor
quality cement to expose the subterranean strata, so as to place good quality
cement.
Embodiments of the present invention are usable to address the issues of
logging,
cementing and milling of conduits in a pressure controlled environment using
coiled
string operations in an economic manner currently unavailable to
practitioners.
[000142] Figure 13, a plan view of a prior art concept of fluid flow within an
eccentric
offset conduits arrangement (167C), illustrates, e.g., a production tubing
conduit (11)
within a production casing conduit (12) within an intermediate casing conduit
(15),
with a control line (79) within the production annulus (24), wherein the
tubing (11)
and production casing (12) are eccentric to the centre of the intermediate
casing (15).
If eccentric conduits are not separated when, e.g., penetrating the conduits
and
circulating down the innermost production passageway (25) and returning
through
either the production conduit annulus (24) or intermediate conduit annulus
(24A), a
channel (207) of higher velocity flow will occur through the lowest fluid
friction areas
that will reduce flow, to a near zero flow rate, through the higher friction
areas (208)
where conduits touch or are closely spaced. Because rig-less abandonment
generally
uses installed conduits to circulate a permanent well barrier, e.g. cement,
into a well,
the effect of zero flow in high frictional areas (208) may prevent cleaning of
conduits
to create a wettable surface and/or placement and bonding of a fluidly
circulatable and
settable permanent well barrier element, e.g. cement, which may result in a
leak path
over time, even if the arrangement holds pressure from above initially, as
lighter
fluids and/or subterranean pressures find their way to the surface, by eroding
contaminated or poorly bonded barriers. Other serious leak path issues for rig-
less
abandonment are control lines (79) and cables in conventionally inaccessible
annuli
that may not fill with cement due to, e.g., capillary frictional resistance.
As
38
CA 2841144 2019-02-12
conventional rig-less approaches are not capable of addressing either the
eccentricity
of conduits or the presence of control lines, drilling rigs are often used to
abandon
wells.
[000143] Figure 14, a diagrammatic elevation view of the prior art concept of
Degradation of a Well Barrier (167B), illustrates poor bonding resulting in a
micro
annulus (210A) between cement and a conduit or missing (209) cement (20),
providing a potential leak path for fluids (210) of a producible zone (95D),
which may
corrode the casing conduit (12) over time. Alternatively, the fluids can make
their
way to the production annulus (24) or travel upwards in the unfilled inner
bore, or
between the casing (12) and cement (20) if a poor cement bond exists, where
the
fluids may escape to pollute a surface or ocean environment, potentially
causing
hazardous conditions for inhabitants. For this reason, conduits and other
apparatuses,
e.g. mechanical packers and plugs, are not considered permanent barriers, as
they will
corrode over time. Additionally surfaces of conduits and equipment must be
clean
and wettable to provide a good bond, thus preventing corrosion, and providing
a
permanent well barrier element that retains its pressure bearing capacity
indefinitely.
[000144] Figure 15 is a diagrammatic elevation view of conventional published
industry
acceptable minimum rig-less abandonment requirements (167A), showing a
paraphrased representation of the Oil and Gas UK Issue 9, January 2009
Guidelines
for Suspension and Abandonment of Wells, Figure 1 entitled 'Permanent Barrier
schematic "Restoring the Cap Rock" used within the publication to describe
''minimum industry best practices."
[000145] Published industry best practice for rig-less placement of a
permanent barrier
specifies a minimum height of good cement (219), of at least 100 feet, that
must be
placed at a depth (218) determined by formation impermeability and strength
with
primary cementation behind casing in place. Pipe circumferential stand-off
(211) is
required to prevent the channelling (207 of Figure 13) of high fluid
frictional areas
(208 of Figure 13) resulting in poor cleaning, bonding and/or missing cement
(209 of
Figure 14). Axial downward cement support (212) is required to prevent cement
movement, slumping and gas migration while setting, and with clean water wet
surfaces to provide a good bond (213), thus preventing poor bonding and micro
annuli
(210A of Figure 14) and leak paths (210 of Figure 14). Once these minimum
39
CA 2841144 2019-02-12
requirements are met, the published references generally conclude that a rig-
less
operation will provide "well barrier elements," of a permanent sealing
abandonment
plug (216), with the innermost conduits sealed with cement in cement (217) and
the
casing and tubing embedded in cement (215). Provided that both the existence
and
sealing bond of primary cementation (214), adjacent to a formation that is
impermeable and of adequate strength, are present, the resulting cement will
contain
future pressures (220). While "cement" is specified, the Oil and Gas UK
Guidelines
also provided for alternative permanent well barrier elements, provided that
they
provide an equivalent function to cement.
[000146] Meeting industry rig-less abandonment best practice therefore
requires logging
of the primary well cementation behind casing to ensure its presence and bond,
followed by cleaning of well conduits to ensure they have wettable surfaces
for
cement bonding and embedding tubing and casings within cement, by providing
offset
where necessary over a sufficient portion of the well opposite an impermeable
and
strong formation that is capable of replacing the cap rock.
[000147] Unfortunately, while current practice emphases the need to design for
future
abandonment of a well, this was not always the case and few existing wells
were
designed with rig-less abandonment in mind. For example, production packers
may
be placed where future abandonment plugs should be placed and the primary
cementation may never have been logged. As a result, conventional rig-less
abandonment practices are generally unsuited for meeting industry well
abandonment
best practices, resulting in the use of over specified drilling rigs.
[000148] However, the present invention is usable to rig-lessly abandon all
of, or a
portion of, a subterranean well's annuli and producible zones while meeting
published
industry best practices, such as those described in the referenced Oil and Gas
UK
Guidelines and NORSOK standards. Meeting industry best practices for
abandoning
wells requires accessing the annuli of a well in a rig-less manner to perform
logging
of primary cementation, then remedying any poor primary cementation and
placing
good cement plugs and/or other suitable permanent abandonment seals within a
well.
[000149] Referring now to Figures 16 to 19, 21 to 46 and 48 to 74 depicting
various
diagrammatic cross sectional slices through a well's components and
subterranean
CA 2841144 2019-02-12
strata, the Figures illustrate methods and system or member embodiments for
operating on wells and accessing producible zones and annuli through a
wellhead (7),
that is shown engaged to a plurality of conduits comprising: conductor casings
(14),
intermediate casings (15), a secondary intermediate casing (15A) and
production
casing (12), cemented (20) at their lower ends for forming casing shoes (16)
within
various diameter subterranean strata bores (17), with an innermost conduit
(11) or
production tubing (11) engaged to the wellhead, within the production casing
(12),
and secured at its lower end with a production packer (40). A liner (19) and
liner top
packer (40A) may also be present in various well configurations, with the
liner or
casings penetrated (129) by perforating gun members or embodiments to allow
production (34P) from a conduit lined producible zone (95F). Any embodiment is
usable with a well head (7), placeable at the mudline (122), if below sea
level (122A),
or at ground level (121) with production (34P) occurring through the
production
tubing (11) from an open hole producible zone (95E). Production (34P) is
controllable with a valve tree (10, 10A) using surface valves (64) and/or with
a
subsurface safety valve (74) and control line (79) engaged to the tubing (11),
with
clamps below the wellhead (7).
[000150] A circulatable fluid column (31C) may be circulated axially downward
or
upward through the tubing (11) returning or entering, respectively, e.g.,
through the
annulus between the production casing (12) and tubing (11), using a sliding
side door
(123), and lower end of the tubing and/or penetrations in the tubing (11), to
take fluid
circulated returns or to pump a circulatable fluid via an annulus opening
(13), annulus
opening valve (13A), and/or valve tree (10). Circulation of the circulatable
fluid
column (31C) in any of the annuli may also occur through openings between
annuli
passageways entering and exiting wellhead annuli openings (13). The
circulatable
fluid column (31C) may be stagnate, circulated through passageways, or
injected into
a permeable reservoir (95E, 95F) or fractures (18) in the strata, if the
pressure exerted
by the fluid column is sufficient. The circulatable fluid column (31C) is
usable to
place well element barriers, e.g. cement or gradated particle mixtures, or to
clean well
components to provide a wettable surface (213 of Figure 15) and/or place
rheology
controllable and annuli placeable fluid members during rig-less abandonment
operations.
41
CA 2841144 2019-02-12
[000151] Conventional logging generally occurs within the innermost passageway
(25)
and is unable to determine the state of primary cementation about the casings
(12, 14,
15 and 15A) because logging tools within the production conduit (11) cannot
contact
the casings. Various embodiments of the present invention, e.g. annular piston
and
annulus boring access members, are usable to access annuli for placement of
logging
tool members to confirm primary cementation adjacent to conduits (214 of
Figure 15).
Signals may, e.g., be broadcast from the logging tool with reflected signals
collected
by a different portion of the logging tool, or signals may be passed between
the
wellhead, surface or subsea location and the downhole transmitter or receiver.
Using
logging tool method embodiments of the present invention, measurement signals
can
be engaged with the circumference of the conduit walls to provide sonic,
acoustic or
various other forms of signal measuring, e.g., the response time of signals
passing
through bonded (216 of Figure 15), and unbonded (209 of Figure 13, 210A of
Figure
14) conduit cementation to measure the degree of bonding and/or cementation
present. The process may be visualized as ringing or pinging a glass and
measuring
the sound or vibration received to determine if the glass is free standing,
within a
liquid or tightly cemented in place.
[000152] Dependent on the result of the logging measurements, various other
members
of the present invention system of members are usable to place temporary or
permanent well barrier elements within the well at the appropriate
subterranean
depths (218-219) to meet industry best practices (211-220 of Figure 15) to
avoid
potential future leak paths (210 of Figure 14, 208 of Figure 13) and/or
simulate a rig
abandonment (172A of Figure 10) by placing cement plugs (20 of Figure 10)
across
casings (12, 15 and 19 of Figure 10). Additionally, all embodiments are cable
string
compatible and are thus usable with either the rig-less arrangement of Figure
5 or the
minimalistic pressure controlled arrangements of Figures 6 to 10, to meet
published
best practices (211-220 of Figure 15) for permanently abandoning a
subterranean well
in a rig-less manner.
[000153] Various methods and members, e.g., rheology controllable and annuli
placeable fluids and swellable expandable mesh membrane members, are usable to
temporarily restore sufficient fluid pressure integrity by bridging across
fluid leaks to
use the circulatable fluid column (31C) to provide sufficient cement (219 of
Figure
42
CA 2841144 2019-02-12
15), at suitable permanent barrier depths (218 of Figure 15), to contain
future
pressures (220 of Figure 15), with annular separating members usable to
provide
circumferential stand-off (211 of Figure 15) for cleanable water wettable
surfaces that
enable good bonding (213 of Figure 15) during circulation of the fluid column
(31C)
and embedding of conduits in cement (215 and 217 of Figure 15), so as to
provide a
sealing permanent abandonment plug (216 of Figure 15) according to published
industry guidelines.
[000154] Various methods and members, e.g., axially slideable annular blockage
bypass, annulus guiding, annulus boring access and boring bit engagable
conduit
members are usable to embed casing (12, 14, 15, 15A, 19) and tubing (11) in
cement
(215 of Figure 15), with the tubing and casings being filled and surrounded
for
providing cement in cement (217 of Figure 15) conduits, using a bypassing
arrangement around blockages in an annular space, e.g. a production packer,
and by
boring into annuli to create a logging space and fluid circulation path, which
can be
usable with logging tool members and the circulatable fluid column in bores
and
annuli of the well, at selected depths (218 of Figure 15), to provide
sufficient cement
(219 of Figure 215) that is adjacent to a primary cement barrier, bonded
between the
outer casings (12, 14, 15 and 15A) and an impermeable formation of sufficient
strength, to contain future pressures (220 of Figure 20). Thus, a sealing
permanent
well barrier element (216 of Figure 15) can be provided according to published
industry guidelines.
[000155] Other various methods and members, e.g., annular piston, jarring,
circumferential shredding and milling, and axial movable screw or tractor
members,
are usable to simulate a rig abandonment (172A of Figure 10) by compressing,
milling and/or shredding of conduits, within casings (12, 15 and 19 of Figure
10), to
remove the conduits within a barrier's height (219 of Figure 15) at the
necessary
barrier depth (218 of Figure 15) and across from a strong impermeable
formation (220
of Figure 15). Accordingly, this provides permanent abandonment cement plugs
(216
of Figure 15) across casings (12, 15 and 19 of Figure 10), pursuant to
published
industry guidelines.
[000156] Still other various methods and members, e.g., rheology controllable
and
annuli placeable fluids, and annular piston members, can be usable as, or for,
43
CA 2841144 2019-02-12
supporting well barrier elements, e.g. cement, to avoid settable barrier
movement,
slumping and/or gas migration, while setting (212 of Figure 15) to provide a
good
bond and to ensure sufficient cement (219 of Figure 15) at a depth (218 of
Figure 15)
adjacent to an impermeable strong formation (220 of Figure 15), to provide
permanent abandonment cement plugs (216 of Figure 15) according to published
industry guidelines.
[000157] Additionally, while Figures 16 to 19, 21 to 46 and 48 to 74
illustrate various
cable (187) compatible string tension and/or electric cable and fluid column
(31C)
operable members, said members are also usable with coiled tubing and/or
jointed
conduit strings, in various other configurations of conventional rig and rig-
less
operable arrangements, wherein circumferential cutting members and rotary
cable
tools of the present inventor and described within the referenced applications
are also
usable as members.
[000158] Figure 75, an isometric view of rotary cable tool conduit cutter
(175) is, e.g.,
usable as a cutting member of the present invention, and illustrates a cutting
arm
assembly (175B) extended by the combination of rotation of the rotary
connector
(175A) and frictional resistance of the drag block (175C), wherein the member
is
deployable through the innermost conduit and usable to cut through various
casing
strings, with its low torque roller cutter. This is similar in nature to a
plumber's pipe
cutter that can be deployed from the inside out, rather than the outside in.
Various
apparatuses of the present inventor, as described in GB1011290.2, including a
boring
bit (174), and/or conventional cutting devices are usable with a conventional
motor
and/or cable compatible motor assemblies of the present inventor, and are
usable as
members within method embodiments of the present invention.
[000159] Referring now to Figure 123, an isometric view of a method (1B0)
embodiment of a motorized member (2B0) is depicted, compatible with cable
operations and usable within various embodiments of the present invention. The
Figure depicts an upper rotary connector (72U) that can be engagable with a
cable
(187 of Figure 9) and deployable through pressure control equipment and the
innermost conduit passageway for operating various conventional and invented
devices (2B01), which can be used to access annuli and producible zones for
placing
the partially shown well barrier elements (380) to abandon a portion (4B0) of
a well.
44
CA 2841144 2019-02-12
The motor member (2B0) is comprised of a lower rotary connector (72L),
engagable
with members (2B01) of the present invention and rotated by a fluid motor
assembly
(2B02), that is held by upper (2B04) and lower (2B03) anti-rotation devices.
The
fluid motor is operated by pumping the circulatable fluid column (31C),
diverted by
seals (2B05) engaging the innermost conduit's circumference, into orifices
(59) that
can be usable to operate the motor (2B02) and lower member (2B01) within
method
embodiments of the present invention, wherein the member is an example of a
usable
motor for the following method embodiments.
[000160] Figures 16, 17, 18, 19 and 20-21, describe methods and members usable
to
access and/or abandon an entire well, which are interchangeable with other
associated
methods and members described throughout the remainder of the specification,
and
which demonstrate that the adaptable system of methods and member sets, of the
present invention, are usable to address the variability of the subterranean
strata and
design characteristics of substantially hydrocarbon and substantially water
wells,
when accessing, using and/or abandoning at least a portion of a subterranean
well's
producible zones and annuli.
[000161] Figure 16, an elevation cross section view of a logging tool member
method
(1A) embodiment usable with a member set (2A) comprising conventional logging
tool signal (2A1-2A3) and receiver (2A4-2A6) members within a plurality of
passageways below a wellhead (7), shows signals deployed axially upward (173A)
or
downward (173B), e.g, through wires or acoustically through the walls of the
conduits and/or through fluid pulses within the fluids in the annuli, to
measure the
installed well barrier elements (3A1-3A3) and to determine the requirement for
new
well barrier elements (3A4-3A6) within portions (4A1-4A3) of the well axially
below
the wellhead (7). Signal transmitters (2A1-2A3 and 2A7) and/or receivers (2A4-
2A6) are engagable with conduits, or annulus fluids, through embodiment
penetrations (2A3, 2A4) or through annulus wellhead openings (13). A signal
may be
sent from the wellhead (2) or from and an external transmitter (2A7), which
can
function in a similar manner to a VSP logging tool used to calibrate seismic
data, but
also can be usable to see the existence of primary cementation adjacent to the
strata
bore (17). Various embodiments of the present invention can be usable to place
logging tool member transmitters or receivers within a well, e.g., the annulus
piston
CA 2841144 2019-02-12
method (1S of Figure 41) can be usable to expose the production casing (12 of
Figure
41) for logging of primary cementation (20 of Figure 41) behind it; or, e.g.,
a annulus
boring access member can be usable to place logging tool members within any
annuli.
[000162] Figure 17, is an elevation cross section view with break lines
representing
removed portions of the subterranean well and strata, which depicts
embodiments of a
method (1B) that can be usable with a set (2B) of motorized annulus access
(2B1,
e.g. 2B02 of Figure 123), circumferential shredding and milling (2B2, 2B5,
e.g.
2BP1-2BP4 of Figure 129), annulus boring access (2B3, e.g. 2BU of Figure 147),
axially slideable annular blockage bypass (2B4, e.g. 2M of Figures 28-30),
abrasive
particle cutting (2B6, e.g. 2AV7 of Figure 72) and an annular piston (2B7,
e.g. 2T3
of Figure 42) members, deployable within a pressure controlled rig-less well
environment (168E). The Figure depicts the members (2B1, 2B2) within the
lubricator (8) that is engaged to the BOPs (9) and a valve tree (10) engaged
to the
wellhead (7), deployable axially downward within the well using a coiled
string (187).
Conventionally, cement may be bull-headed into the perforating gun penetrated,
producible zone (95F) and open hole (95E) reservoirs, by injecting fluid of
the
circulatable fluid column (31C) into the penetrations (129) of the liner (19)
and open
hole (95E), to abandon a portion (4B1) of the well for preventing further
production
(34P). Alternatively, an axially slideable annular blockage bypass member
(2B3) can
be usable to bullhead cement with a significantly reduced risk of losing
injection with
the tubing full of cement, wherein logging through the innermost bore (25) can
determine sufficient primary cement (3B1, 20) exists behind the liner (19) for
isolating the reservoirs prior to said bullheading, while the annulus boring
member
(2B3) is usable to access the annulus (24A) and determine whether the well
barrier
element (3B2) is sufficient to provide permanent well integrity for the
portion (4B2)
of the well.
[000163] The method (1B) is usable to rig-lessly abandon all or a portion of a
well
through a pressure controlled (8, 9, 10) coiled string (187) arrangement,
onshore
below ground level (121) or offshore below mudline (122) and beneath the
ocean's
surface (122A) on, e.g., a subsea wellhead (7 of Figure 3) or offshore
platform (170A
and 170B of Figures 4 and 6), without resorting to conventional methods
requiring a
drilling rig (163-165 of Figures 1-3). An axial slideable annulus (24)
production
46
CA 2841144 2019-02-12
packer (40) bypass member (2B4) can be usable to access the annuli (24, 24A)
through the bore, made by the previous member (2B3) and potentially the
sliding
sleeve (123) ,to place cement above the well barrier element (3B2) within the
annuli,
across the intermediate casing (15) cemented (20) shoe (16) and strata bore
(17), to
abandon the portion (4B2) by using the circulatable fluid column (31C),
circulated
through the innermost bore (25), annuli (24, 24A) and wellhead (7) outlets
(13A).
Abandonment of the upper section may be performed using a milling and
shredding
member (2B2) that can be engaged with the motorized member (2B1) or other
milling
and/or shredding members (2B5) to remove the conduits (11, 12) to place a
permanent
well barrier element across the strata bore (17) for sealing a portion (4B3)
of the well
across the existing well barrier element (3B3) and casing (15), with logging
of the
primary barrier (3B3) occurring once the milling is completed and the
intermediate
casing (15) exposed, prior to placement of the barriers.
[000164] An upper well portion (4B4) can comprise well components that can be
more
difficult to mill, such as, e.g., a subsurface safety valve (74) with
associated control
line (79) and control line clamps, within the production annulus (24), which
may be
used and/or abandoned by first cutting the production tubing (2B6) with, e.g.,
a coiled
string rotary cutter (175 of Figure 75). Then, a piston (e.g. 4U of Figure 43)
can be
used to compress (2B7) or crush the well components for placement of a well
barrier
element (3B4) across the conductor (14) primary cement (20) and casing shoe
(16),
within the annuli (24A, 24B) and through perforating gun penetrations or a
boring bit
engagable conduit, e.g. 2B12 and 2B13 of Figures 112-116. Thereafter, pressure
control (7, 8, 9, 10) is no longer needed and the wellhead and upper end
casing can be
cut and removed from the well by, e.g., conventional abrasive cutting (2B6) of
remaining conduits (14, 15), thus completing the rig-less abandonment.
[000165] Figure 18 depicts an elevation cross section view, which shows
embodiments
of a method (1C) usable with a member set (2C) comprising boring bit engagable
conduit (2C1) and axially slideable annular blockage bypass (2C2) members,
which
can be further usable for rig-less operations on a conventional solution
mining
subterranean well. The Figure illustrates the use of a sealable boring bit
engagable
conduit (2C1), e.g. (2B12-2B13) of Figures 108-109, to bridge across the
annulus
between inner (11A) and outer (11B) leaching strings, thus abandoning a
portion
47
CA 2841144 2019-02-12
(4C1) of the outer leaching string, and allowing fresh water to be applied to
solution
mining of a salt deposit (4) below the top of the salt (5) deposit to expand
(34A, 34B)
the brine producible cavern (34) without using a drilling rig to first remove
the inner
leaching string (11A). Then, the outer leaching string (11B) can be adjusted
and
subsequently the inner leaching string can be replaced. After completing
solution
mining to form the storage product producible cavern (34C), the leaching
strings
(11A, 11B) can be removed and a production casing (11) can be engaged to the
final
cemented production casing (12) with a packer (40), with a valve tree (10A)
and
surface valves (64, also shown in Figure 17) installed at the upper end of the
well, that
can be used for storage operations. Thereafter, a portion (4C2) of the storage
producible cavern (34C) can be used and/or abandoned in a rig-less operation,
by
installing an axially slideable annular blockage bypass (2C2), to flow around
the
packer (40) and to circulate the cavern full of abandonment materials, e.g.
solids
debris, with the remaining portion (4C3) within the primary barriers (3C), rig-
lessly
abandoned by circulating in a well barrier element, such as cement, using the
bypass
(2C2), after which the wellhead (7) can be removed with abrasive cutting or
other rig-
less operations.
