U.S. patent application number 11/617031 was filed with the patent office on 2007-05-10 for method of using a sized barite as a weighting agent for drilling fluids.
Invention is credited to Neale Browne, Mukesh Kapilla, JARROD MASSAM.
Application Number | 20070105724 11/617031 |
Document ID | / |
Family ID | 35463439 |
Filed Date | 2007-05-10 |
United States Patent
Application |
20070105724 |
Kind Code |
A1 |
MASSAM; JARROD ; et
al. |
May 10, 2007 |
METHOD OF USING A SIZED BARITE AS A WEIGHTING AGENT FOR DRILLING
FLUIDS
Abstract
An additive that increases the density of fluids containing a
sized barite weighting agent. The wellbore fluid has rheological
properties comparable to conventional wellbore fluids but does not
exhibit problems with sag and resulting variations in density. An
illustrative embodiment is directed to a method for making the
sized barite weighting agent and a method for using such sized
barite weighting agent in a wellbore fluid. In one preferred
embodiment the sized barite weighting agent has a particle diameter
between 4 .mu.m to 15 .mu.m. In another preferred embodiment, the
additive has a D.sub.50 (by weight) of approximately 1 .mu.m to 6
.mu.m. In another preferred embodiment the additive has a D.sub.90
(by weight) of approximately 4 .mu.m to 8 .mu.m. The additive may
be used in any wellbore fluid such as drilling, cementing,
completion, packing, work-over (repairing), stimulation, well
killing, and spacer fluid.
Inventors: |
MASSAM; JARROD; (Aberdeen,
GB) ; Browne; Neale; (Houston, TX) ; Kapilla;
Mukesh; (The Woodlands, TX) |
Correspondence
Address: |
CARTER J. WHITE LEGAL DEPARTMENT;M-I L.L.C.
5950 NORTH COURSE DRIVE
HOUSTON
TX
77072
US
|
Family ID: |
35463439 |
Appl. No.: |
11/617031 |
Filed: |
December 28, 2006 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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11145053 |
Jun 3, 2005 |
7169738 |
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11617031 |
Dec 28, 2006 |
|
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60576420 |
Jun 3, 2004 |
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Current U.S.
Class: |
507/140 |
Current CPC
Class: |
C09K 8/36 20130101; C09K
8/16 20130101; Y10S 507/906 20130101; C04B 20/1022 20130101; C09K
8/032 20130101 |
Class at
Publication: |
507/140 |
International
Class: |
C09K 8/00 20060101
C09K008/00 |
Claims
1. A method of increasing the density of a fluid phase of a
drilling fluid, the method comprising adding to the fluid phase of
the drilling fluid a solid phase weight material for increasing the
density of the drilling fluid, wherein the solid phase weight
material is a particulate material and has a particle size
distribution of at least 50% by weight particles in the range of
about 1 .mu.m to about 5 .mu.m and at least 90% by weight particles
in the range of about 4 .mu.m to about 8 .mu.m.
2. The method of claim 1, wherein the solid phase weight material
is selected from the group consisting of barite, calcite, hematite,
ilmenite or combinations thereof.
3. The method of claim 1, wherein the solid phase weighting
material is barite.
4. The method of claim 1, wherein the fluid phase is an oleaginous
fluid selected from the group consisting of diesel oil, mineral
oil, synthetic oil such as polyolefins or isomerized polyolefins,
ester oils, glycerides of fatty acids, aliphatic esters, aliphatic
ethers, aliphatic acetals, and combinations thereof.
5. The method of claim 1, wherein the fluid phase is an invert
emulsion in which the continuous phase is an oleaginous fluid
selected from the group consisting of diesel oil, mineral oil,
synthetic oil such as polyolefins or isomerized polyolefins, ester
oils, glycerides of fatty acids, aliphatic esters, aliphatic
ethers, aliphatic acetals, and combinations thereof, and the
discontinuous phase is a non-oleaginous fluid selected from the
group consisting of fresh water, seawater, brine containing
inorganic or organic dissolved salts, aqueous solutions containing
water-miscible organic compounds and mixtures of these.
6. The method of claim 1, wherein the drilling fluid further
comprises at least one additional additive selected from the group
consisting of additives for filtration control, additives for high
temperature pressure control, additives for rheology control and
combinations thereof.
