Note: Descriptions are shown in the official language in which they were submitted.
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INVERT EMULSION DRILLING FLUIDS WITH FUMED SILICA
AND METHODS OF DRILLING BOREHOLES
BACKGROUND
1. Field of the Disclosure
[0001] The present
disclosure relates to compositions and methods for drilling,
cementing and casing boreholes in subterranean formations, particularly
hydrocarbon bearing
formations. More particularly, the present disclosure relates to oil or
synthetic fluid based
invert emulsion drilling fluids which combine high ecological compatibility
with good
stability and performance properties. Most particularly, the disclosure
relates to "clay-free"
invert emulsion drilling fluids.
2. Description of Relevant Art
[0002] A drilling
fluid or mud is a specially designed fluid that is circulated through a
wellbore as the wellbore is being drilled to facilitate the drilling
operation. The various
functions of a drilling fluid include removing drill cuttings from the
wellbore, cooling and
lubricating the drill bit, aiding in support of the drill pipe and drill bit,
and providing a
hydrostatic head to maintain the integrity of the wellbore walls and prevent
well blowouts.
Specific drilling fluid systems are selected to optimize a drilling operation
in accordance with
the characteristics of a particular geological formation.
[0003] Oil or
synthetic fluid-based muds are normally used to drill swelling or
sloughing shales, salt, gypsum, anhydrite or other evaporate formations,
hydrogen sulfide-
containing formations, and hot (greater than about 300 degrees Fahrenheit ("
F')) holes, but
may be used in other holes penetrating a subterranean formation as well.
Unless indicated
otherwise, the terms "oil mud" or "oil-based mud or drilling fluid" shall be
understood to
include synthetic oils or other synthetic fluids as well as natural or
traditional oils, and such
oils shall be understood to comprise invert emulsions.
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[0004] Oil-based muds
used in drilling typically comprise: a base oil (or synthetic
fluid) comprising the external phase of an invert emulsion; a saline, aqueous
solution
(typically a solution comprising about 30% calcium chloride) comprising the
internal phase
of the invert emulsion; emulsifiers at the interface of the internal and
external phases; and
other agents or additives for suspension, weight or density, oil-wetting,
fluid loss or filtration
control, and rheology control. Such additives commonly include organophilic
clays and
organophilic lignites. An oil-based or invert emulsion-based drilling fluid
may commonly
comprise between about 50:50 to about 95:5 by volume oil or oleaginous phase
to water or
aqueous phase.
[0005] Recent
technology as described for example in U.S. Patent Nos. 7,462,580 and
7,488,704 to Kirsner, et al., introduced "clay-free" invert emulsion-based
drilling fluids,
which offer significant advantages over drilling fluids containing
organophilic clays. As used
herein, the term "clay-free" (or "clayless") means a drilling fluid made
without addition of
any organophilic clays or lignites to the drilling fluid composition.
[0006] When used in
drilling, "clay-free" invert emulsion drilling fluids have shown
reduced downhole losses, reduced pressure surges and spikes, and less barite
sag than
traditional drilling fluids containing organophilic clay and lignites. Hole
drilling is faster
with "clay-free" invert emulsion drilling fluids and reservoir productivity is
often greater.
[0007] Upon reuse or
mixing with recycled fluids, "clay-free" invert emulsion fluids
often need additives to bolster the theological properties and particularly
the suspension
character of the system. Prior art has indicated that without addition of low
gravity solids,
such as sized calcium carbonate which is not hydrophilic, or similarly non-
hydrophilic clay
type materials having a specific gravity of about 2.2 to about 2.7, aging of
"clay-free" invert
emulsion drilling fluids through reuse can result in loss of suspension
characteristics and
eventually barite sag. In turn, barite sag can result in fracturing of the
formation and drilling
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fluid losses in the fractures. However, in the prior art, addition of low
gravity solids to a
"clay-free" invert emulsion drilling fluid takes away from the advantages the
fluid offers by
being "clay-free." Thus, the addition of such low gravity solids has been
preferably kept to a
minimum in the prior art.
[0008] As used herein,
"low gravity solids" does not refer to drill cuttings or drill
solids, which typically contain clay and/or silica, even if those solids have
a specific gravity
in the range of about 2.2 to about 2.7, and even though drill cuttings and
drill solids may
enter and become part of the fluid during drilling. As used herein, "low
gravity solids" refers
to solid materials (other than silica) such as sized calcium carbonate, ground
marble, or clay
materials such as zeogel, bentonite, attapulgite, and the like that are non-
hydrophilic and that
are deliberately and purposefully added to drilling fluids in preparing the
drilling fluid
composition or during drilling to alter the drilling fluid composition. Thus,
the term "low
gravity solids" as used herein may also be considered to be "low gravity solid
additives" or
"additives comprising low gravity solids."
