Note: Descriptions are shown in the official language in which they were submitted.
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DIRECT IONAL DRILLING
The present invention relates to a method of
controlling the direction of drilling a borehole in a
subsurface formation, and to a system for directional
drilling a borehole.
In the course of making a borehole, it is often
desirable to control the drilling direction so as to
provide a borehole along a predetermined trajectory. A
common technology of directional mechanical drilling uses
equipment like bent subs, mud motors and rotating seals,
to set only the lower part of the drill string with the
drill bit to drill in a particular direction. Mechanical
drilling uses drilling bits with mechanical cutters such
as roller-cones or polycrystalline diamonds, which
produce cuttings by crushing and/or scraping at the
borehole bottom and at the sides.
More recently, rotary steerable systems (RSS) have
been developed, which can operate with the entire drill
string rotating. Known RSS methods point the mechanical
drill bit into a desired direction using a complex
bending mechanism, or push the drill bit to a particular
side using expandable thrust pads. The side-cutting
ability of the mechanical drill bits used for directional
drilling then allows to deviate the borehole in the
desired direction. For example, polycrystalline diamond
compact (PDC) bits have cutters not only on the front end
but also at the sides.
Some directional drilling systems and methods use
drill bits wherein the nozzles are specially adapted so
as to obtain a directional drilling effect.
In US 4211292 a roller cone drill bit is disclosed,
which has, at a position normally occupied by a
conventional wash nozzle, a nozzle extension with a fluid
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jet emitting nozzle. This extended jet nozzle emits
pressurized fluid onto the gage corner of the borehole
being drilled. Pressurized fluid is selectively conducted
to the jet emitting nozzle during a predetermined partial
interval of one drill bit rotation, so as to increase
cutting of the gage corner in a certain azimuthal sector
of the borehole, thereby deviating the borehole towards
that sector.
GB 2 284 837 discloses another roller cone drill bit,
in which one of three nozzles was modified to direct the
flow into the corner of the workface, so that the flow of
drilling fluid is asymmetric relative to the bit. The
flow of drilling fluid is pulsed so that the flow is high
in a certain azimuthal position and low for the remainder
of the rotation, so as to preferentially drill in a
selected direction.
US 4637479 discloses another roller cone drill bit,
which is modified so that it sealingly co-operates with a
fluid-direction means for sequentially discharging fluid
streams through nozzles only into a selected sector of
the borehole. During rotation of the drill string with
drill bit, fluid communication through one or two nozzles
outside the selected sector of the borehole is always
blocked, and in this way it is achieved that the drill
bit is diverted.
US-2006/0266554 discloses a method and system to
modulate solids in a particular direction. The system
comprises jet means for generating an abrasive jet of a
mixture containing a fluid and a quantity of abrasive
particles. The erosive power of the abrasive jet can be
modulated by modulating the kinetic energy of the
abrasive particles. This can be done by modulating the
mass flow rate of the abrasive particles, for instance by
modulating the quantity of the abrasive particles in the
abrasive jet, or by modulating the velocity of the
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abrasive particles, which can be done for instance by
modulating an acceleration pressure drop of the fluid in
the jet means, or by a combination thereof.
The known methods require substantial modifications
to conventional drill bits, such as nozzle modifications
or implementation of rotating seals. Modifications are
undesirable, as that reduces the choice of drill bit for
the driller and requires use of such drill bit also for
straight parts of the well trajectory. Modifying nozzles
in conventional drill bits will moreover reduce overall
drilling performance, as will the blocking nozzles.
Rotating seals are vulnerable and for that reason not a
desired option in downhole equipment.
There is a need for a robust directional drilling
method and system.
