Note: Descriptions are shown in the official language in which they were submitted.
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IMPACT EXCAVATION SYSTEM AND
METHOD WITH PARTICLE SEPARATION
Cross-reference to Related Applications
[0001] This application claims the benefit of provisional application serial
no.
60/746,833, filed May 9, 2006, the disclosure of which is incorporated herein
by
reference in its entirety.
[0002] This application is related to pending application No. 11/204722,
attorney
docket no. 37163.10, filed on 8/16/2005, which was a continuation-in-part of
pending
application No. 10/897,196, filed July 22, 2004 which, in turn, is a
continuation-in-part of
pending application No. 10/825,338, filed April 15, 2004, which, in turn,
claims the benefit
of 35 U.S.C. 111(b) provisional application Serial No. 60/463,903, filed April
16, 2003,
the disclosures of which are incorporated herein by reference.
[0003] This application is also related to pending application No. 11/204,981,
attorney
docket no. 37163.6, filed on 8/16/2005, U.S. Patent No. 6,386,300, issued on
5/14/2002,
which was filed as application no. 09/665,586 on 9/19/2000, attorney docket
no.
37163.23; U.S. Patent No. 6,581,700, issued on 6/24/2003, which was filed as
10/097,038 on 3/12/2002, attorney docket no. 37163.24; pending application no.
11/204,436, attorney docket no. 37163.7, filed on 8/16/2005; pending
application no.
11/204,442, attorney docket no. 37163.11, filed on 8/16/2005; pending
application no.
11/204,862, attorney docket no. 37163.8, filed on 8/16/2005; pending
application no.
11/205,006, attorney docket no. 37163.9, filed on 8/16/2005; pending
application no.
10/825,338, attorney docket no. 37163.18, filed on 4/15/2004; pending
application no.
10/897,196, attorney docket no. 37163.12, filed on 7/22/2004; pending
application no.
10/558,181, attorney docket no. 37163.46, filed on 5/14/2004; pending
application no.
11/344,805, attorney docket no. 37163.47, filed on 2/01/2006, the disclosures
of which
are incorporated herein by reference.
Background
[0004] This disclosure relates to a system and method for excavating a
formation, such
as to form a well bore for the purpose of oil and gas recovery, to construct a
tunnel, or to
form other excavations in which the formation is cut, milled, pulverized,
scraped,
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sheared, indented, and/or fractured, (hereinafter referred to collectively as
"cutting").
The cutting process is a very interdependent process that preferably
integrates and
considers many variables to ensure that a usable bore is constructed. As is
commonly
known in the art, many variables have an interactive and cumulative effect of
increasing
cutting costs. These variables may include formation hardness, abrasiveness,
pore
pressures, and formation elastic properties. In drilling wellbores, formation
hardness and a
corresponding degree of drilling difficulty may increase exponentially as a
function of
increasing depth. A high percentage of the costs to drill a well are derived
from
interdependent operations that are time sensitive, i.e., the longer it takes
to penetrate the
formation being drilled, the more it costs. One of the most important factors
affecting the
cost of drilling a wellbore is the rate at which the formation can be
penetrated by the drill
bit, which typically decreases with harder and tougher formation materials and
formation
depth.
[0005] There are generally two categories of modern drill bits that have
evolved from
over a hundred years of development and untold amounts of dollars spent on the
research, testing and iterative development. These are the commonly known as
the fixed
cutter drill bit and the roller cone drill bit. Within these two primary
categories, there are a
wide variety of variations, with each variation designed to drill a formation
having a general
range of formation properties. These two categories of drill bits generally
constitute the
bulk of the drill bits employed to drill oil and gas wells around the world.
[0006] Each type of drill bit is commonly used where it's drilling economics
are superior
to the other. Roller cone drill bits can drill the entire hardness spectrum of
rock
formations. Thus, roller cone drill bits are generally run when encountering
harder rocks
where long bit life and reasonable penetration rates are important factors on
the drilling
economics. Fixed cutter drill bits, on the other hand, are used to drill a
wide variety of
formations ranging from unconsolidated and weak rocks to medium hard rocks.
[0007] In the case of creating a borehole with a roller cone type drill bit,
several
actions effecting rate of penetration (ROP) and bit efficiency may be
occurring. The
roller cone bit teeth may be cutting, milling, pulverizing, scraping,
shearing, sliding
over, indenting, and fracturing the formation the bit is encountering. The
desired result
is that formation cuttings or chips are generated and circulated to the
surface by the
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drilling fluid. Other factors may also affect ROP, including formation
structural or rock
properties, pore pressure, temperature, and drilling fluid density. When a
typical roller
cone rock bit tooth presses upon a very hard, dense, deep formation, the tooth
point
may only penetrate into the rock a very small distance, while also at least
partially,
plastically "working" the rock surface.
[0008] One attempt to increase the effective rate of penetration (ROP)
involved
high-pressure circulation of a drilling fluid as a foundation for potentially
increasing
ROP. It is common knowledge that hydraulic power available at the rig site
vastly
outweighs the power available to be employed mechanically at the drill bit.
For
example, modem drilling rigs capable of drilling a deep well typically have in
excess of
3000 hydraulic horsepower available and can have in excess of 6000 hydraulic
horsepower available while less than one-tenth of that hydraulic horsepower
may be
available at the drill bit. Mechanically, there may be less than 100
horsepower
available at the bit/rock interface with which to mechanically drill the
formation.
[0009] An additional attempt to increase ROP involved incorporating entrained
abrasives in conjunction with high pressure drilling fluid ("mud"). This
resulted in an
abrasive laden, high velocity jet assisted drilling process. Work done by Gulf
Research
and Development disclosed the use of abrasive laden jet streams to cut
concentric
grooves in the bottom of the hole leaving concentric ridges that are then
broken by the
mechanical contact of the drill bit. Use of entrained abrasives in conjunction
with high
drilling fluid pressures caused accelerated erosion of surface equipment and
an
inability to control drilling mud density, among other issues. Generally, the
use of
entrained abrasives was considered practically and economically unfeasible.
This
work was summarized in the last published article titled "Development of High
Pressure Abrasive-Jet Drilling," authored by John C. Fair, Gulf Research and
Development. It was published in the Journal of Petroleum Technology in the
May
1981 issue, pages 1379 to 1388.
[00010] Another effort to utilize the hydraulic horsepower available at the
bit
incorporated the use of ultra-high pressure jet assisted drilling. A group
known as
FlowDril Corporation was formed to develop an ultra-high-pressure liquid jet
drilling
system in an attempt to increase the rate of penetration. The work was based
upon
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U.S. Pat. No. 4,624,327 and is documented in the published article titled
"Laboratory
and Field Testing of an Ultra-High Pressure, Jet-Assisted Drilling System"
authored by
J. J. Kolle, Quest Integrated Inc., and R. Otta and D. L. Stang, FlowDril
Corporation;
published by SPE/IADC Drilling Conference publications paper number 22000. The
cited publication disclosed that the complications of pumping and delivering
ultrahigh-
pressure fluid from surface pumping equipment to the drill bit proved both
operationally
and economically unfeasible.
[00011] Another effort at increasing rates of penetration by taking advantage
of
hydraulic horsepower available at the bit is disclosed in U.S. Pat. No.
5,862,871. This
development employed the use of a specialized nozzle to excite normally
pressured
drilling mud at the drill bit. The purpose of this nozzle system was to
develop local
pressure fluctuations and a high speed, dual jet form of hydraulic jet streams
to more
effectively scavenge and clean both the drill bit and the formation being
drilled. It is
believed that these hydraulic jets were able to penetrate the fracture plane
generated
by the mechanical action of the drill bit in a much more effective manner than
conventional jets were able to do. ROP increases from 50% to 400% were field
demonstrated and documented in the field reports titled "DualJet Nozzle Field
Test
Report-Security DBS/Swift Energy Company," and "DualJet Nozzle Equipped M-1
LRG
Drill Bit Run". The ability of the dual jet ("DualJet") nozzle system to
enhance the
effectiveness of the drill bit action to increase the ROP required that the
drill bits first
initiate formation indentations, fractures, or both. These features could then
be
exploited by the hydraulic action of the DualJet nozzle system.
[00012] Due at least partially to the effects of overburden pressure,
formations at
deeper depths may be inherently tougher to drill due to changes in formation
pressures
and rock properties, including hardness and abrasiveness. Associated in-situ
forces,
rock properties, and increased drilling fluid density effects may set up a
threshold point
at which the drill bit drilling mechanics decrease the drilling efficiency.
[00013] Another factor adversely effecting ROP in formation drilling,
especially in
plastic type rock drilling, such as shale or permeable formations, is a build-
up of
hydraulically isolated crushed rock material that can become either mass of
reconstituted drill cuttings or a "dynamic filtercake", on the surface being
drilled,
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depending on the formation permeability. In the case of low permeability
formations,
this occurrence is predominantly a result of repeated impacting and re-
compacting of
previously drilled particulate material on the bottom of the hole by the bit
teeth, thereby
forming a false bottom. The substantially continuous process of drilling, re-
compacting, removing, re-depositing and re-compacting, and drilling new
material may
significantly adversely effect drill bit efficiency and ROP. The re-compacted
material is
at least partially removed by mechanical displacement due to the cone skew of
the
roller cone type drill bits and partially removed by hydraulics, again
emphasizing the
importance of good hydraulic action and hydraulic horsepower at the bit. For
hard rock
bits, build-up removal by cone skew is typically reduced to near zero, which
may make
build-up removal substantially a function of hydraulics. In permeable
formations the
continuous deposition and removal of the fine cuttings forms a dynamic
filtercake that
can reduce the spurt loss and therefore the pore pressure in the working area
of the
bit. Because the pore pressure is reduced and mechanical load is increased
from the
pressure drop across the dynamic filtercake, drilling efficiency can be
reduced.
[00014] There are many variables to consider to ensure a usable well bore is
constructed when using cutting systems and processes for the drilling of well
bores or the
cutting of formations for the construction of tunnels and other subterranean
earthen
excavations. Many variables, such as formation hardness, abrasiveness, pore
pressures,
and formation elastic properties affect the effectiveness of a particular
drill bit in drilling a
well bore. Additionally, in drilling well bores, formation hardness and a
corresponding
degree of drilling difficulty may increase exponentially as a function of
increasing depth.
The rate at which a drill bit may penetrate the formation typically decreases
with harder
and tougher formation materials and formation depth.
[00015] When the formation is relatively soft, as with shale, material removed
by the
drill bit will have a tendency to reconstitute onto the teeth of the drill
bit. Build-up of the
reconstituted formation on the drill bit is typically referred to as "bit
balling" and reduces
the depth that the teeth of the drill bit will penetrate the bottom surface of
the well bore,
thereby reducing the efficiency of the drill bit. Particles of a shale
formation also tend to
reconstitute back onto the bottom surface of the bore hole. The reconstitution
of a
formation back onto the bottom surface of the bore hole is typically referred
to as "bottom
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balling". Bottom balling prevents the teeth of a drill bit from engaging
virgin formation and
spreads the impact of a tooth over a wider area, thereby also reducing the
efficiency of a
drill bit. Additionally, higher density drilling muds that are required to
maintain well bore
stability or well bore pressure control exacerbate bit balling and the bottom
balling
problems.