[000166] Referring now to Figure 19, an elevation view of subterranean slice
through a
well and strata is depicted, showing embodiments of a method (1D) usable with
a set
(2D) of axially slideable annular blockage bypass (2D1), expandable
circumferential
engagable (2D2), boring bit engagable conduit (2D3) and annular piston (2D4,
2D5)
members, that can be usable for rig-less operations on a manifold string well
of the
present inventor, with a dual (11C, 11D) producing string arrangement, which
can be
usable for underbalanced side-tracking operations through pressure control
equipment
(168D) with, e.g., coiled tubing (187), to, e.g., control pressures and avoid
killing the
well with heavy fluids and to reduce skin damage within producible formation
zones.
[000167] In Figure 19, lower end penetrations (129A) and lateral passageway
penetrations (129B) were placed using a bore selector, after which expandable
circumferential engagable (2D2) members were placed across the lateral
penetrations,
e.g. 2AR2 of Figure 67. Then, an axially slideable annular blockage bypass
(2D1)
member, e.g. (1BE) of Figures 85 to 93, can be placeable to abandon the lower
portions (4D1) of the penetrated (129) liner (19), bypassing with the lower
production
48
CA 2841144 2019-02-12
packer (40) to circulate cement and to displace cement with a wiper plug
(25W),
through the inner bore (25) and annuli (24, 24A), to abandon the previous side
track
portions (4D2) of the well's primary barrier (3D1), thus suspending final
abandonment
for a further side-track. A boring bit engagable conduit (2D3) using, e.g., a
flexible
shaft and bit (2Y3 of Figure 48) engagable with a fluid conduit (2BI2 and 2BI3
of
Figures 108 and 109) can be then usable to access a different formation in the
producible zone for production (34) above the cemented lower section and below
the
wiper plug (25W), through the existing production conduit (11C) subsurface
safety
valves (74), valve tree (10A) and production valves (64) engaged to the
wellhead (7).
[000168] After cessation of production, the internal conduits (11C, 11D) may
be
severed and annular pistons (2D4, 2D5), e.g. 2N5 of Figure 33, 202 of Figure
37
and/or 2Q of Figure 39, are usable to abandon the upper portions (4D3) across
the
primary barrier (3D2) at the production casing (12) shoe (16) and upper
portion (4D4)
across the primary barrier (3D3) of the conductor (14) casing by compressing
severed
well equipment downward, and potentially aiding said compression with a
jarring
member, e.g. (2T2 of Figure 42), and rheological controllable fluid member
(2T1) of
Figure 42, after which the upper portion of the wellhead (7), attached
conduits and
valve tree (10A) may be removed with, e.g. rig-less abrasive cutting, to
return the
ground level (121) to its original condition.
[000169] Figure 20 depicts a diagrammatic elevation view of a slice through
the
subterranean strata, with break lines representing removed portions, showing a
prior
art hydrocarbon well completion for subsequent rig-less abandonment (171B),
associated with Figure 21, and using embodiments of the present invention,
that
depict a valve tree (10) with production valves (64) engaged to a wellhead
(7), which
is engaged with conductor (14), intermediate casing (15), production easing
(12),
perforating gun penetrated (129) liner (19) and production tubing (11), that
can be
controlled by a safety valve (74) via a control line (79), extending axially
downward
through pressure and fluid permeable strata formations (95G-95K) and
relatively
impermeable strata formations (94A-94K). The primary
factor affecting all
abandonment design of any subterranean well (171B) is the subterranean strata
(94A-
94K and 95G-95K), which may vary significantly from one well to the next, even
within the same producing region which may potentially cause the abandonment
49
CA 2841144 2019-02-12
design and the usable member embodiments to vary. Various types of production
packers (40, 40B, 40C) can be used to segregate producible zones used, e.g.,
to
control water production, wherein a bottom plug (25F) was used to isolate a
water wet
producible zone (95G), encountered during construction of the well.
[0001701 Figure 21 is a diagrammatic elevation cross section view through the
strata,
with break lines representing removed portions. The Figure shows embodiments
of a
method (1E) usable with a set (2E) of axially slideable annular blockage
bypass (2E1,
2E5), axial conduit shredding (2E2), jarring (2E3), annulus boring access
(2E4),
circumferential milling (2E6), annular piston (2E7) and abrasive particle
cutting (2E8)
members, which can be usable for permanent rig-less abandonment of the well
shown
in Figure 20, depicting suspension and marginal production recovered prior to
final
well abandonment.
[000171] A axially slideable annular blockage bypass member (2E1), e.g. (4M)
of
Figures 28 to 30, is usable to bypass the lower packer (40C of Figure 20) and
place a
cement well barrier element (3E1) to abandon the lower portion (4E1), opposite
a
strong impermeable formation (94C of Figure 20), after which an axial conduit
shredding member (2E2), e.g. (2BR of Figures 135 to 140 with the motorized
member
(2BN) of Figure 124 to 127), may remove conduits around the sliding side door
(123)
which was allowed to fall downward and on top of which a cement barrier (3E2)
may
be placed, by bullheading the circulatable fluid column into the permeable
producible
zone (95H of Figure 20) to abandon the next portion (4E2) of the well.
[000172] Because the liner (19 of Figure 20) top represents a potential leak
path, a
jarring (2E3) member is usable against a jarable surface, such as a piston or
rheological controllable member, to compress equipment and place a well
element
barrier (3E3) to further isolate and permanently abandon the lower portion
(4E2) of
the well, before suspending the abandonment and side-tracking with an annulus
boring access member (2E4), e.g. (2AM4) of Figure 62, to provide marginal
production from a formation (951 of Figure 20), that may not have been
initially
completed, e.g., because it presented a risk to the more favourable producible
zones
(95H and 951 of Figure 20). After producing the side-tracked formation (95J of
Figure 20) the side-tracked portions (4E3) are abandoned by penetrating the
conduits
and placing an axially slideable annular blockage bypass member (2E5) over the
CA 2841144 2019-02-12
penetrations to further place a well barrier element (3E4), using circulation
to place
cement within the annulus and inner bore.
[000173] During the previous abandonment, suspension and side-tracking
operations,
hazardous well substances, e.g. LSA scale, may be injected and abandoned into
a
fracture (18), formed for disposal purposes, that now comprises a portion
(4E4) of the
well that must be abandoned to protect a permeable ground water producible
zone
(95K). A circumferential milling member (2E6), e.g. (2AY I, 2AY2) of Figure 74
or
(2BP1-2BP4) of Figures 128 and 129, can be usable to remove the tubing (11)
and
production casing (12) so that a cement well barrier element (3E5) can be bull-
headed
into the fractures (18), thus abandoning the portion of the well (4E5)
adjacent to the
water table producible zone. Subsequently, an annular piston member (2E7) and
method, e.g. (1BF) of Figure 94 to 99, can be usable to compress the conduits
and
safety valve (74) downward, so that a cement barrier (3E6) can be placed to
abandon
the uppermost portion (4E6) of the well, after which a boring pinning member,
e.g.
(1Z) of Figure 49 and an abrasive particle cutting (2E8) can be usable to
remove the
wellhead in one piece with a crane, so that the ground surface (121) could be
returned
to its original state.
[000174] Additionally, while the rig-less abandonment method (1E) may comprise
numerous steps and members with an increased time to implement, when compared
to
a drilling rig abandonment, the overall cost of the abandonment is, in
practice,
significantly less than that of a rig (163, 164, 165 of Figures 1, 2 and 3,
respectively),
because the work involves a limited amount of equipment and personnel, e.g.
the rig-
less abandonments (166A, 16613 or 166C) of Figures 5, 6 and 7 respectively,
that are
generally available at a significantly lower cost per unit of time, and
wherein they are
usable with the present invention to meet the published minimum industry
recommended guidelines (211-220 of Figure 15).
[000175] Figures 22 to 26 and 26A depict elevation views of slices through
fluid filled
passageways showing method (1F-1K) embodiments usable for blocking associated
passageways, permanently or temporarily, until another well barrier element
member
can be placed, using rheology controllable and annuli placeable fluid members
(2F-
2K) that comprise either conventional fluids or rheological controllable fluid
slurry
embodiments (32, 33), which can be usable with a circulatable fluid column
(31C)
51
CA 2841144 2019-02-12
and the flow regimes described herein to, in use, seal and/or support other
conventional and invented members. The Figures illustrate various arrangements
of
fluid member placement. A rheology controllable and annuli placeable fluid
member
(2F-2J) may comprise any conventional fluid or fluid slurry that can be usable
for
well abandonment, e.g. conventional gradated particle mixtures, or an
embodiment of
the present invention comprising a first fluid with a high concentration of a
hydrated
organophillic clay that can chemically react with hydratable cement and/or a
second
fluid, e.g. oil based mud, forming a viscous "gunk" (32) material. The gunk
(32)
material can be entrained with gradated mixtures of hard non-swellable and
swellable
particles (33) that chemically react with a reagent fluid, placed at the point
of use or
transported with the particles, to form a "swelling or expandable fluid
slurry" that can
be capable of providing a well barrier element member that is placeable,
usable and/or
removable, with the ease of the removal dependent upon the formulation being
non-
hardening and access. Fluid members (2F-2K, 3F-3K) can be deployable using
rheological flow regimes and/or with separating upper (221B-221D) and lower
(221A-221C) axial movable and sealable member plugs, which can comprise, e.g.,
conventional separating viscous non-reactive polymer fluids, mechanical
separating
plugs or alternatively a container, such as coiled slickline string deployable
bailers.
The reagents can be separated by the movable and sealable member plugs and can
be
controllably mixable using rheological flow regimes, as the plugs exit the
segregating
arrangement or bottom of the conduit (11) and fluid circulates upward within
the
various flow regimes, e.g., bubble flow (223), as the lighter and denser
fluids interact,
followed by slug or plug flow (224), for comparatively large volumes of the
first
fluid, or churn flow (225), for comparatively smaller volumes of the first
liquid in
relation to the second fluid, with some annular flow (226) and/or wispy
annular flow
(227) occurring at directional changes or in higher fluid friction passageways
at the
walls of the conduits.
[000176] Swellable particle well annuli abandonment expandable packs may be of
any
shape (2K1-2K4 of Figure 26A) and comprised of uniform (2K of Figure 26A),
coated (2K2 of Figure 26A) and/or layered (2K3, 2K4 of Figure 26A) hydrocarbon
reactive, water reactive or other swellable fluid reactive materials, that can
be fluidly
deployable within a well's plurality of passageways, wherein coatings can be
applied
to swellable materials or a film may inhibit swelling during deployment, that
52
CA 2841144 2019-02-12
dissolves when placed and/or exposed to chemical reagents at a selected well
passageway location and that aid forming a matrix when broken or dissolved,
thus
exposing the swellable materials to a reagent to cause packing of a gradated
particle
mix.
[000177] Various laminar and turbulent flow patterns of multi-rheological
and/or multi-
phase flow are possible when placing a well barrier element member or annulus
engagable member of the present invention, e.g. swellable particle well annuli
abandonment expandable packs, depending on the frictional characteristics of
the
flow passageway and the rheological properties, densities and velocities of
the fluids.
Two or more fluids of differing rheologies and densities, comprising two or
more
liquids and/or liquids and gases passing through a well passageway, can take
any of
an infinite number of possible forms; however, these forms can be classified
into
types of interfacial distribution, commonly called flow regimes or flow
patterns. The
regimes encountered in vertical flows include: Bubble Flow (223), where a
first fluid
is continuous, and there is a dispersion of a second fluid of differing
rheological
properties within causing a bubble effect within the first fluid; Slug or Plug
Flow
(224), where the second fluid bubbles have coalesced to make larger bubbles
which
approach the diameter of the passageway; Churn Flow (225), where the slug flow
bubbles have broken down to form an oscillating churn regime; Annular Flow
(226),
where the first fluid flows on the wall of the tube as a film (with some of
the first fluid
entrained in the core of the second fluid flow in the centre); and Wispy
Annular Flow
(227), whereas the fluid flow rate is increased, the concentration of drops in
the
second fluid core increases, leading to the formation of large lumps or
streaks (wisps)
of the first fluid.
[000178] Rheology controllable and annuli placeable fluid members (2F-2J),
comprising the embodiments of, e.g., abandonment gunk (32) with packable
gradated
swellable and/or non-swellable particles (33), have the desirable features of
being
easily placed within tight spaces, such as well annuli and permeable zones
where,
degraded conduits, partially collapse conduits, debris from milling or
shredding
conduits, and/or reservoir fractures exist, to, in use, provide a pressure
bearing seal,
by using their liquid and/or packed particle arrangement with a controllable
rheology
at placement and chemical reaction with surrounding or placed fluids. The
chemical
53
CA 2841144 2019-02-12
reaction of gunk (32) can be visualized as the hydrated organophillic clays
mixing
with the oils and suspended weighting particles, such as barite, in the oil
based mud to
form a gel like substance or clays mixed with cement to form a settable hard
substance. The chemical reaction in a swelling gradated particle mix (33) can
be
visualized as gradated hard particles (191 of Figure 26A), such as porcelain
beads,
sorted sand and gravel, or any other hard material to form a contacting matrix
with
pore spaces filled by smaller gradated non-swellable and/or swellable
elastomeric
particles (192 of Figure 26A), which can fit within packed pore spaces and
swell
when exposed to, e.g., hydrocarbons, thus further packing the matrix of
contacting
particles to form a gradated swelling particle mix (33) that can be capable of
bearing
pressure.
[000179] The gradated particle mix (33) may be transported via the
cireulatable fluid
column in, e.g., water or non-hydrocarbon gunk (32) components, and then mixed
or
dumped into a hydrocarbon fluid to swell and form a packer within, e.g., well
annuli.
As gunk (32) can be a hydrocarbon based formulation, with the swelling
gradated
particles (33) added to the gunk during mixing or when placed on top of the
gunk in a
plurality of placement stages, with the lighter hydrocarbons rising through
the
particles from the gunk (32) and being usable to swell gradated particle mixes
(33),
deployed separately or together, and dependent upon the swelling time of the
particles
once exposed to the reagent. Gunk (32) and swellable gradated particle (33)
mixes
can be compressed with the circulatable hydrostatic fluid column (31C) by
applying
pressure from the wellhead downward to further pack, compact, and/or solidify
a
gradated particle mix. Selectively controlling the mix of gradated particles
(33) and
low gravity solids of the gunk (32), placed within a well space, and forcing
excess
mobile fluid or gels of the gunk (32) from pores of the swellable gradated
particle mix
(33) can leave a packed matrix of hardened particles with pore spaces
completely
filled by either swellable particles or low gravity solids from the gunk to
form a
bridge across the walls of well conduits, which can be capable of holding more
significant pressure to, e.g., hold a significant column of cement or act as a
temporary
production packer for further marginal production, prior to final abandonment
of a
well.
[000180] Gunk application is not generally practiced within industry because
it involves
54
CA 2841144 2019-02-12
a reaction similar to the flash setting of cement. As a result, its practice
is generally
confined to regional applications where lost circulation presents a larger
risk than said
flash setting. While gunk is practiced in drilling applications where
formation
fractures and lost circulation are prevalent, it is not practiced within well
abandonment. However, as demonstrated herein, the present invention provides a
significant improvement in abandonment by providing methods for its controlled
placement, mixing and application, providing improvement relating to the
inclusion of
packable gradated swellable and non-swellable particles with gunk to form a
fluid
placeable pseudo packer pressure bearing particle matrix within annuli.
Various
formulations of gunk can be summarised, for example, by a first fluid mix of
organophillic clay of 5% to 60% by weight of composition mixed with a
hydratable
gelling agent, sufficient to suspend the clay concentrations, and with
weighting
material and alkaline source components placed within 15% to 60% water by
weight
of composition. The first fluid can be then mixable and chemically reactable
with at
least a second fluid comprising 15% to 60% water by weight of composition, and
mixed with either: i) a hydraulic cement of 15% to 75% by weight of
composition or
an oil based mud comprising 15% to 60% oil by weight of composition, mixed
with
weighting materials of 15% to 75% by weight of composition. Accordingly,
various
fluid rheological controllable embodiments of the present invention may
provide a
gradated mix of packable swellable and/or non-swellable gradated particles
with gunk
to provide a fluid deployable pressure bearing packing or matrix with gunk
filled pore
spaces.
[000181] As the gunk (32) member is a cementation and/or gelatinous mixture
with
optional packable swellable and/or non-swellable gradated particle mixes, it
can form,
for example, a pressure bearing packer embodiment, that relies on the friction
between the reacted gelatinous rheological fluids and/or particles, such that
the gunk
members can be selectively and readily placed, used and then removed with
chemicals that disperse the bonds, causing the gelatinous rheology, for
reducing the
swelling of, e.g., elastomers between hard particles and/or for dislodging the
gels or
particles with, e.g., wireline deployable motors, tractors and bits of the
present
inventor and/or other means.
[000182] Figure 22, an elevation cross section diagrammatic view, illustrates
the left
CA 2841144 2019-02-12
half of a well conduit for a method (1F) embodiment, with a set (2F) of fluid
members
and separating plug (221A, 221B) members that can be usable with, e.g.
production
tubing (11), within another conduit. For example, production casing (12) can
be used
where the method (1F) involves circulating the fluid column (31C) between the
innermost bore (25) and the production annulus (24), and through, e.g., the
lower end
of the tubing (11), a placed boring bit engagable conduit member (e.g. 2B12 of
Figures 112-116) or penetrations, thus, displacing a lighter and less dense
fluid, such
as water, with a more viscous and dense fluid, e.g. a well barrier element
(3F) like
cement (20) or a annulus engagable theological member (2F) like gunk (32),
within
the portion of the well (4F) to be used and/or abandoned. The formation of a
gunk
(32) to, e.g., support a subsequent placement of cement, can occur by using
two
displacements, with the first step of displacing the water with a saturated
highly
concentrated hydrated organophillic clay fluid, and a second step of mixing
the
reagent fluid comprising dense and viscous oil based mud, similar to that used
in
drilling operations, to, e.g., provide a viscous gunk (32) capable of limited
pressure
sealing and/or support of another dense fluid, e.g. cement.
[000183] Referring now to Figure 23, a diagrammatic elevation cross section of
the left
half of a well conduit is depicted, showing a method (1G) embodiment and fluid
members (2G) usable with, e.g. production tubing (11), within another conduit,
such
as production casing (12), where the aim can be to circulate the fluid column
(31C)
between the annulus (24) and innermost bore (25) to place a rheology
controllable and
annuli placcable fluid member (2G), e.g., a swellable gradated particle mix
(33), to
abandon a portion of the well (4G), with the lower bridge across the larger
conduit
(12) walls comprising, e.g., a gunk member (32) or a piston member (e.g. 2AG
of
Figure 56). The swellable gradated particle mix (33) can be deployed by
circulating it
into position and allowing the particles to fall onto a supporting member. A
gunk
fluid member (32 of Figure 22) deployed in this manner may involve pressure
injecting the gelatinous mixture downward into, e.g., any leaking portions of
a
crushing piston arrangement (e.g., 2AG of Figure 56 or 2X2 of Figure 46).
1000184] Figure 24 is a diagrammatic elevation cross section of the right half
of a well
conduit, which depicts a method (1H) embodiment usable with fluid members (2H)
within, e.g. the intermediate casing (15) and with a smaller conduit, e.g. the
56
CA 2841144 2019-02-12
production casing (12), which has been expanded outwardly into the
intermediate
casing annulus (24A) by a piston member (2H1). The method (1H) involves
bullheading fluids of the circulatable fluid column (31C) past the partial
closure,
caused by the deforming of the casing (12) inward by the piston member (2H1),
using
a well barrier element member (3H), e.g. cement, or a rheology controllable
and
annulus placeable fluid member (2H3), e.g. gunk (32), to close and seal the
annulus
(24A) at the closure (2H1). The fluid mixtures can enter through a boring bit
engagable conduit member (2H2), e.g. 2B12 of Figures 112-116, or through
penetrations in the inner conduit (12) with, e.g., churning (225) and wispy
flow (227)
at the intersection, with denser fluid falling in annular flow (226).
[000185] Referring now to Figure 25, a diagrammatic elevation cross section
view of a
method (11) embodiment and fluid member set (20, which can be usable with a
well
conduit, e.g. production tubing (11), within another conduit, such as
production casing
(12), where the portion of the well to be used and/or abandoned (411, 412)
comprises
the tubing (11) and casing (12) walls and a leaking bridge (411) across the
walls of the
casing.
Conventionally, placing cement (20) involves mixing the chemical
components at the surface and transporting them downhole with any misalignment
of
fluid levels (311), equalized (312) by the u-tube effect of the cements higher
density.
The method (H) for placing a rheological controllable fluid, e.g., gunk (32)
and gunk
particle mixes (32, 33) comprises separately placing fluid well barrier
elements (311-
312) or fluid annulus engagable members (211-212), e.g. cement (20), gunk (32)
or
swellable gradated particle (33) components separated by plugs (221A-221C)
that fall
after conveyance through the innermost passageway (25); and allowing mixing of
the
fluids in the annulus (24) with, e.g., churning flow (225), caused by rocking
the inner
(25) and annulus (24) passageways upwards and downwards (211) with alternating
pressures applied between the passageways at the wellhead openings to the
annuli;
followed by allowing the fluids to u-tube or equalize (212) at similar levels
with
density and/or to apply equal pressure from above to compact, e.g., gunk into
the
portions (411, 412) of the well, to be used and/or abandoned for assisting the
packing
of the gradated hard particles (191 of Figure 26A) the mix until the swelling
intermixed gradated particles (192 of Figure 26A) support, e.g., cement, above
the
gunk.
57
CA 2841144 2019-02-12
[000186] Figure 26 is a diagrammatic elevation cross section view of method
(1J) and
member set (2J) embodiments comprising boring bit engagable conduit,
separating
placement plug, rheological controllable fluid gunk and packable gradated
particle
mix members, usable with well conduits comprising, e.g., the intermediate
casing
(15), production casing (12) and tubing (11), where a plug (25A) is installed
within
the innermost passageway (25), connected to surrounding annuli (24, 24A) by a
boring bit engagable conduit member (2J5, 2J6 similar e.g. to 2AQ1 of Figure
66)
penetration, with an expandable burstable seal sleeve (2J4 similar e.g. to
2AR2 of
Figures 67 and 68) across the upper perforating gun or boring bit member
penetrations (129). The lower boring bit engagable conduit member or
penetrations
were placed, then the lead and tail components of, e.g., a gunk (32) pill,
separated by
the lower separating placement plug members (221A, 221B), were transported by
circulating the circulatable fluid column (31C) to mix as the fluids separated
from the
segregating plugs, once they entered the penetrations and annuli, to form a
rheological
controllable fluid gunk (32) annulus engagable member (2J1) in one annulus
(24) and
optionally (2J2) in the surrounding annulus (24A).