In accordance with the invention there is provided
a method of controlling the direction of drilling a
borehole in a subsurface formation, the method comprising
- providing a tubular drill string;
- providing a drill bit connected to a lower end of
the drill string, the drill bit comprising mechanical
cutting means forming a bit face, and comprising a
plurality of nozzles for ejecting drilling fluid, which
nozzles are arranged at different azimuthal positions
with respect to the bit face, and an intermediate space
between an inlet port of the drill bit and the plurality
of nozzles, each of the nozzles having a nozzle inlet for
fluid communication with the intermediate space, from
which consecutively one of the nozzle inlets extends
during rotation of the drill bit;
- rotating the drill bit while passing drilling
fluid comprising solids via the drill string through the
plurality of nozzles, so as to deepen the borehole,
- modifying solids concentration of drilling fluid
portions flowing through the plurality of nozzles while
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rotating the drill bit, so that the solids concentration,
for the drilling fluid portion flowing through each of
the nozzles, is relatively increased when the respective
nozzle is in a selected first angular sector of the
borehole bottom, as compared to the solids concentration
of the drilling fluid portion flowing through the
respective nozzle when said nozzle is in a selected
second angular sector of the borehole bottom.
The invention is based on the insight gained by
applicant that solids concentration in fluid flow through
each nozzle influences drilling performance, and that a
distortion of an equal solids distribution of fluid
ejected from the plurality of bit nozzles allows to
achieve a directional drilling effect. Solids contribute
to drilling progression by erosion, so an imbalance will
lead to different erosion contributions to drilling
progression in different sectors of the borehole bottom.
Merely a relatively small distortion from an equal
solids concentration ejected through different nozzles
can be sufficient to obtain a directional drilling effect
of useful magnitude. Suitably therefore, simultaneous
drilling fluid flow through the first and second nozzles
is maintained during rotation. In this case, flow through
a particular nozzle can be maintained throughout the
rotation, and a modification such as a modulation of the
flow with the frequency of rotation is sufficient. This
eliminates the requirement for rotating seals,
selectively blocking fluid flow through nozzles. It also
allows the use of conventional drill bits without a
modification of the nozzle configuration, i.e. the
nozzles can still be optimally, such as symmetrically,
arranged, as desired for a particular drill bit
configuration.
The purpose of solids modulation in the context of
the present invention is to enable higher abrasion and to
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generate instantaneous orientation dependant rate-of-
penetration (ROP) changes and consequently differential
hole making.
In one embodiment the drill bit comprises an
intermediate space between an inlet port of the drill bit
and the plurality of nozzles, each of the first and
second nozzles having a nozzle inlet for fluid
communication with the intermediate space, and wherein
the step of modifying solids concentration comprises
directing drilling fluid into a first area of the
intermediate space from which consecutively one of the
first and second nozzle inlets extends during rotation of
the drill bit. This allows to vary or modify the solids
concentration by using an inertia effect. In the
intermediate space, the drilling fluid is distributed
over the various nozzle inlets. Solids in the drilling
fluid, having a higher density and therefore higher
inertia, have a longer memory of the flow direction at
which they were released into the intermediate space, and
therefore the concentration in that direction and in the
first area is relatively increased during redistribution
of drilling fluid, as compared to other areas of the
intermediate space.
Thus, at a particular first moment in time, say when
the first nozzle has its inlet in the first area of the
intermediate space, the directing of fluid towards the
first area will cause transfer of drilling fluid with a
higher concentration of solids to that nozzle, compared
to the second nozzle that has its inlet in another area
of the intermediate space. At a second, later moment in
time, when the drill bit has rotated, the inlet of the
second nozzle will be in the first area towards which
fluid is preferentially directed, and now receives a
higher solids concentration, both compared to the first
nozzle at the second moment in time as well as to the
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second nozzle at the first moment in time. It shall be
clear that the intermediate space is herein regarded as
geostationary even though the drill bit rotates.
In one embodiment a flow directing means having an
outlet member is provided for directing drilling fluid,
and the method further comprises maintaining the outlet
member in a geostationary position during at least one
rotation of the drill bit. This is a particularly simple
means of achieving an increased solids concentration
towards consecutive nozzle inlets during rotation.
To maintain a geostationary position, a motor can be
provided, controlled to orient the flow directing means
as desired. In another embodiment, the flow directing
means can be rotatably arranged in the drill string, and
shaped so as to rotate in opposite direction with respect
to the drill string when passing drilling fluid down the
drill string. For example, shaping can include providing
vanes, fins or similar. Moreover, in case rotation caused
by the drilling fluid in this way is too fast, a brake
means for the rotation of the flow directing means can be
provided, and maintaining the flow directing means in a
geostationary position then comprises operating the break
means so as to slow the rotation of the flow directing
means to compensate the opposite rotation of the drill
string. The flow directing means can further include an
electrical generator for converting hydraulic energy of
the drilling fluid or rotational energy of the flow
directing means into electricity, which can for example
power a downhole measurement and/or control unit used for
the directional drilling.