[00016] When the drill bit engages a formation of a harder rock, the teeth of
the drill
bit press against the formation and densify a small area under the teeth to
cause a crack
in the formation. When the porosity of the formation is collapsed, or
densified, in a hard
rock formation below a tooth, conventional drill bit nozzles ejecting drilling
fluid are used
to remove the crushed material from below the drill bit. As a result, a
cushion, or
densification pad, of densified material is left on the bottom surface by the
prior art drill
bits. If the densification pad is left on the bottom surface, force by a tooth
of the drill bit
will be distributed over a larger area and reduce the effectiveness of a drill
bit.
[00017] There are generally two main categories of modern drill bits that have
evolved over time. These are the commonly known fixed cutter drill bit and the
roller cone
drill bit. Additional categories of drilling include percussion drilling and
mud hammers.
However, these methods are not as widely used as the fixed cutter and roller
cone drill
bits. Within these two primary categories (fixed cutter and roller cone),
there are a wide
variety of variations, with each variation designed to drill a formation
having a general
range of formation properties.
[00018] The fixed cutter drill bit and the roller cone type drill bit
generally constitute
the bulk of the drill bits employed to drill oil and gas wells around the
world. When a
typical roller cone rock bit tooth presses upon a very hard, dense, deep
formation, the
tooth point may only penetrate into the rock a very small distance, while also
at least
partially, plastically "working" the rock surface. Under conventional drilling
techniques,
such working the rock surface may result in the densification as noted above
in hard rock
formations.
[00019] With roller cone type drilling bits, a relationship exists between the
number
of teeth that impact upon the formation and the drilling RPM of the drill bit.
A description
of this relationship and an approach to improved drilling technology is set
forth and
described in U.S. Patent No. 6,386,300 issued May 14, 2002. The '300 patent
discloses
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the use of solid material impactors introduced into drilling fluid and pumped
though a drill
string and drill bit to contact the rock formation ahead of the drill bit. The
kinetic energy of
the impactors leaving the drill bit is given by the following equation: Ek
=1/2
Mass(Velocity)2. The mass and/or velocity of the impactors may be chosen to
satisfy the
mass-velocity relationship in order to structurally alter the rock formation.
Brief Description of the Drawings
[00020] Fig. 1 is an isometric view of an excavation system as used in a
preferred
embodiment.
[00021] Fig. 2 illustrates an impactor impacted with a formation.
[00022] Fig. 3 illustrates an impactor embedded into the formation at an angle
to a
normalized surface plane of the target formation.
[00023] Fig. 4 illustrates an impactor impacting a formation with a plurality
of
fractures induced by the impact.
[00024] Fig. 5 is a side elevational view of a drilling system utilizing a
first
embodiment of a drill bit.
[00025] Fig. 6 is a top plan view of the bottom surface of a well bore formed
by
the drill bit of Fig. 5.
[00026] Fig. 7 is an end elevational view of the drill bit of Fig. 5.
[00027] Fig. 8 is an enlarged end elevational view of the drill bit of Fig. 5.
[00028] Fig. 9 is a perspective view of the drill bit of Fig. 5.
[00029] Fig. 10 is a perspective view of the drill bit of Fig. 5 illustrating
a breaker
and junk slot of a drill bit.
[00030] Fig. 11 is a side elevational view of the drill bit of Fig. 5
illustrating a flow
of solid material impactors.
[00031] Fig. 12 is a top elevational view of the drill bit of Fig. 5
illustrating side and
center cavities.
[00032] Fig. 13 is a canted top elevational view of the drill bit of Fig. 5.
[00033] Fig. 14 is a cutaway view of the drill bit of Fig. 5 engaged in a well
bore.
[00034] Fig. 15 is a schematic diagram of the orientation of the nozzles of a
second embodiment of a drill bit.
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[00035] Fig. 16 is a side cross-sectional view of the rock formation created
by the
drill bit of Fig. 5 represented by the schematic of the drill bit of Fig. 5
inserted therein.
[00036] Fig. 17 is a side cross-sectional view of the rock formation created
by drill
bit of Fig. 5 represented by the schematic of the drill bit of Fig. 5 inserted
therein.
[00037] Fig. 18 is a perspective view of an alternate embodiment of a drill
bit.
[00038] Fig. 19 is a perspective view of the drill bit of Fig. 18.
[00039] Fig. 20 illustrates an end elevational view of the drill bit of Fig.
18.
[00040] Fig. 21 is a schematic diagram of a particle trap system for use in
the
system of Fig. 1.
[00041] Fig. 22 is a graph depicting the performance of the excavation system
according to one or more embodiments of the present invention as compared to
two other
systems.
[00042] Fig. 23 illustrates a suspension of impactors and drill cuttings.
[00043] Fig. 24 is a schematic diagram of a magnetic separation system.
Detailed Description
[00044] In the drawings and description that follows, like parts are marked
throughout the specification and drawings with the same reference numerals,
respectively. The drawings are not necessarily to scale. Certain features of
the
invention may be shown exaggerated in scale or in somewhat schematic form and
some
details of conventional elements may not be shown in the interest of clarity
and
conciseness. The present invention is susceptible to embodiments of different
forms.
Specific embodiments are described in detail and are shown in the drawings,
with the
understanding that the present disclosure is to be considered an
exemplification of the
principles of the invention, and is not intended to limit the invention to
that illustrated and
described herein. It is to be fully recognized that the different teachings of
the
embodiments discussed below may be employed separately or in any suitable
combination to produce desired results. The various characteristics mentioned
above,
as well as other features and characteristics described in more detail below,
will be
readily apparent to those skilled in the art upon reading the following
detailed
description of the embodiments, and by referring to the accompanying drawings.
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[00045] Figs. 1 and 2 illustrate an embodiment of an excavation system 1
comprising the use of solid material particles, or impactors, 100 to engage
and excavate
a subterranean formation 52 to create a wellbore 70. The excavation system 1
may
comprise a pipe string 55 comprised of collars 58, pipe 56, and a kelly 50. An
upper
end of the kelly 50 may interconnect with a lower end of a swivel quill 26. An
upper end
of the swivel quill 26 may be rotatably interconnected with a swivel 28. The
swivel 28
may include a top drive assembly (not shown) to rotate the pipe string 55.
Alternatively,
the excavation system 1 may further comprise a drill bit 60 to cut the
formation 52 in
cooperation with the solid material impactors 100. The drill bit 60 may be
attached to
the lower end 55B of the pipe string 55 and may engage a bottom surface 66 of
the
wellbore 70. The drill bit 60 may be a roller cone bit, a fixed cutter bit, an
impact bit, a
spade bit, a mill, an impregnated bit, a natural diamond bit, or other
suitable implement
for cutting rock or earthen formation. Referring to Fig. 1, the pipe string 55
may include
a feed, or upper, end 55A located substantially near the excavation rig 5 and
a lower
end 55B including a nozzle 64 supported thereon. The lower end 55B of the
string 55
may include the drill bit 60 supported thereon. The excavation system 1 is not
limited to
excavating a wellbore 70. The excavation system and method may also be
applicable
to excavating a tunnel, a pipe chase, a mining operation, or other excavation
operation
wherein earthen material or formation may be removed.
[00046] To excavate the wellbore 70, the swivel 28, the swivel quill 26, the
kelly 50,
the pipe string 55, and a portion of the drill bit 60, if used, may each
include an interior
passage that allows circulation fluid to circulate through each of the
aforementioned
components. The circulation fluid may be withdrawn from a tank 6, pumped by a
pump
2, through a through medium pressure capacity line 8, through a medium
pressure
capacity flexible hose 42, through a gooseneck 36, through the swivel 28,
through the
swivel quill 26, through the kelly 50, through the pipe string 55, and through
the bit 60.
[00047] The excavation system 1 further comprises at least one nozzle 64 on
the
lower 55B of the pipe string 55 for accelerating at least one solid material
impactor 100
as they exit the pipe string 100. The nozzle 64 is designed to accommodate the
impactors 100, such as an especially hardened nozzle, a shaped nozzle, or an
"impactor" nozzle, which may be particularly adapted to a particular
application. The
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nozzle 64 may be a type that is known and commonly available. The nozzle 64
may
further be selected to accommodate the impactors 100 in a selected size range
or of a
selected material composition. Nozzle size, type, material, and quantity may
be a
function of the formation being cut, fluid properties, impactor properties,
and/or desired
hydraulic energy expenditure at the nozzle 64. If a drill bit 60 is used, the
nozzle or
nozzles 64 may be located in the drill bit 60.
[00048] The nozzle 64 may alternatively be a conventional dual-discharge
nozzle.
Such dual discharge nozzles may generate: (1) a radially outer circulation
fluid jet
substantially encircling a jet axis, and/or (2) an axial circulation fluid jet
substantially
aligned with and coaxial with the jet axis, with the dual discharge nozzle
directing a
majority by weight of the plurality of solid material impactors into the axial
circulation
fluid jet. A dual discharge nozzle 64 may separate a first portion of the
circulation fluid
flowing through the nozzle 64 into a first circulation fluid stream having a
first circulation
fluid exit nozzle velocity, and a second portion of the circulation fluid
flowing through the
nozzle 64 into a second circulation fluid stream having a second circulation
fluid exit
nozzle velocity lower than the first circulation fluid exit nozzle velocity.
The plurality of
solid material impactors 100 may be directed into the first circulation fluid
stream such
that a velocity of the plurality of solid material impactors 100 while exiting
the nozzle 64
is substantially greater than a velocity of the circulation fluid while
passing through a
nominal diameter flow path in the lower end 55B of the pipe string 55, to
accelerate the
solid material impactors 100.
[00049] Each of the individual impactors 100 is structurally independent from
the
other impactors. For brevity, the plurality of solid material impactors 100
may be
interchangeably referred to as simply the impactors 100. The plurality of
solid material
impactors 100 may be substantially rounded and have either a substantially non-
uniform
outer diameter or a substantially uniform outer diameter. The solid material
impactors
100 may be substantially spherically shaped, non-hollow, formed of rigid
metallic
material, and having high compressive strength and crush resistance, such as
steel
shot, ceramics, depleted uranium, and multiple component materials. Although
the solid
material impactors 100 may be substantially a nonhollow sphere, alternative
embodiments may provide for other types of solid material impactors, which may
include
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impactors 100 with a hollow interior. The impactors may be substantially rigid
and may
possess relatively high compressive strength and resistance to crushing or
deformation
as compared to physical properties or rock properties of a particular
formation or group
of formations being penetrated by the wellbore 70.
[00050] The impactors may be of a substantially uniform mass, grading, or
size.
The solid material impactors 100 may have any suitable density for use in the
excavation system 1. For example, the solid material impactors 100 may have an
average density of at least 470 pounds per cubic foot.
[00051] Alternatively, the solid material impactors 100 may include other
metallic
materials, including tungsten carbide, copper, iron, or various combinations
or alloys of
these and other metallic compounds. The impactors 100 may also be composed of
non-
metallic materials, such as ceramics, or other man-made or substantially
naturally
occurring non-metallic materials. Also, the impactors 100 may be crystalline
shaped,
angular shaped, sub-angular shaped, selectively shaped, such as like a
torpedo, dart,
rectangular, or otherwise generally non-spherically shaped.