[0009] Invert emulsion-
based muds or drilling fluids (also called invert drilling muds
or invert muds or fluids) comprise a key segment of the drilling fluids
industry, but they are
increasingly being subjected to greater environmental restrictions and
performance and cost
demands. The complexities and unpredictability of the interaction and behavior
of the fluid
components with each other and with the conditions encountered during drilling
make
meeting these demands challenging.
[0010] There is a
continuing need and thus ongoing industry-wide interest in new
drilling fluids that provide improved performance while still affording
environmental and
economical acceptance. And there is a continuing interest and desire for "clay-
free" invert
emulsion drilling fluids, that are free of low gravity solids such as calcium
carbonate or
4
organophilic clays and clay type solids, but that may be reused and still be
free from barite sag.
SUMMARY
[0010A] In a first aspect provided herein an invert emulsion drilling
fluid for drilling in a
subterranean formation comprising:
an oleaginous continuous phase;
an aqueous internal phase; and
a suspension agent comprising very fine sized fumed silica in combination with
a
primary viscosifier,
wherein the emulsion drilling fluid is substantially free of organophilic
clays and lignites.
[0010B] In a second aspect provided herein a method for drilling in a
subterranean
formation having shales comprising:
providing or using an invert emulsion drilling fluid having:
a base oil;
an internal aqueous phase; and
a suspension agent comprising a combination of a primary viscosifier and very
fine sized fumed silica; and
drilling through shales in the subterranean formation with the drilling fluid,
wherein the emulsion drilling fluid contains substantially no organophilic
clays or
lignites.
[0011] The present disclosure provides an invert emulsion drilling fluid,
and a method
for the use thereof in drilling wellbores. The drilling fluid of the
disclosure comprises a
viscosifier, such as a dimer fatty acid, or dimer fatty amine, or a
pentaerythritol tetrasterarate,
and very fine sized fumed silica, which impart to the fluid improved
suspension properties
sufficient to avoid barite sag without loss of rheological properties. The
fumed silica used in the
disclosure has a high surface area and low particle size and in one embodiment
is hydrophilic. In
one embodiment, the drilling fluid is also "clay-free," that is, it is made
without addition of any
organophilic clays or lignites to the drilling fluid composition.
[0012] As used herein, the term "drilling" or "drilling wellbores"
shall be understood in
the broader sense of drilling operations, which includes running casing and
cementing as well as
drilling, unless specifically indicated otherwise. The method of the
disclosure comprises using
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the drilling fluid of the disclosure in drilling wellbores. During drilling,
the drilling fluid is not
dependent on organophilic clays (also called "organo-clays") to obtain
suspension of drill
cuttings or other solids at rest, and lacks a significant (if any) pressure
spike upon resumption of
drilling, after a period when drilling has temporarily ceased during the
drilling operation.
[0013] In addition to providing the advantages of an organophilic "clay-
free" system, the
drilling fluid of the disclosure shows high pressure, high temperature (HTHP)
stability. While
some organophilic clay may enter the fluid in the field, for example, due to
mixing of recycled
fluids with the fluid of the disclosure, the fluid of the disclosure is
tolerant of such clay in
insubstantial quantities, that is, in quantities less than about three pounds
per barrel. The fluid of
.. the disclosure, however, behaves more like a traditional drilling fluid
when morethan about three
pounds per barrel of organo-clays are present. Similarly, the fluid of the
disclosure is tolerant of
calcium carbonate and other non-hydrophilic "low gravity solids" that may
enter the fluid in
insubstantial quantities.
BRIEF DESCRIPTION OF THE DRAWINGS
[0014] Figure 1 is a graph showing fragile gel formation with one
embodiment of an
invert emulsion drilling fluid of the disclosure (Fluid 3 in Table 1) after
hot rolling at 250 F.
[0015] Figure 2 is a graph showing fragile gel formation in another
embodiment of an
invert emulsion drilling fluid of the disclosure (Fluid 1 in Table 3) after
hot rolling at 300 F.
[0016] Figure 3 is a diagram of a typical drilling fluid system in
which the invert
emulsion drilling fluids of the disclosure may be used.
DETAILED DESCRIPTION OF SOME EMBODIMENTS
[0017] In one embodiment, the present disclosure provides an invert
emulsion drilling
fluid that meets environmental constraints and provides improved performance
in the field with
the lack of barite sag, even at high temperatures and pressures and even after
aging. In this or
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another embodiment, the invert emulsion drilling fluids of the present
disclosure are "clayless"
or "clay-free," meaning that they are made without the addition of
organophilic clays or lignites.