[000187] The upper penetrations and second plug train can be placed after
placing the
gunk or the expandable burstable sleeve, which is burst during packing and/or
mixing
of the gunk. The second plug train, with (221C 221D) separating members
containing
a swellable gradated particle (33) member (2J3), can be circulated downward
using
the fluid column (31C), by pumping through the innermost passageway and taking
returns through the upper penetration (236 or 129) to release (222), e.g., the
swellable
gradated particles (2J3) through the upper annulus accesses (236 or 129) to
the
production annulus (24) and, optionally, any surrounding annuli (e.g. 24A),
where the
particles (33) are supported by the gunk until their swelling from the
hydrocarbons in
the gunk, supports their mass, providing one or more sealed annuli, thus
closing and
pressure sealing the lower portion (4J) of the annuli to placement and support
of a
more permanent well barrier element member (3J). Member placement within the
annuli does not remove access to the innermost bore (25) because mixing
occurred in
the annulus, and the plug members (25A, 221A-221D) may be of a retrievable or
boreable type. Plug members, whether axial movable separating plugs (221A-
221D)
or supporting plugs (25A), can comprise any form of pumpable conventional
segregation means during placement, such as pumpable foam balls, cross-linked
58
CA 2841144 2019-02-12
polymer fluids, darts and/or convention coiled string deployable devices. For
example, a first portion of a rheological member can be placed using the
circulating
column, with the remaining second reagent portion of the member deployed with
a
conventional slickline bailer, that can be conveyed on a coiled slick line
string,
through a stagnant circulatable fluid column to dump the reagent from the
bailer onto
the first portion. Thereafter, the bailer can be removed and eireulatable
fluid column
flow orientation cycled, if further mixing is required.
[000188] Additionally, chemical injection, using penetrations or embodiments
of the
present invention, may occur into or under the annuli gunk (32) and particle
(33)
placed members (2J1-2J3) to remove the unsettable fluid seal when required.
Hence,
fluid circumferential engagable members (2J1-2J3), e.g. gunk, are placeable,
usable
and removable when required.
[000189] Figure 26A depicts a diagrammatic view of a method (1K) embodiment
that
can be usable with the rheology controllable and annuli placeable fluid member
(2K)
embodiment, comprising a mix (2K1-2K4) of non-swellable, hard gradated
particles
(191) for forming a bridging matrix across the wall portions (between 4K1 and
4K2)
of one or more conduits to abandon a portion of a passageway and/or
potentially
support a permanent well barrier element (3K). Hydrocarbon or water swellable
gradated particles (192) within a passageway may have pores between the harder
particles (191) of the gradated mix (2K), that can be filled by the swelling
particles
(192) that, when exposed to hydrocarbons, or e.g. water, form a bridging seal,
and/or
other substances, e.g. the low gravity solids of an oil based mud used in a
gunk or
other conventional lost circulation materials (LCM), such as graphite or
calcium
carbonate, which are also usable within pore (131) spaces. Gradated hard
particles
(191) may be consistent throughout or partially comprised of swellable
materials
(192), e.g., a hard round particle member (2K2) may be coated in a swellable
material, or vice versa, having any shape, e.g., a square particle member
(2K3) and/or
pentagonal particle member (2K4) may consist of layers and/or corners, and/or
any
irregular sand and/or gravel shaped or sized particles with sharp or rounded
edges to
form a settable/swellable hardened matrix across a wall of conduit or
passageway
after swelling of the swellable materials and/or filling of the pore spaces
within the
matrix. Dependent on the deployment and reactive reagent swelling fluids,
particles
59
CA 2841144 2019-02-12
may be, e.g., water or hydrocarbon swellable, and particles may be coated with
a film
to inhibit exposure to the swelling reagent fluid during transport.
[000190] Figure 27 depicts an elevation view of the left half of a slice
through a well
and strata, depicting embodiments of a method (1L) usable with a set of
members
(2L) comprising logging tool (2L1), axially slideable annular blockage bypass
(2L2)
and annulus boring access (2L3) members. The Figure illustrates the
abandonment of
an onshore or offshore wellhead (7), above ground level (121) or mudline (122)
and
being disposed below the ocean's surface (122A). A annulus boring access
member
(2L3), e.g. 2AD of Figure 53, has been used to bore through conduits (11, 12)
engaged axially below the wellhead (7) to access annuli (24, 24A), within
which a
logging tool member (2L1) was used to measure the presence of primary well
barrier
elements (3L3, 3L4) about casing (12, 15). Having determined the necessary
subterranean depths, placement of a well barrier element (3L2), to meet
published
industry recommended minimum guidelines (211-220 of Figure 15), is attainable
with
an axially slideable annular blockage bypass member (2L2), e.g. (2M) of
Figures 28
to 30, installed to provide flow about a production packer (40), allows a well
barrier
element (3L1) to be bull-headed into the permeable open hole producible zone
(95E)
by using the cireulatable fluid column (31C1, 31C2), circulated down (31C1)
the
inner passageway and taking returns through the annuli (24, 24A) or down
(31C2) the
annuli and up the inner passageway (25), to place the second well barrier
element
(3L2). The method (1L) abandons the well's lowermost portion (4L1) and
intermediate (4L2) portion, above the production casing shoe (16). During the
process, the strata may have been fractured (18) with hazardous waste
materials and
fluids injected (36W) through the intermediate annulus (24B) into the strata,
with the
following step of the method (IL) being the abandonment of the fractured well
portion (4L3).
[000191] Figures 28 to 30 are diagrammatic elevation views of a slice through
a
subterranean well and strata showing embodiments of a method (1M) for using an
axially slideable annular blockage bypass member (2M), with break lines
showing
removed sections of the well and strata. The Figures illustrate a portion (4M)
of the
well, between break lines, to be used and/or abandoned. The member (2M) is
placeable with a coiled string (187) running tool (187A), relative to upper
(129U) and
CA 2841144 2019-02-12
lower (129L) penetrations in the production conduit (11) within the cemented
(20)
production casing (12), with string tension and a setting pressure (31C3)
applied to
engage the tool slips (e.g. 180 of Figure 93) of an engaging tool portion
(2ME) to the
inner conduit (11). Thereafter, the running tool (187A) can be retrieved with
the
coiled string (187) by, e.g., applying pressure to the innermost bore (25)
against the
closed wellhead valves of the annulus (24), with upward jarring of the
assembly. The
axially slideable annular blockage bypass member (2M) can be operated by
circulating down (31C2) the annulus (24) and up the inner most passageway
(25),
through the upper penetrations (129U) and ports (2MP) in the slideable section
and
the engaging portion (2ME) of the member (2M), engaging the tubing (11). The
circulated fluid column (31C2) can actuate the slideable portion (2MS) of the
member
(2M), upward, to disengage the lower penetrations (129L) for circulating
through
ports in its sliding portion. Alternatively, the member (2M) may be operated
by
circulating down (31C1) the inner passageway (25) and up the annulus (24),
through
the upper (129U) and lower (129L) penetrations between the member (2M) and the
production tubing (11), wherein the pressure of the circulated fluid column
(31C1)
can actuate the slideable portion (2MS) of the member (2M) downward to engage
the
lower penetrations (129L), thus closing the ports (2MP) within its slideable
portion.
The method (1M) can be completed when a well barrier element (3M) is
circulated
(31C1) into the bore (25) and annulus (24) to abandon a portion (4M) of the
well.
[000192] The member (2M) may be replaced, within the method embodiment (1M)
with
a cable-compatible, rig-less operable, non-slideable straddle that can cover
penetrations above (129U) and below (129L) the production packer (40), to a
fixed
circulation path, for cleaning walls of conduits and placing cement. The
axially
slideable annular blockage bypass member (2M) can represent a significant
improvement over a fixed conventional straddle because it can be usable to
hydraulically change the circulation path to clean the tubing with reverse
circulation
and/or to hydraulically jar and pack, e.g., LCM, gradated particles mixes
and/or piston
members into an annulus and/or permeable strata formation to seal the
formation,
while minimising the risk of losing the ability to circulate.
[000193] For example, when circulating as described in Figure 29, the
production valve
can be closable on the valve tree that is engaged to the wellhead to cause
pressure to
61
CA 2841144 2019-02-12
be applied to the bottom of the slideable part (2MS), pushing it downward,
thus
causing circulation through the lower penetration and hydraulically jarring,
albeit
lightly for the purposes of packing, the production annulus under the packer,
with
alternating opening and closing of the valve tree master or production valve
during
said jarring. Alternatively, when circulating as described in Figure 30, the
annulus
valve may be closed to hydraulically jar the portion of the well below the
tubing (11).
Finally, alternating between the circulations in Figures 29 and 30, combined
with
closing valves for light hydraulic jarring of packings, allows the placement
and
compaction or packing of a rheological controllable fluid, gradated particle
mixes,
swellable materials and/or LCM into a permeable formation until the formation
locks-
up, or quits taking fluids, after which the circulating path may be re-
established for
controlled placement of a well barrier element, such as cement. In
conventional
practice of bull-heading, this is not possible, because when the cement is
bull-headed
to a formation it "locks up," with no means by which to re-establish
circulation or
clear the tubing. Hence, access is lost and the conventional practice of
bullheading
represents a significant risk that is avoidable with the use of the method
(1M) for a
conventional straddle member or an axially slideable annular blockage bypass
member (2M). The slideable member can allow an intermediate circulation point
above the packer to remove a heavier fluid, e.g., cement, that for any reason
stops
flowing, so as to remove the cement before it sets with a second reverse
circulation to
restore the circulation passageways, after first removing the excessive
hydraulic head
of the heavier cement above the packer.
[000194] Additionally, straddles and axial slideable straddles can be
placeable through
the innermost bore (25) and can be usable in an enlarged innermost bore (25E,
25AE
of Figure 72) to, e.g., circulate around a placed annulus blocking member or a
collapsed portion of casing, using the increased diameter capabilities of
expandable
packers (e.g. 2X2 of Figure 46 or 2K of Figure 38).
[000195] Figures 31 to 34 show diagrammatic elevation cross section views of
embodiments of a method (1N) usable with a set (2N) of members comprising an
axially slideable annular blockage bypass (2N2), annular piston (2N4),
rheology
controllable and annuli placeable fluid (2N1, 2N3, 2N5). boring bit engagable
conduit
(2N6), logging (2N8) and circumferential shredding and milling (2N7) members.
The
62
CA 2841144 2019-02-12
Figures depict a slice through the strata and a well's perforated (129)
production
casing (12), engaged with a permeable formation (95F) formerly produced
through a
conduit (11) engaged to the casing (12) with a packer (40), with production
equipment
(11A), e.g. a nipple or valve, forming part of the production string (11).
[000196] The lower portion (4N1) of the well can be used and/or abandoned by
cutting
the lower end of the conduit (11) with, e.g., a rotary cable tool cutter (175
of Figure
75) for reliable cement placement about the packer (40), with well barrier
element
(3N1) comprising a swellable particle cement gunk fluid member (2N1), e.g.
(2K1) of
Figure 26A, placed with separating wiper plugs (221A-221D of Figure 26) and
mixed,
using various flow patterns (223-227 of Figure 22), dependent on the rheology
and
degree of turbulent flow caused by the pumping rate when bullheading into the
permeable zone (95F). The clay based gunk and swellable graded particles can
be
usable to form a hard particle matrix that can react with each other during
mixing
and/or after if, e.g., any hydrocarbons attempt migration through the mixture,
to form
a barrier (3N1) to support a further permanent barrier (3N2). Alternatively,
LCM,
gradated particles, other conventional packable materials or embodiments of
the
present invention, may be placed, hydraulically jarred, and packed by an
axially
slideable annular blockage bypass (2N2).
[000197] The intermediate well portion (4N2) of the casing (12) may be
cemented (20)
within the strata bore (17) by the placing of upper (129U) and lower (129L)
penetrations in the tubing (II), then placing an axially slideable annular
blockage
bypass (2N2) across the packer (40) and penetrations to, in use, controllably
place a
permanent well barrier element (3N2) above the rheology controllable and
annuli
placeable fluid (2N1). Alternatively, packable materials may replace the
member
(2N1) with the axially slideable member (2N2) used to hydraulically jar and
pack the
materials into the permeable perforations (129), to the reservoir, until solid
support for
placement of the well barrier element (3N2), that prevents gas migration
during
setting of the cement (212 of Figure 15), is achieved so as to control cement
placement.
[000198] The upper well portion (4N3), comprising the intermediate (15) and
uncemented production (12) casing within the strata bore (17), may be used
and/or
abandoned by cutting the tubing (11) and using an annular piston (2N4),
comprising,
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CA 2841144 2019-02-12
e.g., a conventional cement umbrella with a rheology controllable and annuli
placeable fluid member (2N3) or conventional graded particle abandonment
material
member, which can be placed using various methods (1G of Figure 23, e.g.), or
a clay
based gunk embodiment that can be placed, e.g. with method (1I) of Figure 25,
to
compress the conduit (11) and associated downhole equipment (11A) under the
annular piston (2N4), axially downward, by placing pressure on the
circulatable fluid
column (31C) for the inner bore (25) and/or production annulus (24), to allow
space
for use of a logging member (2N8). In this instance, the logging member (2N8)
found
no cement behind the production casing (12), and a pinning boring bit
engagable
conduit (2N6), e.g. (1Z) of Figure 49, is usable to engage and support a well
barrier
element (3N4) and to secure the conduits (11, 12) during removal of the lower
ends
with a circumferential shredding and milling (2N7) member, e.g. (2BF'I-2BP4)
of
Figures 128 and 129, to place the well barrier element (3N4), thus abandoning
the
portion (4N3) above the cemented casing (15) shoe (16).
[000199] Figures 35 to 37 show elevation views of a slice through a
subterranean well
passageway and strata, with break lines representing removed portions, and
depict
embodiments of a method (10) usable with a set (20) with a circumferential
engagable member (201) comprising any conduit cutting device, two annular
piston
members (202, 203), and a logging tool member (204), depicting placement of,
e.g.
a conventional wireline plug, that can be usable as a annular piston member
(202)
and engagable with the annulus (24), after using the circumferential engagable
cutting
member (201), e.g. (175) of Figure 75, to cut the tubing (11U, I IL). The
piston
(202) can be usable as a well barrier element (301) and can be usable to
compress the
tubing (11L) below the piston member (202) for placement of a second piston
member (203) or, e.g. a rheology controllable and annuli placeable fluid above
the
compressed tubing to form an enlarged innermost passageway space (25E) for
cement, in addition to supporting the cement placed above the piston (202) and
preventing it from falling through the annulus (24) below.
[000200] The second piston member (203) may comprise a loose bag made of,
e.g.,
Kevlar, to prevent puncture from sharp edges within the well bore and can be
filled
with a rheology controllable and annuli placeable fluid member of gradated
hard and
swellable materials (2K of Figure 26A) that may fluidly move loosely within
the bag
64
CA 2841144 2019-02-12
to allow deployment through the innermost passageway (25) using pressure from
the
circulatable fluid column (31C). The force of the fluid column can be further
usable
to burst a disc (2K ID) fitted with a screen to allow a reagent fluid of, e.g.
water or
hydrocarbons, to cause swelling of the inner gradated particle mix, with a
mesh to
prevent escape of the gradated particles (2K of Figure 26A). Pressure applied
to the
expanded or swollen bag can force compressional bending or crushing of the
tubing,
which may also have been cut and weaken prior to placing the first piston
(201),
until, e.g., sufficient space is created for use of a logging tool member
(204) to
determine if a well barrier element (302), such as cement may be placed, using
the
circulatable fluid column (31C), to abandon the lower portion (40) of the
well.
[000201] Figure 38, a diagrammatic isometric view of a method (1P) embodiment
usable with an annular piston member (2P) embodiment, with segmented portions
and
a relief valve, illustrates abandoning an intermediate casing (15) portion
(4P) of a well
without cement, within the intermediate annulus (24A), by compressing the
production casing (12) to form an enlarged innermost passageway (25E) with a
segmented (2PS1, 2PS2, etc...) deformable bag that can be transportable
through an
innermost passageway (e.g. 11 of Figure 41) and used to retain a piston shape,
and/or
membrane filed with gradated and/or swellable particles (e.g. 2K of Figure
26A). A
pressure regulated one way valve (2PV) can be added to allow fluid movement
through the bag piston member (2P) to, e.g., allow a reagent fluid, e.g.
water, to enter
the segments and chemically react with swellable materials (2K of Figure 26A)
and/or
allow fluid, from below, to exhaust upward when being forced down by pressure
of
the circulatable fluid column (31C), for placement of a well barrier element
(3P). In
this instance, the inner conduits (11 of Figure 36) have been cut with the
lower end
(11U of Figure 37) compressed downward, after weakening of the casing (12)
with
apparatus described in the referenced application GB1011290.2, and/or using a
tractor
embodiment of the present invention to weaken or push the conduits downhole.
[000202] Figure 39 shows a diagrammatic elevation view of a slice through a
subterranean well and strata and depicts embodiments of a method (1Q) usable
with
an annular piston member (2Q), with break lines representing removed portions.
The
Figure shows the abandonment of a portion (4Q) of a casing (12) that is
cemented
(20) within a strata bore (17), after the piston member has exited a cut
conduit (11U).
CA 2841144 2019-02-12
The piston member (2Q) comprises a deformable bag (2QB) engaged with, e.g.,
slips
(2QS), to a conduit (11L) and filled with conventional gradated particles,
e.g.,
gradated sand or cement, or a gradated swellable particle member (2K of Figure
26A),
whereby a breakable membrane may be used to temporarily isolate, or a
deployable
tool may be used to engage, either the bag or conduit connection (2QC) to
instigate a
swelling reaction with the mixing of a swellable gradated mix and reagent
fluid,
during or after said bag is deployed through the innermost passageway (25) of
the
upper end of an installed conduit (11U) that has been cut. The engagement
(2QS)
holds the lower end of the cut conduit (11L), and applied pressure from the
circulatable fluid column (31C) forces it downward by, e.g. crushing or
helically
buckling the lower conduit column (11L) until the bag exits the upper conduit
(11U)
and falls into the annulus (24) within the casing (12). Thereafter, the
trapped fluid
can be released through the pressure relief one-way valve (2QV). After logging
of the
cement (20) behind the casing (12) and placement of a well barrier element
(3Q),
comprising, e.g., a cap or plug to isolate the valve (2QV) engaged to the
upper
connector (2QC), cement may be placed on top of the entire member (2Q).
[000203] Figure 40 is a diagrammatic elevation cross section view with break
lines
representing upper and lower removed portions of a slice through a
subterranean well
bore, which shows a method (1R) embodiment usable with a set (2R) of a
straddle
pipe member (2R2) or an axially slideable annular blockage bypass, e.g. (2M)
of
Figures 28 to 30, adapted with annular piston member (2R1) embodiments. The
annular piston member (2R1) embodiments can be usable in combination, as a
production packer, to form another member (2R) embodiment to fluidly isolate a
lower portion of the well (4R) with a well barrier element (3R) comprising a
deformable bag (2RB) and/or another barrier, e.g. cement, axially above
supported by
the bag. A lower piston portion (2RL) with a bag (2RB), filled with package
conventional gradated material or filled with swellable gradated packable
materials
capable of isolating fluid flow in the annulus (24) after falling from the
bore of the
upper cut conduit (11U) and engaging the circumference of the casing (12), is
further
engaged (2RS) to the lower end of a cut conduit (11L). After forcing the
piston
member portion (2R1) downward with the circulatable fluid column (31C),
logging
can confirm cement behind casing and a straddle member portion (2R2) and upper
straddle portion (2RU) may be engaged to the piston member portion (2R1) and
upper
66
CA 2841144 2019-02-12
conduit (11U) to form a pseudo production packer with an internal bore and
blocked
annular space.
[000204] Figure 41, a diagrammatic elevation view of the left half of a slice
through a
surface (121) or seabed (122) subsea well, below the ocean surface (122A) and
subterranean strata, depicts embodiments of a method (1S) usable with annular
piston
(2S1), rheology controllable, and annuli placeable fluid (2S2), swellable
expandable
mesh membrane members (2S3) and jarring (2S4) members. The Figure shows
placement of a well barrier element (3S) for abandoning a lower portion (4S)
of the
well. As shown, operations begin with cutting the tubing (11U, 1 1 L), placing
a piston
member (2S I), and using applied pressure to the circulatable fluid column
(31C) to
compress the lower portion of the tubing (11 L) secured to the casing (12),
which is
cemented (20) within the strata bore (17), with a production packer (40) and
casing
(12) shoe (16) above a producible zone (95E). The annular space (24) is
increased,
both, by applied pressure to the piston (2S1) and by jarring the fluid column
(31C)
with a jarring member (2S4), comprising any conventional jar suitable for the
task or
an embodiment of the present invention, e.g. (2T2) of Figure 42, operated with
the
innermost passageway (25) conduit (11U).
[000205] A logging member can be usable, then, within the enlarged inner
passageway
space (25E) above the piston member (2S1) to determine the primary cement (20)
level and/or bond between the strata wall (17) and the production casing (12),
thus
allowing selective placement of a lower penetration (129L) through the casing
(12) at
the required depth. For subsea wells, the annulus access passageway to annuli,
other
than the production annulus (24), are generally not readily available. Thus
the
intermediate annulus (24A), between the production casing (12) and
intermediate
casing (15), is not easily accessible. On surface wells, the annulus access
valves may
also be unusable if, e.g., the valves are seized or were never installed. Such
conventionally inaccessible annuli can be accessed with, e.g., a boring member
to
penetrate the wells of the conduits.
[000206] Upper penetrations (129U) through the production tubing (11U) and
casing
(12) were then placed and a swellable expandable mesh membrane member (2S3)
was
placed to cover the penetrations in the tubing (11U), so that a circulation
path is
possible through the intermediate annulus (24A), using the circulatable fluid
column
67
CA 2841144 2019-02-12
(31C). Weighted abrasive cleaning and/or viscous fluids can be usable to choke
the
pore spaces of the expandable mesh or, e.g., a cleaning reagent may activate
swelling
of a membrane to close mesh pores, after which circulation through the
passageways
can continue until the surfaces are sufficiently clean and wettable to provide
a good
bond with the subsequent fluid well barrier element (3S), potentially using
the jarring
member (2S4) to help initiate circulation within the intermediate casing (15)
annulus
(24A), after which the well barrier element member (3S) is placed.
[000207] Referring now to Figure 42, a diagrammatic elevation cross section
view
through a subterranean well and strata, with break lines representing upper
and lower
removed portions, is shown and illustrates embodiments of a method (1T) usable
with
a member set (2T), comprising rheology controllable and annuli placeable fluid
(2T1),
jarring (2T2), annular piston (2T3) and swellable expandable mesh membrane
(2T4)
members. A casing leak (228B) to a subterranean fracture (18) prevents
applying
sufficient pressure (229) to force the piston member (2T3) axially downward
within
the casing (12) with the circulatable fluid column (31C). A swellable
expandable
mesh membrane member (2T4) can be placed across the tubing leak (228A) to
allow
the pressurization of the tubing (11U) to drive a hydraulic jar member (2T2)
that can
be placeable within the inner passageway (25), and can be operated with
deployment
string (e.g. 187 of Figure 9) tension and fluid pressure (229) to act against
a rheology
controllable fluid member of, e.g., circulatable viscosifying materials and
LCM, or a
gelatinous gunk usable to seal the leaking (228) fracture (18) and any leakage
(228C)
about the piston (2T3) member for compressing the lower tubing (11L). With
sufficient space created by driving the piston downward, a logging member can
be
used to measure the cement bonding behind the casing (12) and a well barrier
element
(3T), such as cement, can be placed for abandoning a portion (4T) of the well,
wherein excess viscous fluids and LCM are circulated out or gunk is removable
using
a rotary cable configuration with, e.g. a tractor member, wherein after
cleaning of the
conduits, the piston (2T3), with any remaining viscous fluid or remaining gunk
(2T1)
members above the crushed section, can be usable to support the barrier (3T)
placement to meet the appropriate industry practices (211-220 of Figure 15).