[00052] The impactors 100 may be selectively introduced into a fluid
circulation
system, such as illustrated in Fig. 1, near an excavation rig 5, circulated
with the
circulation fluid (or "mud"), and accelerated through at least one nozzle 64.
"At the
excavation rig" or "near an excavation rig" may also include substantially
remote
separation, such as a separation process that may be at least partially
carried out on the
sea floor.
[00053] Introducing the impactors 100 into the circulation fluid may be
accomplished by any of several known techniques. For example, the impactors
100
may be provided in an impactor storage tank 94 near the rig 5 or in a storage
bin 82. A
screw elevator 14 may then transfer a portion of the impactors at a selected
rate from
the storage tank 94, into a slurrification tank 98. A pump 10, such as a
progressive
cavity pump may transfer a selected portion of the circulation fluid from a
mud tank 6,
into the slurrification tank 98 to be mixed with the impactors 100 in the tank
98 to form
an impactor concentrated slurry. An impactor introducer 96 may be included to
pump or
introduce a plurality of solid material impactors 100 into the circulation
fluid before
circulating a plurality of impactors 100 and the circulation fluid to the
nozzle 64. The
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impactor introducer 96 may be a progressive cavity pump capable of pumping the
impactor concentrated slurry at a selected rate and pressure through a slurry
line 88,
through a slurry hose 38, through an impactor slurry injector head 34, and
through an
injector port 30 located on the gooseneck 36, which may be located atop the
swivel 28.
The swivel 36, including the through bore for conducting circulation fluid
therein, may be
substantially supported on the feed, or upper, end of the pipe string 55 for
conducting
circulation fluid from the gooseneck 36 into the latter end 55a. The upper end
55A of
the pipe string 55 may also include the kelly 50 to connect the pipe 56 with
the swivel
quill 26 and/or the swivel 28. The circulation fluid may also be provided with
rheological
properties sufficient to adequately transport and/or suspend the plurality of
solid material
impactors 100 within the circulation fluid.
[00054] The solid material impactors 100 may also be introduced into the
circulation fluid by withdrawing the plurality of solid material impactors 100
from a low
pressure impactor source 98 into a high velocity stream of circulation fluid,
such as by
venturi effect. For example, when introducing impactors 100 into the
circulation fluid,
the rate of circulation fluid pumped by the mud pump 2 may be reduced to a
rate lower
than the mud pump 2 is capable of efficiently pumping. In such event, a lower
volume
mud pump 4 may pump the circulation fluid through a medium pressure capacity
line 24
and through the medium pressure capacity flexible hose 40.
[00055] The circulation fluid may be circulated from the fluid pump 2 and/or
4, such
as a positive displacement type fluid pump, through one or more fluid conduits
8, 24, 40,
42, into the pipe string 55. The circulation fluid may then be circulated
through the pipe
string 55 and through the nozzle 64. The circulation fluid may be pumped at a
selected
circulation rate and/or a selected pump pressure to achieve a desired impactor
and/or
fluid energy at the nozzle 64.
[00056] The pump 4 may also serve as a supply pump to drive the introduction
of
the impactors 100 entrained within an impactor slurry, into the high pressure
circulation
fluid stream pumped by mud pumps 2 and 4. Pump 4 may pump a percentage of the
total rate of fluid being pumped by both pumps 2 and 4, such that the
circulation fluid
pumped by pump 4 may create a venturi effect and/or vortex within the injector
head 34
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that inducts the impactor slurry being conducted through the line 42, through
the injector
head 34, and then into the high pressure circulation fluid stream.
[00057] From the swivel 28, the slurry of circulation fluid and impactors may
circulate through the interior passage in the pipe string 55 and through the
nozzle 64.
As described above, the nozzle 64 may alternatively be at least partially
located in the
drill bit 60. Each nozzle 64 may include a reduced inner diameter as compared
to an
inner diameter of the interior passage in the pipe string 55 immediately above
the nozzle
64. Thereby, each nozzle 64 may accelerate the velocity of the slurry as the
slurry
passes through the nozzle 64. The nozzle 64 may also direct the slurry into
engagement with a selected portion of the bottom surface 66 of wellbore 70.
The nozzle
64 may also be rotated relative to the formation 52 depending on the
excavation
parameters. To rotate the nozzle 64, the entire pipe string 55 may be rotated
or only the
nozzle 64 on the end of the pipe string 55 may be rotated while the pipe
string 55 is not
rotated. Rotating the nozzle 64 may also include oscillating the nozzle 64
rotationally
back and forth as well as vertically, and may further include rotating the
nozzle 64 in
discrete increments. The nozzle 64 may also be maintained rotationally
substantially
stationary.
[00058] The circulation fluid may be substantially continuously circulated
during
excavation operations to circulate at least some of the plurality of solid
material
impactors 100 and the formation cuttings away from the nozzle 64. The
impactors 100
and fluid circulated away from the nozzle 64 may be circulated substantially
back to the
excavation rig 5, or circulated to a substantially intermediate position
between the
excavation rig 5 and the nozzle 64.
[00059] If a drill bit 60 is used, the drill bit 60 may be rotated relative to
the
formation 52 and engaged therewith by an axial force (WOB) acting at least
partially
along the wellbore axis 75 near the drill bit 60. The bit 60 may also comprise
a plurality
of bit cones 62, which also may rotate relative to the bit 60 to cause bit
teeth secured to
a respective cone to engage the formation 52, which may generate formation
cuttings
substantially by crushing, cutting, or pulverizing a portion of the formation
52. The bit 60
may also be comprised of a fixed cutting structure that may be substantially
continuously engaged with the formation 52 and create cuttings primarily by
shearing
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and/or axial force concentration to fail the formation, or create cuttings
from the
formation 52. To rotate the bit 60, the entire pipe string 55 may be rotated
or only the bit
60 on the end of the pipe string 55 may be rotated while the pipe string 55 is
not rotated.
Rotating the drill bit 60 may also include oscillating the drill bit 60
rotationally back and
forth as well as vertically, and may further include rotating the drill bit 60
in discrete
increments.
[00060] Also alternatively, the excavation system 1 may comprise a pump, such
as
a centrifugal pump, having a resilient lining that is compatible for pumping a
solid-
material laden slurry. The pump may pressurize the slurry to a pressure
greater than
the selected mud pump pressure to pump the plurality of solid material
impactors 100
into the circulation fluid. The impactors 100 may be introduced through an
impactor
injection port, such as port 30. Other alternative embodiments for the system
1 may
include an impactor injector for introducing the plurality of solid material
impactors 100
into the circulation fluid.
[00061] As the slurry is pumped through the pipe string 55 and out the nozzles
64,
the impactors 100 may engage the formation with sufficient energy to enhance
the rate
of formation removal or penetration (ROP). The removed portions of the
formation may
be circulated from within the wellbore 70 near the nozzle 64, and carried
suspended in
the fluid with at least a portion of the impactors 100, through a wellbore
annulus
between the OD of the pipe string 55 and the ID of the wellbore 70.
[00062] At the excavation rig 5, the returning slurry of circulation fluid,
formation
fluids (if any), cuttings, and impactors 100 may be diverted at a nipple 76,
which may be
positioned on a BOP stack 74. The returning slurry may flow from the nipple
76, into a
return flow line 15, which maybe comprised of tubes 48, 45, 16, 12 and flanges
46, 47.
The return line 15 may include an impactor reclamation tube assembly 44, as
illustrated
in Fig. 1, which may preliminarily separate a majority of the returning
impactors 100 from
the remaining components of the returning slurry to salvage the circulation
fluid for
recirculation into the present wellbore 70 or another wellbore. At least a
portion of the
impactors 100 may be separated from a portion of the cuttings by a series of
screening
devices, such as the vibrating classifiers 84, to salvage a reusable portion
of the
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impactors 100 for reuse to re-engage the formation 52. A majority of the
cuttings and a
majority of non-reusable impactors 100 may also be discarded.
[00063] The reclamation tube assembly 44 may operate by rotating tube 45
relative
to tube 16. An electric motor assembly 22 may rotate tube 44. The reclamation
tube
assembly 44 comprises an enlarged tubular 45 section to reduce the return flow
slurry
velocity and allow the slurry to drop below a terminal velocity of the
impactors 100, such
that the impactors 100 can no longer be suspended in the circulation fluid and
may
gravitate to a bottom portion of the tube 45. This separation function may be
enhanced
by placement of magnets near and along a lower side of the tube 45. The
impactors
100 and some of the larger or heavier cuttings may be discharged through
discharge
port 20. The separated and discharged impactors 100 and solids discharged
through
discharge port 20 may be gravitationally diverted into a vibrating classifier
84 or may be
pumped into the classifier 84. A pump (not shown) capable of handling
impactors and
solids, such as a progressive cavity pump may be situated in communication
with the
flow line discharge port 20 to conduct the separated impactors 100 selectively
into the
vibrating separator 84 or elsewhere in the circulation fluid circulation
system.
[00064] The vibrating classifier 84 may comprise a three-screen section
classifier
of which screen section 18 may remove the coarsest grade material. The removed
coarsest grade material may be selectively directed by outlet 78 to one of
storage bin 82
or pumped back into the flow line 15 downstream of discharge port 20. A second
screen section 92 may remove a re-usable grade of impactors 100, which in turn
may be
directed by outlet 90 to the impactor storage tank 94. A third screen section
86 may
remove the finest grade material from the circulation fluid. The removed
finest grade
material may be selectively directed by outlet 80 to storage bin 82, or pumped
back into
the flow line 15 at a point downstream of discharge port 20. Circulation fluid
collected in
a lower portion of the classified 84 may be returned to a mud tank 6 for re-
use. The
vibrating classifier 84 may include a plurality of screens, preferably two or
three.
[00065] The circulation fluid may be recovered for recirculation in a wellbore
or the
circulation fluid may be a fluid that is substantially not recovered. The
circulation fluid
may be a liquid, gas, foam, mist, or other substantially continuous or
multiphase fluid.
For recovery, the circulation fluid and other components entrained within the
circulation
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fluid may be directed across a shale shaker (not shown) or into a mud tank 6,
whereby
the circulation fluid may be further processed for re-circulation into a
wellbore.
[00066] The excavation system 1 creates a mass-velocity relationship in a
plurality
of the solid material impactors 100, such that an impactor 100 may have
sufficient
energy to structurally alter the formation 52 in a zone of a point of impact.
The mass-
velocity relationship may be satisfied as sufficient when a substantial
portion by weight
of the solid material impactors 100 may by virtue of their mass and velocity
at the exit of
the nozzle 64, create a structural alteration as claimed or disclosed herein.
Impactor
velocity to achieve a desired effect upon a given formation may vary as a
function of
formation compressive strength, hardness, or other rock properties, and as a
function of
impactor size and circulation fluid rheological properties. A substantial
portion means at
least five percent by weight of the plurality of solid material impactors that
are introduced
into the circulation fluid.