In one embodiment a solids concentration means is
provided for increasing the concentration of solids in a
drilling fluid portion. When at least part of the solids
in the drilling fluid is deflectable in a magnetic field,
wherein the solids concentration means can be arranged to
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apply a rotating magnetic field to the drilling fluid.
This can for example be a rotating magnet arrangement,
e.g. a permanent magnet or an electromagnet. Such
rotating magnet arrangement can for example be combined
with a rotating flow diverter, to enhance the solids
concentration effect. A rotating magnetic field can also
be provided without moving parts, by arranging an
electromagnet arrangement in and/or around the flow path
of drilling fluid, comprising a plurality of
electromagnetic poles in a plane or ring crossing the
drilling fluid flow lines, and driving the
electromagnetic arrangement such that an effective force
is exerted on the particles, the vector characterizing
this force rotating as desired.
Alternatively or in addition, the solids
concentration means can comprise a curved flow path so as
to effectuate a concentration due to centrifugal forces.
In some embodiments the flow directing means, solids
concentration means and/or the flow guide (when present
or desired) can be shaped so that they can be passed
downwardly from surface and/or retrieved to surface in
the course of drilling the borehole. This allows
selective conducting of directional drilling only when it
is desired, without the need to retrieve the drill string
to exchange the drill bit or parts of the bottom hole
assembly.
In one embodiment a flow guide is provided in the
intermediate space, which is rotated together with the
drill bit, the flow guide comprising first and second
channels each co-operating during time periods of the
rotation at an upstream end with the outlet member,
depending on the relative rotational position the outlet
member and the drill bit, and at a downstream end with
the first and second nozzle inlets, respectively. This
embodiment allows the outlet member directing the fluid
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to interface with the upstream end of the flow guide,
which can be near the inlet port of the drill bit, which
may be more convenient than interfacing directly with an
area of nozzle inlets in the intermediate space some
distance into the drill bit.
The invention moreover provides a system for
directional drilling a borehole, the system comprising:
- a drill string element for passing drilling fluid
comprising solids;
- a drill bit connected to the drill string element,
the drill bit comprising a bit body, mechanical cutting
means forming a bit face, an inlet port for receiving the
drilling fluid from the drill string element, a plurality
of nozzles for ejecting the drilling fluid, which nozzles
are arranged at different azimuthal positions with
respect to the bit face, and an intermediate space
between the inlet port and the plurality of nozzles, each
of the nozzles having a nozzle inlet for fluid
communication with the intermediate space; and
- a diverter for directing at least part of the
solids to a first area of the intermediate space, from
which first area consecutively one of the nozzle inlets
extends during relative rotation of the drill bit with
respect to the diverter, as compared with a second area
of the intermediate space.
By directing fluid with relatively higher solids
concentration towards the first area of the intermediate
space, more solids are ejected through the nozzles that
are consecutively extending from this area during
rotation. This causes a small difference in drilling
progression between the side of the first area and the
opposite side. Controlling the diverter such that the
area in which the solids concentration is relatively
increased is kept geostationary, so that the first area
of the intermediate space forms an azimuthal sector of
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the intermediate space, will result in a directional
drilling action.
In one embodiment the diverter comprises
- a flow directing means at least part of which
being provided in the drill string element, the flow
directing means comprising an outlet member in rotatable
arrangement with respect to the drill bit, the outlet
member being arranged to direct drilling fluid into a
first area of the intermediate space from which
consecutively one of the first and second nozzle inlets
extends during a relative rotation of the outlet member
with respect to the drill bit;
- a means for controlling relative rotation of the
outlet member with respect to the drill bit.
In one embodiment the outlet member can in particular
be a flow diverter.
In a particular embodiment the outlet member extends
into the intermediate space, such as via the inlet port
of the drill bit. That allows a direct interaction with
the first area of the intermediate space. Possibly it is
advantageous to adapt the outlet member to the geometry
of the inlet port and/or intermediate space.