[000208] The use of rheology controllable fluid (e.g. 2T1) and swellable
expandable
mesh membrane (e.g. 2T4) members, comprising, e.g., conventional high
viscosity
68
CA 2841144 2019-02-12
materials, LCM, conventional expandable conduits and/or embodiments of the
present
invention, can be usable within any of the present invention method
embodiments
(1A-1BU of Figures 16 to 147) for accessing and abandoning wells where during
use,
over the life of the well, its structural integrity may have been weakened or
removed,
thus preventing full pressure control. A rheology controllable fluid and/or
swellable
expandable mesh membrane members can be usable to temporarily or permanently
reinstate pressure control by, e.g., placing a well barrier element (3A-3BU of
Figures
16 to 147) to abandon a portion (4A-4BU of Figures 16 to 147) of a well.
[000209] The jarring member (2T2) can be operable and usable, e.g., with cable
string
(187) tension to lift the lower portion of the jarring member piston and to
compress its
acceleration spring (144), where it is latched into the upper portion and
engaged to the
tubing (11U), after which pressure may be applied to the inner passageway (25)
to
release a fluid pressure pulse (230), that is increased by the release of the
compressed
spring, with the jar piston acting against the rheological fluid member (2T1),
engaged
with the piston member (2T3), to further drive it down with a fluid hammer
effect.
The upward reflected fluid hammer effect (230U) can be further controllable
by, e.g.,
placing a pressure relief valve on the annulus outlet (13 of Figure 16 or 13A
of Figure
17).
[000210] Figure 43 shows a diagrammatic elevation view of a slice through a
portion of
subterranean wellbore and strata and depicts a method (1U) embodiment usable
with
the member set (2U) embodiment, comprising a jarring (2U2) embodiment,
conventional jarring member (2U3) and annular piston member (2U1 for
illustrating
that a significant length of enlarged innermost passageway (25E), represented
between the break lines, can be formable for deep wells of, e.g., 10,000-ft or
3,000
metres, with long conduit strings capable of being compressed, buckled,
crushed,
shredded, milled or otherwise demolished. If, e.g.,
accounting for various
subterranean parameters, such as inclination and frictional resistance within
the casing
(12), the lower end of a cut conduit (1 IL) can be compressible by 25% over a
length
of 1000 metres, an enlarged inner passageway space of 250 meters can be usable
then
for logging of cement (20) behind casing (12) and placement of a well barrier
element
member (3U) to abandon a portion (4U) of the well, whereby the adverse effects
of
various subterranean parameters, e.g. dog-legs, inclination and friction, may
be
69
CA 2841144 2019-02-12
lessened by various jarring members (2U2, 2U3).
[000211] The jarring member (2U2), shown as a dashed line to represent any
usable
configuration, also applies to explosive charge hydraulic jarring effects upon
a piston
member (2U1) to displace any conduits (11A) axially downward, thus providing
an
enlarged innermost passageway (25E). The possible usable configurations
include,
but are not limited to: i) a compressed air or gravity deployable ram type
jarring
arrangement, similar to a pile driver engaged to the top of the wellhead or
valve tree
for jarring the entire fluid column, ii) an explosive charge tool using a
series of light
explosives capable of exploding within and jarring the circulatable fluid
column
(31C) without incurring lateral or upward damage to well components, and iii)
sudden
release of displacing gases within the circulatable fluid column comprising,
e.g.,
compressed air and/or nitrogen that suddenly releases the displaced liquid
fluid
column, allowing a jarring plug or slug to accelerate downward while releasing
gasses
upward. The jar functions by suddenly releasing the energy stored in the
deployment
string, associated subassembly and/or circulatable fluid column (31C) when the
jar
fires. In a manner similar to using a hammer, kinetic energy is stored in the
hammer
as it is swung and suddenly released to the nail and board when the hammer
strikes
the nail. The method (1U) comprises the use of a conventional mechanical or
hydraulic jarring member (2U3) and/or a jarring member embodiment (2U2) to
further compress the piston member (2U1), e.g. (2X2) of Figure 46, where a
conventional jarring member (2U3) may be engaged with the piston member (2U1)
or
a fluid hammering jar (2U2) engaged to the circulatable fluid column (31C)
jarring
the piston member (2U1).
[000212] Referring now to Figure 44, a diagrammatic elevation cross section
view with
break lines representing removed portions is shown, and the Figure depicts a
method
(1V) embodiment of separate portions of a jarring member (2V) embodiment
usable
to compress members and/or well barrier elements (3V), showing the jar piston
(2V1)
prior to firing in its latched position, above the dashed line representation
of the jar
piston (2V2), during firing. A piston housing (182) provides a cylinder for
the jar
piston (2V2), usable with seals (66), to hold the energy from pressurizing
(229) and
compressing the circulatable fluid column (31C) above and against the piston,
e.g.,
with fluid communication through an internal bore of the travelling rod (184)
from the
CA 2841144 2019-02-12
fluid column until the springs (144B), holding the latching dogs (186), are
urged away
from the travelling piston rod (184) to release the compressed energy of the
fluid
column and fire the jar piston, creating a fluid pulse (230) with its motion,
equivalent
to a fluid hammer with its initial motion assisted by an accelerating spring
(144A),
wherein the fluid pulse passing through orifices (59) of the housing (182) can
be
usable to fluidly impact or jar downhole apparatuses, e.g. 203 of Figure 36,
axially
downward.
[000213] A viscous rheological controllable fluid member may be placed within
the
annulus (24) between the tubing (11) and casing (12) to further increase the
axially
downward jarring force by retarding fluid movement and compression upward.
Line
tension of the string (187) can be usable to hold the jar (2V1) in place while
pressure
(229) can be used to engage the slips (180) and to anchor the jar to the
circumference
of the conduit (11), after which the travelling rod (184) can be usable to re-
engage the
latching dogs (186), after the jar has fired. Pressure (229) can be used to
keep the
slips (180) engaged and to push the travelling rod past the dogs (186) springs
(144B),
with the piston lying against the bottom of the orifice (59) housing (182).
[000214] Figure 45 depicts a diagrammatic elevation view of a slice through an
installed
well conduit, with break lines representing a removed portion of a method (1W)
embodiment. The Figure shows upper and lower portions of a jarring member (2W)
embodiment, and illustrates the jar housing (182A) in the upper portion of the
Figure
and a jar piston (2W2) that has fired and now rests on the bottom of the
travelling
piston rod (187) at the lower portion of the Figure. The jar piston (2W2)
travels along
the jar rod (184) when firing, with the rod (184) lifting the piston (2W2)
after firing,
for relatching into the housing (187A). Through repeated firing and
relatching, the
member (2W1) can be usable to compress members and/or well barrier elements
(3W), e.g. conventional cement mixtures, rheology controllable gradated
particle
and/or organophillic clay and cement members, to abandon a portion (4W) of a
well.
[000215] The jar (2W1) may be re-latched by pulling line tension on the string
(187) to
lift the travelling piston rod (184) and piston (2W2) at its lower end to
engage and
latch the dogs (186) within the housing receptacle (2W3) recess (102). During
latching and firing, pressure may be applied through the pressure port (2W4)
to force
the locking pin (2W5) downward, against the locking pin spring (144C). When in
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CA 2841144 2019-02-12
latching position, pressure may be removed with the locking pin (2W5) spring
(144C), forcing the dogs (186) into the receptacle (102) of the housing
(182A). Then,
the travelling piston rod (184) can be axially lowered to prepare the jar
(2W1) for
firing. Repressurizing the circulatable fluid column (31C) above the member
can be
usable to compress the circulatable fluid column, thus storing energy, and
providing
pressure through the ports (2W4) to the locking pin (2W5), which will depress
the
springs (144C), at a definable pressure, and the locking pin to release the
dogs (186)
from the receptacle (2W3, 102) and to fire the piston, which allows the sudden
release
of the stored energy in the compressed fluid to drive the piston and to cause
a fluid
pressure pulse axially downward as the piston (2W2) travels to the end of the
rod
(184). The amount of stored energy released is controllable with selective
placement
of the piston, wherein compressing a relatively large volume of fluid above
the piston
and applying it to relatively small value of relatively incompressible fluid
below the
piston, results in the largest release of energy. As a consequence, the jar
piston (2W2)
can be usable to induce a fluid pulse or hydraulic hammering effect on
downhole
apparatuses axially below when, e.g., the tool is arranged and positioned so
as to place
the lower end of the travelling rod at rest on conduits, apparatuses or piston
members
being jarred, so that the piston travels a short distance to an intermediate
stop
engagement on the travel rod, such that the lower end of the rod delivers a
mechanical jarring force as the piston strikes the intermediate stop
engagement.
[000216] If the slips (180) are extended, e.g., by an expandable centralizer
(2X3 of
Figure 46) that is engagable to the casing (12 of Figure 46) circumference and
the jar
piston (2W2) is usable on the casing (12 of Figure 46) circumference, e.g.,
(2X2) of
Figure 46, the jarring member (2W1) can be usable to hydraulically and/or
mechanically jar on the downhole apparatus (e.g. 2U1 of Figure 43) within an
enlarged innermost passageway (25E of Figure 37). The method (1W) can be
usable
to easily engage the slips (180) with the circumference of the tubing (11) or
casing
(12 of Figure 46) when latching the piston (2W2) to the housing (182A), using
well
pressure against string tension, and to disengage the slips (180) when jarring
upward
using, e.g., a conventional mechanical/hydraulic jar engaged to the upper end
of the
member (2W1), when the circulatable fluid column is not hydraulically
pressurized.
Thus, the member (2W1) can be usable to hydraulically and mechanically jar
upon
conduits and associated apparatuses while chasing the compressed conduits and
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CA 2841144 2019-02-12
apparatus as they are forced downhole.
[000217] Referring now to Figure 46, an elevation view of a slice through two
installed
well conduits, inclined within a directional well, is shown and the Figure
depicts
embodiments of a method (1X) usable with a set (2X) of jarring (2X5 shown as a
dashed line), conventional logging (2X6), annular separation (2X3, 2X4) and
piston
(2X1, 2X2) members supplemented by a rheological controllable viscous fluid
sealing
member (2X7), usable to abandon a portion (4X) of a well. As shown in Figure
46,
an upper (11U, also shown in Figure 42) and lower (11L) conduit is cut and
forced
apart to form an enlarged innermost passageway (25E), by a piston member (2X2)
engaged to the lower end cut conduit (11L) and forced downward by pressure
exerted
on the circulatable fluid column (31C) and a jarring member (2X5) for placing
a well
barrier element (3X). After forming sufficient height (219 of Figure 15) for
placement of a well barrier element, e.g. cement, within the enlarged
innermost
passageway (25E) between the innermost passageway (25) and conventional sized
annulus (24), a logging member (2X6) can be usable to confirm cement (20)
between
the casing (12) and strata bore (17). Geologic records during drilling of the
well may
be used to confirm a strong impermeable formation, with primary cementation
behind
the casing (218 of Figure 15) confirmed by logging (2X6). A hanger (2X4) and
expandable separating member (2X3) can be usable to provide stand-off (211 of
Figure 15) for sealing both sides of the tubing (11U) in cement (217 of Figure
15),
thus embedding (215 of Figure 15) all conduits (11U, 12) in cement, once
placed
through the tubing bore (25) and penetrations (129), using annular flow (226
of
Figures 22 and 24) on the lower side of the casing (12), with the lighter
fluid of the
circulatable fluid column (31C) returning through the upper part of the
annulus (24).
[000218] Figure 47 is a diagrammatic elevation view of an example prior art
flexible
shaft and boring bit (174), showing a rotatable boring bit (174A) on a
flexible (174B)
rotatable shaft that are usable to form bored penetrations of well conduit and
strata
walls selectively through a guiding surface (2Y1, 2Y2 of Figure 48).
[000219] Referring now to Figure 48, a diagrammatic isometric view, showing
embodiments of a method (1Y) usable with a set (2Y) of annulus boring access
(2Y3)
and annular access guiding member parts (2Y1, 2Y2) with only a portion (4Y) of
the
well strata and barriers (3Y, 20) is depicted. The Figure illustrates a
flexible shaft and
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CA 2841144 2019-02-12
boring bit (174) guided by a chamber junction (43) and bore selector (47),
which can
be usable to, e.g., access and/or penetrate a wall of the conduit (11) through
which it
was deployed, including, e.g., any surrounding conduits, and the strata wall
(17) to
place logging members (2Y4) and/or to access a producible zone (95F) for
production
and subsequent placement of a well barrier element (3Y). The flexible shaft
and
boring bit (174) can be rotatable (231), retrievable, and replaceable through
the exit
conduit (39) of the chamber junction (43) and orifice (59) of the bore
selector (47),
which is also rotatable (231A), when not in conflict with the shaft and bit
(174), using
rotational guidance prongs (176) and associated guidance surfaces (176) to
align the
bore selector orifice (59) with the exit bore conduit (39), when the bore
selector (47)
is placed within the chamber junction (43). With reciprocation of the bore
selector
(47), flexible shaft, and boring bit (147), a plurality of selectively
placeable
penetrations through the walls of well conduits and the subterranean strata
may be
carried out.
[000220] Figures 76 and 77, are isometric views of a chamber junction (43) and
a
rotatable bore selector (47), respectively, with dashed lines showing hidden
surfaces
in Figure 77, illustrating that a bore selector can be insertable within the
chamber (41)
of a chamber junction (43) and usable as a selective guiding member with the
orifice
(59) of the chamber junction, and bore selector can be alignable to
selectively access
an exit bore conduit (39). For example, piston, separating, fluid, flexible
shaft and
boring bit embodiments can be usable with a chamber junction and bore selector
within the innermost passageway of a well to selectively bore or enter a wall
penetration, to access and re-access a plurality of penetrations through
various conduit
and strata bore walls, thus acting as a penetration selectable guiding member.
[000221] Referring now to Figure 78 and 79, isometric views of ratcheting
rotational
guides (176A (also shown in Figure 48) and 176B, respectively), depicting a
bore
selector's (47) upper or lower end and a guiding surface of the chamber (41A)
of a
chamber junction, wherein any guiding surface shape, such as a helical
surface, is
usable to align a bore selector orifice (59 of Figure 77) with an exit conduit
(39 of
Figure 76) orifice (59 of Figure 76) to selectively engage exit conduits (39
of Figure
76) for engagement of, e.g., a boring bit with the wall of a conduit or the
strata wall
when using or abandoning a well.
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CA 2841144 2019-02-12
[000222] Figure 49 is a diagrammatic elevation view of a method (1Z)
embodiment
usable with embodiments of a conduit pinning and separating member (2Z) and
boring bit engagable conduit (2Z1 and 2Z2) members, with only a portion (4Z)
of the
well elevation radial cross section shown below an upper right hand transverse
side
view elevation cross section of only the pinning shaft member's (2Z1, 2Z2,
2Z2A,
174B) diameters in differing left hand side and right hand pinning shaft
configurations, shown in the upper right side. The Figure illustrates how a
flexible
shaft and boring bit (174) may be used to bore through conduits (11, 12, 15)
with the
flexible shaft (174B) usable alone or as a spine for linked partial conduit
members
(2Z1) that may be combined with securing and/or stiffening partial conduit
members
(2Z2, 2Z2A). The stiffening conduit member (2Z2) may be arranged with the
linked
member (2Z1) to pin the conduits (11, 12, 15) before their consolidated
removal or to
support a well barrier element (3Z) placed within an annulus. The
stiffening
member may become a securing member (2Z2A) if its collapsible edges are
secured
about the linked member (2Z1) to prevent the assembly from separating. If the
stiffening member (2Z2) is not collapsed about the linked member (2Z1), then
they
may become separated after passing through the penetration in the wall of a
surrounding conduit, preventing the boring bit (174A) from being retrieved and
allowing the flexible shaft (174B) to be tensioned to separate conduits, thus
creating
standoff (211 of Figure 15) for placement and support of a piston member
and/or well
barrier element (3Z). Boring bit engagable conduit members, whether comprising
pinning supports or fluid passageways, selectively placed from the innermost
passageway, can be usable to engage and support axial movable piston members
and/or well barrier elements, placed from above the boring bit engagable
conduit
pinning members to, in use, selectively place axially piston and barrier
members at a
selected depth within the annuli of a well.
[000223] Referring now to Figure 50, an elevation view of the left half of a
slice
through a subterranean well and strata is shown, and depicts embodiments of a
method (1AA) usable with a member set (2AA) comprising annulus boring access
(2AA1) and swellable expandable mesh membrane (2AA2) members, illustrating
boring through the tubing (11) and casings (12, 15) to access the annuli (24,
24A,
24B), then placing of an swellable expandable mesh membrane (2AA2) to repair
the
bore through the tubing (11). The circulatable fluid column may be circulated
in
CA 2841144 2019-02-12
(31C2) through annulus (24B) wellhead (7) accesses and returned through other
annuli (24, 24A) wellhead accesses (13) to place heavy cement, e.g., well
barrier
elements (3AA1, 3AA2) to abandon a portion of the well (4AA) strata wall (17)
where a water producible zone (95F) exists below the intermediate casing (15)
shoe
(16), using channelled flow (226 of Figures 22 and 24) with lighter fluids
travelling
upward and heavier fluids travelling downward. A series of borings (2AA1) and
expandable membranes (2AA2) may be used at various depths to systematically
clean
conduit walls (11, 12, 15), with the fine particulates resulting from cleaning
the sand
screen like expandable mesh permeability, to provide clean water wet surfaces
for
good well barrier element (3AA1, 3AA2) bonds (113 of Figure 15). Additionally,
if
the tubing (11) is breached and the wells integrity has been lost, the method
(IAA)
can be usable to restore well integrity for further production from the
producible zone
(95E) by, e.g., applying the mesh membrane (2AA2) and using the sliding side
door
(123) to place, e.g., cement in the production annulus (24) with the cement
closing the
mesh's permeability to repair the breach. Use of swellable expandable mesh
membrane (2AA2) for placement of cement in the production annulus is a
significant
improvement over conventional expanded tubing patches, because there is a high
probability that the condition of the tubing, which caused the first breach,
will lead to
further breaches that cannot be repaired with a single patch, but can be
repaired by the
present method (IAA) because the permeability of the mesh provides pressure
relief
to prevent collapse of the tubing while the cement is hardening and allows
release of
free water associated with cement setting, unlike a solid tubing patch.
[000224] Figure 51 depicts a diagrammatic elevation cross section view showing
embodiments of a method (1AB) usable with a set (2AB) of annulus boring access
member (2AB1), logging tool (2AB2) and boring bit engagable conduit (2AB3,
2AB4) members, with dashed lines showing the hidden surface of the flexible
shaft
(174B). The Figure illustrates tracking of the flexible shaft and boring bit
(174)
guided through orifices (59) of a guidance member, selectively orienting the
annulus
(24) access conduit carrying boring member (2AB1), adjusting operating line
tension
and the fluid column pumping rate to selectively control direction, and
measuring its
position by reflecting (173D) a signal (173C) back to the broadcasting and
receiving
logging tool (2AB2) member, engaged to the guiding member and tubing (11) with
slips (180). The carried conduit member (2AB3) has a rotatable cutting portion
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CA 2841144 2019-02-12
(2AC1 of Figure 52), rotatable by the flexible shaft (174B) passing through
the bit
(174A) carried conduit, further usable to place a well barrier element (3AB)
to
abandon a portion (4AB) of the well accessed by the conduit (2AB3). The
flexible
cable can be usable with an expandable carried conduit by, e.g., pulling the
bit
(174A), which acts as an expander, through the carried conduit (2AB3) to
expand the
conduit against the sidetrack bore (59T) of the tubing (11), after which a
secondary
rotatable cutter (2AB4) may be used to severe the expanded carried conduit
(2AB3)
engaged to the tubing (11) at the sidetrack (59T).
[000225] Referring now to Figure 52, a diagrammatic elevation view of a slice
through
a boring bit engagable conduit member (2AC) embodiment is shown, which can be
usable with a method embodiment (1AC) depicting a carried conduit (2AC2) with
an
engaged independent rotatable (231) cutting conduit (2AC1) at its lower end,
which
may be driven with a gear teeth (174AT) engagement to rotationally coincide
and
bore with the rotatable (231) bit (174A) of the flexible shaft (174B) and bit
assembly
(174). The circulatable fluid column (31C) may be pumped (31P) through
orifices
(59) of a housing with rotation of the bit (174A) to lubricate boring. The
method
(1AC) can be usable to, e.g., bore through one or more walls of a well to
place a well
barrier element (3AC) in a portion of the well (4AC), that can be accessed
through the
wall penetration made by the member (2AC).
[000226] Figure 53, a diagrammatic elevation cross section view of a method
(IAD)
embodiment of a boring bit engagable separating or conduit member (2AD)
embodiment, illustrates a flexible shaft (174B) and rotatable bit (174A)
engaged to a
stiff conduit section (2AD3), bent housing (2AD2) and more flexible conduit
section
(2AD1), which can be usable to directionally control boring direction and
orientation
during boring, e.g. with a boring separating member (2AZ of Figure 80-82)
forming
the stiff conduit section (2AD3). Thereafter, a separating member may be
expanded or
a member apparatus can be placed with a well barrier element (3AD) placed
through a
bored penetrated wall portion (4AD) of the well.
[000227] Figure 54, a diagrammatic elevation view of the left half of a slice
through a
subterranean well and strata shows embodiments of a method (1AE) usable with a
member set (2AE) of annulus boring access (2AE1), annular piston (2AE2) and
rheological controllable gradated particle (2AE3) members, depicts a bored
hole
77
CA 2841144 2019-02-12
through the tubing (11) and casing (12, 15) that can be usable to place
annular pistons
(2AE2, 2AE3), e.g. (2AG) of Figure 56 or (2A1) of Figure 58, in the production
annulus (24) inflated to collapse the tubing (11) to provide a radially inward
movable
piston, and can be further usable for well barrier element (3AE1, 3AE2, 3AE3)
support to prevent cement movement, slumping and gas migration while setting
(212
of Figure 15), to abandon a portion (4AE) of the well and to isolate the
producible
zone (95E). The well barrier elements (3AE1, 3AE2, 3AE3), e.g. cement, are
placeable below the intermediate casing (15A) cement (20) shoe (16) using the
circulatable fluid column (31C) through the tubing (11) bore (25) and annuli
(24,
24A, 24B) exiting or entering the wellhead annuli accesses (13), depending on
circulation orientation, and settling at a common depth using u-tubing forces
(312 of
Figure 25). Also, rheological controllable gradated particle (2AE3) members
may be
replaced by, e.g., bladder or swellable pistons (2AF of Figure 55) or a coiled
bladder
piston member (2AK of Figure 60).