[00067] The impactors 100 for a given velocity and mass of a substantial
portion by
weight of the impactors 100 are subject to the following mass-velocity
relationship. The
resulting kinetic energy of at least one impactor 100 exiting a nozzle 64 is
at least 0.075
Ft.Lbs or has a minimum momentum of 0.0003 Lbf.Sec.
[00068] Kinetic energy is quantified by the relationship of an object's mass
and its
velocity. The quantity of kinetic energy associated with an object is
calculated by
multiplying its mass times its velocity squared. To reach a minimum value of
kinetic
energy in the mass-velocity relationship as defined, small particles such as
those found in
abrasives and grits, must have a significantly high velocity due to the small
mass of the
particle. A large particle, however, needs only moderate velocity to reach an
equivalent
kinetic energy of the small particle because its mass may be several orders of
magnitude
larger.
[00069] The velocity of a substantial portion by weight of the plurality of
solid
material impactors 100 immediately exiting a nozzle 64 may be as slow as 100
feet per
second and as fast as 1000 feet per second, immediately upon exiting the
nozzle 64.
[00070] The velocity of a majority by weight of the impactors 100 may be
substantially the same, or only slightly reduced, at the point of impact of an
impactor 100
at the formation surface 66 as compared to when leaving the nozzle 64. Thus,
it may be
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appreciated by those skilled in the art that due to the close proximity of a
nozzle 64 to the
formation being impacted, the velocity of a majority of impactors 100 exiting
a nozzle 64
may be substantially the same as a velocity of an impactor 100 at a point of
impact with
the formation 52. Therefore, in many practical applications, the above
velocity values
may be determined or measured at substantially any point along the path
between near
an exit end of a nozzle 64 and the point of impact, without material deviation
from the
scope of this invention.
[00071] In addition to the impactors 100 satisfying the mass-velocity
relationship
described above, a substantial portion by weight of the solid material
impactors 100 have
an average mean diameter of between approximately .050 to .500 of an inch.
[00072] To excavate a formation 52, the excavation implement, such as a drill
bit
60 or impactor 100, must overcome minimum, in-situ stress levels or toughness
of the
formation 52. These minimum stress levels are known to typically range from a
few
thousand pounds per square inch, to in excess of 65,000 pounds per square
inch. To
fracture, cut, or plastically deform a portion of formation 52, force exerted
on that portion
of the formation 52 typically should exceed the minimum, in-situ stress
threshold of the
formation 52. When an impactor 100 first initiates contact with a formation,
the unit
stress exerted upon the initial contact point may be much higher than 10,000
pounds
per square inch, and may be well in excess of one million pounds per square
inch. The
stress applied to the formation 52 during contact is governed by the force the
impactor
100 contacts the formation with and the area of contact of the impactor with
the
formation. The stress is the force divided by the area of contact. The force
is governed
by Impulse Momentum theory whereby the time at which the contact occurs
determines
the magnitude of the force applied to the area of contact. In cases where the
particle is
contacting a relatively hard surface at an elevated velocity, the force of the
particle when
in contact with the surface is not constant, but is better described as a
spike. However,
the force need not be limited to any specific amplitude or duration. The
magnitude of
the spike load can be very large and occur in just a small fraction of the
total impact
time. If the area of contact is small the unit stress can reach values many
times in
excess of the in situ failure stress of the rock, thus guaranteeing fracture
initiation and
propagation and structurally altering the formation 52.
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[00073] A substantial portion by weight of the solid material impactors 100
may
apply at least 5000 pounds per square inch of unit stress to a formation 52 to
create the
structurally altered zone Z in the formation. The structurally altered zone Z
is not limited
to any specific shape or size, including depth or width. Further, a
substantial portion by
weight of the impactors 100 may apply in excess of 20,000 pounds per square
inch of
unit stress to the formation 52 to create the structurally altered zone Z in
the formation.
The mass-velocity relationship of a substantial portion by weight of the
plurality of solid
material impactors 100 may also provide at least 30,000 pounds per square inch
of unit
stress.
[00074] A substantial portion by weight of the solid material impactors 100
may
have any appropriate velocity to satisfy the mass-velocity relationship. For
example, a
substantial portion by weight of the solid material impactors may have a
velocity of at
least 100 feet per second when exiting the nozzle 64. A substantial portion by
weight of
the solid material impactors 100 may also have a velocity of at least 100 feet
per second
and as great as 1200 feet per second when exiting the nozzle 64. A substantial
portion
by weight of the solid material impactors 100 may also have a velocity of at
least 100
feet per second and as great as 750 feet per second when exiting the nozzle
64. A
substantial portion by weight of the solid material impactors 100 may also
have a
velocity of at least 350 feet per second and as great as 500 feet per second
when
exiting the nozzle 64.
[00075] Impactors 100 may be selected based upon physical factors such as
size,
projected velocity, impactor strength, formation 52 properties and desired
impactor
concentration in the circulation fluid. Such factors may also include; (a) an
expenditure
of a selected range of hydraulic horsepower across the one or more nozzles,
(b) a
selected range of circulation fluid velocities exiting the one or more nozzles
or impacting
the formation, and (c) a selected range of solid material impactor velocities
exiting the
one or more nozzles or impacting the formation, (d) one or more rock
properties of the
formation being excavated, or (e), any combination thereof.
[00076] If an impactor 100 is of a specific shape such as that of a dart, a
tapered
conic, a rhombic, an octahedral, or similar oblong shape, a reduced impact
area to
impactor mass ratio may be achieved. The shape of a substantial portion by
weight of
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the impactors 100 may be altered, so long as the mass-velocity relationship
remains
sufficient to create a claimed structural alteration in the formation and an
impactor 100
does not have any one length or diameter dimension greater than approximately
0.100
inches. Thereby, a velocity required to achieve a specific structural
alteration may be
reduced as compared to achieving a similar structural alteration by impactor
shapes
having a higher impact area to mass ratio. Shaped impactors 100 may be formed
to
substantially align themselves along a flow path, which may reduce variations
in the
angle of incidence between the impactor 100 and the formation 52. Such
impactor
shapes may also reduce impactor contact with the flow structures such those in
the pipe
string 55 and the excavation rig 5 and may thereby minimize abrasive erosion
of flow
conduits.
[00077] Referring to Figs. 1- 4, a substantial portion by weight of the
impactors
100 may engage the formation 52 with sufficient energy to enhance creation of
a
wellbore 70 through the formation 52 by any or a combination of different
impact
mechanisms. First, an impactor 100 may directly remove a larger portion of the
formation 52 than may be removed by abrasive-type particles. In another
mechanism,
an impactor 100 may penetrate into the formation 52 without removing formation
material from the formation 52. A plurality of such formation penetrations,
such as near
and along an outer perimeter of the wellbore 70 may relieve a portion of the
stresses on
a portion of formation being excavated, which may thereby enhance the
excavation
action of other impactors 100 or the drill bit 60. Third, an impactor 100 may
alter one or
more physical properties of the formation 52. Such physical alterations may
include
creation of micro-fractures and increased brittleness in a portion of the
formation 52,
which may thereby enhance effectiveness the impactors 100 in excavating the
formation
52. The constant scouring of the bottom of the borehole also prevents the
build up of
dynamic filtercake, which can significantly increase the apparent toughness of
the
formation 52.
[00078] Fig. 2 illustrates an impactor 100 that has been impaled into a
formation 52,
such as a lower surface 66 in a wellbore 70. For illustration purposes, the
surface 66 is
illustrated as substantially planar and transverse to the direction of
impactor travel 100a.
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The impactors 100 circulated through a nozzle 64 may engage the formation 52
with
sufficient energy to effect one or more properties of the formation 52.
[00079] A portion of the formation 52 ahead of the impactor 100 substantially
in the
direction of impactor travel T may be altered such as by micro-fracturing
and/or thermal
alteration due to the impact energy. In such occurrence, the structurally
altered zone
Z may include an altered zone depth D. An example of a structurally altered
zone Z is a
compressive zone Z1, which may be a zone in the formation 52 compressed by the
impactor 100. The compressive zone Z1 may have a length L1, but is not limited
to any
specific shape or size. The compressive zone Zl may be thermally altered due
to impact
energy.
[00080] An additional example of a structurally altered zone 102 near a point
of
impaction may be a zone of micro-fractures Z2. The structurally altered zone Z
may be
broken or otherwise altered due to the impactor 100 and/or a drill bit 60,
such as by
crushing, fracturing, or micro-fracturing.
[00081] Fig. 2 also illustrates an impactor 100 implanted into a formation 52
and
having created an excavation E wherein material has been ejected from or
crushed
beneath the impactor 100. Thereby the excavation E may be created, which as
illustrated
in Fig. 3 may generally conform to the shape of the impactor 100.
[00082] Figs. 3 and 4 illustrate excavations E where the size of the
excavation may
be larger than the size of the impactor 100. In Fig. 2, the impactor 100 is
shown as
impacted into the formation 52 yielding an excavation depth D.
[00083] An additional theory for impaction mechanics in cutting a formation 52
may
postulate that certain formations 52 may be highly fractured or broken up by
impactor
energy. Fig. 4 illustrates an interaction between an impactor 100 and a
formation 52. A
plurality of fractures F and micro-fractures MF may be created in the
formation 52 by
impact energy.
[00084] An impactor 100 may penetrate a small distance into the formation 52
and
cause the displaced or structurally altered formation 52 to "splay out" or be
reduced to
small enough particles for the particles to be removed or washed away by
hydraulic
action. Hydraulic particle removal may depend at least partially upon
available hydraulic
horsepower and at least partially upon particle wet-ability and viscosity.
Such formation
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deformation may be a basis for fatigue failure of a portion of the formation
by "impactor
contact," as the plurality of solid material impactors 100 may displace
formation material
back and forth.
[00085] Each nozzle 64 may be selected to provide a desired circulation fluid
circulation rate, hydraulic horsepower substantially at the nozzle 64, and/or
impactor
energy or velocity when exiting the nozzle 64. Each nozzle 64 may be selected
as a
function of at least one of (a) an expenditure of a selected range of
hydraulic
horsepower across the one or more nozzles 64, (b) a selected range of
circulation fluid
velocities exiting the one or more nozzles 64, and (c) a selected range of
solid material
impactor 100 velocities exiting the one or more nozzles 64.
[00086] To optimize ROP, it may be desirable to determine, such as by
monitoring,
observing, calculating, knowing, or assuming one or more excavation parameters
such
that adjustments may be made in one or more controllable variables as a
function of the
determined or monitored excavation parameter. The one or more excavation
parameters may be selected from a group comprising: (a) a rate of penetration
into the
formation 52, (b) a depth of penetration into the formation 52, (c) a
formation excavation
factor, and (d) the number of solid material impactors 100 introduced into the
circulation
fluid per unit of time. Monitoring or observing may include monitoring or
observing one
or more excavation parameters of a group of excavation parameters comprising:
(a) rate
of nozzle rotation, (b) rate of penetration into the formation 52, (c) depth
of penetration
into the formation 52, (d) formation excavation factor, (e) axial force
applied to the drill
bit 60, (f) rotational force applied to the bit 60, (g) the selected
circulation rate, (h) the
selected pump pressure, and/or (i) wellbore fluid dynamics, including pore
pressure.