7. The method of claim 1, wherein the drilling fluid is used in
drilling operations such that sag is eliminated or avoided.
8. The method of claim 1, wherein the drilling fluid has at least
one property selected from the group consisting of low difference
in surface and downhole equivalent circulating densities, no
significant sag, a generally flat rheology between higher and lower
temperatures.
9. A method of increasing the density of a fluid phase of a
drilling fluid, the method comprising adding to the fluid phase of
the drilling fluid a solid phase weight material for increasing the
density of the drilling fluid, wherein the solid phase weight
material is particulate material and has a cumulative volume
particle distribution such that: <10% is less than 1 .mu.m;
<25% is in the range of 1 .mu.m to 3 .mu.m; <50% is in the
range of 2 .mu.m to 6 .mu.m; <75% is in the range of 6 .mu.m to
10 .mu.m; <90% is in the range of 10 .mu.m to 24 .mu.m.
10. The method of claim 9, wherein the solid phase weight material
is selected from the group consisting of barite, calcite, hematite,
ilmenite, or combinations thereof.
11. The method of claim 9, wherein the solid phase weighting
material is barite.
12. The method of claim 9, wherein the fluid phase is an oleaginous
fluid selected from the group consisting of diesel oil, mineral
oil, synthetic oil such as polyolefins or isomerized polyolefins,
ester oils, glycerides of fatty acids, aliphatic esters, aliphatic
ethers, aliphatic acetals, and combinations thereof.
13. A method of increasing the density of a fluid phase of a
drilling fluid, the method comprising adding to the fluid phase of
the drilling fluid a solid phase weight material for increasing the
density of the drilling fluid, wherein the solid phase weight
material is particulate material and has a particle size
distribution such that: particles having a diameter less than 1
.mu.m are 0 to 15% by volume; particles having a diameter between 1
.mu.m and 4 .mu.m are 14 to 40% by volume; particles having a
diameter between 4 .mu.m and 8 .mu.m are 15 to 30% by volume;
particles having a diameter between 8 .mu.m and 12 .mu.m are 5 to
15% by volume; particles having a diameter between 12 .mu.m and 16
.mu.m are 3 to 7% by volume; particles having a diameter between 16
.mu.m and 20 .mu.m are 0 to 10% by volume; particles having a
diameter greater than 20 .mu.m are 0 to 5% by volume; and wherein
the drilling fluid has at lest one property selected from the group
consisting of low difference in surface and downhole equivalent
circulating densities, no significant sag, a generally flat
rheology between higher and lower temperatures.
Description
[0001] This application is a continuation application of U.S.
application Ser. No. 11/145,053, filed Jun. 3, 2005, which in turn
claims the benefit of U.S. Provisional Application No. 60/576,420,
filed Jun. 3, 2004. Said applications are expressley incorporated
herein by reference in their entireties.
BACKGROUND
[0002] A wellbore fluid serves many important functions throughout
the process in drilling for oil and gas. One such function is
cooling and lubricating the drill bit as it grinds though the
earth's crust. As the drill bit descends, it generates "cuttings,"
or small bits of stone, clay, shale, or sand. A wellbore fluid
serves to transport these cuttings back up to the earth's surface.
As drilling progresses, large pipes called "casings" are inserted
into the well to line the borehole and provide stability. One of
skill in the art should appreciate that these uncased sections of
the borehole, which are exposed to the high pressures of the
reservoir, must be stabilized before casing can be set; otherwise,
a reservoir "kick" or, in the extreme case, a "blowout"--a
catastrophic, uncontrolled inflow of reservoir fluids into the
wellbore--may occur. A wellbore fluid, if monitored properly, can
provide sufficient pressure stability to counter this inflow of
reservoir fluids.
[0003] A critical property differentiating the effectiveness of
various wellbore fluids in achieving these functions is density, or
mass per unit volume. The wellbore fluid must have sufficient
density in order to carry the cuttings to the surface. Density also
contributes to the stability of the borehole by increasing the
pressure exerted by the wellbore fluid onto the surface of the
formation downhole. The column of fluid in the borehole exerts a
hydrostatic pressure (also known as a head pressure) proportional
to the depth of the hole and the density of the fluid. Therefore,
one can stabilize the borehole and prevent the undesirable inflow
of reservoir fluids by carefully monitoring the density of the
wellbore fluid to ensure that an adequate amount of hydrostatic
pressure is maintained.