[0018] The invert emulsion drilling fluids for use in one embodiment
of the present
disclosure are mineral oil based systems or mineral oil/paraffin based
systems, such as, for
example, the INNOVERT invert emulsion fluid system, which has a paraffin
and/or mineral oil
base and is available from Baroid Fluid Services, a Halliburton Company, in
Houston, Texas and
Duncan, Oklahoma. An example of a commercially available base oil for use in
the disclosure is
ESCAID 110 desulfurized hydrogenated kerosene oil base from ExxonMobil, USA
in
Houston, Texas and ExxonMobil Chemical Company in Houston, Texas. These base
oils are
environmentally acceptable but other base oils, natural or synthetic, may be
used in other
embodiments. Other examples of base oils may include kerosene, diesel or
esters, either on their
own or in any combination other possible base oils disclosed herein. The
internal phase of the
invert emulsion drilling fluids of the present disclosure typically comprises
an aqueous fluid.
[0019] The invert emulsion drilling fluids of the present disclosure
contain a suspension
agent comprising a primary viscosifier such as: a dimer fatty acid, for
example, commercially
available RHEMOD LTM additive having 36 carbons; a dimer diamine; a dimer
fatty amine, for
example, commercially available BDF 57QTM additive having 36 carbons; or a
pentaerythritol
tetrastearate, for example, commercially available BDF 489TM additive. In one
embodiment the
primary viscosifier may have about 28 to about 48 carbon atoms. In another
embodiment the
primary viscosifier may have about 36 carbon atoms. Each of these commercially
available
products may be obtained from Halliburton Energy Services, Inc. in Houston,
Texas and
Duncan. Oklahoma. Hydrophobic amines such as VERSAM1NE 552 hydrogenated fatty
C36
dimer diamine and VERSAMINE 551 fatty C36 dimer diamine, both available from
Cognis
Corporation of Monheim, Germany and Cincinnati, Ohio, may also be
alternatively used as a
primary viscosifier for invert emulsion drilling fluids of this disclosure.
Other fatty dimer
diamines suitable for use in the invert emulsion drilling fluids of the
present disclosure include
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C28 fatty dimer diamines to C48 fatty dimer diamines which are prepared via
dimerization of the
relevant C14 to C24 fatty acids. Typically, an amount of such viscosifier in
the range of about 1
pound per barrel (ppb) to about 3 ppb is sufficient for purposes of the invert
emulsion drilling
fluids of the disclosure.
[0020] The invert emulsion drilling fluids of the present disclosure
further contain very
fine sized fumed silica as a suspension agent. For purposes of the invert
emulsion drilling fluids
of this disclosure, this fumed silica should have a high surface area,
preferably at least 90m2/g
and most preferably greater than about 90m2/gm up to about 700 m2/gm. in one
embodiment of
the disclosure, the primary viscosifier is used with the very fine sized fumed
silica as a
suspension agent in a ratio of about 1 to about 5 or in a range of about 0.5
ppb to about 3 ppb of
primary viscosifier to about 0.5 ppb to about 15 ppb very fine sized fumed
silica. In another
embodiment, two different grades of silica are used, one with a
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higher surface area than the other, such as, one with an average particle size
of 7 nm or a
specific surface area of 380 m2/gm 380¨for example, AEROSILO 380 hydrophilic
fumed
silica available from Evonik Industries in Germany, Singapore, Japan, and
Parsippany, New
Jersey in the United States¨and one with an average particle size of 0.1-0.3
pm or a surface
area of 17-30 m2/gm¨for example, SILICA FUME hydrophilic fumed silica,
available from
Norchem, Inc. in Hauppage, New York and Fort Pierce, Florida. Generally, the
lower the
surface area of the fumed silica the more fumed silica will be needed. Fumed
silica having a
surface area less than 90 m2/gm may require too high of a concentration to be
effective in the
invert emulsion drilling fluids of this disclosure. While hydrophobic fumed
silica is also
available, hydrophilic fumed silica is preferred for the present disclosure,
even though low
gravity solids traditionally or commonly used in the prior art are not
hydrophilic and are often
hydrophobic and even though hydrophilic fumed silica may enter the internal
phase of the
invert emulsion.
[0021] Silica is
listed in the PLONOR list of additives that can be used in the North
Sea. It is thus environmentally compatible or "eco-friendly." Silica is also
thermally very
stable and thus is reliable for use under high temperature, high pressure
(HTHP) conditions,
as those conditions are commonly understood to one of ordinary skill in the
art.