[00087] One or more controllable variables or parameters may be altered,
including
at least one of (a) rate of impactor 100 introduction into the circulation
fluid, (b) impactor
100 size, (c) impactor 100 velocity, (d) drill bit nozzle 64 selection, (e)
the selected
circulation rate of the circulation fluid, (f) the selected pump pressure, and
(g) any of the
monitored excavation parameters.
[00088] To alter the rate of impactors 100 engaging the formation 52, the rate
of
impactor 100 introduction into the circulation fluid may be altered. The
circulation fluid
circulation rate may also be altered independent from the rate of impactor 100
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introduction. Thereby, the concentration of impactors 100 in the circulation
fluid may be
adjusted separate from the fluid circulation rate. Introducing a plurality of
solid material
impactors 100 into the circulation fluid may be a function of impactor 100
size,
circulation fluid rate, nozzle rotational speed, wellbore 70 size, and a
selected impactor
100 engagement rate with the formation 52. The impactors 100 may also be
introduced
into the circulation fluid intermittently during the excavation operation. The
rate of
impactor 100 introduction relative to the rate of circulation fluid
circulation may also be
adjusted or interrupted as desired.
[00089] The plurality of solid material impactors 100 may be introduced into
the
circulation fluid at a selected introduction rate and/or concentration to
circulate the
plurality of solid material impactors 100 with the circulation fluid through
the nozzle 64.
The selected circulation rate and/or pump pressure, and nozzle selection may
be
sufficient to expend a desired portion of energy or hydraulic horsepower in
each of the
circulation fluid and the impactors 100.
[00090] An example of an operative excavation system 1 may comprise a bit 60
with an 8'/z inch bit diameter. The solid material impactors 100 may be
introduced into
the circulation fluid at a rate of 12 gallons per minute. The circulation
fluid containing
the solid material impactors may be circulated through the bit 60 at a rate of
462 gallons
per minute. A substantial portion by weight of the solid material impactors
may have an
average mean diameter of 0.100". The following parameters will result in
approximately
a 27 feet per hour penetration rate into Sierra White Granite. In this
example, the
excavation system may produce 1413 solid material impactors 100 per cubic inch
with
approximately 3.9 million impacts per minute against the formation 52. On
average,
0.00007822 cubic inches of the formation 52 are removed per impactor 100
impact.
The resulting exit velocity of a substantial portion of the impactors 100 from
each of the
nozzles 64 would average 495.5 feet per second. The kinetic energy of a
substantial
portion by weight of the solid material impacts 100 would be approximately
1.14 Ft Lbs.,
thus satisfying the mass-velocity relationship described above.
[00091] Another example of an operative excavation system 1 may comprise a bit
60 with an 8'/2" bit diameter. The solid material impactors 100 may be
introduced into
the circulation fluid at a rate of 12 gallons per minute. The circulation
fluid containing
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the solid material impactors may be circulated through the nozzle 64 at a rate
of 462
gallons per minute. A substantial portion by weight of the solid material
impactors may
have an average mean diameter of 0.075". The following parameters will result
in
approximately a 35 feet per hour penetration rate into Sierra White Granite.
In this
example, the excavation system 1 may produce 3350 solid material impactors 100
per
cubic inch with approximately 9.3 million impacts per minute against the
formation 52.
On average, 0.0000428 cubic inches of the formation 52 are removed per
impactor 100
impact. The resulting exit velocity of a substantial portion of the impactors
100 from
each of the nozzles 64 would average 495.5 feet per second. The kinetic energy
of a
substantial portion by weight of the solid material impacts 100 would be
approximately
0.240 Ft Lbs., thus satisfying the mass-velocity relationship described above.
[00092] In addition to impacting the formation with the impactors 100, the bit
60
may be rotated while circulating the circulation fluid and engaging the
plurality of solid
material impactors 100 substantially continuously or selectively
intermittently. The
nozzle 64 may also be oriented to cause the solid material impactors 100 to
engage the
formation 52 with a radially outer portion of the bottom hole surface 66.
Thereby, as the
drill bit 60 is rotated, the impactors 100, in the bottom hole surface 66
ahead of the bit
60, may create one or more circumferential kerfs. The drill bit 60 may thereby
generate
formation cuttings more efficiently due to reduced stress in the surface 66
being
excavated, due to the one or more substantially circumferential kerfs in the
surface 66.
[00093] The excavation system 1 may also include inputting pulses of energy in
the
fluid system sufficient to impart a portion of the input energy in an impactor
100. The
impactor 100 may thereby engage the formation 52 with sufficient energy to
achieve a
structurally altered zone Z. Pulsing of the pressure of the circulation fluid
in the pipe
string 55, near the nozzle 64 also may enhance the ability of the circulation
fluid to
generate cuttings subsequent to impactor 100 engagement with the formation 52.
[00094] Each combination of formation type, bore hole size, bore hole depth,
available weight on bit, bit rotational speed, pump rate, hydrostatic balance,
circulation
fluid rheology, bit type, and tooth/cutter dimensions may create many
combinations of
optimum impactor presence or concentration, and impactor energy requirements.
The
methods and systems of this invention facilitate adjusting impactor size,
mass,
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introduction rate, circulation fluid rate and/or pump pressure, and other
adjustable or
controllable variables to determine and maintain an optimum combination of
variables.
The methods and systems of this invention also may be coupled with select bit
nozzles, downhole tools, and fluid circulating and processing equipment to
effect many
variations in which to optimize rate of penetration.
[00095] Fig. 5 shows an alternate embodiment of the drill bit 60 (Fig. 1) and
is
referred to, in general, by the reference numeral 110 and which is located at
the
bottom of a well bore 120 and attached to a drill string 130. The drill bit
110 acts
upon a bottom surface 122 of the well bore 120. The drill string 130 has a
central
passage 132 that supplies drilling fluids to the drill bit 110 as shown by the
arrow Al.
The drill bit 110 uses the drilling fluids and solid material impactors 100
when acting
upon the bottom surface 122 of the well bore 120. The drilling fluids then
exit the
well bore 120 through a well bore annulus 124 between the drill string 130 and
the
inner wall 126 of the well bore 120. Particles of the bottom surface 122
removed by
the drill bit 110 exit the well bore 120 with the drilling fluid through the
well bore
annulus 124 as shown by the arrow A2. The drill bit 110 creates a rock ring
142 at
the bottom surface 122 of the well bore 120.
[00096] Referring now to Fig. 6, a top view of the rock ring 124 formed by the
drill bit 110 is illustrated. An excavated interior cavity 144 is worn away by
an interior
portion of the drill bit 110 and the exterior cavity 146 and inner wall 126 of
the well
bore 120 are worn away by an exterior portion of the drill bit 110. The rock
ring 142
possesses hoop strength, which holds the rock ring 142 together and resists
breakage. The hoop strength of the rock ring 142 is typically much less than
the
strength of the bottom surface 122 or the inner wall 126 of the well bore 120,
thereby
making the drilling of the bottom surface 122 less demanding on the drill bit
110. By
applying a compressive load and a side load, shown with arrows 141, on the
rock
ring 142, the drill bit 110 causes the rock ring 142 to fracture. The drilling
fluid 140
then washes the residual pieces of the rock ring 142 back up to the surface
through the
well bore annulus 124.
[00097] The mechanical cutters, utilized on many of the surfaces of the drill
bit 110,
may be any type of protrusion or surface used to abrade the rock formation by
contact of
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the mechanical cutters with the rock formation. The mechanical cutters may be
Polycrystalline Diamond Coated (PDC), or any other suitable type mechanical
cutter such
as tungsten carbide cutters. The mechanical cutters may be formed in a variety
of
shapes, for example, hemispherically shaped, cone shaped, etc. Several sizes
of
mechanical cutters are also available, depending on the size of drill bit used
and the
hardness of the rock formation being cut.
[00098] Referring now to Fig. 7, an end elevational view of the drill bit 110
of Fig. 5
is illustrated. The drill bit 110 comprises two side nozzles 200A, 200B and a
center nozzle
202. The side and center nozzles 200A, 200B, 202 discharge drilling fluid and
solid
material impactors (not shown) into the rock formation or other surface being
excavated.
The solid material impactors may comprise steel shot ranging in diameter from
about
0.010 to about 0.500 of an inch. However, various diameters and materials such
as
ceramics, etc. may be utilized in combination with the drill bit 120. The
solid material
impactors contact the bottom surface 122 of the well bore 120 and are
circulated through
the annulus 124 to the surface. The solid material impactors may also make up
any
suitable percentage of the drilling fluid for drilling through a particular
formation.
[00099] Still referring to Fig. 7 the center nozzle 202 is located in a center
portion
203 of the drill bit 110. The center nozzle 202 may be angled to the
longitudinal axis of
the drill bit 110 to create an excavated interior cavity 244 and also cause
the rebounding
solid material impactors to flow into the major junk slot, or passage, 204A.
The side
nozzle 200A located on a side arm 214A of the drill bit 110 may also be
oriented to allow
the solid material impactors to contact the bottom surfqace 122 of the well
bore 120 and
then rebound into the major junk slot, or passage, 204A. The second side
nozzle 200B is
located on a second side arm 214B. The second side nozzle 200B may be oriented
to
allow the solid material impactors to contact the bottom surface 122 of the
well bore 120
and then rebound into a minor junk slot, or passage, 204B. The orientation of
the side
nozzles 200A, 200B may be used to facilitate the drilling of the large
exterior cavity 46.
The side nozzles 200A, 200B may be oriented to cut different portions of the
bottom
surface 122. For example, the side nozzle 200B may be angled to cut the outer
portion of
the excavated exterior cavity 146 and the side nozzle 200A may be angled to
cut the
inner portion of the excavated exterior cavity 146. The major and minor junk
slots, or
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passages, 204A, 204B allow the solid material impactors, cuttings, and
drilling fluid 240
to flow up through the well bore annulus 124 back to the surface. The major
and minor
junk slots, or passages, 204A, 204B are oriented to allow the solid material
impactors
and cuttings to freely flow from the bottom surface 122 to the annulus 124.
[000100] As described earlier, the drill bit 110 may also comprise mechanical
cutters
and gauge cutters. Various mechanical cutters are shown along the surface of
the drill
bit 110. Hemispherical PDC cutters are interspersed along the bottom face and
the side
walls of the drill bit 110. These hemispherical cutters along the bottom face
break down
the large portions of the rock ring 142 and also abrade the bottom surface 122
of the
well bore 120. Another type of mechanical cutter along the side arms 214A,
214B are
gauge cutters 230. The gauge cutters 230 form the final diameter of the well
bore 120.
The gauge cutters 230 trim a small portion of the well bore 120 not removed by
other
means. Gauge bearing surfaces 206 are interspersed throughout the side walls
of the
drill bit 110. The gauge bearing surfaces 206 ride in the well bore 120
already trimmed
by the gauge cutters 230. The gauge bearing surfaces 206 may also stabilize
the drill
bit 110 within the well bore 120 and aid in preventing vibration.