[0004] It has been long desired to increase the density of wellbore
fluids, and, not surprisingly, a variety of methods exist. One
method is adding dissolved salts such as sodium chloride, calcium
chloride, and calcium bromide in the form of an aqueous brine to
wellbore fluids. Another method is adding inert, high-density
particulates to wellbore fluids to form a suspension of increased
density. These inert, high-density particulates often are referred
to as "weighting agents" and typically include powdered minerals of
barite, calcite, or hematite.
[0005] Naturally occurring barite (barium sulfate) has been
utilized as a weighting agent in drilling fluids for many years.
Drilling grade barite is often produced from barium sulfate
containing ores either from a single source or by blending material
from several sources. It may contain additional materials other
than barium sulfate mineral and thus may vary in color from
off-white to grey or red brown. The American Petroleum Institute
(API) has issued international standards to which ground barite
must comply. These standards can be found in API Specification 13A,
Section 2.
[0006] Other materials, such as finely divided metals, have been
used as weighting agents for wellbore fluids, such as found in PCT
Patent Application WO085/05118, which discloses using iron
ball-shaped particles having a diameter less than 250 .mu.m and
preferably between 15 and 75 .mu.m, and calcium carbonate and iron
carbonate, as disclosed in U.S. Pat. No. 4,217,229, have also been
proposed as weighting agents.
[0007] It is known in the art that during the drilling process
weighting agents, as well as cuttings, can create sedimentation or
"sag" that can lead to a multitude of well-related problems such as
lost circulation, loss of well control, stuck pipe, and poor cement
jobs. The sag phenomenon arises from the settling out of particles
from the wellbore fluid. This settling out causes significant
localized variations in mud density or "mud weight," both higher
and lower than the nominal or desired mud weight. The phenomenon
generally arises when the wellbore fluid is circulating bottoms-up
after a trip, logging or casing run. Typically, light mud is
followed by heavy mud in a bottoms-up circulation.
[0008] Sag is influenced by a variety of factors related to
operational practices or drilling fluid conditions such as:
low-shear conditions, drillstring rotations, time, well design,
drilling fluid formulation and properties, and the mass of
weighting agents. The sag phenomenon tends to occur in deviated
wells and is most severe in extended-reach wells. For drilling
fluids utilizing particulate weighting agents, differential
sticking or a settling out of the particulate weighting agents on
the low side of the wellbore is known to occur.
[0009] Particle size and density determine the mass of the
weighting agents, which in turn correlates to the degree of sag.
Thus it follows that lighter and finer particles, theoretically,
will sag less. However, the conventional view is that reducing
weighting agent particle size causes an undesirable increase in the
fluid's viscosity, particularly its plastic viscosity. Plastic
viscosity is generally understood to be a measure of the internal
resistance to fluid flow that may be attributable to the amount,
type or size of the solids present in a given fluid. It has been
theorized that this increase in plastic viscosity attributable to
the reduction in particle size--and thereby increasing the total
particle surface area--is caused by a corresponding increase in the
volume of fluids, such as water or drilling fluid, adsorbed to the
particle surfaces. Thus, particle sizes below 10 .mu.m have been
disfavored.
[0010] Because of the mass of the weighting agent, various
additives are often incorporated to produce a rheology sufficient
to allow the wellbore fluid to suspend the material without
settlement or "sag" under either dynamic or static conditions. Such
additives may include a gelling agent, such as bentonite for
water-based fluid or organically modified bentonite for oil-based
fluid. A balance exists between adding a sufficient amount of
gelling agent to increase the suspension of the fluid without also
increasing the fluid viscosity resulting in reduced pumpability.
One may also add a soluble polymer viscosifier such as xanthan gum
to slow the rate of sedimentation of the weighting agent.
[0011] Various approaches exist in the art to provide a wellbore
fluid with the desired density with a minimum impact on its fluid
properties, or "rheology." One approach has been disclosed in U.S.
