Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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SYSTEM FOR DRILLING A WELLBORE
The present invention relates to a system for
drilling a borehole into an earth formation, comprising a
casing arranged in the borehole, and a drill string
extending through the interior of the casing to a lower
end portion of the borehole, the casing having an inner
surface susceptible of wear due to contact with an outer
surface of the drill string during drilling of the
borehole with the drill string.
During rotary drilling of the wellbore, the drill
string is rotated from surface by a rotary table at the
drilling rig to deepen the wellbore, whereby the rotating
drill string normally is in frictional contact with the
inner surface of the casing and the wellbore wall.
Generally the accumulated friction force between drill
string and casing/wellbore wall increases with increasing
depth, tortuosity and inclination of the borehole, thus
leading to increased torque at the rotary table.
Furthermore, the frictional contact between the drill
string and the casing potentially leads to wear of both
the drill string and the casing. In conventional drilling
applications, casing are installed at selected depth
intervals of the wellbore, whereby generally the fracture
pressure and the pore pressure of the surrounding
formation are the determining factors for the length of
each such depth interval. Except for the surface casing,
each casing is lowered through a previously installed
casing and extends from surface to near the lower end of
the newly drilled depth interval. In view thereof
subsequent casings necessarily are of stepwise decreasing
diameter. The resulting nested casing arrangement implies
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that each casing normally is in frictional contact with
the rotating drill string only for the duration of
drilling the next depth interval. Therefore, for such
applications, casing wear is normally not a significant
problem.
EP-1044316-B1 discloses a wellbore system whereby
subsequent casings do not extend to surface. Instead,
each new wellbore interval is provided with a casing that
extends from the lower end of the previous casing to near
the newly drilled wellbore interval. Furthermore, each
casing is radially expanded in the wellbore after having
been lowered to the desired depth so that the wellbore
can be drilled at a substantially uniform diameter along
the length thereof.
It is a problem of the known wellbore system that
each casing is exposed to wear due to frictional contact
with the rotating drill string, for prolonged periods of
time. The present invention therefore sets out to provide
an improved system for drilling a wellbore, which
overcomes the problems of the prior art.
In accordance with the invention there is provided a
system for drilling a borehole into an earth formation,
comprising a casing arranged in the borehole, a drill
string extending through the interior of the casing to a
lower end portion of the borehole, and a body of drilling
fluid extending into the casing, the casing having an
inner surface susceptible of wear due to frictional
contact with an outer surface of the drill string during
drilling of the borehole with the drill string, wherein
the system further comprises means for reducing wear of
said inner surface of the casing, said means including at
least one of a hardened layer at the inner surface of the
casing, a friction-reducing layer at the outer surface of
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the drill string, and a lubricating compound contained in
the body of drilling fluid.
Tests have indicated that each said means are
effective to protect the inner surface of the casing
against wear, whereby the hardened inner layer of the
casing protects the casing against the abrasive action of
small particles contained in the drilling fluid, and the
friction-reducing layer of the drill string and the
lubricating compound in the drilling fluid protect the
casing against high friction forces from direct contact
with the drill string. For some applications, the best
result is obtained if the system comprises each of the
three wear reducing means, i.e. a hardened layer at the
inner surface of the casing, a friction-reducing layer at
the outer surface of the drill string, and a lubricating
compound contained in the body of drilling fluid.
Suitably the hardened layer at the inner surface of
the casing has a first hardness and the outer surface of
the drill string has a second hardness, and wherein said
first hardness is larger than said second hardness. For
example, the ratio of the first hardness to the second
hardness is between 1 and 5. Preferably the first
hardness has a value of between 150 Hv and 600 Hv.
Suitably the friction-reducing layer of the drill
string comprises poly-tetra-fluor-ethene (PTFE). The
friction-reducing layer can be provided in the form of a
coating applied to the outer surface of the drill string.
In an exemplary application, the lubricating
compound includes between 64.25-90.89 wt% base oil, such
as a natural triglyceride oil, fish oil, animal oil,
vegetable triglyceride oil, sunflower seed oil, soybean
oil, rapeseed oil canola oil, palm nut oil, palm oil,
olive oil, rapeseed oil, canola oil, linseed oil, ground
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nut oil, soybean oil, cottonseed oil, sunflower seed oil,
pumpkin seed oil, coconut oil, corn oil, castor oil,
walnut oil, natural or synthetic oil, or an ester.
Suitably the lubricating compound includes between
0.02-0.05 wt% metal deactivator, for example Triazol or
benzotriazol derivatives, such as tolytriazol.