[000101] Still referring to Fig. 7 the center portion 203 comprises a breaker
surface,
located near the center nozzle 202, comprising mechanical cutters 208 for
loading the
rock ring 142. The mechanical cutters 208 abrade and deliver load to the lower
stress
rock ring 142. The mechanical cutters 208 may comprise PDC cutters, or any
other
suitable mechanical cutters. The breaker surface is a conical surface that
creates the
compressive and side loads for fracturing the rock ring 142. The breaker
surface and
the mechanical cutters 208 apply force against the inner boundary of the rock
ring 142
and fracture the rock ring 142. Once fractured, the pieces of the rock ring
142 are
circulated to the surface through the major and minor junk slots, or passages,
204A,
204B.
[000102] Referring now to Fig. 8, an enlarged end elevational view of the
drill bit 110
is shown. As shown more clearly in Fig. 8, the gauge bearing surfaces 206 and
mechanical cutters 208 are interspersed on the outer side walls of the drill
bit 110. The
mechanical cutters 208 along the side walls may also aid in the process of
creating drill
bit 110 stability and also may perform the function of the gauge bearing
surfaces 206 if
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they fail. The mechanical cutters 208 are oriented in various directions to
reduce the
wear of the gauge bearing surface 206 and also maintain the correct well bore
120
diameter. As noted with the mechanical cutters 208 of the breaker surface, the
solid
material impactors fracture the bottom surface 122 of the well bore 120 and,
as such,
the mechanical cutters 208 remove remaining ridges of rock and assist in the
cutting of
the bottom hole. However, the drill bit 110 need not necessarily comprise the
mechanical cutters 208 on the side wall of the drill bit 110.
[000103] Referring now to Fig. 9, a side elevational view of the drill bit 110
is
illustrated. Fig. 9 shows the gauge cutters 230 included along the side arms
214A,
214B of the drill bit 110. The gauge cutters 230 are oriented so that a
cutting face of the
gauge cutter 230 contacts the inner wall 126 of the well bore 120. The gauge
cutters
230 may contact the inner wall 126 of the well bore at any suitable backrake,
for
example a backrake of 15 to 45 . Typically, the outer edge of the cutting
face scrapes
along the inner wall 126 to refine the diameter of the well bore 120.
[000104] Still referring to Fig. 9 one side nozzle 200A is disposed on an
interior
portion of the side arm 214A and the second side nozzle 200B is disposed on an
exterior portion of the opposite side arm 214B. Although the side nozzles
200A, 200B
are shown located on separate side arms 214A, 214B of the drill bit 110, the
side
nozzles 200A, 200B may also be disposed on the same side arm 214A or 214B.
Also,
there may only be one side nozzle, 200A or 200B. Also, there may only be one
side
arm, 214A or 214B.
[000105] Each side arm 214A, 214B fits in the excavated exterior cavity 146
formed
by the side nozzles 200A, 200B and the mechanical cutters 208 on the face 212
of each
side arm 214A, 214B. The solid material impactors from one side nozzle 200A
rebound
from the rock formation and combine with the drilling fluid and cuttings flow
to the major
junk slot 204A and up to the annulus 124. The flow of the solid material
impactors,
shown by arrows 205, from the center nozzle 202 also rebound from the rock
formation
up through the major junk slot 204A.
[000106] Referring now to Figs. 10and 11, the minor junk slot 204B, breaker
surface, and the second side nozzle 200B are shown in greater detail. The
breaker
surface is conically shaped, tapering to the center nozzle 202. The second
side nozzle
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200B is oriented at an angle to allow the outer portion of the excavated
exterior cavity
146 to be contacted with solid material impactors. The solid material
impactors then
rebound up through the minor junk slot 204B, shown by arrows 205, along with
any
cuttings and drilling fluid 240 associated therewith.
[000107] Referring now to Figs. 12 and 13, top elevational views of the drill
bit 110
are shown. Each nozzle 200A, 200B, 202 receives drilling fluid 240 and solid
material
impactors from a common plenum feeding separate cavities 250, 251, and 252.
Since
the common plenum has a diameter, or cross section, greater than the diameter
of each
cavity 250, 251, and 252, the mixture, or suspension of drilling fluid and
impactors is
accelerated as it passes from the plenum to each cavity. The center cavity 250
feeds a
suspension of drilling fluid 240 and solid material impactors to the center
nozzle 202 for
contact with the rock formation. The side cavities 251, 252 are formed in the
interior of
the side arms 214A, 214B of the drill bit 110, respectively. The side cavities
251, 252
provide drilling fluid 240 and solid material impactors to the side nozzles
200A, 200B for
contact with the rock formation. By utilizing separate cavities 250, 251,252
for each
nozzle 202, 200A, 200B, the percentages of solid material impactors in the
drilling fluid
240 and the hydraulic pressure delivered through the nozzles 200A, 200B, 202
can be
specifically tailored for each nozzle 200A, 200B, 202. Solid material impactor
distribution can also be adjusted by changing the nozzle diameters of the side
and
center nozzles 200A, 200B, and 202 by changing the diameters of the nozzles.
However, in alternate embodiments, other arrangements of the cavities 250,
251, 252,
or the utilization of a single cavity, are possible.
[000108] Referring now to Fig. 14, the drill bit 110 in engagement with the
rock
formation 270 is shown. As previously discussed, the solid material impactors
272 flow
from the nozzles 200A, 200B, 202 and make contact with the rock formation 270
to
create the rock ring 142 between the side arms 214A, 214B of the drill bit 110
and the
center nozzle 202 of the drill bit 110. The solid material impactors 272 from
the center
nozzle 202 create the excavated interior cavity 244 while the side nozzles
200A, 200B
create the excavated exterior cavity 146 to form the outer boundary of the
rock ring 142.
The gauge cutters 230 refine the more crude well bore 120 cut by the solid
material
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impactors 272 into a well bore 120 with a more smooth inner wall 126 of the
correct
diameter.
[000109] Still referring to Fig. 14 the solid material impactors 272 flow from
the first
side nozzle 200A between the outer surface of the rock ring 142 and the
interior wall
216 in order to move up through the major junk slot 204A to the surface. The
second
side nozzle 200B (not shown) emits solid material impactors 272 that rebound
toward
the outer surface of the rock ring 142 and to the minor junk slot 204B (not
shown). The
solid material impactors 272 from the side nozzles 200A, 200B may contact the
outer
surface of the rock ring 142 causing abrasion to further weaken the stability
of the rock
ring 142. Recesses 274 around the breaker surface of the drill bit 110 may
provide a
void to allow the broken portions of the rock ring 142 to flow from the bottom
surface
122 of the well bore 120 to the major or minor junk slot 204A, 204B.
[000110] Referring now to Fig. 15, an example orientation of the nozzles 200A,
200B, 202 are illustrated. The center nozzle 202 is disposed left of the
center line of the
drill bit 110 and angled on the order of around 20 left of vertical.
Alternatively, both of
the side nozzles 200A, 200B may be disposed on the same side arm 214 of the
drill bit
110 as shown in Fig. 15. In this embodiment, the first side nozzle 200A,
oriented to cut
the inner portion of the excavated exterior cavity 146, is angled on the order
of around
left of vertical. The second side nozzle 200B is oriented at an angle on the
order of
around 14 right of vertical. This particular orientation of the nozzles
allows for a large
interior excavated cavity 244 to be created by the center nozzle 202. The side
nozzles
200A, 200B create a large enough excavated exterior cavity 146 in order to
allow the side
arms 214A, 214B to fit in the excavated exterior cavity 146 without incurring
a substantial
amount of resistance from uncut portions of the rock formation 270. By varying
the
orientation of the center nozzle 202, the excavated interior cavity 244 may be
substantially larger or smaller than the excavated interior cavity 244
illustrated in Fig. 14.
The side nozzles 200A, 200B may be varied in orientation in order to create a
larger
excavated exterior cavity 146, thereby decreasing the size of the rock ring
142 and
increasing the amount of mechanical cutting required to drill through the
bottom surface
122 of the well bore 120. Alternatively, the side nozzles 200A, 200B may be
oriented to
decrease the amount of the inner wall 126 contacted by the solid material
impactors 272.
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By orienting the side nozzles 200A, 200B at, for example, a vertical
orientation, only a
center portion of the excavated exterior cavity 146 would be cut by the solid
material
impactors and the mechanical cutters would then be required to cut a large
portion of the
inner wall 126 of the well bore 120.
[000111] Referring now to Figs. 16 and 17, side cross-sectional views of the
bottom
surface 122 of the well bore 120 drilled by the drill bit 110 are shown. With
the center
nozzle angled on the order of around 20 left of vertical and the side nozzles
200A, 200B
angled on the order of around 10 left of vertical and around 14 right of
vertical,
respectively, the rock ring 142 is formed. By increasing the angle of the side
nozzle
200A, 200B orientation, an alternate rock ring 142 shape and bottom surface
122 is cut as
shown in Fig. 17. The excavated interior cavity 244 and rock ring 142 are much
more
shallow as compared with the rock ring 142 in Fig. 16. It is understood that
various
different bottom hole patterns can be generated by different nozzle
configurations.
[000112] Although the drill bit 110 is described comprising orientations of
nozzles and
mechanical cutters, any orientation of either nozzles, mechanical cutters, or
both may be
utilized. The drill bit 110 need not comprise a center portion 203. The drill
bit 110 also
need not even create the rock ring 142. For example, the drill bit may only
comprise a
single nozzle and a single junk slot. Furthermore, although the description of
the drill bit
110 describes types and orientations of mechanical cutters, the mechanical
cutters may
be formed of a variety of substances, and formed in a variety of shapes.
[000113] Referring now to Figs. 18-19, a drill bit 150 in accordance with a
second
embodiment is illustrated. As previously noted, the mechanical cutters, such
as the
gauge cutters 230, mechanical cutters 208, and gauge bearing surfaces 206 may
not be
necessary in conjunction with the nozzles 200A, 200B, 202 in order to drill
the required
well bore 120. The side wall of the drill bit 150 may or may not be
interspersed with
mechanical cutters. The side nozzles 200A, 200B and the center nozzle 202 are
oriented in the same manner as in the drill bit 150, however, the face 212 of
the side
arms 214A, 214B comprises angled (PDCs) 280 as the mechanical cutters.
[000114] Still referring to Figs. 18-20 each row of PDCs 280 is angled to cut
a
specific area of the bottom surface 122 of the well bore 120. A first row of
PDCs 280A
is oriented to cut the bottom surface 122 and also cut the inner wall 126 of
the well bore
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120 to the proper diameter. A groove 282 is disposed between the cutting faces
of the
PDCs 280 and the face 212 of the drill bit 150. The grooves 282 receive
cuttings,
drilling fluid 240, and solid material impactors and direct them toward the
center nozzle
202 to flow through the major and minor junk slots, or passages, 204A, 204B
toward the
surface. The grooves 282 may also direct some cuttings, drilling fluid 240,
and solid
material impactors toward the inner wall 126 to be received by the annulus 124
and also
flow to the surface. Each subsequent row of PDCs 280B, 280C may be oriented in
the
same or different position than the first row of PDCs 280A. For example, the
subsequent rows of PDCs 280B, 280C may be oriented to cut the exterior face of
the
rock ring 142 as opposed to the inner wall 126 of the well bore 120. The
grooves 282
on one side arm 214A may also be oriented to direct the cuttings and drilling
fluid 240
toward the center nozzle 202 and to the annulus 124 via the major junk slot
204A. The
second side arm 214B may have grooves 282 oriented to direct the cuttings and
drilling
fluid 240 to the inner wall 126 of the well bore 120 and to the annulus 124
via the minor
junk slot 204B.