Pat. No. 6,180,573 which involved purposefully removing some or all
of the finest particles from a ground barite (i.e. particles below
6 .mu.m), and then monitoring and maintaining the selected particle
size by adding coarser material as the particle size degrades
during use.
[0012] It is worth noting that, despite the general industry
disfavor, other approaches have used small particles as weighting
agents. One approach, disclosed in U.S. Pat. No. 5,007,480, uses
manganomanganic oxide (Mn.sub.3O.sub.4) having a particle size of
at least 98% below 10 .mu.m in combination with conventional
weighting agents such as API grade barite, which results in a
drilling fluid of higher density than that obtained by the use of
barite or other conventional weighting agents alone. Another
approach is disclosed in EP-A-119 745, which describes an ultra
high-density fluid for blowout prevention comprised of water, a
first and possible second weighting agent, and a gellant made of
fine particles of average diameter between 0.5 and 10 .mu.m. The
gelling agent particles are small enough to impart good static gel
strength to the fluid by virtue of interparticle attractive forces.
Yet another approach is disclosed in U.S. Patent Application
20040127366, the specification of which is incorporated by
reference herein, which discloses a weighting agent having a weight
average particle diameter of less than 1.5 .mu.m and coated with a
dispersant for controlling the interparticle interactions, thereby
minimizing any increase in viscosity incurred by the use of SIZED
particles.
[0013] The need exists to provide a high-density fluid that has an
improved sag performance as compared to conventional fluids, while
maintaining comparable rheological properties.
SUMMARY
[0014] An illustrative embodiment of the claimed subject matter is
generally directed to a sized weighting agent and a wellbore fluid
containing such sized weighting agent that has an increased density
with improved suspension stability without a significant viscosity
increase such that the wellbore fluid has rheological properties
comparable to a conventional wellbore fluid. An illustrative
embodiment of the claimed subject matter is further directed to a
method for making the sized weighting agent and a method for using
such sized weighting agent in a wellbore fluid. In one illustrative
embodiment the sized barite weighting agent has an particle size
distribution such that at least 90% by volume of the measured
particle diameter is between about 4 .mu.m and about 20 .mu.m and
preferably is in the range of about 8 .mu.m to about 16 .mu.m. In
another illustrative embodiment, the sized barite weighting agent
includes at least 50% by volume particles is preferably in the
range of about 1 .mu.m to about 10 .mu.m, and preferably in the
range of about 4 .mu.m to about 8 .mu.m.
BRIEF DESCRIPTION OF THE DRAWING
[0015] The following Description of Illustrative Embodiments makes
reference to the following drawing:
[0016] FIG. 1 Graphically shows the particles size distributions of
the API barite and a barite ground in accordance with the teachings
of the present invention.
DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS
[0017] Contrary to conventional belief, using sized barite
weighting agent in the formulation of a wellbore fluid results in
rheological properties no less favorable than when using coarser
barite weighting material. The fluid formulation techniques as
found in the normal practice of fluid formulations would not
generally change. One would still need to adjust the amounts of
dispersants added depending on the mud weight and density of the
fluid and rheological profile that was required in order to achieve
a suitable mud formulation. One of skill in the art would
appreciate the surprising results demonstrating that wellbore
fluids containing sized barite weighting agents as described herein
actually provide superior sag performance to wellbore fluids
formulated with the well-known coarser barite weighting agents. One
of skill in the art would further appreciate the surprising results
as described herein that the wellbore fluid containing sized barite
weighting agents has no appreciable difference in rheologies as
compared to wellbore fluids formulated with well-known coarser
barite weighting agents. In particular, it has been unexpectedly
and surprisingly found that a sized barite weighting agent
generates high-density suspensions or slurries without the expected
increase in plastic viscosity previously associated with using
finely ground weighting agent particles.
[0018] As previously reported in the art, decreasing barite
weighting agent particle sizes were thought to increase the
viscosity of the fluid, such as reported in "Drilling and Drilling
Fluids," Chilingarian G. V. and Vorabutor P. 1981, pages 441-444.