[000228] Referring now to Figure 55, a diagrammatic plan view of a slice
through a
well bore and strata showing a method (1AF) embodiment usable with an annular
bladder or swellable piston (2AF) member embodiment, showing finable bladder
and/or swellable piston elements (2AF) placeable, e.g., through the inner
tubing (11)
passageway (25) and wall penetration bore made by a flexible shaft and boring
bit
member that can expand within the annulus (24) between conduits, e.g. the
tubing
(11) and production casing (12) cemented (20) with a strata bore (17) wall
portion
(4AF) to act as, and/or to support a well barrier element (3AF). If the
elements (2AF)
are inflated or otherwise over expanded, they are usable to form (2AG) of
Figure 56.
[000229] Figure 56 and 58 are diagrammatic plan view cross sections through a
well
bore depicting method (1AG, 1AI, respectively) embodiments usable with an
annular
bladder or swellable annular piston member (2AG, 2AI, respectively)
embodiments,
and the Figures illustrate finable bladder and/or swellable piston elements
(2AG, 2AI)
that can be placeable, e.g., through the inner tubing (11) passageway (25) and
bore of
the wall penetration made by a flexible shaft and boring bit member, which can
expand within the annulus (24) to crush the tubing (11) passageway (25) by
expanding between conduits, e.g. the tubing (11) and production casing (12),
cemented (20) within a strata bore (17) wall portion (4AG, 4AI, respectively),
to act
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CA 2841144 2019-02-12
as and/or support a well barrier element (3AG, 3AI, respectively). Rheological
controllable fluid gradated swellable particle members can be usable above
and/or
about the elements (2AG, 2AI) to provide pressure bearing capacity and barrier
(3AG,
3AI) support.
[000230] Referring now to Figure 57, a diagrammatic plan view of a slice
through a
subterranean well bore is shown. The Figure depicts a method (1AH) embodiment
usable with a annular passageway separating member (2AH) embodiment,
illustrating
a fillable bladder or swellable piston element (2AH) placeable, e.g., through
the inner
tubing (11) passageway (25) and bore made by a flexible shaft and boring bit
member, that can expand within the annulus (24) to separate conduits, e.g. the
tubing
(11) and production casing (12), cemented (20) with a strata bore (17) walled
well
portion (4AH), to provide stand-off (211 of Figure 15) for well barrier
element (3AH)
placement. If the element (2AH) is inflated or otherwise over expanded, it is
usable
to form (2AI) of Figure 58.
[000231] Referring now to Figure 59, a diagrammatic isometric view of a
placement
method (1AJ) embodiment, usable with a set (2AJ) of annular passageway
separating
member (2AJ1-2AJ3) embodiments, is depicted. The Figure shows a fillable
bladder
or swellable piston element in various placement positions (2AJ1-2AJ3) after,
e.g.,
being conveyed through the casing (12) enlarged innermost passageway (25E),
after
compressing the tubing with a different embodiment, then exiting the wall
penetration bore made by a flexible shaft and boring bit member through the
production casing (12) with, e.g., a guiding member (2BL of Figures 119 and
120),
and with pressure from the circulatable fluid column (10 of Figure 36), so as
to be
longitudinally (2AJ1) placed through the bore with tethers (2AJ4, 2AJ5), and
turning
the placement position (2AJ2), as the tethers reach their extents, to place
the element
circumferentially (2AJ3) within the intermediate casing (15) annulus (24A),
to, e.g.,
provide the placement of a tillable bladder or swellable piston element (2AH)
in
Figure 57, and wherein three such elements can be placeable as shown in (2AF)
of
Figure 55. The tether (2AJ4) can be usable to inflate a bladder type
inflatable and/or
swellable element by placing a fluid within, e.g. injecting a small quantity
of oil into
an oil swellable bladder and causing a portion to expand and push the oil to
the next
portion until the bladder is fully swollen. Alternatively, the tether (2AJ4)
may
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CA 2841144 2019-02-12
comprise a flexible shaft with a surrounding bladder and auger bit for boring
between
conduits with the other tether (2AJ5) causing a directional turn within an
annulus to
bore between and lift or separate the production casing (12) from the
intermediate
casing (15), thus providing stand-off (211 of Figure 15). Also, Figure 59
includes a
well barrier element (3AJ), which can be supported by the production casing
(12)
and/or a wall portion (4AJ) of the intermediate casing (15) or the well.
[000232] Figure 60 is a diagrammatic plan view of a method embodiment (1AK),
with
conduits (11, 12) shown as dashed lines, that can be usable with a swellable
conduit
member about a disposable flexible shaft and boring bit member (2AK)
embodiment.
The Figure shows a helical pattern of deployment within the annulus (24) from,
e.g., a
helical pathway guide placed within the tubing (11) that coils the swellable
conduit
(2AK) around the annulus between the tubing (11) and casing (12), wherein a
tether
(2AJ5 of Figure 59) can be usable to coil swellable material about an
approximate
depth with an auger, like boring bit (174A1) usable to auger between and
separate
conduits (11, 12), to provide standoff (211 of Figure 15), while retaining
axial flow
through helical coil for placement of the well barrier element (3AK). After
placement, a swellable reagent, e.g. water for a water swellable conduit or
oil for an
oil swellable conduit, surrounds the flexible shaft of the auger boring bit
(174A1) to
provide further stand-off for an unpacked coil bored, e.g., in an axial
downward
orientation or sealing of the passageway if the coils are tightly packed about
the
tubing (11) by, e.g., boring in an axial upward orientation using gravity a
hydraulic
jarring member to pack the coil, to support (212 of Figure 15) a well barrier
element
(3AK) placed with a annular and gravity slugging flow regimes to abandon a
portion
(4AK) of the well.
1000233] Referring now to Figure 61, a diagrammatic plan view of a method
(1AL)
usable with the bladder and swellable piston members (2AL) as a placement
embodiment is depicted. The Figure shows a fan or accordion type deployment
(1AL) from a compressed position, that can be usable for placing the member
(2AL)
through the smaller penetration diameters and can be usable to seal or support
(212 of
Figure 15) a well barrier element (3AL) to abandon a portion (4AL) of a well,
e.g.,
with the elements (2AF, 2AG, 2AH, 2A1) of Figures 55 to 58, after being placed
through, e.g., a wall penetrating bore of a flexible shaft and boring bit
member.
CA 2841144 2019-02-12
[000234] Figure 62 depicts an elevation cross section left side view through a
subterranean well and strata, showing embodiments of a method (1AM), usable
with a
set (2AM) of axially slideable annular blockage bypass (2AM1), annulus boring
access (2AM2), logging (2AM3) and boring bit engagable conduit (2AM4) members,
depicting first abandoning of a producible zone (95E), then side-tracking to a
new
producible zone (95G) for additional production (34P), prior to final
abandonment for
an onshore (121) or offshore subsea level (122A) wellhead (7) at mudline
(122).
Penetrations in the tubing (11) are placeable above the production packer
(40),
through the tubing (11) and production casing (12), and below the packer (40),
through the tubing (11) using an annulus boring access (2AM2) member with a
flexible shaft and boring bit (174), after which an axially slideable annular
blockage
bypass (2AM1) member can be usable to straddle the penetrations and place a
cement
well barrier element (3AM1) within the annuli (24, 24A), adjacent to the
cemented
intermediate casing (15) shoe (16), and across (3AM2) the producible zone
(95E), to
abandon the lower portion (4AM1) of the well using the circulatable fluid
column
(31C), to place the cement with any of the various flow regimes, after which u-
tubing
causes levelling of the cement within the annuli (24, 24A).
[000235] A boring bit engagable conduit (2AM4) member can then be usable to
side-
track to the new producible formation (95G), leaving a swellable sheathed
and/or
expandable conduit within the bore to seal the side-track passageway, after
which a
logging tool member (2AM3) can be usable to confirm the bonding and to seal
prior
to production (34P) from the new producible zone (95G). While the new
producible
zone may not have warranted completion during well construction, e.g., it may
now
provide sufficient marginal production to delay the cost of final abandonment
and
therefore may now be economically producible if it can be accessed using low
cost
cable compatible rig-less operations. Once production from the producible zone
is
completed, the logging tool member (2AM3) may again be used to determine a
bond
prior to placing a well barrier element (3AM3) to abandon that portion (4AM2)
of the
well.
[000236] Referring now to Figure 63, a diagrammatic isometric view of a method
(IAN) embodiment, providing a motorized annulus access member (2AN) usable
with a plurality of flexible shafts and boring bits (174), is shown. Figure 63
depicts a
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CA 2841144 2019-02-12
plurality of fluid motors, comprising rotors (109) and stators (108) engaged
between
anti rotation members (2AN1, 2AN2) and operable from a cable engaged to the
upper
rotary connection (72). The circulatable fluid column (31C) is pumpable and
divertible by seals (2AN3), through orifices (59), to rotate the rotors (109)
within the
stators (108) to consequently rotate a plurality of, e.g., disposable flexible
shafts and
boring bits (174D), which can be rotationally engaged to the lower end of the
rotors
(109) for boring through conduits to access portions (4AN) of the well through
the
resulting wall penetrations and annuli access, for placement of well barrier
elements
(3AN).
[000237] Disposable flexible shafts and boring bits (e.g. 174D) can be usable
for
various tasks, including the pinning of conduits together prior to abrasive
cutting and
removal of the wellhead and riser from, e.g., an offshore platform well or
providing
logging member sensors if, e.g., the flexible shaft also includes wiring or,
alternatively, transponders or transmitters for passing a measurement signal
to a
receiver hooked to another part the well to, e.g., measure the bonding and
existence of
primary cementation behind the casing and between the casing and the strata
from
within any annulus.
[000238] As an outside diameter of conventional fluid motors can be, e.g.,
1.68 inches,
they are usable for simultaneous downhole boring of a plurality of small
diameter
bores, thus it is feasible to provide, e.g., three fluid motors within the
4.67 inch inside
diameter of, e.g., a 5 1/2 inch tubing (11), or significantly more with
various guiding
members, e.g., (2BM) of Figures 122 and 123, if flexible shafts are extended
to pass
with gaps (2AP7) between the fluid motors. While larger motors provide more
power
for boring larger fluid communicating bores, a plurality of smaller motors
with less
power and smaller flexible shafts and boring bits are usable to, e.g., provide
a
plurality of logging sensors for measuring cement bonding and existence, or to
improve the helically coiling (1AK of Figure 60) and bird-nest capability of
choking
an annulus to support, e.g., placement of a rheological controllable gradated
particle
member and/or permanent well barrier element through and/or above the bird
nested
plurality of disposable flexible shafts and boring bits (174D).
[000239] Figure 64 is a diagrammatic plan view of cross section through an
installed
well conduit (11), showing a method (1A0) embodiment usable with a set (2A0)
of
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CA 2841144 2019-02-12
members, shown in a left hand plan view, comprising an annular access guiding
member (2A01) embodiment adjacent to a right hand magnified detail plan view
of
the flexible shaft (174B) boring bit engagable conduit (2A02, 2A03)
embodiments.
The Figure shows three slips (180) engaged to guiding whipstocks for side-
tracking
out of the tubing (11) by rotating (231) bits at the end of flexible shafts
(174B) to
three different portions (4A01, 4A02, 4A03) of a well. For example, one
portion
(4A01) may be the conductor annulus (24C of Figure 65), another portion (4A02)
may be the outer intermediate casing annulus (24B of Figure 65), and the
remaining
portion (4A03) may be the inner intermediate casing annulus (24A of Figure
65).
The outer boring bit engagable conduit (2A02) can be, e.g., a mechanically
expandable metal conduit with the inner conduit (2A03) being a chemically
swellable
material, or vice versa, with the rotatable flexible shaft (174B) within,
wherein a
single conduit or any plurality of conduits, layering, and material types are
possible.
The annular space between the conduits (2A02, 2A03) and flexible shaft (174B)
can
be both usable for fluid communication and fillable with a well barrier
element (3A0)
to embed the conduits (2A02, 2A03) in, e.g., cement (217 of Figure 15),
wherein
filling may also involve inflating a membrane, thus becoming an annular piston
member, similar to those described in Figures 55 to 60.
[000240] Referring now to Figure 65, a plan view of a method (1AP) embodiment,
usable with a member set (2AP) comprising an annular access guiding (2AP) and
annulus boring access or boring bit engagable conduit annulus access member
(2AP1-
2AP6) embodiments, is shown. The Figure further depicts a common conventional
well conduit size configuration below a wellhead of a 30 inch outside diameter
(OD)
conductor (14), with 20 inch OD outer intermediate casing (15A), 13 3/8 inch
OD
inner intermediate casing (15), 9 5/8 inch OD production casing (12), and 5
1/2 inch
OD and 4.67 inch internal diameter production tubing within which three 1.68
inch
OD fluid motors may be fitted into a 3.625 inch outside diameter side-tracking
whipstock guiding member (2AP). The members (2AP1-2AP6) may extend to and
access any annulus (24, 24A, 24B, 24C) to place a well barrier element (3AP)
in a
portion of the well (4AP1-4AP4) or to access a producible zone, instead of
using
conventional perforating guns, to create larger and longer producible strata
wall
penetrations than are possible with conventional perforating gun tunnels,
where the
guiding member (2AP) may be rotated to provide various radial arrangements,
such as
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CA 2841144 2019-02-12
the one shown, with a rotation of, e.g., 60 degrees using two simultaneous
borings of
three or six individual borings.
[000241] Figure 66 depicts an elevation view with break lines showing removed
well
sections of a method (1AQ) embodiment, usable with a set (2AQ) of annular
access
guiding (2AQ1) and boring bit engagable conduit (2AQ2) member embodiments.
The Figure shows a single motor member (2AQ3) and bit conduit assembly (2AQ2)
with a flexible shaft and boring bit (174), usable in two opposite positions,
where the
guiding member (2AQ1) was rotated 180 degrees, and further usable to access
portions (4AQ1-4AQ4) of the well, comprising annuli (24, 24A, 24B, 24C)
between
well conduits (11, 12, 14, 15, 15A), dependent upon the length of the flexible
shaft
and boring bit or annulus access boring bit and the engagable conduit (2AQ2)
member used, wherein a conduit carried by the bit assembly (2AQ2) may be left
as a
well barrier element (3AQ1) for placing a fluid well barrier element (3QA2) in
portions (4AQ1-4AQ4) of the well.
[000242] Referring now to Figures 67 and 68, diagrammatic isometric views,
with
dashed lines showing hidden surfaces and Figures 68A and 68B showing magnified
detail views of a method (1AR) embodiment of a member set embodiment (2AR)
comprising a swellable expandable mesh membrane member (2AR2), are shown. The
Figures depict a swellable expandable mesh membrane (2AR2) that can be
placeable
with an expander (2AR1), explosive initiating jar (2AR4) and bottom supporting
seal
(66A), usable as a temporary LCM barrier until a substantial well barrier
clement
(3AR) is placeable in the portion (4AR) of a well, comprising a breach or
penetration
in the tubing (11). A coating or packaging (2AR5) of sealing elastomeric
material,
LCM, gradated particles and/or a rheological controllable gradated particle
members
may also be present.
[000243] While conventional tubing patch technology is usable with the present
invention, its primary purpose and associated cost is for applying a
persistent patch to
repair breached tubing to an production operable specification, wherein the
lost
circulation method (1AR) can be usable to place a chokable sand screen, like
mesh, to
allow pumping while the annulus behind the breach is filled with, e.g., cement
to not
only repair the obvious breach, but also to remove the potential of further
breaches
within the worn conduit. The swellable expandable mesh membrane of the present
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CA 2841144 2019-02-12
invention provides a significant improvement over conventional expandable
tubing
patches because it provides a LCM chokable mesh, fillable with swellable
materials,
gradated particle mixes, chemically reactive fluids and/or conventional LCM to
provide a thin membrane usable to resist circulation pressures for placement
of well
barrier elements, e.g. placing cement within a production annulus across a
leak
without creating a significant circumferential obstruction to subsequent tool
passage
(1AM of Figure 50). Additionally, e.g., if the membrane is no longer needed or
hinders operations, it may be more easily removed with rotary cable tools of
the
present invention, which can be usable to remove the structural integrity of
the mesh
with, e.g., a boring bit and tractor. Also, the membrane (2AR2) can be
designable as
a pressure relief membrane if, e.g., only swellable materials or LCM are only
placed
within the pore spaces of the mesh, omitting the sealing cement, thus allowing
the
pore spaces to be cleared or the membrane ruptured, with excess pressure used,
to
dislodge or break the sealing portions.
[000244] Figure 67 illustrates the member set (2AR) comprising an expandable
mesh
membrane between an expander (2AR1) and supporting deformable seal (66A),
placeable on a cable string (187). Figure 68 shows the member set (2AR)
arrangement after the explosive initiating jar has fired and acted in an
axially
downward direction to rupture the coating or package (2AR5 of Figure 67),
exposing
swellable materials to a swelling reagent, forcing LCM and/or a chemically
reacting
rheological controllable fluid through the breach or penetration and engaging
the
expandable top seal (66B) to the tubing (11), providing a seal and allowing
pressure
to be applied axially downward to continue expansion of the mesh with the
circulatable fluid column (3IC), while holding string (187) tension. If, for
example,
electric line is used, the explosive initiating jar may be fired by initiating
a signal at
surface level, or if slick line or non-electrical braided wire is used, the
explosive
initiating jar may be set with a timer, pressure and/or other downhole
parameters. The
explosion of the jar initially forces the top seal (66B) and breaks the
coating or
package (2AR5 of Figure 67) with applied circulatable fluid column (31C)
pressure,
which can be usable to operate the expander (2AR1) axially downward on the
dance
pole (2AR3) until the supporting seal (66A) engages the dance pole (2AR3) end
with
fluid exiting the breaches or penetrations (4AR) or through the innermost
passageway
(25) below the assembly, deforming the supporting seal (66A) downward as the
CA 2841144 2019-02-12
swellable expandable mesh membrane (2AR2) is engaged with the circumference of
the tubing (11) to form a well barrier element (3AR) over the breaches or
penetrations
(4AR). Any portion of the mesh (2AR2), not inflated by the expander (2AR1),
can
be expanded, then, by releasing string tension to allow the expander to move
downward and/or by using the curved downward surface of the deformable seal
(66A), as the assembly is pulled axially upward through the mesh (2AR2) with
string
(187) line tension.
[000245] Figure 68A shows a magnified elevation view of the member set (2AR)
portion, comprising the swellable expandable mesh membrane member (2AR2) with
a
metal mesh (2ARX) similar to an expandable sand screen and with encapsulated
or
coated swellable material (2ARS) or LCM engaged within its pore spaces, with
the
coating preventing contact with the swelling reagent, e.g. water. When the
swellable
expandable mesh membrane's (2AR2) circumference is expanded (2ARE) to engage
the tubing's (11 of Figures 67-68) inside circumference, the coating is
broken,
exposing the membrane to the swelling reagent, thus causing swelling of the
material
(2ARS) to hold the mesh's shape, thus providing pressure integrity as it seals
against
the metal mesh (2ARX). Portions of the mesh (2ARX) pore spaces may not be
filled
with swellable material (2ARS) until the material swells to seal the pore
space
forming a membrane, while other portions of the pore space may be filled to
provide a
holding force, once swelled. Alternatively, the expandable metal mesh (2ARX)
may
be designed to form selectively sized pore spaces before and after expansion,
such
that, e.g., circulatable LCM slurry is usable to fill the pore spaces.
[000246] Figure 68B shows a magnified elevation view of the member set (2AR)
portion comprising the swellable expandable mesh membrane (2AR2), with a
dashed
line showing optional layers, wherein the metal mesh (2ARX) can be usable as
the
only layer or can be placeable on the inside, outside or between a swellable
membrane
(2ARS), with the diamond shapes of Figure 68A being, e.g., raised surfaces on
a
surrounding swellable membrane or only occurring within the pore spaces of the
mesh
(2ARX) by, e.g., pumping a fluid slurry of gradated particle sizes through the
mesh to
choke its pore spaces, wherein a coating on swellable gradated particles is
rupturable
by the mesh to provide exposure to swelling reagent within the circulatable
fluid
column, thus securing the particles within the mesh and strengthening it.
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CA 2841144 2019-02-12
[000247] Referring now to Figures 69, 70 and 71, diagrammatic elevation views
of a
slice through a subterranean well and strata, through 3 stages of abandoning a
portion
(4AS) and accessing a new producible zone (95K) before final abandonment, as
reshown. The Figures depict embodiments of methods (1AS, lAT, 1AU,
respectively) usable with member sets (2AS, 2AT, 2AU, respectively) comprising
annulus boring access (2AS1, 2AT1), swellable expandable mesh membrane (2AS2,
2AU2), annular piston or rheological controllable fluid (2AU1), boring bit
engagable
conduit (2AT1) and coilable swellable conduit, flexible shaft and boring bit
(2AT3)
member embodiments, which can be usable with logging tool (2AT2) and
circumferential engagable perforating (2AU3) members. Figure 69 depicts
cleaning a
well to create wettable surfaces for good bonding (213 of Figure 15). Figure
70
illustrates confirming the sealing bond of the primary cement adjacent to a
formation
that is impermeable and strong formation (214 of Figure 15). Figure 71 shows
providing pipe circumferential stand-off to prevent channelling (212 of Figure
15)
with axially downward cement support to prevent cement movement, slumping and
gas migration (212 of Figure 15) to provide casing and tubing embedded (215 of
Figure 15) in a minimum height of cement (219 of Figure 15), wherein marginal
production may occur until the final abandonment, when logging occurs to
confirm
bonding, and cement is bull-headed to the formation, filling the production
tubing
(11) to seal conduits with cement in cement (217 of Figure 15). Thus, a
sealing
permanent abandonment plug (216 of Figure 15) is provided at a depth of
formation
impermeability and strength, with cement behind casing (218 of Figure 15) to
contain
future pressure (220 of Figure 15) to, in use, meet published minimum industry
best
practice.
[000248] Referring now to Figure 69, a member set (2AS) is shown that can be
usable
with the tubing (11) that is penetrated (129) or cut, with cleaning chemicals
added to
the pumped (2SAP) circulatable fluid column (31C) to clean the casings (12,
14, 15),
and tubing (11) held at the lower end, by a production packer (40), to the
production
casing (12), wherein a annulus boring access (2AS1) member has been used to
penetrate through the walls of the conduits (11, 12, 15), which is shown above
and/or
adjacent to the placement of well barrier elements (3AS) to seal fractured
strata (18),
and to potentially penetrate the strata wall (17) to provide fluid
communication
(2ASP) through the innermost bore (25) and annuli (24, 24A, 24C) and fluid
disposal
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CA 2841144 2019-02-12
to the permeable depleted reservoir (95ED) and/or a fractured (18) strata
portion
(4AS) of the well, with a swellable expandable mesh membrane (2AS2) covering
the
penetration through the tubing (11) to provide a circulation path for cleaning
circulation prior to sealing the fractures (3AS).