[000115] The PDCs 280 located on the face 212 of each side arm 214A, 214B are
sufficient to cut the inner wall 126 to the correct size. However, mechanical
cutters may
be placed throughout the side wall of the drill bit 150 to further enhance the
stabilization
and cutting ability of the drill bit 150.
[000116] Referring to Fig. 21, an embodiment of a particle separation system
is
shown, in general, by the reference numeral 300 for use in the excavation
system 1 of
Fig. 1. The system 300 is designed to separate the particles from the drilling
fluid after
the suspension has discharged from the nozzles 200, 200A and 200B (Fig. 7) in
the drill
bit 110 and removed a portion of the well bore 120 (Fig. 5), as described
above.
[000117] The system 300 includes a conduit 302, one end of which is coupled to
the
return flow line 15 (Fig. 1) of the reclamation tube assembly 44, which is
otherwise
replaced by the system 300. The other end of the conduit 302 is coupled to the
input of a
choke 304, and a return line 306 is coupled to the output of the choke.
Although not
shown in the drawing, it is understood that a conventional choke valve is
provided in the
choke 304 to control the volume of flow through the choke under conditions to
be
described. The above couplings can be done in any manner such as by providing
flanges
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on the corresponding ends of the members to be coupled, as shown, and using
bolts,
other fasteners, weldments, brazing, or other metal-to-metal joining
techniques.
[000118] One end of a conduit 308 registers with an opening in the conduit
302, and
a screen separator 310 is disposed in the conduit 302 at its junction with the
conduit 308.
The screen separator 310 may extend across the interior of the conduit 302 and
at an
angle to the longitudinal axis of the conduit.
[000119] The other end of the conduit 308 is coupled, via an elbow 312, to the
inlet
side of a valve 314, and one end of a conduit 316 extends from the outlet side
of the latter
valve. The valve 314 may be conventional and, as such, includes a closure
device 314a,
such as a disc, flap, or the like, that moves in the valve housing between two
positions
shown by the solid lines and the dashed lines to open or close the valve,
respectively.
[000120] The other end of the conduit 316 registers with an inlet of another
valve 320,
and a discharge elbow 322 is coupled to the outlet of the latter valve. The
valve 320 is
includes a closure device 320a, such as a disc, flap, or the like, that moves
in the valve
housing between two positions shown by the solid lines and the dashed lines to
open or
close the valve, respectively. In this closed position of the valve 320, the
impactors 100
in the suspension will be blocked from flowing through the valve 320 and will
settle in the
lower portion of the conduit 316 under the force of gravity.
[000121] A pressure relief conduit 326 communicates with an opening in the
conduit
316 between the valves 314 and 320, and a screen separator 328 is disposed at
the
junction of the conduits 316 and 326. A valve 330 is disposed in the conduit
326 for
controlling the relief of the pressure in the latter conduit to atmosphere,
under conditions
to be described.
[000122] In operation, the valve 314 is fully opened, the valves 320 and 330
are
closed. The suspension of the fluid and impactors 100 from the bottom of the
well bore
124 (Fig. 5) flows into and through the return flow line 15 (Fig. 1), into the
conduit 302,
and to the screen 310. The screen 310 is sized so as to permit passage of the
fluid
therethrough but to prevent passage of the impactors 100.
[000123] The choke 304 is adjusted as needed to provide the desired flow
characteristics, and the separated fluid passes from the screen 310 through
the conduit
302 and discharges from the conduit 306 after which it can be recycled or
discarded.
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[000124] The separated impactors 100, carrying a small volume of fluid with
them,
pass through the conduit 308 and the elbow 312, through the open valve 314,
through the
conduit 316, and to the closed valve 320. Thus, a mixture of the separators
100 and a
relatively small volume of the fluid accumulates in the conduit 316 and the
valve 330 is
opened as necessary to provide adequate pressure relief to the atmosphere. The
screen
328 blocks any flow of the impactors 100 into the conduit 326, and the
impactors settle to
the bottom of the conduit 316 under the force of gravity. When a sufficient
volume of the
impactors 100 have accumulated in the conduit 316 in the above manner, the
valve 320 is
then opened and the impactors flow out the conduit 316, through the open valve
320 and
through the discharge elbow 322. The impactors 100 can be transported to a
holding
tank, or the like for reuse.
[000125] It is understood that other solids, such as cuttings, fines, dirt,
etc. might be
also present in the suspension that passes into the system 300 from the flow
line 15. In
this case, the size of the screen can be selected to let these solid pass
through with the
fluid or to block their passage. In the former case the solids would pass
through the
choke 304 and discharge with the fluid from the conduit 306. In the latter
case, the solids
would pass through the conduit 308, the open valve 314 and into the conduit
316 with the
impactors 100 and settle in the conduit 316 with the impactors, as described
above.
[000126] Other variations may be made in the embodiment of Fig. 21. For
example,
the valves can be disposed in their corresponding conduits or in a separate
housing
attached to the conduits. Also, the elbows and/or the choke may be eliminated,
and the
type of screen and the type of valves may be varied. Further, the various
conduits can be
coupled together in any conventional manner.
[000127] In another embodiment, separation of the particles from the fluid may
be
accomplished with a magnetic separation device. Such a device is particularly
useful in
removing drill cuttings which are substantially similar in size to the
impactors.
[000128] As shown in Fig. 23, the circulation fluid stream can contain a
variety of
particles, including large cuttings 402, impactors 404, small cuttings or
fines 406 and
impactor sized cuttings 408. Impactor sized cuttings can be any shape, but
generally
have a cross sectional area approximately the same as the cross sectional area
of the
impactors. The circulation fluid stream may also contain gas bubbles (not
shown).
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Generally, the large cuttings 402 and small cuttings 406 can be separated from
the
impactors 404 by screening means due to the discrepancy in the size of the
particles.
However, because the impactor sized cuttings 408 are similar in size to the
impactors
404, at least some of the impactor sized cuttings 408 may not be removed
during the
screening process for recovering impactors 404.
[000129] To improve separation of the impactors from drill cuttings, in one
embodiment, a magnetic separation process may be employed either in
conjunction with,
or instead of, the screen separation process. Preferably, the screen and
magnetic
separation processes are used in conjunction, wherein the screening process is
employed
to remove large and small drill cuttings and the magnetic separation process
is employed
to remove cuttings which are substantially shot sized.
[000130] In one embodiment, a washing step may be employed during the
separation
process to remove the majority of the drilling fluid that may be present with
the impactors.
Due to the high viscosity typical of drilling fluids, a high surface tension
between the
particle, drilling fluid and a surface frequently exists. The washing step,
which may
include a washing of the feedstream using a petroleum or non-petroleum based
solvent,
can assist in reducing the surface tension and reducing and "stickiness"
present in the
particles. The washing step may be employed either before, during or after the
screen
separation process and/or before or during the magnetic separation process.
[000131] Referring to Figure 24, an exemplary magnetic separation unit 500
which
may be included in the impact excavation system is shown. The unit can include
a
housing 502 and an inlet 504 to supply feed for separation. The feed
preferably includes
magnetic impactors 510 and non-magnetic drill cuttings 512. Preferably, the
feed only
includes a minimum amount of circulation fluid. Unit 500 includes a drum 505
which can
include a stationary magnetic field source 506 and a rotatable shell 508,
which can rotate
about the magnetic field source 506.
[000132] The separation unit 500 may also include a deflector 514 positioned
near
the inlet portion of the device, which can be used to regulate the volume of
feed flow. The
unit 500 may also include a divider 516 which can be positioned below the drum
and can
assist with the separation of the impactors and non-magnetic particles to an
impactor
collection outlet 518 and a non-magnetic particle collection outlet 520,
respectively.
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[000133] The magnetic separation unit may be incorporated into the reclamation
tube,
either upstream, downstream or instead of a screen separation unit. In one
embodiment,
more than one magnetic separation unit may be employed. Preferably, the
magnetic
separation unit is positioned downstream of a screen separation unit.
[000134] Many commercial magnetic separation units may be incorporated to the
excavation system, such as for example, the rotary drum separators produced by
Eriez
Magnetics. Drum separators produced by Eriez can range from 12-36 inches in
diameter,
with widths ranging from 12 to 60 inches, capable of separation on volumes up
to 25,000
cubic feet per hour. It is understood that Eriez magnetic separators are
exemplary of
commercially available magnetic separation units, and that other commercially
available
units, or customized separation units may be employed.
[000135] In operation, a particulate feed stream which is substantially free
of
circulation fluid is supplied to the inlet 504 of the separation unit 500. A
particle feed
consisting of ferrous impactors and non-magnetic particles is fed to rotating
drum 505.
Flow of the particulate feedstream can be controlled by the positioning of an
adjustable
deflector 514. As shown in Figure 24, the magnetic separation unit 500 is
designed to
rotate in a clockwise manner, although it is understood that the unit 500 can
be configured
to rotate in a counterclockwise manner. The feed contacting the rotating shell
506 of the
drum 505 enters the magnetic field produced by magnetic field source 508. The
ferrous
impactors 510 present in the feed are held to the surface of the shell 508 by
the magnetic
field. Non-magnetic particles 512 are carried on the surface of the drum 505
until the
drum rotates to a position wherein gravity causes the non-magnetic particle to
fall freely
from the shell 506, into the non-magnetic particle collection outlet 520,
whereas the
impactors 510 remain attracted to the surface of the drum, while the impactors
510 are in
close proximity to the magnetic field source 506. Once the impactors 510 on
the rotating
surface 508 are no longer in proximity to the magnetic field source 506,
contact between
the impactors 510 and the rotating surface 508 of the drum 505 is broken and
the
impactors 510 fall freely into the impactor collection outlet 518.
[000136] In one embodiment, the particulate feed stream may be supplied to a
screening apparatus, such as for example, system 300 shown in Figure 21, to
remove the
large and small particulates, prior to supplying the feedstream to the
magnetic separation.
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In another embodiment, the particulate feed stream may be supplied to a
washing step to
remove circulation fluid and reduce the tackiness of the particles, prior to
the particulate
feedstream being supplied to the magnetic separator. In preferred embodiments,
the
feedstream is first fed to a washing step to reduce the concentration of
drilling fluids
present, followed by a screen separation apparatus to remove large and small
drill
cuttings, and finally to a rotary magnetic separation process to achieve a
nearly pure
stream of impactors, with a loss of impactors of less than 0.50%.
[000137] Separation of impactors from a simulated feedstream was evaluated
using a
feedstream consisting of shot and stone chips retrieved from drilling mud.
Specifically,
the feedstream consisted of steel shot impactors having an average diameter of
approximately 2mm, and stone ships having a diameter of less than 12mm, and
having a
moisture of between 3-5%, wherein the moisture is present as water and
drilling mud.
Bulk density of the feedstream was greater than 180 pcf and a solids specific
gravity of
approximately 7.