In one embodiment the system comprises a flow guide
provided in the intermediate space in a rotatably locked
configuration with the drill bit, the flow guide
comprising first and second channels each adapted to co-
operate, depending on the relative rotational position
the outlet member and the drill bit, at an upstream end
with the outlet member, and at a downstream end with the
first and second nozzle inlets, respectively. In this
embodiment the solids diverter can have a standardized
interface co-operating with the upstream end of the flow
guide, and adaptation to the geometry of the drill bit
can be achieved by the flow guide, which can take the
form of an adapter or insert.
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In one embodiment, at least a part of the solids in
the drilling fluid is magnetic, and the diverter
comprises a magnet for diverting said part of the solids
towards the first area of the intermediate space. The
magnet can be a rotatable permanent magnet or an
electromagnet with a driver unit capable of producing a
rotating magnetic field.
In one embodiment the diverter can comprise a curved
flow path.
In one embodiment at least part of the diverter
and/or flow directing means and/or the flow guide can be
retrievable through the drill string element. This makes
it possible to conduct directional drilling only during
certain periods of a drilling operation. By being
retrievable, components are also insertable or re-
insertable.
Suitably the system further comprises a controller
means for controlling relative rotation of the outlet
member with respect to the drill bit. In one embodiment
the controller means can comprise a break means for
slowing relative rotation of the outlet means with
respect to the drill string.
The invention will be described hereinafter in more
detail, and by way of example, with reference to the
accompanying drawings in which:
Figure 1 schematically shows an embodiment of system
for directional drilling a borehole in an earth formation
in accordance with the invention;
Figure 2 schematically shows an electromagnetic
brake arrangement;
Figure 3a and 3b show schematic views down the
borehole as in Figure 1, for two moments in time;
Figure 4 schematically shows another embodiment of a
system for directional drilling a borehole in an earth
formation in accordance with the invention;
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Figure 5 schematically shows a cross-sectional view
of the flow guide in Figure 4;
Figure 6 shows the result of a model calculation of
drilling radius in dependence of a differential hole
making (DHM) effect;
Figures 7a and 7b schematically show an embodiment
of a deflection means alternative to outlet member 45 in
Figures 1 and 4, in perspective and top view; and
Figures 8a and 8b schematically show alternative
methods and means for solids diversion.
In the Figures, like reference numerals relate to
the same or similar components or objects.
Referring now to Figure 1 there is shown an
embodiment of a method and system 1 for directional
drilling a borehole 3 in an earth formation 5 in
accordance with the invention. The system 1 comprises a
drill bit 10 connected to a sub 14, which is a part of
drill string 16 extending to the earth's surface. A drill
collar 17 is shown connected to the upper end of sub 14
as a further part of the drill string 16. The
longitudinal axis of drill string 16 as well as drill bit
10 is indicated as 18. A length of drill string above the
drill bit 10 is referred to as a drill string element,
and can be the entire drill string.
The drill bit 10 of shown in this embodiment is a
polycrystalline diamond cutter (PDC) bit, but other drill
bit types such for example a roller-cone it can also be
used. The PDC bit of shown here comprises a bit body 20
provided with mechanical cutting means in the form of PDC
cutters 24. The cutters form a bit face 26, which is
during normal operation near the borehole bottom 28. The
drill bit 10 further is provided with an inlet port 30
for receiving drilling fluid from the drill string
element, in this example from sub 14. The port 30 is the
inlet to intermediate space 32, from which a plurality of
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inlet channels to nozzles for ejecting drilling fluid
extend. In this example a first nozzle 35 with first
inlet channel 36 and a second nozzle 38 with second inlet
channel 39 are provided. The first and second nozzles are
arranged at different azimuthal positions with respect to
the bit face, in this example 180 degrees apart, as
counted with respect to rotation of the drill string 16
along its longitudinal axis.