[000249] Figure 70 shows a member set (2AT) that can be usable for placement
of a
well barrier element (3AT) to isolate the lower depleted reservoir and the use
of a
boring bit engagable conduit (2AT1) for providing a guiding conduit into the
production annulus (24), for a logging member (2AT2), to determine the
presence and
bonding of cement (20) behind the production casing (12) annulus (24) or the
intermediate casing (15) if, e.g., the conduit extended to that annulus (24A).
A
coilable swellable conduit, flexible shaft and boring bit (2AT3) is then
usable to auger
a swellable coil about the tubing (11) for stand-off and subsequent placement
of a
viscous mixture of, e.g., conventional polymers, LCM and/or gradated particle
material or embodiments of the present invention to support a subsequently
placed
well barrier element member (3AT), which can be positioned within an annulus
to
support a well barrier element (4AT) within the well.
[000250] Figure 71 depicts the use of a member set (2AU) comprising an annular
piston
or rheological controllable fluid (2AU1) placed on top of the coilable
swellable
conduit, flexible shaft and boring bit usable to form a permeable bird's nest
(AT3 of
Figure 70) to provide support for cement within the annuli (24, 24A, 24C). A
swellable expandable mesh membrane (2AU2) may be held below the annulus access
conduits (2AT1 of Figure 70), while cement (20), e.g., is placed in the annuli
(24,
24A, 24C) using the circulatable fluid column (31C) pumped down one or more of
the
annuli and returned through the innermost passageway (25), or vice versa, with
an
explosive device initiating jarring and expansion of the swellable expandable
mesh
membrane (2AU2), set for time and pressure activation. Prior to reaching the
designated firing time and pressure, the membrane (2AU2) may be raised to
cover the
penetration (2AT1 of Figure 70), after cementing, to expand and hold the
cement
within the annulus, having initially held the heavier cement with u-tube
forces
between the annuli, causing an even top of cement (20), thus providing a
permanent
well barrier element (3AT) over a portion (4AS) of the well. Once the cement
has set,
logging can confirm the cement bonding of the tubing and a perforating member
88
CA 2841144 2019-02-12
(2AU3) can be usable to penetrate the conduits (11, 12) and cement adjacent to
the
new producible zone (95K). After producing the zone (95K), the logging members
can be re-run to confirm cement bonding of the tubing (11), and the well
barrier
element (3AT) may be removed to bullhead a rheological and hydrocarbon reagent
controllable fluid reacting to and blocking permeability as it enters the
hydrocarbon
producible zones to, in use, to prevent gas migration and support a trailing
cement
during injection into the new zone (95K) and the depleted producible zone
(95ED),
thus permanently abandoning the remaining lower portions of the well.
[000251] Referring now to Figure 72, a diagrammatic elevation left side view
of a cross
section through a well bore within the strata, showing embodiments of a method
(1AV) usable with a member set (2AV) comprising circumferential shredding and
milling (2AV1), piston or rheological controllable gradated particle (2AV2,
2AV5),
circumferential milling (2AV3), annulus boring access (2AV4), boring bit
engagable
conduit pinning (2AV6) member embodiments, usable with tubing plug (25A1-25A3)
and abrasive particle cutting and/or explosive severance (2AV7) members, is
shown.
The Figure depicts primary cement sealing (3AV1, 3AV2, 3AV3), adjacent to
formation well portions (4AV1, 4AV2, 4AV3) that are impermeable and strong
(214
of Figure 15), and the providing of pipe circumferential stand-off using
various
members to prevent channelling (212 of Figure 15) with axially downward cement
support (2AV2, 2AV5) to prevent cement movement, slumping and gas migration
(212 of Figure 15), thus providing casing and tubing embedded (215 of Figure
15)
within a minimum height of cement (219 of Figure 15). The production tubing
(11)
can be sealed with cement in cement (217 of Figure 15), further providing a
sealing
permanent abandonment plug (216 of Figure 15) at a depth of formation
impermeability and strength with the primary cement behind casing (218 of
Figure
15) logged to ensure that it will contain future pressure (220 of Figure 15),
thus
meeting published industry best practice. The surface (121) is returnable to
its
original state by cutting off the wellhead engaged conduits (11, 12, 15, 15A,
14) with
a conventional rig-less abrasive cutter or explosives, after pinning (2AV6)
the various
conduits (11, 12, 15) that are to be lifted off as a unit to safely save the
cost of
handling them separately. Additionally, by logging of the primary cement
bonding
and placement of primary well barrier elements (3AV1, 3AV2) within the
enlarged
innermost passageways (25E, 25AE), the present invention simulates abandonment
by
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CA 2841144 2019-02-12
a drilling rig (172A of Figure 10) with all of its inherent advantages at a
significantly
lower level of resource usage and associated cost.
[000252] One of the possible sequences for the method (1AV) is to set the
lowest tubing
plug (25A1) member and then shred and/or mill the tubing (11) with member
(2AV1),
comprising e.g. with (2AW) of Figure 73, (2AY) of Figure 74 or (2BT) of Figure
146,
followed by using a logging member within the enlarged inner passageway (25E),
after compressing any shredding and/or milling downward with a piston member
to
confirm the cement bond (213 of Figure 15) behind the production casing (12);
and
then, placing the well barrier element (3AV1), e.g. cement, within the
enlarged
innermost passageway (25E) to abandon the lower portion (4AV1) of the well. If
a
good cement bond behind the production casing (12) does not exist, it may be
milled
and/or shredded prior to placing a barrier (3AV1).
[000253] In this embodiment, a review of the logging performed during
construction of
the well shows that the necessary cement does not exist in the intermediate
casing
(15) annulus (24A), so the next step is to place an intermediate tubing plug
(25A2)
member, followed by operation of a milling member (2AV3) to destruct the
tubing
(11) and production casing (12), allowing it to fall downhole and/or
compressing it
with a piston member, after which a logging member can be usable within the
enlarged innermost passageway (25AE) to confirm cement bonding behind the
outer
intermediate easing (15A), after which a rheological controllable fluid,
swellable
gradated particle mix and/or pistons member (2AV2) are placeable in the annuli
(24,
24A), above any debris from milling, to support the well barrier element
(3AV2)
placed in the enlarged innermost passageway (25AE) to abandon the adjacent
portion
(4AV2) of the well.
[000254] With primary (3AV1) and secondary (3AV2) permanent well barrier
elements
in place in the well, the next steps may involve using an annulus boring
access
member (2AV4) to provide fluid communication with the annuli (24, 24A, 24B,
24C),
after which piston and/or rheological controllable fluids, swellable gradated
particle
members (2AV5) can be usable to provide support within the annuli for the well
barrier element (3AV3) to abandon the final portion (4AV3) of the well.
Additionally, if penetrations are placed above and below the pistons and/or
packed
and partially solidified rheological fluids (2AV5), an axial slideable annular
bypass
CA 2841144 2019-02-12
member method (1M of Figures 28-30) can be usable to straddle the bores (2AV4)
and penetrations to hydraulically jar and pack the annular blockages (2AV5) to
ensure
that they can support the well barrier element (3AV3). After placing the final
barrier,
the surface level (121) is returnable to its original state, potentially using
a boring bit
engagable conduit pinning (2AV6) member, e.g (2Z) of Figure 49, to secure the
conduits together for lifting, followed by operation of a conventional
abrasive cutting
or explosive severance member (2AV7) to cut all of the conduits engaged to the
wellhead (7) so that it might be lifted off using, e.g., a mobile or floating
crane, for
offshore wells, to complete the abandonment of the well.
[000255] Figure 73 depicts a diagrammatic elevation view of slice through
installed
well conduits and shows a method (lAW) embodiment that can be usable with the
member set (2AW) comprising circumferential kelly milling (2AW1), axial
conduit
shredding (2AW2), axial movable screw tractor (2AW3) member embodiments
and/or conventional tractor (2AW3C), showing the shredding and milling of
tubing
to create an enlarged innermost passageway (25E) usable to place the partially
shown
well barrier element (3AW) to abandon a portion (4AW) of the well. The cable
string
(187) operable kelly mill (2AW1) can be rotated by a kelly bushing (2AW4),
that can
be operated by a rotor (109) turned by pumping (31CP) the circulatable fluid
column
(31C), diverted by seals (66) between a stator (108), held by a tractor (2AW3
or
2AW3C) pulling the assembly axially upward to engage shredding cutters (2AW2)
with the tubing (11) and the motor, an anti-rotation member (2AW5) with spring
operated anti-rotation wheels to pass obstructions and prevent rotation of the
cable
string (187). A constant force can be applied by the tractor to shred the
tubing while
the rotating kelly mill is operable axially with string (187) tension and the
axial
rolling circumferential anti-rotation swivel member (2AW5) is engagable,
between
the stationary string (187) and rotating kelly mill, and further usable to
engage and
disengage the rotating mill to and from the tubing, thus preventing jamming of
the
shredding mill member (2AW). In various other embodiments, the tractor unit
(2AW3) can be usable to weaken the tubing prior to shredding and milling.
[000256] Once engaged, the member (2AW) can be operated with string tension,
usable
to operate the mill and fluid pressure of circulated fluid column (31C),
usable to
operate the tractor and shredding assembly, after which the tool may be
disengaged by
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CA 2841144 2019-02-12
mechanically and/or hydraulically jarring downward to shear various pins
within the
member (2AW) to release the cutters and mills from the tubing, thus allowing
it to be
retrieved to the surface for repair and/or replacement. Alternatively,
conventional
disposable or releasable motors are usable, with low cost shredding and
milling
assemblies that are usable to dispose of worn shredding, cutting and milling
equipment downhole, which is possible by, e.g., cutting tubing to which it is
engaged
and letting it fall into the enlarged innermost passageway formed by the
milling
and/or shredding to further support a rheological fluid member and/or well
barrier
element placed axially above it.
1000257] Referring now to Figure 74, a diagrammatic isometric view of a method
(lAY) embodiment, usable with the circumferential milling (2AY) member
embodiment comprising an annular separating elbow (2AY2), roller mills (2AY3),
elbow connector (2AY1), screw shaft (2AY4) and elbow screw (2AY5) parts, is
shown. The Figure includes the formation of an enlarged innermost passageway
(25AE) that can be usable to place the partially shown well barrier element
(3AY) to
abandon a portion (4AY) of a well. The mill can be usable with a motor member
of a
cable string (187M) for rotating the screw shaft (2AY4) to screw the lower
elbow
connector (2AY5) axially upward, extending the separating elbows (2AY2) and
roller
mills (2AY3), and pivoting on the upper elbow connector (2AY1) secured to the
screw shaft (2AY4). In this instance, the tubing has already been compressed
axially
downward, forming an enlarged production passageway (25E) and a logging member
has found that the cement bond was unacceptable or there was an absence of
cementation behind the production casing (12), thus the milling assembly (2AY)
is
being operated to enlarge (25AE) the innermost passageway into the
intermediate
casing (15) annulus (24A). The separating elbows and rotatable milling sleeves
(2AY3) may extend until the mill engages the production casing (12) or the
separating
elbow engages the intermediate casing (15), wherein expansion of the assembly
(2AY) centralizes and mills the production casing when rotated by the motor
member
(187M) engaged at its upper end to the cable string. The elbow mill (2AY) is
therefore operable with string line tension holding the mill against the
casing (12),
while the motor using, e.g., a positive displacement fluid motor, can be used
to turn
the rotating mills (2AY3). Retraction and retrieval of the mill is possible
with the
opposite rotation unscrewing the mills deployment, so that it may be retrieved
using
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CA 2841144 2019-02-12
the cable string.
[000258] As cable compatible operations cannot, generally, be operated in a
robust
manner of a jointed pipe operation on a drilling rig, the objective in rotary
cable
operations is less than milling in the jointed pipe drilling rig conventional
sense, and
more akin to abrasively eroding the casing (12) and/or poor cementation with
continued rotation of the mill, while limiting the tension placed on coiled
cable strings
to prevent becoming jammed or otherwise unable to rotate. While conventional
drilling rig operations may mill a sufficient length of casing, on average
with ample
torque available, to provide an acceptable barrier height in a matter of hours
and days,
cable compatible operations may take significantly longer to abrade conduits
using
significantly lower torque and may be measured in days and weeks. The costs of
performing low torque cable compatible abrasive casing erosion is, however,
significantly less than using, e.g. a drilling rig, even with such disparities
in required
time for milling.
[000259] Figures 80, 81 and 82 are plan, elevation and projected views,
respectively,
with Figure 80 section line A-A associated with Figure 81 cross section along
line A-
A, and Figure 82 a projection of Figure 81, showing a method (1AZ) embodiment
of a
collapsed annular passageway separating member (2AZ) embodiment. The Figures
illustrate a flexible shaft connector (2AZ1) that can be usable to drive a
shaft (2AZ2)
with threads and a boring bit (174C), at its lower threads, engagable to a nut
(2AZ6)
for compressing, bowing and/or bending a flexible blade (2AZ2) with fluid
communication ports (2AZ4). The flexible blades (2AZ2) can be held by the bore
(223) made by the boring bit (174C) or passageway of a guide member (e.g. 2BK
of
Figures 117-118) and can be usable as stabilizers on the drilling assembly,
with the
assembly (2AZ) rotatably placeable through a penetration (1AZH) made by
rotating
the assembly's boring bit (174C) or, e.g., using an auger type bit for pulling
the
assembly into a previously made wall penetration or using the assembly and
placing it
without a bit using a flexible shaft and rotation after insertion in an
annulus to expand
the flexible blades (2AZ2) by rotating the nut (2AZ6) on the threads, with the
blades
(2AZ2, 2AZ6) usable to provide stand-off (211 of Figure 15) between the tubing
(11)
and the production casing (12) to place the partially shown well barrier
element (3AZ)
and to abandon a portion (4AZ) of a well.
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CA 2841144 2019-02-12
[000260] Referring now to Figure 83, an isometric cross sectional view along
line A-A
of Figure 80, showing a method (1BA) embodiment of an expanded annular
passageway separating member (2AZ of Figures 80-82) is shown. The Figure
includes a shaft (2AZ3) with sufficient rigidity to facilitate thread and nut
movement
that has rotated the flexible shaft rotary connector (2AZ1) to cause the nut
(2AZ6) to
travel on the threaded portion of the shaft, which is causing the penetrated
(2AZ4)
blades (2AZ2) to bend and further provide stand-off between, e.g., the tubing
(11) and
the casing (12) so that the partially shown well barrier element (3BA) may be
placed
to abandon the portion (4BA) of the well, thus providing tubing conduits
sealed with
cement in cement (217 of Figure 15). If a logging member is placed through the
penetration (1AZH of Figure 80), prior to placement of the separating member
(2AZ),
and confirms a good cement bond (213 of Figure 15) then the methods (1AZ and
IBA) can be usable to provide stand-off between casing (12) and tubing (11) so
that
each may be embedded in cement (215 of Figure 15). The member (2AZ) is
placeable through penetrations formed by other boring members using an auger
bit
and/or by using the member engaged to flexible shaft for boring and separation
with a
cable compatible motor that can be deployable and operable from the innermost
passageway.
[000261] Figure 84 depicts a plan view above an elevation view of method (1BB,
1BC,
1BD) embodiments that can be usable with annular passageway separating member
(2BB, 2BC, 2BD) embodiments, respectively, for depicting a central member part
(2BB1, 2BC1, 2BD1) engaged with left (2BB2, 2BC2, 2BD2) and right (2BB3,
2BC3, 2BD3) bendable parts, which can be placeable and engagable between
conduit
circumferential walls of the production casing (12) and intermediate casing
(15) to
provide stand-off (211 of Figure 15) between the conduit, by displacing their
walls to
a more concentric position for placement of the partially shown well barrier
elements
(3BB, 3BC, 3BD) usable for abandoning a portion (4BB, 4BC, 4BD) of a well. The
stand-off can be usable to provide conduits, which are embeddable within
cement
(215 of Figure 15), that when combined with providing a logging member to
measure
the existence of cement behind the casing prior to placement of the separating
members (2BB, 2BC, 2BD), can be usable to provide a permanent well barrier
element. Both the separating and logging members can be placeable, e.g.,
through
bores made by other members penetrating conduit walls to access annuli. The
method
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(1BB) illustrates that conduit stand-off right (2BB2) and left (2BB3) members
can be
orientatable with the curvature of the concentric annuli conduits, about the
central
member (2BB1), to allow full expansion of the member. The method (1BC) shows
that a member (2BC) part (2BC2) may bend to fully expand and provide stand-off
or,
as shown, the right hand method (1BD) one or more elbow joints may be added to
a
member part to provide better expansion, dependent on the annulus in which the
members (2BB, 2BC, 2BD) are expanded for stand-off, wherein rotation of the
central
member (2BB1, 2BC1, 213D1) by a flexible shaft extending from a motor in the
innermost bore, causes through penetration in a conduit wall to an annulus,
bends the
separating member to provide stand-off between the member parts and conduits
they
separate.
[000262] Referring now to Figures 85 and 86, a plan view and elevation cross
section
view with and along line B-B, respectively, with break lines representing
removed
portions of a method (1BE) embodiment, usable with the axially slideable
annular
blockage bypass member (2BE) embodiment are shown. The Figures illustrate
circulation through upper (129U) and lower (129L) penetration between the
member
(2BE) and production tubing (11) to bypass a production packer (40) engaged
between the tubing (11) and production casing (12) and to place the partially
shown
well barrier element (3BE) to abandon a portion (4BE) of the well.
[000263] The slideable conduit (177), with upper (177UP) and lower (177LP)
pistons,
moves within the housing (178), which can be usable to engage the tubing (11)
with
slips (180) held by slip piston fingers (179) passing through slip finger
passageways
(179P) in the housing (178), wherein the member (2BE) can be placeable with a
cable
string using a receptacle (45E) and pressure applied against the top of the
slip piston
fingers (179) to engage the slips (180) in the slip receptacle (180R of Figure
91), thus
causing them to engage the tubing, after which the member is anchored and the
cable
string may be removed. Upper (66U1) and lower (66L1) seals on the upper
(177UP)
and lower (177LP) pistons, respectively, react to the orientation and
circulating
pressure of the circulatable fluid column (31C) to move the slideable conduit
(177),
dependent on the direction of circulation, to open and close the body's (178)
upper
circulating passageway (31CP2) and orifices (59U1) in the slideable conduit
(177).
The body's (178) upper circulating passageway (31CP2) and orifices (59U1) in
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CA 2841144 2019-02-12
slideable conduit (177) are open during reverse circulation (31CR of Figures
89-90)
and closed during forward circulation (31CF of Figure 89-90).
[000264] Once anchored with the upper (66U2) and lower (66L2) seals straddling
the
penetrations (129U, 129L) and packer (40), the member (2BE) can be operable
with
the circulatable fluid column (31C) using: forward circulation (31CF of Figure
89-90)
axially downward through the tools innermost bore (25BE) and returning fluid
axially
upward through the production annulus to the lower penetration (129L), then
between
the member (2BE) and the tubing (11) until exiting the upper penetration
(129),
having bypassed the packer (40) and re-entered the production annulus, and
reverse
circulation (31CR of Figures 89-90), axially downward through the production
annulus above the packer (40) and returning axially upward through the upper
penetration (129U), the circulation passageway (31CP) in the body (178), and
through
the orifices (59U1) in the slideable conduit (177) and into the member's inner
bore
(25BE).
[000265] Figure 87 depicts a projected view of Figure 86 with removed cross
sections
corresponding to the associated break lines, with detail lines C and D
associated with
Figures 88 and 89, respectively, of the axially slideable annular blockage
bypass
member (2BE). The Figure illustrates the slideable conduit (177) with upper
(177UP)
and lower (177LP) pistons within the housing (178 of Figure 91).
[000266] Referring now to Figures 88 and 89, magnified views of the portion of
the
axially slideable annular blockage bypass member (2BE) within detail lines C
and D
of Figure 87, respectively, are shown, illustrating the member (2BE) in a
reverse
circulation (31CR) position with the upper slideable piston (177UP) allowing
circulation to occur axially downward through the production annulus and the
upper
penetration (129U) above the packer (40) to return axially upward through the
body's
(178) upper fluid passageway (31CP2), to be diverted by the seals (66U1)
against the
tubing (11) into the orifices (59U1) and then axially upward or downward in
the
member's (2BE) bore (25BE). As the maximum circulating pressure is against the
lower side of the upper slideable piston (177UP), which is held in a raised
position
during reverse circulation, the reverse circulation position can be usable to,
e.g., first
place a cement plug below the production packer (40) with forward circulation,
and
then reverse circulate to remove excess cement from above the production
packer,
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CA 2841144 2019-02-12
after which a plug may be placed in the tubing to isolate formation below the
production packer. Alternatively, reverse circulation can be usable for
cleaning the
production annulus prior to cementing, directly injecting waste cleaning
fluids into the
permeable reservoir before forward circulating and packing a fluid member into
the
pore spaces of a reservoir to support cement within the production tubing and
production annulus and prevent gas migration.
[000267] Forward circulation travels axially downward from above the upper
slideable
piston (177UP) holding it in a closed position and, thus, closing the body's
(178)
upper fluid passageway (31CP2) orifice (59U2) with the piston's lower face,
while
placing the slideable orifices (59U1) against the body's bore to close them
also.
Circulation (31CF) continues axially downward until reaching the annulus and
returning axially upward to the lower penetration (129L) and diverting, as a
result of
the production packer (40) or other annular blockage, into the space between
the
tubing and the member (2BE) to the lower body (178) fluid passageway (31CP1)
until
reaching the closed upper fluid passageway (31CP2) orifices (59U2) and, then,
exiting through the upper penetrations (129U) to continue in the production
annulus.
This forward circulation method is usable, e.g. to clean the production
annulus and
tubing, while intermittently closing the annulus to inject waste fluids into
the
permeable reservoir, repeatedly, until a clean circulation fluid is achieved.
Once
clean, a cement, rheological controllable fluids and/or swellable gradated
particle
members may be intermittently squeezed into the permeable reservoir until it
locks up
and is capable of supporting a cement column, after which circulation can be
rocked
between reverse and forward circulation, against alternately open and closed
annular
and tubing bores, to hydraulically jar and pack the reservoir to fluidly
isolate it
sufficiently and to stop gas migration upward while clearing the circulating
pathways
for subsequent placement of a well barrier element, e.g. cement.
[000268] Referring now to Figure 90, an isometric view associated with Figures
85 to
89 is depicted, showing the reciprocating slideable straddle piston (177)
within the
axially slideable annular blockage bypass member (2BE) of Figures 85 to 89,
and
depicting upper (177UP) and lower (177LP) pistons with intermediate
circulating
orifices (59U1).
[000269] Referring now to Figure 91, an isometric view of a reciprocating
slideable
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straddle piston housing body (178), associated with Figures 85 to 90 of the
axially
slideable annular blockage bypass member (2BE) parts, is shown, depicting
upper
(31CP2) and lower (31CP1) fluid passageways adjacent to slip engagement finger
(179 of Figure 92) passageways (179P) for engaging slips (180 of Figure 93)
through
slip receptacles (180R).