[000138] Feed samples were run on a DFA-25 drum as received with a feed rate
of
approximately 34 gallons per minute of feed per foot of drum width. The DFA-25
magnetic separator has a drum having a diameter of approximately inches. As
shown in Table 1, a first sample was run with the drum separator operated at a
speed of
approximately 750 FPM (rotational speed of the drum; 250 rpm), nearly pure
magnet shot
is obtained, with a loss of approximately 0.42% of the shot from the feed. A
second
sample was run with the drum separator operated at a speed of approximately
380 FPM
(126 rpm), resulting in some stone chips were carried over with the magnetic
shot, and a
loss of approximately 0.15% of the shot from the feed.
Table 1
Sample Feedstream Feed Rotational Speed Magnetic Stream Shot Loss
Rate of Drum (% of feed
1 Steel shot, 34 750 FPM Nearly pure 0.42%
stone chips GPMF
and
water/drilling
mud (3-5%)
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2 Steel shot, 34 380 FPM High purity, some 0.15%
stone chips GPMF stone chips
and
water/drilling
mud (3-5%)
[000139] Preferably, the rotational speed of the drum is between 25 and 500
rpm,
more preferably between 50 and 300 rpm, between 100 and 250 rpm and most
preferably
between 125 and 250 rpm.
[000140] The separation step results in an impactor loss of less then 5%,
preferably
less than 4%, less than 3%, and less than 2% of the impactors. More
preferably, the
separation step results in impactor loss of less than 1%, and most preferably
less than
0.5%.
[000141] The recovered impactors include very little formation cuttings.
Preferably, at
least 95% of the recovered particles are impactors (i.e., less than 5%
formation cuttings),
at least 97%, and at least 98% of the recovered particles are impactors. More
preferably,
at least 99% of the particles recovered are impactors. Most preferably, at
least 99.5% of
the particles recovered are impactors.
[000142] Because ferrous materials can, over time, become magnetized, in
certain
embodiments a demagnetizer may be used in conjunction with the magnetic
separator to
ensure no magnetized impactors are supplied to the injector system.
Demagnetizers
(also known as degaussers) are known in the art, and any such device may be
employed
in the present process for the purpose of demagnetizing ferrous materials
employed as
impactors. The demagnetizer may be employed at any point in the impactor
recovery
process, preferably after the magnetic separation. In addition, a demagnetizer
may be
employed in separation systems which do not employ magnetic separation.
[000143] Fig. 22 depicts a graph showing a comparison of the results of the
impact
excavation utilizing one or more of the above embodiments (labeled "PDTI in
the drawing)
as compared to excavations using two strictly mechanical drilling bits - a
conventional
PDC bit and a "Roller Cone" bit - while drilling through the same
stratigraphic intervals.
The drilling took place through a formation at the GTI (Gas Technology
Institute of
Chicago, Illinois) test site at Catoosa, Oklahoma.
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[000144] The PDC (Polycrystalline Diamond Compact) bit is a relatively fast
conventional drilling bit in soft-to-medium formations but has a tendency to
break or wear
when encountering harder formations. The Roller Cone is a conventional bit
involving two
or more revolving cones having cutting elements embedded on each of the cones.
[000145] The overall graph of Fig. 22 details the performance of the three
bits though
800 feet of the formation consisting of shales, sandstones, limestones, and
other
materials. For example, the upper portion of the curve (approximately 306 to
336 feet)
depicts the drilling results in a hard limestone formation that has
compressive strengths of
up to 40,000 psi.
[000146] Note that the PDTI bit performance in this area was significantly
better than
that of the other two bits - the PDTI bit took only .42 hours to drill the 30
feet where the
PDC bit took1 hour and the roller cone took about 1.5 hours. The total time to
drill the
approximately 800 foot interval took a little over 7 hours with the PDTI bit,
whereas the
Roller cone bit took 7.5 hours and the PDC bit took almost 10 hours.
[000147] The graph demonstrates that the PDTI system has the ability to not
only drill
the very hard formations at higher rates, but can drill faster that the
conventional bits
through a wide variety of rock types.
[000148] Table 2 below shows actual drilling data points that make up the PDTI
bit
drilling curve of Fig. 22. The data points shown are random points taken on
various days
and times. For example, the first series of data points represents about one
minute of
drilling data taken at 2:38 pm on July 22"d, 2005, while the bit was running
at 111 RPM,
with 5.9 thousand pounds of bit weight ("WOB"), and with a total drill string
and bit torque
of 1,972 Ft Lbs. The bit was drilling at a total depth of 323.83 feet and its
penetration rate
for that minute was 136.8 Feet per Hour. The impactors were delivered at
approximately
14 GPM (gallons per minute) and the impactors had a mean diameter of
approximately
0.100" and were suspended in approximately 450 GPM of drilling mud.
Table 2
DATE TIME RPM TORQUE WOB DEPTH PENETRATION PENETRATION
Ft. Lbs. Lbs. Ft. FT/MIN FT/HR
7/22/05 2:38 PM 111 1,972 5.9 323.83 2.28 136.8
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DATE TIME RPM TORQUE WOB DEPTH PENETRATION PENETRATION
Ft. Lbs. Lbs. Ft. FT/MIN FT/HR
7/22/05 4:24 PM 103 2,218 9.1 352.43 2.85 171.0
7/25/05 9:36 AM 101 2,385 9.5 406.54 3.71 222.6
7/25/05 10:17 AM 99 2.658 10.9 441.88 3.37 202.2
7/25/05 11:29 AM 96 2.646 10.1 478.23 2.94 176.4
7/25/05 4:41 PM 97 2,768 12.2 524.44 2.31 138.6
7/25/05 4:54 PM 96 2,870 10.6 556.82 3.48 208.8
[000149] In an exemplary embodiment, one or more of the exemplary embodiments
described above include a conventional magnetic device for conveying the solid
material
impactors 100 through one or more elements of one or more of the exemplary
embodiments described above. For example, a magnetic device capable of
conveying
materials carried within a carrying fluid, and equivalents thereof, may be
used to
displace the solid material impactors 100.
[000150] In an exemplary embodiment, one or more of the exemplary embodiments
described above include a conventional magnetic device for separating the
solid material
impactors 100 from the carrying fluid in which the solid material impactors
are conveyed.
For example, a magnetic device capable of separating materials carried within
a
carrying fluid from the carrying fluid, and equivalents thereof, may be used
to separate
the solid material impactors 100 from the carrying fluid.
[000151] In one aspect, provided herein is a system for excavating a
subterranean
formation that includes a body member for receiving a suspension of liquid and
a plurality
of impactors and discharging the suspension so that the impactors remove a
portion of
the formation, a first conduit for receiving the suspension after the removal,
an impactor
separation system for separating the impactors from at least a portion of the
liquid; and a
second conduit for receiving the separated impactors from the separator.
[000152] In one embodiment, the impactor separation system comprises a screen
separation process. In another embodiment the impactor separation system
comprises a
magnetic separation process. In another embodiment, the impactor separation
system
includes both a screen separation process and a magnetic separation process.
The
magnetic separation process can include a rotary drum magnetic separator. In
one
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embodiment, a demagnetizer may be positioned upstream or downstream of the
magnetic
separation system.
[000153] In another aspect, provided herein is a method for excavating a
subterranean formation, the method including the steps of introducing a
suspension of
liquid and a plurality of impactors into at least one cavity formed in a body
member,
discharging the suspension from the cavity so that the impactors remove a
portion of the
formation, separating the impactors from at least a portion of the liquid; and
passing the
impactors to a conduit so that a substantial portion of the impactors
accumulate in the
conduit. In one embodiment, the method includes using screens to separate
impactors
from other particles and liquids in the separation step.
[000154] In another aspect, provided herein is a system for excavating a
subterranean formation, wherein the system includes a body member, first means
disposed in the body member for receiving a suspension of liquid and a
plurality of
impactors and discharging the suspension so that the impactors remove a
portion of the
formation, a first conduit for receiving the suspension after the removal,
second means in
the first conduit for separating the impactors from at least a portion of the
liquids, a
second conduit for receiving the separated impactors from the separator, and
third means
for controlling the flow of impactors to the second conduit so that a
substantial portion of
the impactors can accumulate in the second conduit. In one embodiment, the
system
separation means further includes screen or magnetic separation means.
[000155] In another aspect, provided herein is a method for excavating a
subterranean formation, the method including introducing a suspension of
liquid and a
plurality of impactors into at least one cavity formed in a body member,
discharging the
suspension from the cavity so that the impactors remove a portion of the
formation,
separating the impactors from at least a portion of the liquids and passing
the impactors
to a conduit.
[000156] In one embodiment, the separation step includes using a magnetic
separator. In another embodiment the separation step includes using a rotary
magnetic
drum separator rotating at a speed between 50 and 400 RPM. In another
embodiment,
the separation step results in impactor loss of less than 3%. In another
embodiment, the
conduit for recovering impactors comprises at least 97% by weight impactors.
In another
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embodiment, the impactors are separated from the liquid with a screen
separation
process prior to the magnetic separation.
[000157] In another aspect, provided herein is a system for excavating a
subterranean formation, the system including means for introducing a
suspension of liquid
and a plurality of impactors into at least one cavity formed in a body member,
means for
discharging the suspension from the cavity so that the impactors remove a
portion of the
formation, means for washing the suspension, means for physically separating
the
impactors from at least a portion of the liquid, and means for magnetically
separating the
impactors from at least a portion of the liquid and/or non-magnetic particles.
[000158] In another aspect, provided herein is a method for excavating a
subterranean formation, the method including magnetically introducing a
suspension of
liquid and a plurality of impactors into at least one cavity formed in a body
member,
discharging the suspension from the cavity so that the impactors remove a
portion of the
formation, and separating the impactors from at least a portion of the liquid
by a screening
process.
[000159] In another aspect, provided herein is a system for excavating a
subterranean formation, the system including means for magnetically
introducing a
suspension of liquid and a plurality of impactors into at least one cavity
formed in a body
member, means for discharging the suspension from the cavity so that the
impactors
remove a portion of the formation and means for magnetically separating the
impactors
from at least a portion of the liquid.
[000160] In another aspect, provided herein is a system for separation of
ferrous
impactors from circulation fluid, the system including means for receiving
circulation fluid
from a wellbore, wherein said circulation fluid comprises drilling fluid,
drill cuttings and
ferrous impactors, a separation system, said separation system comprising a
screen
separator and a magnetic separator, and means for receiving impactors from the
separation system.
[000161] In another aspect, provided herein is a system for excavating a
subterranean formation including a drill bit, a body member for receiving a
suspension of
liquid and a plurality of impactors and discharging the suspension so that the
impactors
remove a portion of the formation, a pump, a first conduit for receiving the
suspension
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after the removal, an impactor separation system for separating the impactors
from at
least a portion of the liquid, wherein said separation systems includes a
rotary magnetic
separator, and a second conduit for receiving the separated impactors from the
separator.
[000162] While specific embodiments have been shown and described,
modifications can be made by one skilled in the art without departing from the
spirit
or teaching of this invention. The embodiments as described are exemplary only
and
are not limiting. Many variations and modifications are possible and are
within the
scope of the invention. Accordingly, the scope of protection is not limited to
the
embodiments described, but is only limited by the claims that follow, the
scope of
which shall include all equivalents of the subject matter of the claims.
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