Advantageously the lubricating compound includes
between 0.5-3.0 wt% antioxidant, for example aromatic
amine antioxidant and/or hindered phenolic antioxidants
antioxidants, such as for example, 2,6-bis (tert butyl-4-
methylphenol, BHT). Example commercially available
products are: Octylated, Butylated Diphenylamine
Antioxidant from Ciba-Geigy Corp (lrganox L 57); 2,6-bis
(1,I-dimethylethyl)-4-methyl-Phenol, from PMC, Inc (BHT);
and Benzenepropanoic acid, 3,5-bis (1,1-demethylethyl)-4-
hydroxy-, thiodi-2, 1-ethanediyl ester, from Ciba-Geigy
Corp (Irganox 1035).
The lubricating compound preferably includes between
4-12 wt% sulfurized natural oils like sulfurized
vegetable or animal fatty oils, with natural oils sulfur
content 9%-21%, such as for example 13.5%-17.5%. Example
commercially available products are: Sulfurized vegetable
oils from Rhein Chemie Corporation (Additin RC-2515); and
Sulfurized Lard Oil from Ferro Corporation (HSL).
The lubricating compound can include between 4-
12 wt% phosphate ester, such as phosphoric acid esters
with ethoxylated fatty ester (C12-C15) alcohols,
preferably mixture of phosphoric acid ester with
ethoxylated lauryl alcohol and phosphoric acid ester with
ethoxylated tridecyl alcohol. Example commercially
available products are: Phosphoric acid ester with
ethoxylated lauryl alcohol and phosphoric acid ester with
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ethoxylated tridecyl alcohol from Houghton International
(Houghton 5653).
The lubricating compound can include between 0.4-
1.5 wt% phosphoric acid, for example phosphoric acid
esters with ethoxylated fatty ester (C12-C15) alcohols,
preferably mixture of phosphoric acid ester with
ethoxylated lauryl alcohol and phosphoric acid ester with
ethoxylated tridecyl alcohol. Example commercially
available products are: Phosphoric acid ester with
ethoxylated lauryl alcohol and phosphoric acid ester with
ethoxylated tridecyl alcohol from Houghton International
(Houghton 5653).
The lubricating compound suitably includes between
0.08-1.5 wt% viscosity modifier, such as polyacrylates,
polymethacrylates, modifier inylpyrrolidone/methacrylate-
copolymers, polyvinylpyrrolidones, polybutanes, olefin-
copolymers, styrene/-acrylate-copolymers, polyethers,
such as for example, styrene or butadiene-styrene
polymer. An example commercially available product is
Styrene Hydrocarbon Polymer from Lubrizol Corporation
(Lubrizol 7440S).
The lubricating compound suitably includes between
0.1-0.5 wt% pour-point depressant, for example
polymethacrylates, alkylated naphthalene depressant
derivatives, such as alkyl ester copolymers. An example
commercially available product is Alkyl ester copolymer
from Lubrizol Corporation (Lubrizol 6662).
The lubricating compound suitably includes between
0.01-0.2 wt% defoamer, such as silicon based antifoam
agent. An example commercially available product is
Silicon based antifoam agent from Ultra Additives (Foam
Ban 103).
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The lubricating compound can include between 0-5 wt%
carboxylic acid soaps, for example alkali, alkanolamine,
alkyl amine or alkoxylated acid soaps amine salts of
mono-or dibasic fatty acids, or mixture thereof. An
example commercially available product is Soap formed in
situ as a product of reaction between Tall Oil Fatty
Acids (Sylvatal D3OLR from Arizona Chemical Co.) and
triethanol amine (TEA 99 from Huntsman Corporation).
A number of drilling fluids were tested to determine
the effect of various lubricating compounds on drill
string wear, casing wear, and friction coefficient
between drill string and casing. The tested drilling
fluids were:
fluid 1: water based drilling fluid containing 3 wt%
bentonite;
fluid 2: water based drilling fluid containing 3 wt%
barite;
fluid 3: water based drilling fluid containing 3 wt%
Cosmolubric ETL manufactured by Houghton International
Inc.;
fluid 4: water based drilling fluid containing 3 wt%
Torque Trim manufactured by Halliburton;
fluid 5: water based drilling fluid containing 3 wt%
Oleon manufactured by Oleon;
fluid 6: water based drilling fluid containing 3 wt%
Anderson manufactured by Leonard Andersen with Mobil Oil
composition and PTFE particles;
fluid 7: water based drilling fluid containing G-seal.