[000270] Figure 92, an isometric view of a piston with slip engagement fingers
(179) for
actuating slips (180 of Figure 93) associated with Figures 85 to 91 of the
axially
slideable annular blockage bypass member (2BE) parts, shows a piston with
circulation orifices (59U1) above upper (180U) and lower (180L) slip (180 of
Figure
93) surfaces that hold the slip in place when the upper piston is forced
downward with
pressure from the circulating system, and wherein jarring upward jarring of
the string
is usable to remove the engagement of slips for retrieval of the assembly.
[000271] Figure 93 shows an isometric view associated with Figures 85 to 92 of
axially
slideable annular blockage bypass member's (2BE) parts, depicting a slip
segment
usable with the member (2BE) and various other embodiments.
[000272] Referring now to Figures 94 to 104, methods (1BF to 1BH) are shown
for
using an annulus jarring member to provide an explosive hydraulic pulse with
the
circulatable fluid column to displace a member and/or conduit wall to, in use,
provide
space for placement of well barrier elements to permanently fluidly isolate
(211-220
of Figure 15) at least one of producible zone or annuli from the wellhead.
[000273] Figures 94 to 96 illustrate embodiments of the method (1BF) for a
cocked jar
(2BF) and Figures 97 to 99 depict embodiments of the method embodiment (1BG)
for
a fired jar (2BG), for illustrating the firing sequence, wherein the same
apparatus is
used within Figures 94 to 99 with different positional relationships (213F,
2BG), while
the method embodiment (1BH) of Figures 100 to 104 illustrates the latched
(2BH1 of
Figure 102), latching (2BH2 of Figure 103) and unlatched (2BH3 of Figure 104)
positions of the hydraulic housing and piston assembly (2BH).
[000274] Referring now to Figure 94, an elevation view with break lines
showing
removed sections, associated with Figures 95 to 104, of a method (1BF)
embodiment
usable with a jarring member (2BF) embodiment is shown, depicting the member
(2BF) in a cocked position within the upper end of cut production tubing
(11U)and
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CA 2841144 2019-02-12
centralized by two expandable frame members (2BF2), thus providing stand-off
(211
of Figure 15) of the tubing from the production casing (12) above a piston
member
(213F1) of the present inventor, engaged to the lower end (11L) of the cut
production
tubing, wherein the arrangement is used to form an enlarged innermost
passageway
(25E) for placement of the partially shown well barrier element (3BF) to
abandon a
portion (4BF) of a subterranean well. The enlarged innermost passageway (25E)
is
further enlarged by forcing the piston (2BF1) axially downward with pressure
exerted
on the circulatable fluid column (31C) and by the hydraulic jarring of the
piston
member (2BF1) by the other member (2BG of Fig. 97).
[000275] The jar (2BF) can be engagable to the upper tubing (11U) with the
slips (180)
of a hanger (181) initiated by the rapid downward movement of releasing
tension in
the cable string (187 of Figure 95) acting against frictional drag blocks
(185), engaged
with the tubing (11U), after which pressure may be applied to circulatable
fluid
column (31C) to fully actuate and secure the hydraulic jar (2BF) for
subsequent
operation. After operation, the jar is released with upward tension of the
cable string
(187), wherein mechanical jars may be added to the assembly (2BF) above the
hanger
(181) to aid retrieval. The piston travel rod (184) has been retracted into
its upper
most position with pressure applied to the circulating column to ensure the
jar piston
(186 of Figure 96) is latched (2BF3) within the jar piston housing (182).
[000276] Figure 95, an elevation view associated with Figure 94 and 97, shows
the
embodiment of a jarring member (2BF) removed from the casing (12 of Figure 94)
and tubing (11U, 111 of Figure 94) in the latched position (2BF3). The upper
end is
engagable with a cable string (187), coiled tubing or jointed pipe arrangement
with
the slips (180) extending from the hanger (181), which is settable using the
drag block
(185) friction when quickly releasing line tension, after which the slips are
settable by
pressuring the hydrostatic column and releasable with upward movement of the
string
(187), optionally using an upward acting mechanical jar to release the
assembly. The
hydraulic jar's (2BF) piston (183) is shown engaged within the piston housing
(182),
wherein the piston (183), when fired, travels from the housing (182) to the
spring
(144) at the lower end of the piston travelling rod (184).
[000277] Figure 96, an elevation view associated with Figure 95, shows the
parts
(2BF4) of the jarring member (2BF of Figure 95) comprising the piston (183)
with
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CA 2841144 2019-02-12
latching dogs (186) movable along the piston travelling rod (184) with a
string (187)
connection at its upper end and a dampening spring (144) at its lower end,
wherein the
anchor (181 of Figure 95) and piston housing (182 of Figure 95) are removed.
[000278] Referring now to Figure 97, an elevation view with break lines
showing
removed sections, associated with Figures 94 to 96 and Figures 98 to 100 of a
method
(1BG) embodiment of a jarring member (2BG6) is shown. The Figure depicts the
member (2BG) in a fired position (2BG6) within the upper end (11U) of cut
(2BG2)
production tubing, centralized by two expandable frame members (2BG4) above a
piston and hanger member (2BG3) of the present inventor, engaged to the lower
end
(11L) of the cut and compressed (2BG1) production tubing, wherein the
arrangement
is used to form an enlarged innermost passageway (25E) for placement of the
partially
shown well barrier element (3BG) to abandon a portion (4BG) of a subterranean
well.
The enlarged innermost passageway (25E) is further enlarged by forcing the
piston
(2BG3) axially downward with pressure exerted on the circulatable fluid column
(31C) with hydraulic jarring by the member (2BG) to further compress or crush
(2BG I) the cut (2BG2) lower end (1 IL) of the production tubing.
[000279] After latching the hydraulic jar (1BF of Figure 94), pressure is
applied to the
fluid column (31C) acting against seals (66P) of the piston (186) causing it
to fire
(2BG6), after which it travels along the rod (184) to engage the dampening
string
(144) at the lower end of the rod (184), having delivered a sudden jarring
hydraulic
pulse (2BGJ) to the upper end of the piston and hanger member (2BG3) to
further
compress (2BG1) the cut (2BG2) tubing (11L) with, e.g., helical buckling,
plastic
failure and/or contortion, thus causing the enlarged innermost passageway
(25E) to
become larger so that a well barrier element (3B0) may be placed adjacent to a
portion of the well (4BG), wherein a viscous rheological fluid (2BG5) may be
used to
bridge a breach (4BGX) in the casing. After increasing the enlarged inner
passageway space sufficiently to allow logging, the vertical extent of the
breach may
be determined for subsequent cement squeezes or the cement bond can be
confirmed
behind the casing (12). The centralizing (2BG4) member can be usable during a
jarring operation, but is not required. If logging is required, the
centralizing member
(2BG4) could, e.g., be removed to provide space for a logging member, then
replaced
to provide tubing (11U) stand-off.
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CA 2841144 2019-02-12
[000280] Figure 98 is an elevation view, associated with Figures 94 and 97 of
an
embodiment of a jarring member (2BG) removed from the casing (12 of Figure 97)
and tubing (11U, 1 1 L of Figure 97) in a fired position (2BG6). The piston
(183), with
latching dogs (186) and seals (66P), can be positioned at the lower end of the
travelling piston rod (184) adjacent to the impact dampening and latching
spring
(144).
[000281] Figure 99, an elevation view associated with Figure 98, shows the
parts
(2BG7) of the jarring member (2BG of Figure 97) comprising the piston (183)
with
latching dogs (186) movable along the piston travelling rod (184) with a
string (187)
connection at its upper end and a latching and dampening spring (144) at its
lower
end, wherein the anchor (181 of Figure 97) and piston housing (182 of Figure
97) are
removed.
[000282] Referring now to Figures 100 and 101, plan and elevation cross
section views
with line E-E and along line E-E, respectively, are shown with break lines
representing removed sections of method (1BH) and jarring member (2BH)
embodiments associated with Figures 94 to 99, wherein Figure 101 has a detail
line F
associated with Figures 102 to 104, depicting the latched position (2BH1) of
the cable
string (187) deployable jarring member (2BH), usable to enlarge an inner
passageway
(25E of Figures 95 and 97) and to place a well barrier element (3BH) adjacent
to a
portion (4BH) of a well to be used or abandoned. The piston (183) can be
usable to
create an explosive hydraulic jarring fluid pulse as it is driven by
compressed
pressurized fluid above the piston and exits the housing (182) travelling
along the re-
latching rod (184) until it reaches a dampening and latching spring (144).
[000283] Figures 102, 103 and 104 are magnified views of a portion within
detail line F
of Figure 101 of the latched (2BH1), latching (2BH2) and unlatched (2BH3)
jarring
member positional embodiments, respectively, showing a travelling rod (184)
passing
through the piston (183) with piston seal (66P) secured to a piston body
(183A), and
with seals (66) and maintenance connections (189), shown as bolts for repair
and
replacement of parts, like the latching dogs (186) within the piston housing
(182). A
triggering cam (188) between upper (144U) and lower (144L) springs within the
piston body (183A) actuate and release latching dogs (186) from the piston
housing
(182) during latching and firing of the jarring member.
101
CA 2841144 2019-02-12
[000284] Figure 102 shows the hydraulic jarring piston assembly (2BH) in the
latched
position (2BH1) with the triggering cam (188) positioned by upper and lower
springs
(144U, 144L) to extend the latching dogs (186) into a receptacle in the
housing (182),
to hold the piston assembly in place against the pressure of the circulatable
fluid
column (31C) being hydraulically compressed over its volume to store energy
for
firing jarring member, with the firing pressure defined by the spring's (144U,
144L)
resistance.
[000285] Figure 103 shows the hydraulic jarring piston assembly (2BH) in the
latching
position (2BH2) with the triggering cam (188) pushed upward by string (187 of
Figure 101) tension applied to the travelling rod (184), and the
latching/dampening
spring (144) against the fluid column (31C) and upper spring (144U) to allow
the
latching dogs (186) to retract against the cam's surface and enter the housing
(182)
moving upward until reaching the receptacle in the housing (182), when string
tension
is released and the upper spring (144U) pushes the cam (188) downward as the
latching/dampening spring (144) holds the piston (183) in place when the
travelling
rod (184) is lowered. Thus, the dogs (186) are allowed to extend into the
receptacles
of the housing (182) and latch (2BH1 of Figure 102) the piston assembly (2BH)
in
place.
[000286] Figure 104, shows the piston in the firing position (2BH3), where the
pressure
exerted on the circulatable fluid column (31C) is increased until the
triggering cam
(188) is pushed down to release the latching dogs (186) from the receptacle in
the
housing (182), thus firing the hydraulic piston with pressure from the
compressed
fluid column expanding and acting first against seals (66) on the piston body
(183A)
against the housing (182) and, then, on seals (66P) on the piston (183)
engaged
against the conduit (11 of Figure 101), thus forming an explosive hydraulic
pressure
pulse or fluid hammer acting on the fluid trapped fluid and/or fluid member
below the
piston, thus transferring a kinetic jarring force onto downhole equipment
(2BG3 of
Figure 97 e.g.).
[000287] Referring now to Figures 105 to 122, methods (1BI, 1BJ) of using an
annulus
boring access members in a retracted deployable position (2BI) and extended
boring
position (2BJ) are shown, usable with various other method and cable
compatible rig-
less string operable member embodiments to penetrate conduits and/or strata
walls
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CA 2841144 2019-02-12
and to access annuli at one or more subterranean depths (218-219 of Figure 15)
to
permanently fluidly isolate (211-220 of Figure 15) at least one of producible
zone or
annuli from the wellhead.
[000288] Referring now to Figures 105 and 106, plan and cross-section
elevation views
with line G-G and along line G-G, respectively, are shown and include a method
(1BI) embodiment usable with an annulus boring access (2BI1), boring bit
engagable
conduits (2BI2), swellable conduit (2BI3), pressure assist piston (2BI4),
boring
conduit (2BI5) and annular access guiding (2BI6) member embodiments, which are
associated with Figure 107 to 111. The Figures further depict a flexible shaft
(174B)
and boring bit (174A) assembly (174) in a retracted (2B11) deployable
position,
operable with a downhole motor (111) and using the line tension of the
deployment
string and applied pressure of the circulatable fluid column (31C) against an
assisting
piston (2BI4) through a guide (e.g., whipstock) (2BI6) to penetrate a conduit
wall
(11), at a selected depth, for placing the partially shown well barrier
element (3BI) to
use and/or abandon a portion (4BI) of a well.
[000289] The whipstock guiding member (2BI6) can be deployable with the motor
(111), e.g. a motor assembly of the present inventor (2B0 of Figure 123), and
can be
usable with any form of engagement (180A) between the whipstock (2B16) and
conduit (11), operable with string tension and/or fluid pressure, such as
slips or
inflatable element grips, wherein after boring the guide may be left in place
by
releasing the motor assembly (111) from the guide at a connector engagement
(45R).
As guides are usable to, e.g., place logging members or direct fluids, such as
cement,
they may be left downhole permanently or retrieved at their connector
engagement
(45R) after disengaging the hold (180A) on the conduit in which they are
placed.
[000290] Placeable conduits (2BI2, 2BI3) may or may not be present with the
flexible
shaft and boring bit (174) being retrievable or detachable and disposable
through the
guide and/or conduits. In some instances flexible shafts (174B) and/or boring
bits
(174A) may be sheared from the motor (111) and left within the annuli to,
e.g., free a
stuck assembly and/or provide standoff (211 of Figure 15). A boring bit also
can be
usable as a mechanical expander to expand an expandable conduit (2BI2) placed
within an annulus and held by an assisting piston (2BI4) as the bit (174A) is
retrieved
from its bore by pulling the flexible shaft (174B). A guide (2BI6) may be
relatively
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CA 2841144 2019-02-12
straight or curved as shown in the depicted method (1BI), to accommodate
conduits
that are relatively inflexible or malleable materials requiring protection
from adverse
stresses during placement. Alternatively, if the axial length of the guiding
whipstock
is significant, e.g. 10 metres, relatively straight conduit members usable for
guiding
and deploying, e.g., long logging tools within an annulus are usable without
adverse
affect upon most conduit materials because inclinations and the associated
curvature
are relatively low.
[000291] Figure 107, a rotated isometric view of an annulus boring access
(2B11)
member embodiment associated with Figure 106 and engagable members of Figures
108 to 111, shows a motor (111) with a flexible shaft (174B) and boring bit
(174A)
assembly (174) with orifices (59B) through the bit for fluid communication and
engagement orifices (59A) for the boring conduit (2BI5 of Figure 111) with,
e.g.,
shear pins. The bit (174A) is shown without cutting surfaces as it may be of
any type
or angularity, including, e.g., a tractor or auger to crawl and/or bore
between the
circumferences of adjacent conduits within an annulus to create stand-off (211
of
Figure 15) and separation or flow between eccentric conduits (167C of Figure
13),
wherein the auger pushes through a coupon cut, e.g., by a cutting conduit
(2BI5 of
Figure 111).
[000292] Referring now to Figures 108 and 109, isometric views associated with
Figures 105 and 106 of boring bit engagable conduit (2BI2) and swellable
conduit
(2BI3) member embodiments, respectively, are shown with dashed lines
illustrating
hidden surfaces, and showing conduits that may be, e.g., rigid, flexible,
expandable
and/or swellable dependent upon use, e.g., the swellable conduit (2B13) can
create a
pressure seal between annuli after having been expanded against the bore
through the
walls of the conduits by the expandable conduit (2B12). Dependent upon the
application, conduits may be rotated with the flexible shaft and boring bit
(174 of
Figure 107) or held stationary by the guide (2B16 of Figures 105-106). A race
or
bearing engagement (190B) at the lower end of the non-rotational conduit
(2B12)
allows the lower end conduit (2BI5 of Figure 111) to rotate and bore a round
coupon
for an auger bit to push through or assist a boring bit (174A of Figure 107)
during
boring operations. An assisting piston (2B14 of Figure 110) can be usable for
insertion of the conduit into a bored hole and/or pressure assisting the
penetration rate
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CA 2841144 2019-02-12
of boring bit by engaging a pushing surface (96B of Figure 110) with the
conduit's
end or a load shoulder (96A), further usable to engage the conduit (11) wall,
thus
determining when the conduit is fully inserted and preventing over-insertion.
The
conduit lip (96A) also serves to connect the bit engagable conduit (2B12) to
the bored
conduit (11 of Figures 105-106) by, e.g., shaping the lip to the inside
diameter of the
bored conduit and placing a sealing material between the lip and conduit
and/or by
constructing the conduit and lip of an expandable metal to deform to the
inside
diameter of the installed, wherein the lip connector (96A) may hold
differential fluid
pressure. The boring bit engagable conduit (2B12) and swellable conduit (2B13)
may
also comprise, e.g., swellable expandable mesh membranes (97).
[000293] Figure 110, an isometric view associated with Figure 105 and 106 of a
pressure assisting annular piston part (2B14) of annulus engagable member
usable to
increase the force applied to the boring bit and conduits, illustrates an
internal orifice
(59C) for passageway for the flexible shaft (174B of Figure 107) arranged with
angular offset surfaces within the orifice to prevent binding of the flexible
shaft, when
passing through the annular guide member (2BI6 of Figures 105 and 106). The
piston
portion (143) can be arranged to provide a surface for continued pressure
assistance
once the conduit engagable lip (96A) has left the guide (2B16 of Figures 105-
106)
with the conduit engagement surface (96B) to the conduit lip connection (96A)
to,
e.g., deform a sealable elastomeric or metal material to the circumference of
the
conduit (11 of Figures 105-106).
[000294] Figure 111 is an isometric view associated with Figure 105 and 106 of
a
rotatable boring bit engagable conduit member (2B15) embodiment that can be
engagable to the flexible shaft and bit (174 of Figure 107), with orifices
(59A) to, e.g.,
engage shear pins anchoring the cutting structure (100) rotatable conduit
(2B15) to the
bit (174A of Figure 107), illustrating a conduit engagement race or bearing
(190A)
axially secured for rotation about a rotating or non-rotating conduit (2BI2 of
Figure
108), wherein the member (2BI5) may rotate with the boring bit (1 74A of
Figure 107)
to, e.g., enlarge the bore for passage of the trailing conduit (2B12 of Figure
108).
[000295] Referring now to Figures 112 and 113, a partial plan view and
elevation cross
section, with line H-H and along line H-H, respectively, associated with
Figures 105
to 111 and Figures 114, 115 and 116 magnified views, showing portions within
detail
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lines J, K and L of Figure 113, respectively, are shown and depict a method
(lBJ) and
boring bit engagable conduit member (2BJ) embodiments, which illustrate a
flexible
shaft and boring (174) arrangement in an extended position (2BJ1) having bored
through installed conduits of a well to access annuli (24, 24A, 24B, 24C) and
to place
the partially shown well barrier element (3BJ), thus using and/or abandoning
the
annulus (24C) adjacent to a portion (4BJ) of the well. Conduits may be placed
with
the boring bit or placed after removing the bit and, depending on the pressure
bearing
nature of the conduit along its axis, one or more annuli may be fluidly
accessed.
[000296] Straight or curved and relatively rigid or flexible conduits of
malleable or hard
material are usable with the arrangement (1BJ1), showing that a rigid conduit
is
placeable through the inner bore (25), concentric conduits (11, 12, 15, 15A)
and
annuli (24, 24A, 24B) to reach the outer annulus (24C) within commonly sized
concentric conduits contained within, e.g, the 30 inch outside diameter
conductor
(14) casing. Alternatively, the curvature and inclination of the whipstock,
(2BI6)
deployable through and engagable (180A) to the innermost conduit (25), may be
varied and arranged to access any number concentric or eccentric conduits and
their
associated annuli with flexible or rigid conduit members.
[000297] Figures 114, 115 and 116, are magnified detail views of the portions
of the
boring bit engagable conduit member (2BJ), in an extended position (2BJ1),
within
detail line J of Figure 113 and detail lines K and L of Figure 114,
respectively,
illustrating a conduit member (2BJ) comprising, e.g., an expandable metal
conduit
(2BI2) with an elastomeric conduit sheath (2BI3) or a rigid metal conduit
(2BJ2) with
a swellable elastomeric sheath (2BJ3), or other suitable combinations, that
are
placeable and sealable against the bores penetrating the walls of the well
conduits (11,
12, 15, 15A) to provide, e.g., selective fluid communication between the
innermost
passageway (25) and the outer annulus (24C), wherein the length and sealing
capabilities of the wall of the conduits (2BI2, 2B32, 2BI3, 2BJ3) may be
varied to
access and selectively communicate between the innermost passageway (25) and
one
or more of the annuli (24, 24A, 24B, 24C).
10002981 The flexible shaft and boring bit assembly (174) is contained within
a conduit
capable of fluid communication of the circulatable fluid column (31C) to
supply fluid
boring bit lubrication and cooling, while penetrating through the well conduit
walls,
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with fluid flowing between the flexible shaft (174B) and the pressure
assisting piston
(2B14), carried conduits (2B12, 2BJ2, 2B13, 2B.13), and passageway orifices
(59B) of
the bit (174A). A rotatable boring conduit (2B15) can be engagable to the bit
(174A)
with, e.g., shear pins (92) through orifices (59A), thus providing a slightly
larger
diameter bore than the bit (174A) for ease of conduit placement, conduit
expansion,
bit retrieval and/or fluid circulation, cleaning, lubricating and/or cooling.
[000299] The pressure assisting piston (2B14) can be latchable into the guide
(2B16) to
hold conduits (2BI2, 2BJ2, 2B13, 2BJ3) within the bore while extracting the
flexible
shaft (174B) and boring bit (174A). Conduits may be secured and sealed within
the
wall penetrations through the conduits (11, 12, 15, 15A) by using expandable
metal
conduits (2B12) expanded by boring bit extraction, swellable conduit sheaths
(2BJ3)
expanded by chemical reactions or other means, such as settable materials like
glues,
cements or wedges within the space between conduits. After securing placed
conduits
(2BI2, 2BJ2, 2B13, 2BJ3) within installed conduit (11, 12, 15, 15A)
penetrations, the
bit and pressure assisting piston can be retrieved with the guiding member
(2B16) or
the guiding member can remain to guide further members or fluid
communications,
after which the guide (2B16) may be permanently left downhole or retrieved.
[000300] Referring now to Figure 117 and 118, plan and elevation cross section
views
with line M-M and along line M-M, respectively, with dashed lines showing
hidden
surfaces of method (1BK) and annular access guiding member (2BK) embodiments,
usable with flexible shafts and boring bits to access the annuli (24, 24A) of
a well for
use and/or placement of a well barrier clement (3BK) adjacent to a portion
(4BK) of
the well. Guiding whipstock members, e.g. (2BK), are usable for accessing a
plurality
of annuli (24, 24A) with a plurality of penetrations (232) through a plurality
of
conduit (11, 12) circumferential walls at one or more subterranean depths for
using a
well and/or placing a permanent barrier. Guiding whipstocks are placeable,
usable
and retrievable with various conduit (11) engagement means (180A), shown for
illustration purposes as slips, and connections (45R), wherein a spring
operated check
valve (84) is usable for fluid displacement from above when, e.g., checking
pressures
below the whipstock and/or operating a positive fluid displacement motor.