[0022] Other additives
to comprise a complete drilling fluid may also be used in the
invert emulsion drilling fluids of the present disclosure so long as the
additives do not include
organophilic clays or lignites. Typical additives suitable for use in drilling
fluids of the
present disclosure include, for example: additives to reduce or control
temperature rheology
or to provide thinning, for example, additives having the tradenames
COLDTROLO, ATC ,
and OMC2Tm; additives for enhancing viscosity, for example, an additive having
the
tradename RHEMOD LTM; additives for providing temporary increased viscosity
for shipping
(transport to the well site) and for use in sweeps, for example, an additive
having the
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tradename TEMPERUSTm (modified fatty acid); additives for filtration control,
for example,
additives having the tradename ADAPTA ; additives for high temperature high
pressure
control (HTHP) and emulsion stability, for example, additives having the
tradename
FACTANTrm (highly concentrated tall oil derivative); and additives for
emulsification, for
example, additives having the tradename LE SUPERMULTm (polyaminated fatty
acid) or
emulsifier activators like lime. All of the aforementioned trademarked
products are available
from Halliburton Energy Services, Inc. in Houston, Texas, U.S.A. and Duncan
Oklahoma,
U.S.A. The exact formulations of the invert emulsion drilling fluids of the
disclosure vary
with the particular requirements of the subterranean formation.
[0023] When compared
to invert emulsion drilling fluids commonly used, and when
making such comparisons after aging or recycling, the invert emulsion drilling
fluids of the
present disclosure advantageously afford superior suspension properties and
avoid barite sag
while they are simultaneously environmentally compatible or "eco-friendly."
[0024] Example
formulations of invert emulsion drilling fluids of the disclosure and
results of laboratory tests with same are set forth below to demonstrate the
effectiveness of
these fluids.
Experiments
[0025] Except where
noted otherwise, all products in Table 1 are available from
Halliburton Energy Services, Inc. in Houston, Texas and Duncan Oklahoma,
including:
ADAPTA crosslinked copolymer for HTHP filtration control;
BAROID weighting agent, which is ground barium sulfate;
BDFTm 570 dimer diamine rheology modifier.
EZ MULO NT emulsifier, which is a polyaminated fatty acid;
RHEMODTm L viscosifier, which is a modified fatty acid that is used to provide
suspension
and viscosity in non-aqueous drilling fluids;
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and
ESCA1D O 110 oil, which is a desulfurized hydrogenated kerosene low toxicity
oil
containing less than 0.1% sulfur and less than 1% aromatics, and which is
available from
ExxonMobil Company, U.S.A., Houston, Texas, and ExxonMobil Chemical Company,
Houston, Texas.
[0026] Table 1
provides various formulations of "clay-free" invert emulsion drilling
fluids prepared with ESCAID 110 oil base (comprising desulfurized
hydrogenated
kerosene¨C11-C14 hydrocarbons: n-allcanes, isoalkanes, cyclics, <2%
aromatics), and an
aqueous internal phase. Fluid 1 in Table 1 is a "control" prepared according
to prior art
drilling fluids, that is, an invert emulsion drilling fluid prepared with
ESCALD base oil and
an aqueous internal phase, with a commercially available primary viscosifier
(RHEMODTm L
viscosifier), but without any organophilic clays or lignites and without any
"low gravity
solids." Fluid 2 in Table 1 has the same formulation as Fluid 1 except that
Fluid 2 includes a
commercially available very fine sized hydrophilic fumed silica, AEROSIL 380
funied
silica, having a specific gravity of 2.2, instead of the primary viscosifier,
RHEMODTm L.
Fluid 3 has an example formulation of a fluid of the disclosure, having the
components of
Fluid 1 but also including AEROSIL 380 fumed silica as a suspension agent,
(as well as or
in combination with the primary viscosifier, RHEMODTm L). These 12ppg LGS-free
fluids
were hot rolled at the desired temperature, viz. 250 F in this experiment,
followed by testing
for rheological and suspension characteristics.
[0027] The theological
characteristics of Yield Point (YP) and Plastic Viscosity (PV)
of the invert emulsion drilling fluid were determined on a direct-indicating
rheometer, a
FANN 35 rheometer, powered by an electric motor. The rheometer consists of two
concentric
cylinders, the inner cylinder is called a bob, while the outer cylinder is
called a rotor sleeve.
The drilling fluid sample is placed in a thermostatically controlled cup and
the temperature of
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the fluid is adjusted to 120 ( 2) F. The drilling fluid in the
thermostatically controlled cup is
then placed in the annular space between the two concentric cylinders of the
FANN 35. The
outer cylinder or rotor sleeve is driven at a constant rotational velocity.
The rotation of the
rotor sleeve in the fluid produces a torque on the inner cylinder or bob. A
torsion spring
restrains the movement of the bob, and a dial attached to the bob indicates
displacement of
the bob. The dial readings are measured at different rotor sleeve speeds of 3,
6, 100, 200, 300
and 600 revolutions per minute (rpm). Generally, Yield Point (YP) is defined
as the value
obtained from the Bingham-Plastic rheological model when extrapolated to a
shear rate of
zero. It may be calculated using 300 rpm and 600 rpm shear rate readings as
noted above on
a standard oilfield rheometer, such as a FANN 35 or a FANN 75 rheometer.