In the sub 14 a solids diverter is arranged. The
solids diverter in this embodiment is a flow directing
means 42 comprising an outlet member 45, connected via
support member 46 and shaft 48 to a rotation means
schematically shown as 50, and controlled by control unit
52 for controlling relative rotation of the outlet member
with respect to the drill bit 10. The support member 46
is arranged such that it allows drilling fluid to pass
down the interior of the drill string towards the inlet
port 30. The outlet member 45 in this embodiment is a
flow diverter, shown as a flat plate as seen from the
side, but it can also have other shapes such as a curved
lip or a channel. The outlet member 45 in this embodiment
extends via the inlet port 30 into the intermediate space
32, and this way delivers drilling fluid in a direction
towards a first area 55 of the intermediate space 32. As
shown in Figure 1, the first inlet channel 36 to first
nozzle 35 extends from the first area 55, and the second
inlet channel 39 to second nozzle 38 extends from the
second area 56 which second area is outside of the area
towards which drilling fluid is directed. When the drill
string 16 has rotated by 180 degrees, and the outlet
member 45 remains geostationary, then the second inlet
channel 39 to second nozzle 38 extends from the first
area 55. Areas 55 and 56 are regarded as geostationary.
The control unit 52 is adapted to obtain orientation
data, such as from external, connected or integrated
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measurement devices, e.g. MWD devices, and/or via
communication with an external data source, e.g. at
surface. From actual and desired orientation data for the
outlet member it is determined, which relative rotation
of the outlet member with respect to the drill string is
needed.
When the drill string 16 rotates, say right-handed,
a left-handed rotation relative to the drill string would
be required for the outlet member to remain
geostationary. The rotation means 50 can for example be
an active drive motor.
Another option is shaping a part of the flow
direction means 42, such as the support member 46 or
outlet member 45, such that it is driven by the flow of
drilling fluid into an opposite rotation relative to the
drill string. In the latter case, control over the
direction of the flow diverter can be achieved by way of
a controlled brake that slows the left hand rotation to
such an extent that the right hand rotation of the drill
string is compensated and the flow diverter points into a
fixed direction relative to earth.
In Figure 2, a schematic electromagnetic brake
arrangement for the rotation means is shown, in a view
down the borehole 3 as in Figure 1. Within the sub 14 a
stator 60 is arranged, which is rotatably locked to the
sub 14. The stator can also be integrally formed with the
sub. A rotor 64 is rotatably arranged with respect to the
stator 60/sub 14. The rotor 64 comprises means , e.g. a
vane, fin or rib, exerting a torque when fluid flows
along and is deflected, so as to rotate the rotor
relative to the stator 60 when drilling fluid flows down
the sub 14. One option for such means is schematically
indicated by lip 45a that is standing up from outlet
member 45. This relative rotation of the rotor 64 is
indicated by arrow 66. The rotation of the sub 14 in the
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borehole 3 during drilling operation, together with
stator 60, is indicated by arrow 68. Stator 60 and rotor
64 together form an electromagnetic generator, in
particular one of stator and rotor comprising a permanent
magnet arrangement and the other comprising an
electromagnetic coil arrangement. For example, the stator
can comprise the permanent magnet arrangement, and the
rotor the electromagnetic coil arrangement interacting
with the permanent magnet arrangement during relative
rotation so as to create a voltage over electrical poles
of the electromagnetic coil arrangement, and thereby
electrical energy. This energy can be dissipated in a
load. The load can e.g. be a resistor. Instead of
dissipating the energy as heat, it can also at least
partly be used for powering other electrical equipment,
directly or by loading a battery. By changing the load,
such as a resistor connected to the electrical poles, the
resistance to rotation can be controlled, and thereby the
electromagnetic brake can be adjusted such that the
rotations 64 and 68 compensate each other, so that the
rotor 64 to which the outlet member 45 of the embodiment
of Figure 1 is connected, remains geostationary. The
outlet member causes a diversion of solids in the
direction 70.
The flow directing means 42 in this embodiment can
be retrieved to surface upwardly through the interior of
the drill string 16. Also, the flow directing means 42
can be introduced through the drill string from surface,
for instance to replace the flow directing means after
retrieval thereof.
During directional drilling operation of the system
1, drilling fluid comprising solids is pumped down the
interior of drill string 16.
The drilling fluid comprising solids suitably
comprises at least 0.01 wt% solids, in particular at
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least 0.05 wt%. Suitably the drilling fluid comprises 10
wt% solids or less, in particular 5 wt% or less, such as
2 wt% or less. A suitable concentration of solids is in
the range of from 0.02 wt% to 5 wt%, in particular from
0.05 wt% to 2 wt%.