The drill string and casing were made of VM 50
steel.
The results of the tests are listed in table 1,
whereby drill string wear and casing wear are indicated
in mm/km which refers to wall thickness reduction (mm)
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per km relative movement between the contact surfaces of
the drill string and the casing.
Table 1
drill string casing wear friction
wear (mm/km) (mm/km) coefficient
fluid 1 0.035 0.47 0.45
fluid 2 0.009 0.09 0.21
fluid 3 0.004 0.03 0.16
fluid 4 0.003 0.05 0.16
fluid 5 0.006 0.06 0.27
fluid 6 0.002 0.03 0.16
fluid 7 0.057 0.41 0.6
Also, tests were performed for various coatings
applied to the outer surface of the drill string, to
determine the effect of the coatings on drill string
wear, casing wear, and friction coefficient between drill
string and casing. The tested drill string coatings were:
coating 1: Victrex coat manufactured by Victrex Peek
Coating (Houston TX, USA);
coating 2: Ruby Red manufactured by Kersten
Kunstofcoating (Netherlands);
coating 3: MC coat manufactured by Metal Coating Corp.
(Coating (Houston TX, USA);
coating 4: Ceram coat manufactured by Freecom INC.
(Coating (Houston TX, USA);
coating 5: Green coat manufactured by Endura Coating
(Warren MI, USA);
coating 6: H329 coat manufactured by Hitemco Southwest
(Coating (Houston TX, USA);
coating 7: T15 coat manufactured by Hitemco Southwest
(Coating (Houston TX, USA);
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coating 8: T90 green manufactured by Hitemco Southwest
(Coating (Houston TX, USA).
The drill string was made of VM 50 steel, and the
casing was made of VM 50 steel. The drilling fluid was
water based and included Bentonite and barite as friction
reducing compounds.
The results of the tests are listed in table 2,
whereby drill string wear and casing wear are indicated
in mm/km which refers to wall thickness reduction (mm)
per km relative movement between the contact surfaces of
the drill string and the casing.
Table 2
drill string casing wear friction
wear (mm/km) (mm/km) coefficient
coating 1 0.02 0.08 0.2
coating 2 0.01 0.02 0.08
coating 3 0.079 0.82 0.3
coating 4 0.06 0.75 0.3
coating 5 0.06 1.1 0.6
coating 6 0.08 1.1 0.31
coating 7 0.055 0.96 0.8
coating 8 0.011 0.3 0.23
The invention will be described hereinafter by way
of example in more detail with reference to the
accompanying drawings, in which:
Fig. 1 schematically shows a wellbore drilled with
an embodiment of the drilling system of the invention;
Fig. 2 schematically shows the wellbore of Fig. 1
during continued drilling of the wellbore; and
Fig. 3 schematically shows the wellbore of Figs. 1
and 2 after drilling is completed.
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Referring to Fig. 1 there is shown a wellbore 1
formed into an earth formation 2 during drilling thereof
using a drill string 4 provided with a drill bit 5. The
drill string 4 extends from a drilling rig 6 at the earth
surface 8 to the bottom 10 of the wellbore 1, and is
provided with a flow passage (not shown) for pumping
drilling fluid from the drilling rig 6 via the flow
passage to the drill bit 5, and from there into the
wellbore 1. An upper portion 12 of the wellbore 1 is
provided with a first steel casing 14 having a lower end
part 15 of increased diameter to receive a second casing
(referred to hereinafter) therein. The first casing 14 is
radially expandable and has a hardened inner surface 16,
with hardness larger than the hardness of the outer
surface of the drill string 4.
The drill string 4 is provided with an outer layer
in the form of a poly-tetra-fluor-ethene (PTFE) coating
18. Suitably the PTFE coating 18 comprises Ruby Red
Teflon marketed as Teflon PFA Coating by Kersten
Kunstofcoating (Netherlands).
In Fig. 2 is shown the wellbore 1 after drilling of
a further section thereof, whereby a second steel casing
20 is arranged below the first casing 14 in the wellbore
1. The second casing 20 extends a short distance into the
lower end part 15 of the first casing 14 to provide a
sealed connection between the two casings 14, 20.
Similarly to the first casing 14, the second casing 20 is
radially expandable and has a hardened inner surface 22,
with hardness larger than the hardness of the outer
surface of the drill string 4. Furthermore, the second
casing 20 has a lower end part 24 of increased diameter
to receive a third casing (referred to hereinafter)
therein.