The reasoning follows, small particles will adsorb significantly
more fluid than larger particles due to their higher surface
area-to-volume ratio, and because of this higher adsorption of
fluid to the surface of the particle, an increase in the viscosity
(that is, a decrease in the fluidity) of the wellbore fluid is
observed. Thus, one of skill in the art should understand that it
has generally been desirable to eliminate fine barite particles in
order to reduce fluid viscosity. This approach to controlling
rheology has been disclosed in U.S. Pat. Nos. 6,180,573 and
6,548,452.
[0019] However, wellbore fluids with coarser, larger-sized barite
weighting agents are generally formulated with higher rheologies
than desired in order to overcome the problematic issue of barite
sag. TABLE 1 shows a typical prior art invert emulsion drilling
fluid formulation that includes an emulsifier(s), organoclay, lime,
and fluid loss additives. As shown in TABLE 1, an internal brine
phase is emulsified into a continuous oil phase by means of a
suitable emulsifier package. The volume of weighting agent can be
adjusted to produce fluids with a range of densities and, although
a preferred weighting agent is barite, it is feasible to
manufacture drilling or other wellbore fluids with other known
minerals such as calcium carbonate, hematite, or ilmenite. As
demonstrated in TABLE 1, various additives typically are used in
order to produce the necessary rheological and filtration
characteristics for the drilling fluid to perform its functions. In
particular, the rheology must be adequate to allow the fluid to
suspend the dense weighting agent without settlement or "sag" under
either dynamic or static conditions. A typical, non-limiting range
of mud weight (MW) is 10-19 lb/gal and an oil to water ratio (OWR)
is 60/40 to 95/5. TABLE-US-00001 TABLE 1 (Prior Art) Typical Invert
Emulsion Drilling Fluid Formulation Typical Product pounds/barrel
Base oil As required Weight Material (i.e. Barite) As required
Emulsifier/s 10-20 Organoclay 2-8 Lime 4-10 Brine As required Fluid
Loss Additive 1-5
[0020] However, the disclosure herein demonstrates that, contrary
to conventional wisdom, one may not need to formulate a wellbore
fluid with higher rheologies than desired to counter the problem of
sag. Instead, the sized barite weighting agent as disclosed herein
may be used with no significant difference in rheology from a
drilling fluid using a known coarser ground material. And by using
a sized barite weighting agent, the particles remain in suspension
and therefore provide a superior sag performance. In view of the
art above, one of skill in the art should immediately appreciate
the surprising and significant results contained herein, which
utilizes barite particles ground to a particle size distribution
such that at least 90% of the cumulative volume of the measured
particle diameters (d.sub.90) is between about 4 .mu.m and about 20
.mu.m and includes at least 50% of the cumulative volume of the
measured particle diameters (d.sub.50) is preferably in the range
of about 1 .mu.m to about 10 .mu.m. As illustrated below such a
wellbore fluid exhibits a reduced plastic viscosity while at the
same time both greatly reducing sedimentation or sag and
maintaining comparable rheologies to other conventional wellbore
fluids.
[0021] In rotary drilling of subterranean wells numerous functions
and characteristics are expected of a drilling fluid. A drilling
fluid should circulate throughout the well and carry cuttings from
beneath the bit, transport the cuttings up the annulus, and allow
their separation at the surface. At the same time, the drilling
fluid is expected to cool and clean the drill bit, reduce friction
between the drill string and the sides of the hole, and maintain
stability in the borehole's uncased sections. The drilling fluid
should also form a thin, low permeability filter cake that seals
openings in formations penetrated by the bit and act to reduce the
unwanted influx of formation fluids from permeable rocks.
[0022] Drilling fluids are typically classified according to their
base material. In oil base fluids, solid particles are suspended in
oil, and water or brine may be emulsified with the oil. The oil is
typically the continuous phase. In water base fluids, solid
particles are suspended in water or brine, and oil may be
emulsified in the water. The water is typically the continuous
phase.
[0023] Invert emulsion fluids, i.e. emulsions in which a
non-oleaginous fluid is the discontinuous phase and an oleaginous
fluid is the continuous phase, are employed in drilling processes
for the development of oil or gas sources, as well as, in
geothermal drilling, water drilling, geoscientific drilling and
mine drilling. Specifically, the invert emulsion fluids are
conventionally utilized for such purposes as providing stability to
the drilled hole, forming a thin filter cake, lubricating the
drilling bore and the downhole area and assembly, and penetrating
salt beds without sloughing or enlargement of the drilled hole.