The solids can be solids known to be used in
drilling mud, e.g. barite, hematite and/or corundum.
Alternatively or in addition, solids can comprise solids
that can be deflected in a magnetic field, e.g.
ferromagnetic, paramagnetic or dielectric solids. An
example is steel.
Solids are preferably present as particles of a
particle size that does not block passages or nozzles in
the drill string and/or drill bit, but provides
sufficient inertia effect. Suitably, at least 90 % of the
particles, preferably substantially all particles, more
preferably all particles, pass through a 1 mm sieve, in
particular a 500 pm sieve, more in particular a 212 pm
sieve, even more in particular a 150 pm sieve. Particles
included in the drilling fluid for abrasive effect have
suitably a minimum particle size. Suitably at least 90 %
of these particles, preferably substantially all of these
particles, more preferably all of these particles, do not
pass through a 20 pm sieve, in particular a 32 pm sieve,
more in particular a 450 pm sieve. A suitable range of
particle size is a sieve fraction between 45 and 150 pm
sieves, such as a sieve fraction between 75 and 125 pm
sieves. Sieves as used herein are specified in ASTM Ell,
and a suitable sieving method is described in ASTM B214.
The specific density of the solids is higher than
that of the liquid phase of the drilling fluid. Suitably
the specific density is 2000 kg/m3 or more, in particular
3000 kg/m3 or more, and is typically less than 20000
kg/m3.
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The flow diverter, outlet member 45, is kept
geostationary by the operation of the control unit 52 and
rotation means 50, so that drilling fluid is directed
towards the first area 55 of the intermediate space 32.
In the intermediate space, the drilling fluid is
distributed over the first and second nozzle inlets.
Solids in the drilling fluid, having a higher density and
therefore higher inertia, have a longer memory of the
flow direction at which they were released into the
intermediate space, and therefore the concentration in
fluid ejected through the respective nozzle having its
inlet in the first area is relatively increased during
redistribution as compared to the respective other
nozzle.
In Figures 3a and 3b, schematic views down the
borehole 3 as in Figure 1 are shown, for two different
moments in time. The Figures show four sectors of the
borehole bottom 28, including first sector 81 and second
sector 82, separated by third sector 83 and fourth sector
84. At the first moment in time, see Figure 3a, a first
nozzle 35 with first inlet channel 36 is located in first
angular sector 81 of the borehole bottom near point A in
the formation 5. For clarity, the direction of solids
diversion 70 is shown instead of the flow diverter 45, or
of any other means used for solids diversion. In this
embodiment, the solids concentration towards first area
55 is increased by inertia, and from this area the first
inlet channel 36 extends at this moment in time. The
second nozzle 38 is located in second angular sector 82
opposite sector 81 of the borehole bottom and receives
fluid from the second area 56 of the intermediate space,
which in the area receiving a relatively lower solids
concentration than the first area 55. Figure 3b shows a
later moment in time, when the drill bit has turned so
that the second nozzle 38 with inlet channel 39 is in the
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first sector 81 near point A, and receives drilling fluid
with higher solids concentration from the area 55 of the
intermediate space 32 that is considered to be
geostationary. The first nozzle 35 now is in the second
sector 82 and receives fluid from the second area 56.
Modulating the solids concentration provided to
nozzles such that the solids concentration in the first
sector 81 is relatively increased compared to the second
sector 82 results in a higher abrasion effect in the
first sector compared to the second sector. If other
influences can be disregarded, that provides a
directional drilling component towards the side of point
A.
The angular sectors 81, 82, 83, 84 are shown in the
Figure as quadrants of the borehole bottom 28, the first
and second sectors forming opposite quadrants. It will be
understood that the first and second sectors can be
chosen differently; they can for example be opposite half
circles, or can be two mutually exclusive sectors of
different size (angle), together forming a full circle.
For an intermediate space having circular cross-
sections, the first and second areas can be analogously
defined with respect to such circular cross-section
instead of the borehole bottom.