Similarly, Yield
Stress or Tau zero is the stress that must be applied to a material to make it
begin to flow (or
yield), and may commonly be calculated from rheometer readings measured at
rates of 3, 6,
100, 200, 300 and 600 rpm. The extrapolation may be performed by applying a
least-squares
fit or curve fit to the Herchel-Bulidey theological model. A more convenient
means of
estimating the Yield Stress is by calculating the Low-Shear Yield Point (LSYP)
by the
formula shown below in Equation 2 except with the 6 rpm and 3 rpm readings
substituted for
the 600-rpm and 300-rpm readings, respectively. Plastic Viscosity (PV) is
obtained from the
Bingham-Plastic theological model and represents the viscosity of a fluid when
extrapolated
to infinite shear rate. The PV is obtained from the 600 rpm and the 300 rpm
readings as given
below in Equation 1. A low PV may indicate that a fluid is capable of being
used in rapid
drilling because, among other things, the fluid has low viscosity upon exiting
the drill bit and
has an increased flow rate. A high PV may be caused by a viscous base fluid,
excess
colloidal solids, or both. The PV and YP are calculated by the following set
of equations:
PV = (600 rpm reading) ¨ (300 rpm reading) (Equation 1)
YP = (300 rpm reading) ¨ PV (Equation 2)
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More particularly, each of the experiments or tests were conducted in
accordance with
standard procedures set forth in Recommended Practice 13B-2, Recommended
Practice for
Field Testing of Oil-based Drilling Fluids, Fourth Edition, American Petroleum
Institute,
March 1, 2005, known to those of ordinary skill in the art.
[0028] The suspension
characteristics were determined by calculating the sag
factors according to the following procedure. Generally, only drilling fluids
and related
treatment fluids that are considered "stable" after performing stability
testing are tested for
the "sag factor" (SF). The fluid to be tested for "sag factor" is placed into
a high-temperature,
high-pressure aging cell. The fluid is then static aged at a specified
temperature for a
specified period of time. The specific gravity (SG) of the fluid is measured
at the top of the
fluid and at the bottom part of the fluid in the aging cell. The sag factor is
calculated using
the following formula: SF = SGbottorn/(SGbottorn + SGtop). A sag factor of
greater than
0.53 indicates that the fluid has a potential to sag; therefore, a sag factor
of less than or equal
to 0.53 is considered to be a good sag factor.
[0029] For a drilling
fluid to exhibit acceptable suspension characteristics for use as a
drilling fluid and to avoid barite sag, the sag factor should be between 0.50
and 0.53, which
allows for some expected and unavoidable settling of solids. A drilling fluid
which has a sag
factor of greater than 0.53 is considered to have inadequate suspension
properties and as
stated above implies that the fluid has potential to sag.
[0030] Thus, Table 1
below provides an example formulation and properties for a
"clay-free," "low-gravity-solids"-free, invert emulsion drilling fluid of the
disclosure (Fluid 3
in Table 1) and compares it to the "control," a "clay-free," "low-gravity-
solids"-free invert
emulsion drilling fluid with a primary viscosifier and without very fine sized
fumed silica
(Fluid 1 in Table 1), and to a formulation using very fine sized fumed silica
as a suspension
agent without the primary viscosifier (Fluid 2 in Table 1). Table 2 provides
an example
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formulation (Fluid 4 in Table 2) and properties for a "clay-free," "low-
gravity-solids"-free,
invert emulsion drilling fluid with a primary yiscosifier and a silica fume
commonly used in
cement and different from the fumed silica used in the invert emulsion
drilling fluids of this
disclosure, with a lower surface area than the fumed silica used in the
example formulation of
the invert emulsion drilling fluids of this disclosure set forth in Table 1.
Table 3 provides
another (different) example formulation (Fluid 5 in Table 3) and properties
for a "clay-free,"
"low-gravity-solids"-free invert emulsion drilling fluid of the disclosure hot
rolled at a
temperature of 300 F instead of at 250 F. This formulation is similar to that
of Fluid 3 in
Table I, except that this formulation (Fluid 5) in Table 3 also includes a
dimer diamine
rheology modifier.
[0031] In determining
the properties set forth in the tables, samples of the fluids were
formulated and sheared at 11,000 rpm to 12,000 rpm on a multimixer for the
times and
concentrations indicated in the tables, and then rolled at 250 F or 300 F as
indicated for 16
hours, and then static aged for 24 hours at 250 F or 300 F. Measurements were
taken with
the fluids at 120 F, except where indicated otherwise. Measurements of SAG
factor and oil
separation as well as rheological properties were taken. Brookfield viscosity
measurements
for fragile gels were also taken.