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In Fig. 3 is shown the wellbore 1 after drilling is
completed, whereby the drilling rig 6 has been replaced
with a wellhead 26. A third casing 28 is arranged below
the second casing 20 in the wellbore 1. The third casing
28 extends a short distance into the lower end part 24 of
the second casing 20 to provide a sealed connection
between the two casings 20, 28. Similarly to the first
and second casings, the third casing 28 is radially
expandable and has a hardened inner surface 30, with
hardness larger than the hardness of the outer surface of
the drill string 4.
During normal operation, the drill string is rotated
by a rotary table (not shown) at the drilling rig 6 to
drill an upper portion of the wellbore 1, whereafter the
drill string is retrieved and the first casing 14 is
installed in the upper wellbore portion.
Subsequently, the wellbore is drilled deeper whereby
the drill string 4 passes through the first casing 14,
and into the new wellbore portion being drilled. A
drilling fluid is simultaneously pumped through the flow
passage of the drill string 4 into the lower portion of
the wellbore 1. The drilling fluid returns to surface
through the annular space 32 formed between the wellbore
wall and the casing 14 on one hand, and the drill string
4 on the other hand. The drilling fluid is provided with
a lubricating compound in the form of vegetable oil to
reduce frictional forces between the rotating drill
string 4, and the casing 14 and wellbore wall.
After the new wellbore portion has been drilled to a
selected depth, the drill string 4 is retrieved to
surface and the second casing 20 is installed in the
newly drilled wellbore portion. The second casing 20
extends a short distance into the lower end part 15 of
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the first casing 14 to provide a sealed connection
between the two casings 14, 20.
In a next step, a further wellbore portion is
drilled whereby the drill string 4 passes through the
first casing 14, the second casing 20, and into the
further wellbore portion being drilled. Drilling fluid is
simultaneously circulated downwardly through the drill
string 4, and upwardly through the annular space 32
between the drill string 4 on one hand, and the wellbore
wall and the casings 14, 20 on the other hand. The
drilling fluid is provided with said vegetable oil to
reduce frictional forces between the rotating drill
string 4, and the casings 14, 20 and wellbore wall.
After the further wellbore portion has been drilled
to a selected depth, the drill string 4 is retrieved to
surface and the third casing 28 is installed below the
second casing 20 in the wellbore 1. The third casing 28
extends a short distance into the lower end part 24 of
the second casing 20 to provide a sealed connection
between the two casings 20, 28.
The above steps are repeated as many times as
required to drill the wellbore 1 to the desired depth.
By virtue of the hardened inner surfaces 16, 22, 30
of the respective casings 14, 20, 28, the PTFE coating on
the outer surface of the drill string 4, and the
lubricating compound in the drilling fluid, it is
achieved that the frictional forces between the drill
string 4 on one hand, and the inner surfaces 16, 22, 30
of the respective casings 14, 20, 28 is minimal.
Moreover, it is achieved that any wear of the inner
surfaces 16, 22, 30 of the respective casings 14, 20, 28
due to contact with the rotating drill string 4, is
limited to a minimum. The latter effect is of particular
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importance since the major part of each casing section
14, 20, 28 does not overlap with any other casing section
during drilling, so that each casing section 14, 20, 28
is exposed to frictional contact with the drill string 4
for prolonged periods of drilling. This is in contrast to
conventional wellbore drilling whereby the casings are
arranged in a nested arrangement with each subsequent
casing extending to surface through a previous casing
which thereby no longer is exposed to frictional forces
from the drill string during further drilling of the
wellbore.
Instead of using a conventional drill string which
is retrieved to surface after drilling the respective
wellbore portions, a drill string can be used that is
transformed into a casing after a selected wellbore
portion has been drilled. Such method is generally
referred to as "casing drilling" or "liner drilling". For
example, the drill string can be formed as an expandable
tubular element that is radially expanded in the newly
drilled wellbore portion to form a casing therein. It is
envisaged that the method of the invention is of
particular interest for these "casing drilling" or "liner
drilling" applications since the drill string (which is
to be transformed into casing) has no radial upsets like
in a conventional drill string, which otherwise can be
designed to minimise friction between the drill string
and the borehole wall/casing, and wear of the casing.
Furthermore, it is envisaged that friction reduction
between drill string and borehole wall/casing is
particularly important for "casing drilling" or "liner
drilling" applications because it helps to reduce the
rotational torque increase due to the relatively large
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diameter of the rotating "casing" or " liner" relative to
the borehole diameter.