Referring now to Figure 4 there is showna further
embodiment of a method and system 101 for directional
drilling a borehole 3 in an earth formation 5 in
accordance with the invention. Components that are
substantially the same or similar to that of the
embodiment of Figure 1 are given the same reference
numerals and reference is made to their description
hereinabove. By way of difference with Figure 1, the
drill bit 110 is a roller-cone drill bit having three
roller cones of which only two are shown with reference
numerals 111,112. Roller cone 112 and its supporting leg
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are dashed, to indicate that this cone is behind the
paper plane. The third roller cone (not shown) would be
generally in front of roller cone 112. With each of the
roller cones a nozzle is associated, first nozzle 35 with
first roller cone 111, second nozzle 38 with second
roller cone 112, and a third nozzle with the third roller
cone (not shown). The nozzles communicate via inlet
channels with the intermediate space 32 of the bit 110.
As a further difference with the embodiment of Figure 1,
in the intermediate space 32 a flow guide 133 is
arranged. The flow guide 133 in this embodiment is an
insert that is adapted to and can be placed in a
conventional roller-cone bit. The flow guide 133 is
arranged such that it is rotatably locked to the bit,
i.e. it rotates with the drill bit 110. The flow guide
133 comprises a first channel 134 co-operating at a
downstream end 135 with the inlet to the first inlet
channel 36, and a second channel 137 co-operating at its
downstream end 138 with second inlet channel 39. A cross-
sectional view of the flow guide 133 is shown in Figure
5, indicating a third channel 141 communicating with the
third nozzle.
The flow guide 133 in this embodiment can be
retrieved to surface upwardly through the interior of the
drill string 16.
The flow directing means 42 of this embodiment
comprises an outlet member 145 which, different from the
outlet member 45 in Figure 1, does not extend into the
intermediate space 32 of drill bit 110. Rather, it is
arranged to deliver fluid towards the upstream end, e.g.
142, 143, of one of the flow channels 134,137 or 141 in
turn, dependent on the relative rotational position of
drill bit 110 and the outlet member 145.
Normal directional drilling operation is essentially
as in the embodiment of Figure 1.
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Reference is made to Figures 7a and 7b,
schematically showing an alternative flow direction
means, in the form of deflection means 101, in
perspective view and in top view. The deflection means
can be arranged in principle instead of the outlet member
45 with lip 45a in the embodiments discussed hereinabove.
The deflection means acts as a solids diverter, due to
the higher inertia of solids with higher density as
discussed hereinabove. Deflection means 101 has an
upstream end 103 for receiving fluid flowing along the
drill string element, a downstream end 105 forming a non-
axial outlet 106 for fluid, and a flow path 108 for fluid
between the upstream and downstream ends. The direction
of fluid flow is indicated by arrow 109. The deflection
means is rotatable about the axis of the drill string
element in which it is arranged during normal operation,
which drill string element is not shown but for example
similar to sub 14 discussed above. The axis of the drill
string element 18 coincides with the axis 110 of the
deflection means 101. The deflection means 101 of this
embodiment comprises a deflection member 112 forming an
at least partly helical flow channel 113 for fluid,
coinciding with the flow 108 path. The flow path is
arranged such that fluid flowing from the upstream end to
the downstream end exerts a torque about the axis 110.
The torque is indicated by force vector 115 which does
not cross the axis 110.
Reference is made to Figures 8a and 8b, showing
schematically alternative methods and means for solids
diversion, in cross-section through the drill string 3.
These methods can be applied when at least part of the
solids can be deflected in magnetic field. Then, a
geostationary magnetic field can be used to direct solids
towards first area 55. One schematic embodiment for this
is shown in Figure 8a, and is based on the
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electromagnetic brake of Figure 2. However, instead of
the flow diverter with outlet member 45, a magnet 72 can
be arranged. The operation of the brake is in principle
as discussed with reference to Figure 2, but now the
magnet diverts solids in the direction 70. The magnet 72
is suitably a permanent magnet so that no power is
required.
In Figure 8b a further embodiment of a solids
diverter is schematically shown. The solids diverter 80
of this embodiment comprises a plurality of
electromagnetic coils 82, which are connected to a power
source control unit, which energizes individual coils as
a function of time such that an effective magnetic field
is obtained that is rotating relatively opposite the
rotation 68 of the sub 14, thereby also providing a
geostationary solids deflection in the direction 70. An
advantage of this embodiment is that it does not include
mechanically rotating parts, but it requires an electric
power source.