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Table 1
12 ppg 70/30 OWR
Base
Formulation No. 1 2 3 3
ESCAID@
150.34 151.23 148.84
110,bbl
EZ MUL@ NT,
pph 2 10.00 10.00 10.00
Lime, ppb 2 1.50 Fluid 1.50 Fluid 1.50 Fluid
RHEMODTm Fluid 3
2 was 3 was 5 3.00 1 was 0.00 3.00
L, ppb static ____ static ___ static was
ADAPTA@, aged ..., aged static
2.00 /.00 2.00 aged
PPb @ _________ @ ________ @ aged
AEROSIL 250 F 250 F 250 F @
5 0.00 10.00 10.00 150 F
380, ppb 24 hrs ____ 24 hrs ___ 24 hrs
120 hrs
CaC12, ppb 29.60 29.30 29.30
Water, ppb 5 85.30 84.50 84.50
BAROID@,
222.2 215.40 221.74
ppb
Hot rolled at 250 F, 16 firs
600 rpm 37 34 46 46 81 82
300 rpm 23 20 24 24 , 49 50
200 rpm 18 15 14 15 38 39
100 rpm 12 10 8 8 25 25
6 rpm 4 3 1 1 7 9
_
3 rpm 3 2 1 1 6 9
PV 14 14 22 22 32 32
YP , 9 6 1 2 17 18
LSYP 2 1 1 1 5 9
GELS 10 sec 5 3 1 1 6 8
GELS 10 min . 5 4 1 1 58 50
HTHP,
rn1/30min
(250 F)
Sag factor 0.68 0.68 0.50 0.5
8cm / 7cm /
Oil separation 100m1 95m1 0.2cm 0.2cm
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Table 2
Mixing time, min 4
ESCAID 110,bbl 150.34
EZ MULO NT, ppb 9 10.00
Lime, ppb 2 1.50
Fluid 4
RHEMODTm L, ppb 5 3.00
was
ADAPTA , ppb 5 2.00 static aged
Silica fume, ppb 5 10.00 @250 F
24 hrs
CaCl2, ppb 29.60
Water , ppb 5 85.30
BAROIDO, ppb 10 222.20
Hot rolled at 250 F, 16 hrs
600 rpm @120 F 31
300 rpm @120 F 15
200 rpm @120 F 10
100 rpm @120 F 6
6 rpm @120 F 1
3 rpm @120 F 1
PV @120 F 16
YP @120 F 1
LSYP @120 F 1
GELS 10 sec @120 F 2
GELS 10 min @120 F 2
Sag factor 0.69
Oil separation 10cm /110m1
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Table 3
Mixing
time, 5
min
ESCAID 110,bbl 147.00
EZ MULO NT, ppb 2 10.00
Lime, ppb 2 1.50 Fluid 5
was
RHEMODTm L, ppb 5 3.00 Fluid 5
static aged
ADAPTA , ppb 5 100 @ 300 F was
static aged
AEROSILO 380, ppb 5 10.00 24 hrs
@ 150 F
CaCl2, ppb 29.30 120 hrs
Water , ppb 5 83.53
BAROID , ppb 10 214.96
BDF 5707m, ppb 5 3.00
Hot rolled at 300 F, 16 hrs
@120
600 rpm F 86 99
@120
300 rpm F 58 68
@120
200 rpm 45 54
F
@120
100 rpm F 31 38
@120
6 rpm 9 11
F
@120
3 rpm
F 7 9
@120 28 PV 31
F
@120
YP 30 37
F
@120
LSYP 5 7
F
@120
GELS 10 sec 8 10
F
@120
GELS 10 nun 34 28
F
HTHP, m1/30min
4.0
(250 F)
Sag factor 0.52 0.507
Oil separation 0.5cm/4m1 2m1
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[0032] These
measurements indicate that Fluid 1 in Table 1, formulated without
fumed silica but with a primary modified fatty acid viscosifier, allowed
barite settling, with a
sag factor of 0.68 and oil separation of 8 cm corresponding to 100 ml. Fluid 2
in Table 1,
formulated with fumed silica instead of the primary viscosifier also allowed
barite settling,
with a sag factor of 0.68 and oil separation of 7 cm corresponding to 100 ml.
Fluid 3 in Table
1, an example formulation of the invert emulsion drilling fluids of this
disclosure, with both a
primary viscosifier and fumed silica, was stable, did not indicate barite
settling, and had a sag
factor of 0.5 with negligible oil separation of 0.2 cm. When this fluid was
further static aged
at 150 F for 120 hours, the sag factor was still 0.50 with oil separation of
0.2 cm. When a
similar invert emulsion drilling fluid was formulated according to the
disclosure, Fluid 1 in
Table 3, was hot rolled at 300 F and then static aged at 300 F for 24 hours,
the measurements
as shown in Table 3 indicated that the fluid was stable, without significant
barite sag, with a
sag factor of 0.52 and oil separation of 0.5 cm. When this fluid was further
mixed on a
multimixer for 5 minutes and static aged at 150 F for 120 hours, the fluid
gave an oil
separation of 0.2 cm with a sag factor of 0.507.