[0024] Oil-based drilling fluids are generally used in the form of
invert emulsion muds. An invert emulsion mud consists of
three-phases: an oleaginous phase, a non-oleaginous phase and a
finely divided particle phase. Also typically included are
emulsifiers and emulsifier systems, weighting agents, fluid loss
additives, viscosity regulators and the like, for stabilizing the
system as a whole and for establishing the desired performance
properties. Full particulars can be found, for example, in the
article by P. A. Boyd et al entitled "New Base Oil Used in
Low-Toxicity Oil Muds" in the Journal of Petroleum Technology,
1985, 137 to 142 and in the Article by R. B. Bennet entitled "New
Drilling Fluid Technology-Mineral Oil Mud" in Journal of Petroleum
Technology, 1984, 975 to 981 and the literature cited therein. Also
reference is made to the description of invert emulsions found in
Composition and Properties of Drilling and Completion Fluids, 5th
Edition, H. C. H. Darley, George R. Gray, Gulf Publishing Company,
1988, pp. 328-332, the contents of which are hereby incorporated by
reference.
[0025] As used herein the term "oleaginous liquid" means oil which
is a liquid at 25.degree. C. and immiscible with water. Oleaginous
liquids typically include substances such as diesel oil, mineral
oil, synthetic oil such as polyolefins or isomerized polyolefins,
ester oils, glycerides of fatty acids, aliphatic esters, aliphatic
ethers, aliphatic acetals, or other such hydrocarbons and
combinations of these fluids. In one illustrative embodiment of
this invention the oleaginous liquid is an polyolefin material
which provides environmental degradability to the overall drilling
fluid. Such polyolefins should be selected such that the molecular
weight permits for a functional invert emulsion drilling fluid to
be formulated. Especially preferred are isomerized polyolefins
having a carbon backbone of 16 to 18 carbons and in which at least
one point of unstaturation is internal.
[0026] The amount of oleaginous liquid in the invert emulsion fluid
may vary depending upon the particular oleaginous fluid used, the
particular non-oleaginous fluid used, and the particular
application in which the invert emulsion fluid is to be employed.
However, generally the amount of oleaginous liquid must be
sufficient to form a stable emulsion when utilized as the
continuous phase. Typically, the amount of oleaginous liquid is at
least about 30, preferably at least about 40, more preferably at
least about 50 percent by volume of the total fluid.
[0027] As used herein, the term "non-oleaginous liquid" mean any
substance which is a liquid at 25.degree. C. and which is not an
oleaginous liquid as defined above. Non-oleaginous liquids are
immiscible with oleaginous liquids but capable of forming emulsions
therewith. Typical non-oleaginous liquids include aqueous
substances such as fresh water, seawater, brine containing
inorganic or organic dissolved salts, aqueous solutions containing
water-miscible organic compounds and mixtures of these. In one
illustrative embodiment the non-oleaginous fluid is brine solution
including inorganic salts such as calcium halide salts, zinc halide
salts, alkali metal halide salts and the like.
[0028] The amount of non-oleaginous liquid in the invert emulsion
fluid may vary depending upon the particular non-oleaginous fluid
used and the particular application in which the invert emulsion
fluid is to be employed. Typically, the amount of non-oleaginous
liquid is at least about 1, preferably at least about 3, more
preferably at least about 5 percent by volume of the total fluid.
Correspondingly, the amount should not be so great that it cannot
be dispersed in the oleaginous phase. Therefore, typically the
amount of non-oleaginous liquid is less than about 90, preferably
less than about 80, more preferably less than about 70 percent by
volume of the total fluid.
[0029] According to a preferred embodiment, an additive of solid
sized barite particles or sized weighting agents is added to a
wellbore fluid. This generates a high density suspension with
superior sag performance. One of skill in the art would understand
that in addition to the sized particle weighting agents disclosed
herein, one may add any of the known drilling or other wellbore
fluid formulation additives such as emulsifiers, dispersants,
oil-wetters, water-wetters, foamers and defoamers to the fluid
depending on the particular fluid requirements and rheologies
desired.