Reference is made to Figure 6, showing the result of
a model calculation of drilling radius in dependence of a
differential hole making (DHM) effect between two
opposite sides at the borehole bottom. DHM can be defined
as the difference, expressed in percent, between the
rates of penetration at the opposite sides (diametrically
opposite points). Calculations were performed for a
15,2 cm (6 inch) drill bit. Figure 6 shows, that a very
small differential hole making effect is sufficient to
achieve a practically useful directional drilling effect.
E.g. a differential hole making of only 0.1% is
sufficient to obtain a radius of only 150 m. This model
calculation does not take the stiffness of the bottom
part of the drill string/bottom hole assembly (BHA) into
account. In the practice of the invention this stiffness
can determine the minimum radius that can be drilled; if
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the drill bit has a tendency for a smaller radius, it can
set the drilling system into a mode to drill the minimum
radius determined by the BHA.
Examples
Experiments were conducted in lab drilling tests. A
15,2 cm drill bit of PDC type was used to drill into a
limestone.
Drilling was performed at 60 rotations per minute
(RPM), and at a downhole pressure of 10 MPa, with a
pressure drop over the bit of 7 MPa and a flow rate of
drilling fluid of 700 1/min. As drilling fluid water was
used, as well as water to which corundum particles of 100
pm, and a particle density of 4 kg/1, were added in
various solids concentrations (in volume% based on total
drilling fluid). Concentrations are shown in Table 1.
Weight-on-Bit values (WOB) were also varied.
The ROP was measured with solids present in the drilling
fluid (ROP solids). For comparison, ROP was also measured
without solids, before and after the measurement with
solids, and the average of these measurements is given as
"ROP no solids" in Table 1 as well.
Table 1
Exp WOB ROP no solids ROP solids
(tons) solids concentration (m/hr)
(m/hr) (vol%)
1 2,8 1,60 1,49% 1,73
2 2,8 1,49 2,06% 1,75
3 2,2 0,47 1,07% 0,73
The experiments show that the rate of penetration
significantly increases with solids in the drilling
fluid. The relative increase of "ROP solids" compared to
"ROP no solids" at the same WOB is larger with increasing
solids concentration (18% increase in experiment 2 as
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compared to 8% in experiment 1). At very low WOB, where
the normal drilling progression of the drill bit is
small, the relative increase is much more pronounced.
Generally, the rate of penetration depends on
weight-on-bit applied. This dependency is typically
substantially linear for a range of WOB, and with the
method of the invention it is preferred to operate in
that linear regime.
The experiments demonstrate that providing higher
solids concentration to nozzles in a first sector of the
borehole bottom, as compared to nozzles in a second
sector, provides a differential ROP and leads to a
directional drilling effect.
When the solids concentration is increased by means
of a flow directing means, for example as discussed with
reference to Figures 1 and 4, a parameter of fluid flow
through a particular nozzle is normally modulated
together with the solids concentration. For example, the
flow rate of drilling fluid through the nozzle receiving
a higher solids concentration is increased at the same
time. It has been found that for a PDC bit the increased
flow rate also increases the rate of penetration,
therefore the two effects both contribute to a
directional drilling effect in the same direction. It was
found for a roller-cone bit that the increase of flow
rate through a nozzle leads to a decrease in
instantaneous ROP (i.e. ROP at a time scale of one
rotation or less), so to a directional drilling effect in
the opposite direction. When solids are added to the
drilling fluid, a certain minimum concentration may be
required in case of solids diversion by means of flow
diversion, before a directional drilling effect in the
same direction as with a PDC bit is obtained. Clearly,
these considerations do not apply if the solids
concentration is modulated without influencing flow rate.
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If no directional drilling is desired, this can be
achieved by taking the solids diverter out of a
geostationary position, or out of operation, such that a
straight hole is drilled. This is for example the case if
a rotating solids diverter such as a rotating flow
diverter or a rotating permanent magnet rotates together
with the drill bit.
The present invention is not limited to the
embodiments thereof described above, wherein various
modifications are conceivable within the scope of the
appended claims. Features of embodiments may for instance
be combined.