[0033] The fluid
formulation shown in Table 2 is generally like that of the invert
emulsion drilling fluids of the disclosure, except that it uses silica fume,
having a lower
surface area than fumed silica, instead of fumed silica. This formulation with
silica fume
resulted in barite settling, with a SAG factor of 0.68 and an oil separation
of 7 cm, indicating
the importance of the size and surface area of the fumed silica in the
effectiveness of the
fumed silica in preventing barite sag.
[0034] The Brookfield
measurements reported in Table 3 were taken to determine the
presence of fragile gels in example invert emulsion drilling fluids formulated
according to the
disclosure¨Fluid 3 in Table 1 and Fluid 1 in Table 3. The measurements showed
that the gel
strengths were progressive as tested on a FANN 35 rheometer, but these gels
were observed
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to be fragile as shown in Figures 1 and 2 respectively. The fragile gel peak
heights were
approximately 20 in both of these invert emulsion fluids of the disclosure. A
peak height
greater than 5 is considered good.
[0035] The
measurements shown in the tables above indicate that the invert emulsion
drilling fluids of the disclosure provide stable invert emulsions and have
good rheological
properties for drilling. Moreover, the invert emulsion drilling fluids of the
disclosure are able
to provide good sag control, that is, the fluids of the disclosure avoid a
tendency toward barite
sag after aging, while still maintaining good fragile gel properties
characteristic of "clay-free"
invert emulsion drilling fluids. The invert emulsion drilling fluids of the
disclosure thus not
only help resolve issues related to barite sag without the addition of
organophilic clays or
lignites or "low gravity solids," but also minimize surge and swab pressures
while tripping in
and out of the borehole. Fumed silica used in the invert emulsion drilling
fluids of the
disclosure has low gravity and is a solid and in this sense is also a low
gravity solid.
However, the term "low gravity solids" as used herein, and as defined
previously herein,
refers to "low gravity solids" in the traditional sense and common manner used
by the oil and
gas industry and does not include fumed silica.
[0036] As indicated
above, the advantages of the methods of the disclosure may be
obtained by employing invert emulsion drilling fluids of the disclosure in
drilling operations.
The drilling operations¨such as, drilling a vertical, directional or
horizontal borehole,
conducting a sweep, or running casing and cementing¨may be conducted as known
to those
skilled in the art with other drilling fluids. That is, a drilling fluid of
the disclosure is
prepared or obtained and circulated through a wellbore as the wellbore is
being drilled (or
swept or cemented and cased) to facilitate the drilling operation. The
drilling fluid removes
drill cuttings from the wellbore, cools and lubricates the drill bit, aids in
support of the drill
pipe and drill bit, and provides a hydrostatic head to maintain the integrity
of the wellbore
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walls and prevent well blowouts. The specific formulation of the drilling
fluid in accordance
with the present disclosure is optimized for the particular drilling operation
and for the
particular subterranean formation characteristics and conditions (such as
temperatures). For
example, the fluid is weighted as appropriate for the formation pressures and
thinned as
appropriate for the formation temperatures. As with other "clayfree" drilling
fluids, the fluids
of the disclosure afford real-time monitoring and rapid adjustment of the
fluid to
accommodate changes in such subterranean formation conditions. Further, the
fluids of the
disclosure may be recycled during a drilling operation such that fluids
circulated in a
wellbore may be recirculated in the wellbore after returning to the surface
for removal of drill
cuttings for example. The drilling fluid of the disclosure may even be
selected for use in a
drilling operation to reduce loss of drilling mud during the drilling
operation and/or to
comply with environmental regulations governing drilling operations in a
particular
subterranean formation.
[0037] The exemplary
suspension agent (drilling fluid additives) disclosed herein
may directly or indirectly affect one or more components or pieces of
equipment associated
with the preparation, delivery, recapture, recycling, reuse, and/or disposal
of the disclosed
additives. For example, and with reference to FIG. 3, the disclosed additives
may directly or
indirectly affect one or more components or pieces of equipment associated
with an
exemplary wellbore drilling assembly 100, according to one or more
embodiments. It should
be noted that while FIG. 3 generally depicts a land-based drilling assembly,
those skilled in
the art will readily recognize that the principles described herein are
equally applicable to
subsea drilling operations that employ floating or sea-based platforms and
rigs, without
departing from the scope of the disclosure.
[0038] As illustrated,
the drilling assembly 100 may include a drilling platform 102
that supports a derrick 104 having a traveling block 106 for raising and
lowering a drill string
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108. The drill string 108 may include, but is not limited to, drill pipe and
coiled tubing, as
generally known to those skilled in the art. A kelly 110 supports the drill
string 108 as it is
lowered through a rotary table 112. A drill bit 114 is attached to the distal
end of the drill
string 108 and is driven either by a downhole motor and/or via rotation of the
drill string 108
from the well surface. As the bit 114 rotates, it creates a borehole 116 that
penetrates various
subterranean formations 118.