[000301] The whipstock member (e.g. 2BK) may form part of a multi-motor
assembly
(2AN of Figure 63) or single motor assembly (2B0 of Figure 123) with multi-
part
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CA 2841144 2019-02-12
(43, 47 of Figure 48) rotatable whipstocks (2Y of Figure 48). The method (1BK)
may
also be combined with various rotatable engagements (180 of Figure 51) and/or
indexing means (e.g. 176A, 176B of Figures 78-79) to produce the pattern shown
in
method (1AP) of Figure 65 when rotated once to produce 6 bores or, e.g., twice
to
produce 9 bores. A plurality of bores is usable for cleaning of conduits walls
to
ensure a wettable surface for bonding (213 of Figure 15) and, e.g., placement
of
rheological controllable fluid members around the circumference of annuli
conduit
walls to support (212 of Figure 15) or form well barrier elements that bridge
the entire
annuli.
[000302] Referring now to Figures 119 and 120, plan and cross section
elevation views
with line N-N and along line N-N, respectively, are shown and are associated
with
Figures 121 and 122, with dashed lines depicting hidden surfaces. The Figures
depict
method (1BL) and annular access guiding member (2BL) embodiments, usable to
guide another annulus accessing member to place the partially shown well
barrier
element (3BL) for using and/or abandoning a portion (4BL) of a well.
[000303] The member (2BL) can be usable with any conventional rig-less
conveyance
and/or anchoring apparatuses (e.g. 45R and 180B of Figures 117-118) to place a
member at one or more selected depths, wherein any annulus engagable (2BL4,
2BL5) or well barrier element (3BL) member parts, being transversely sized or
fluidly
mobile, may pass through any of the member's (2BL) guiding passageways (2BL1,
2BL2, 2BL3). Cables for logging members (2BL5), flexible shafts for boring
bits, or
any suitably sized or fluidly acting member is both guidable and usable within
the
method (1BL).
[000304] Swellable and/or fluid members comprising, e.g., a swellable packer
element
and/or swellable gradated particles (2BL4) may be expelled from the main
passageway (2BL4) and forced downward through the enlarged innermost
passageway (25E) within the casing (12) using the density, rheological
properties
and/or pressure exerted on circulatable fluid column to the lower end of the
member
(2BL), with reagent swelling fluids and/or segregated reactive reagents
expelled
through each of smaller passageways (2BL2, 2BL3) to mix within the enlarged
passageway (25E) forming a gunk and/or swellable packing that bridges across
the
inner wall of the casing (12). Various conventional pressure burstable
separating
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CA 2841144 2019-02-12
members may be placed at the lower ends of, e.g., the smaller passageways
(2BL2,
2BL3) to release reagents at a defined pressure. Additionally, a motor member
(e.g.
2B0 of Figure 123) may be engaged with, and rotate the upper end of the
member,
(2BL) to assist mixing of a rheological controllable fluid member.
[000305] Figures 121 and 122 are plan and elevation views, respectively, with
dashed
lines showing hidden surfaces of method (1BM) and annular access guiding
member
(2BM) embodiments, depicting a stack of angularly offset members (2BL of
Figures
119 and 120) usable with various other embodiments to access or place other
members, including the partially shown well barrier element (3BM) within one
(4BM)
or more portions of a plurality of annuli simultaneously. The guiding member
comprises larger passageways (2BM1, 2BM3, 2BM5) usable for holding and
deploying suitably sized mechanical, elastomeric or fluid annulus engagable
members, wherein the larger passageways extend axially downward from smaller
connected passageways (2BM2, 2BM4) usable to, e.g., transmit pressure from the
circulatable fluid column and to deploy mechanical or electrical cables,
flexible shafts
or other member parts usable from within the spaces, wherein a plurality of
angular
offset passageways can be usable, at various depths, to guide the annular
engagement
of another member, and wherein the guiding member can be selectively
rotatable,
repeatably around the circumference at the same depth with, e.g., ratcheting
devices
(176A, 176B of Figures 78, 79).
[000306] The method (1BM) can be usable to, e.g., guide larger boring bits
than are
possible from (2BK) of Figures 117 and 118, wherein flexible shafts (174B,
2BM6,
28M7) can be placeable through passageways (2BM2, 2BM4) to engage larger
diameter boring bits (174A) extending from within associated larger
passageways
(2BM1, 2BM3, 2BM5) and usable to bore through an innermost passageway conduit
(11) engaging the annulus (24) between the conduit and the casing (12) for
placement
of the partially shown well barrier element (3BM) to abandon a portion (4BM)
of the
well. The service breaks (2BM8, 2BM9) are usable to access the flexible shafts
and
boring bits for repair and replacement, with conduits and associated
passageways
placeable between the service breaks to vary the depths between penetrations.
Additionally by rotating the member (2BM), it is possible to form a plurality
of
passageways (e.g. 1AP of Figure 65) simultaneously at various depths using a
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CA 2841144 2019-02-12
motorized member (e.g. 2AN of Figure 63).
[000307] Referring now to Figures 123 to 147, methods (1B0 to 1BU) of using
annulus
engagable members to mill and shred conduits to form an enlarged innermost
passageway are depicted and can be usable for logging and cement placement to
permanently fluidly isolate (211-220 of Figure 15) at least one of producible
zone or
annuli from the wellhead and to emulate a drilling rig abandonment, wherein
the
methods and members are also usable in various other embodiments.
[000308] Figure 124 is an isometric view of method (1BN) and axial screw
tractor
member (2BN) embodiments with an intermediate section removed to show an
internal rotor (109) and stator (108), wherein detail lines P, Q and R are
associated
with Figure 125, 126 and 127, respectively. The upper end rotary connector
(72U)
can be engagable to a slickline or braided wire cable using anti-rotation
devices to
prevent undesirable twisting of the cable in the event of tractor (2BN)
slippage and
the lower end rotary connector can be usable with, e.g., a mill (1BT of
Figures 143-
145) the appropriate cross-over and/or vibration dampening devices, wherein
the
assembly can be usable with, e.g., a conduit shredding member (1BR of 135-140)
to
form an enlarged innermost passageway (25E of Figure 127) for placement of the
partially shown well barrier element (3BN of Figure 127) for using and/or
abandoning
a portion (4BN of Figure 127).
[000309] Referring now to Figure 125, 126 and 127, magnified views of the
portion of
the axial movable screw or tractor member (2BN of Figure 124), within detail
lines P,
Q, R of Figure 124, respectively, are shown and illustrate using the flow of
the
circulatable fluid column (31C), diverted by an upper seal (2BN1), into upper
passageways (2BN2) and to an internal positive displacement fluid motor,
comprising
a rotor (109) within a stator (108), to drive a lower rotary connector (72L),
engagable
to, e.g., rotary cleaning, cutting and boring members , an axially tractor
within a
subterranean conduit engaged to a wellhead, such as a well conduit (11) or
buried
pipeline engaged through a production header and valve tree to the wellhead,
to move
the assembly (2BN) axially upward, downward or laterally within the vertical
and
horizontal portions (4BN) of the innermost passageway of a well or pipeline
conduit,
depending on the orientation of the screw arrangements (2BQ) against the
subterranean conduit wall and, of course, the orientation of the subterranean
conduit
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CA 2841144 2019-02-12
itself.
[000310] The method (1BN) and apparatus (2BN) can be usable for accessing and
using
a portion (4BN) of a subterranean conduit engaged to a producible zone and/or
abandoning a well conduit with a well barrier element (3BN). The tractor (2BN)
functions with reactive torque from the rotor (109), with the tractor screw
(2BQ)
secured to the stator (108), wherein as fluid is positively displaced between
the rotor
and stator through the fluid, the stator urges the screw (2BQ) engagement of
the
tractor (2BN) to the conduit (11) and pushes or pulls drive the tractor
axially to
operate, e.g., cutters (2BP2 of Figure 129) constrained by the shredding of
tubing or
other devices.
[000311] Fluid from the fluid motor may be discharged through lateral ports
(2BN3)
and/or axially downward about a solid shaft or through a rotating conduit
fluid
passageway engaged to, e.g., a drilling bit or cleaning brush with jetting
fluid nozzles
pulled by the tractor axially downward, wherein the discharged fluid that can
be
usable by the boring drilling bit for cooling, lubricate and jetting downward
to remove
a bored object, e.g., previously placed expandable conduits, expandable mesh
and/or
cement, or, e.g., a nozzled brush may be used to mechanically brush and
hydraulically
jet clean scale from an installed conduit, so as to provide a clean wettable
surface for
a permanent cement bond.
[000312] Figures 128 and 129 are elevation views with the strata and a half
section of
the conduits removed, wherein the portion below the break line at the bottom
of
Figure 128 is connected to the portion shown below the break line at the upper
end of
Figure 129. The method embodiment (1BP) can be usable with the set (213P) of
circumferential milling (213P1), axial conduit shredding (2BP2) and axial
movable
screw tractor (2BP3) member embodiments rig-lessly operable, using cable
string
tension and the circulatable fluid column, to drive a fluid motor and kelly
(233). The
fluid column (31C) can be circulated down the innermost passageway (25),
diverted
by seals (2BP6) through ports (2BP5) to drive a fluid motor (239),
conventional mill
(238) and tractor screws (2BP3, 2BP4) pulling a conduit shredder (2BP2),
wherein the
circulated fluid returns past the lower end of the innermost conduit (11U)
through the
annulus (24), resulting in the arrangement forming an enlarged innermost
passageway
(25E) usable to place the partially shown well barrier element (3BP) and
abandon a
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CA 2841144 2019-02-12
portion (4BP) of the well.
[000313] The members (2BP) can be usable to mill the lower end of production
tubing
(11U) to form an enlarged innermost annulus (25E) engaged with the production
annulus (24) using a conventional mill (238) or embodiments (e.g. 2AY of
Figure 74
or 2BT of Figure 146), wherein an internal kelly (233) extending through the
motor
(239) to the swivel (234) can be rotated by a kelly bushing engaged to the
rotor within
the motor, such that the kelly and mill are axially movable (237) to mill the
conduit
(11U) after it has been shredded by an embodiment (2BP2) pulled by upper
(2BP4)
and lower (2BP3) screw tractors with radial circumferential fixed or wheeled
screw
cutters, operated with the reactive torque of the stator, to cut and weaken
(236) the
conduit helically. The
helical weakening (236) of the conduit (11U) assists the
shredder (2BP2) restraining, and the pulling by the tractor to split the
conduit while
the mill (238) is rotated by the motor and reciprocated upward and downward
(237),
to minimise jamming and stalling of the motor, thus deconstructing the tubing
(11U)
with the assembly (2BP).
[000314] The rotation of the reciprocating (237) kelly (233) and mill (238)
are
prevented from transferring, damaging and potentially breaking the coiled
slickline or
braided wire cable string (187) using the bearings and races of the swivel
(234) with a
further anti-rotation device (235) used to hold the upper end of the swivel
(234), thus
preventing the transfer of rotation. Rotary cable tool anti-rotation devices
of the
present inventor engage the wall of the conduit (11U) with spring operated
rollers to
allow passage of the tools through restrictions, such as nipples, without
damaging the
inner wall, should it be further needed.
[000315] Referring now to Figures 130 and 131, plan and cross section
elevation views,
with line S-S and along line S-S, respectively, of method (1BQ) and axial
movable
screw member (2BQ) embodiments with dashed lines showing hidden surfaces in
Figure 130, and the detail line T of Figure 131 associated with Figure 133,
are shown.
The Figures illustrate a series of helically placed rotational screw wheel
cutters (240)
arranged to act as a moving rotational screw tractor within the walls of the
containing
and deployment conduit (11) that cuts and weakens (236) the wall as it uses
its
helically placed and rotatable screw wheels. The screw tractor's (2BQ) upper
end
(2BQ I ) or lower end (2BQ2) are engagable to a stator of a fluid motor or the
housing
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CA 2841144 2019-02-12
of an electric downhole motor and arranged to move upward, e.g., with a
conduit
shredder, or downward with, e.g., a boring bit, wherein a solid shaft or fluid
conduit
engaged to the bit, mill or other rotational device can rotate within the
central
passageway (247) as the tractor pushes or pulls the device. The tractor (2BQ)
is
therefore usable to apply axial force to a rotating device using the reactive
torque of
any downhole motor against the a wall of a subterranean well, e.g., to form an
enlarged innermost passageway (2BP3 of Figure 129) for placement of the
partially
shown well barrier element (3BQ) to use or abandon a portion (4BQ) of a well.
[000316] Figures 132, 133 and 134 depict an isometric projected view of Figure
131, a
magnified portion of Figure 131 within line T and an exploded view of
component
parts of the axial movable screw (2BQ of Figure 130), respectively, showing
that the
tractor (2BQ) can be arranged with deployable and retractable wall
engagements, to
pass restrictions, such as subsurface safety valves and nipples, using, e.g.,
cam
retractable and deployable cutting wheels (240) to weaken (236 of Figure 129)
a wall
or non-damaging gripping wheel comprised of a reinforced elastomeric tyre, or
tire,
material engagable and disengagable from the wall using reactive torque
applied to
the upper (2BQ1) or lower (2BQ2) connection with the circumference of the tool
acting as drag block. For example, when used with a cable deployable downhole
motor of the present inventor, the tractor (2BQ) may be deployed with its
wheels
retracted to pass restrictions within the production tubing (11 of Figure
130), then
deployed to push or pull the fluid motor using the reactive torque of the
motor,
activated with fluid circulation at a selected depth, to rotate internal cam
plates (242U,
242L) and engage the wheels (240) the wall of the conduit (11).
[0003171 The upper connector (2BQ1) can have gear teeth (245) or splines
engagable
with associated gear teeth or splines (246) of cam plates (241, 241U, 241L)
for
driving screw wheel shafts (243) within associated terraced or inclined cammed
wheel
guides (242U, 242L), arranged to deploy the screw wheels (240) with right hand
rotation from the reactive torque of a motor and to retract the wheels with
left hand
rotation from reactive torque of the motor turning in the opposite direction,
or vice
versa, dependent on the rotary connections involved and the direction of
tractor axial
travel. The helical curving of the wheels (240), to form the screw to push or
pull the
tractor along the wall, is formable with the terraced upper (242U) and lower
(242L)
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CA 2841144 2019-02-12
cam guide using eccentric shim washers (244) to angularly align the wheels to
form a
helical screw about the circumference of the member. Alternatively, e.g., the
surface
may be inclined instead of terraced, without the need for eccentric shimmed
washers,
wherein an eccentric bearing passageway through the wheel (240) for the shaft
(243)
is used to form the helical screw.
[000318] Referring now to Figures 135, 136, 137 and 138, plan, elevation,
isometric
projection and isometric exploded views, respectively, are shown with a half
section
of the installed well conduits removed and line U-U of Figure 135 associated
with
Figures 139 and 140. The Figures depict a method (1BR) and axial conduit
shredding
member (2BR) embodiments, with an upper end (2BR1) rotatable pass through
internal axial cam (260) shaft (251) engagable to, e.g., a tractor, motor or a
braided
cable line pulled by a surface capstan unit capable of supplying sufficient
line tension
to shred the same conduit through which the member was deployed to, after use,
place
the partially shown well barrier element member (3BR) to permanently seal a
portion
(4BR) of a well.
[000319] The depicted method (1BR) uses the member (2BR) to shear or shred the
weakened (236) conduit (11U) in an axial direction using line tension applied
to the
upper end or tension applied by an engaged device, e.g., a tractor engaged to
the
upper end. The cutting extendable and retractable knifes (248) can extend into
and
engage the annulus (24) within the production casing (12) to produce a cut
(250),
wherein associated cutting wheels (249) arc also usable to weakened the
conduit
(11U) prior to engagement of the knife (248).
[000320] A series of cutting wheels (249) are engagable to and deployable with
pivot
arms (258) hinged with a pin (not shown) through a shaft support (261) in the
body
(252) from within cavities (255), that can be actuated by the axial cam (260),
wherein
the cam (260) is also usable to deploy knives (248) with similar shaft support
(253)
and knife recesses (254) from within the body (252). The recesses (254, 255)
of the
body (252) are supported with upper (257) and lower (259) plates secured with
connectors (256) to the body (252).
[000321] Referring now to Figures 139 and 140, elevation cross section views
along U-
U of Figure 135 showing the method (1BR1) associated with the axial conduit
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CA 2841144 2019-02-12
shredding member (2BR) and the method (1BR) associated with the axial conduit
shredding member (2BR) of Figures 135 to 138, illustrating a rotatable shaft
(251 of
Figure 139) and cam (260 of Figure 139) in an inactivated deployment position
(2BR3), with the wheel cutters (249) and knives (248) deployable through the
inner
passageway (25) of the innermost conduit (11U) and in an activated position
(260 of
Figure 140), and with the cutters (249) and knives (248) deployed to cut (250)
and
shred the conduit (11U), which in Figure 140 has been weakened (136) by a
tractor's
screw cutters.
[000322] The method (1BR1) can be usable with a coiled cable string and
capstan
pulling unit deployed within a previously uncut conduit (11 shown as dashed
lines),
wherein the cam can be arrangable to extend the cutters with applied string
tension
using, e.g., a mechanical and/or hydraulic jar to selectively actuate the tool
at a depth
with upward acceleration and/or jarring, and releasing the tool from the wall
of the
conduit with, e.g., downward jarring. A shredding member is formable with both
or
either of the knives (248) and wheel cutters (148), with or without tractor
cutter
weakening (136). In this method, the member can be deployable once the
assembly
(1BR, 2BR) has exited a cut conduit (11U) with a compressed lower end or,
e.g.,
directly from within an uncut conduit (11) using a surface hoisting and/or
capstan
unit. Additionally, the complexity and associated construction cost of member
may
be such that they are disposable downhole, within the well to be abandoned
after
having served their purpose. For example, a shredder may be activated with a
small
explosive charge after placement at a desired depth followed by shredding of
the
conduit with a capstan, disengaging the coiled cable string and leaving the
shredder
downhole, once a sufficient length of tubing has been shredded. This may be
followed by circulation, cleaning and placement of cement or, e.g., cutting
the tubing
above the shredded conduit portion and disposed of member, then placing a
piston
member to compress the shredded conduit leaving an enlarged innermost bore
within
the production casing to simulate drilling rig abandonment (172A of Figure
10).
[000323] Figures 141 and 142 are elevation and isometric views of an axial
adjustable
cam arrangement method (MS) for a kelly slideable cam member (2BS) usable with
the axial conduit shredding member (2BR, 2BR1 of Figures 135 to 140) and
hexagonal kelly (233 of Figure 129), to allow pass through of a kelly (233),
through
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CA 2841144 2019-02-12
an axial cam (260) sleeve (262), for actuating an axial conduit shredding
member
between shredding (2BR) and deployment (2BR1). The cam can be engagable to any
member, e.g. a tractor (2BP2 of Figure 129) to allow axial movement (237 of
Figure
129) and rotation of the kelly together with actuation and deactivation of a
shredder
by moving the sleeve (262) upward or downward. The method can be usable with
axial movable and rotational mills, cutters, boring devices and/or other
annulus access
members to displace at least one wall of a well for placement of the partially
shown
well barrier element (3BS), usable to abandon a portion (4BS) of a well
within, e.g., a
strata wall (17) of the well.
[000324] Referring now to Figures 143, 144 and 145, plan, elevation cross
section and
isometric exploded views with line V-V, along line V-V and associated with
Figure
143, respectively, are shown and depict a circumferential milling member (2BT)
embodiment usable in the method (1BT of Figure 146) to place a well barrier
element
(3BT of Figure 146) for abandoning a portion (4BT of Figure 146) of a well,
wherein
the apparatus represents a low cost milling member that is disposable downhole
should it become stuck.
[000325] An upper rotary connector (72) can be usable to engage the mill to,
e.g., a
cable deployable fluid motor (2B1 of Figure 17) with rotation of the upper
ball joint
housing (263) and ball joints usable to deploy the milling arms (2BT3) outward
with
the centrifugal force of rotation, with milling sleeves (2BT2) rotatable about
the arms
(2BT3), such that the ball joints (265) at the upper end of the milling arm
and
rotatable sleeves (2BT2) and associated cutting structures reduce the required
torque
and propensity to jam the mills, because jamming forces are limited by the
centrifugal
deployment and rotating sleeves.
[000326] Releasing bolts (266), engaging the lower ball joint housing (264) to
the upper
ball joint housing (263), resist shearing during rotation, but may be jarred
out of the
lower ball joint housing (264) to retrieve the remaining portion of the motor
assembly
if the milling arms (2BT2, 2B13) become struck.
[000327] Flexibility of the ball joints (265), rotatable abrasive sleeves
(2BT2) and
disposable lower end mills provide an economic means for milling casing (12)
and/or
poorly bonded cement, because the method is usable with the low space
requirements
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and available torque of rotary slickline unit operations, albeit additional
time will be
required at a significantly lower daily cost than a drilling rig. Where
conventional
rig-less methods use tools generally requiring more torque than is supportable
on, e.g.
minimal facilities (170A and 170B of Figures 4 and 6, respectively), the
present
inventions casing milling methods can be usable for milling over a sufficient
period of
time, wherein if tools become stuck, they may be left downhole without
significant
consequences to the cost of operations or the well being abandoned.
[000328] Figure 146 is an isometric view associated with Figure 143 to 145 of
a method
embodiment (1BT) within a plurality of installed conduits, with a half section
removed, to show a circumferential milling member (2BT), illustrating the mill
in a
centrifugal force deployed position (2BT1) having milled the conduits (11, 12)
and
engaged the annuli (24, 24A) through rotation of the motor engagable rotary
connector (72) to allow placement of the partially shown well barrier element
(3BT)
in the annuli (24, 24A) and enlarged innermost passageway (25AE) within the
intermediate casing (15) to abandon a portion (4BT) of the well.
[000329] Figure 147 is an isometric view of method (1BU) and circumferential
shredding and milling arm member (2BU) embodiment, depicting an arm with a
ball
joint (265) usable with the mill of Figures 143 to 146. The arm (2BU1) has a
shaft
(268) for rotatable cutting wheels (267) that can be usable to reduce torque
requirements and jamming or sticking of a mill, so as to mill and or shred
within and
including the conductor (14) and to place the partially shown well barrier
element
(3BU) to abandon a portion (4BU) of the well.
[000330] Embodiments of the present invention thereby provide a system of
methods
and members usable in any order, depth or well configuration as demonstrated
in
Figures 16 to 19, Figures 21 to 46, Figures 48 to 74 and Figures 80 to 147 to
rig-lessly
access annuli to use and/or abandon a well with better economics than are
possible
with conventional drilling rig operations, said system being usable with
minimal
supporting facilities and within a limited space and/or within environmentally
sensitive areas, such as offshore or the arctic, to suspend, side-track and/or
abandon
wells rig-lessly placing a permanent barrier according to published industry
minimum
requirements.
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[000331] While various embodiments of the present invention have been
described with
emphasis, it should be understood that within the scope of the appended
claims, the
present invention might be practiced other than as specifically described
herein.
[000332] Reference numerals have been incorporated in the claims purely to
assist
understanding during prosecution.
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