[0039] A pump 120
(e.g., a mud pump) circulates drilling fluid 122 through a feed
pipe 124 and to the kelly 110, which conveys the drilling fluid 122 downhole
through the
interior of the drill string 108 and through one or more orifices in the drill
bit 114. The
drilling fluid 122 is then circulated back to the surface via an annulus 126
defined between
the drill string 108 and the walls of the borehole 116. At the surface, the
recirculated or spent
drilling fluid 122 exits the annulus 126 and may be conveyed to one or more
fluid processing
unit(s) 128 via an interconnecting flow line 130. After passing through the
fluid processing
unit(s) 128, a "cleaned" drilling fluid 122 is deposited into a nearby
retention pit 132 (i.e., a
mud pit). While illustrated as being arranged at the outlet of the wellbore
116 via the annulus
126, those skilled in the art will readily appreciate that the fluid
processing unit(s) 128 may
be arranged at any other location in the drilling assembly 100 to facilitate
its proper function,
without departing from the scope of the scope of the disclosure.
[0040] One or more of
the disclosed additives may be added to the drilling fluid 122
via a mixing hopper 134 communicably coupled to or otherwise in fluid
communication with
the retention pit 132. The mixing hopper 134 may include, but is not limited
to, mixers and
related mixing equipment known to those skilled in the art. In other
embodiments, however,
the disclosed additives may be added to the drilling fluid 122 at any other
location in the
drilling assembly 100. In at least one embodiment, for example, there could be
more than
one retention pit 132, such as multiple retention pits 132 in series.
Moreover, the retention
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pit 132 may be representative of one or more fluid storage facilities and/or
units where the
disclosed additives may be stored, reconditioned, and/or regulated until added
to the drilling
fluid 122.
[0041] As mentioned
above, the disclosed additives may directly or indirectly affect
the components and equipment of the drilling assembly 100. For example, the
disclosed
additives may directly or indirectly affect the fluid processing unit(s) 128
which may include,
but is not limited to, one or more of a shaker (e.g., shale shaker), a
centrifuge, a
hydrocyclone, a separator (including magnetic and electrical separators), a
desilter, a
desander, a separator, a filter (e.g., diatomaceous earth filters), a heat
exchanger, any fluid
reclamation equipment, The fluid processing unit(s) 128 may further include
one or more
sensors, gauges, pumps, compressors, and the like used store, monitor,
regulate, and/or
recondition the exemplary additives.
[00421 The disclosed
additives may directly or indirectly affect the pump 120, which
representatively includes any conduits, pipelines, trucks, tubulars, and/or
pipes used to
fluidically convey the additives downhole, any pumps, compressors, or motors
(e.g., topside
or downhole) used to drive the additives into motion, any valves or related
joints used to
regulate the pressure or flow rate of the additives, and any sensors (i.e.,
pressure, temperature,
flow rate, etc.), gauges, and/or combinations thereof, and the like. The
disclosed additives
may also directly or indirectly affect the mixing hopper 134 and the retention
pit 132 and
their assorted variations.
[0043] The disclosed
additives may also directly or indirectly affect the various
downhole equipment and tools that may come into contact with the additives
such as, but not
limited to, the drill string 108, any floats, drill collars, mud motors,
downhole motors and/or
pumps associated with the drill string 108, and any MVVD/I,WD tools and
related telemetry
equipment, sensors or distributed sensors associated with the drill string
108. The disclosed
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additives may also directly or indirectly affect any downhole heat exchangers,
valves and
corresponding actuation devices, tool seals, packers and other wellbore
isolation devices or
components, and the like associated with the wellbore 116. The disclosed
additives may also
directly or indirectly affect the drill bit 114, which may include, but is not
limited to, roller
cone bits, PDC bits, natural diamond bits, any hole openers, reamers, coring
bits, etc.
[0044] While not
specifically illustrated herein, the disclosed additives may also
directly or indirectly affect any transport or delivery equipment used to
convey the additives
to the drilling assembly 100 such as, for example, any transport vessels,
conduits, pipelines,
trucks, tubulars, and/or pipes used to fluidically move the additives from one
location to
another, any pumps, compressors, or motors used to drive the additives into
motion, any
valves or related joints used to regulate the pressure or flow rate of the
additives, and any
sensors (i.e., pressure and temperature), gauges, and/or combinations thereof,
and the like.
[0045] The foregoing
description of the disclosure is intended to be a description of
some embodiments. Various changes in the details of the described fluids and
methods of
use can be made without departing from the intended scope of this disclosure
as defined by
the appended claims.