[0030] A drilling fluid is typically designed based on a number of
technical performance and cost factors. The subject matters
disclosed herein enables the fluid to be tailored to suit the
rheological and sag properties as well as the cost element. The
data reported herein shows that the rheology of the drilling fluid
is largely unaffected by the introduction of sized barite weight
material and that the sag performance of the fluid is directly
related to the particle size of the weight material used.
[0031] As previously noted although a preferred weighting agent is
barite a naturally occurring mineral composed primarily of barium
sulfate. Naturally occurring barite (barium sulfate) has been
utilized as a weighting agent in drilling fluids for many years.
Drilling grade barite is often produced from barium sulfate
containing ores either from a single source or by blending material
from several sources. It may contain additional materials other
than barium sulfate mineral and thus may vary in color from
off-white to grey or red brown. The American Petroleum Institute
(API) has issued international standards to which ground barite
must comply. These standards can be found in API Specification 13A,
Section 2.
[0032] It is feasible to manufacture drilling or other wellbore
fluids with other known minerals such as calcite (calcium
carbonate), hematite (iron oxides), or ilmenite. According to a
preferred illustrative embodiment, the weighting agent is formed of
solid particles that are composed of a material having a specific
gravity of at least 4.2. This allows a wellbore fluid to be
formulated to meet most density requirements yet have a particulate
volume fraction low enough for the fluid to remain pumpable.
[0033] According to one illustrative embodiment, the weight average
particle diameter of the weighting agent measures approximately 4
.mu.m to 15 .mu.m. In another illustrative embodiment, the
weighting agent includes at least 50% by weight particles in the
range of about 1 .mu.m to about 5 .mu.m. And in another
illustrative embodiment, the weighting agent includes at least 90%
by weight particles in the range of about 4 .mu.m to about 8 .mu.m.
As shown in the examples below, use of these particle sizes enables
one to achieve the objective of reducing sedimentation or sag
potential without undesirably increasing the wellbore fluid
viscosity.
[0034] According to another alternative illustrative embodiment the
weighting agent is preferably barite and the sized barite weighting
agent has a particle size distribution such that at least 90% by
volume of the measured particle diameter is between about 4 .mu.m
and about 20 .mu.m and preferably is in the range of about 8 .mu.m
to about 16 .mu.m. In this illustrative embodiment, the sized
barite weighting agent includes at least 50% by volume particles is
preferably in the range of about 1 .mu.m to about 10 .mu.m. and
preferably in the range of about 4 .mu.m to about 8 .mu.m.
[0035] It has been found that a predominance of particles that are
too fine (i.e. below about 1 .mu.m) results in the formation of a
high rheology paste. Thus it has been unexpectedly found that the
barite particles must be sufficiently small to avoid issues of
barite sag and ECD, but not so small as to have an adverse impact
on rheology. Thus barite particles meeting the particle size
distribution criteria disclosed herein may be utilized without
adversely impacting the rheological properties of the wellbore
fluids. In one preferred and illustrative embodiment a barite
weighting agent is sized such that: particles having a diameter
less than 1 .mu.m are 0 to 15% by volume; particles having a
diameter between 1 .mu.m and 4 .mu.m are 15 to 40% by volume;
particles having a diameter between 4 .mu.m and 8 .mu.m are 15 to
30 by volume; particles having a diameter between 8 .mu.m and 12
.mu.m are 5 to 15% by volume; particles having a diameter between
12 .mu.m and 16 .mu.m are 3 to 7% by volume; particles having a
diameter between 16 .mu.m and 20 .mu.m are 0 to 10% by volume;
particles having a diameter greater than 20 .mu.m are 0 to 5% by
volume. In another alternative illustrative embodiment, the barite
weighting agent is sized so that the cumulative volume distribution
is: <10% is less than 1 .mu.m; <25% is in the range of 1
.mu.m to 3 .mu.m; <50% is in the range of 2 .mu.m to 6 .mu.m;
<75% is in the range of 6 .mu.m to 10 .mu.m; <90% is in the
range of 10 .mu.m to 24 .mu.m.
[0036] A person skilled in the art should immediately appreciate
that the particle size distribution of the weighting agents
disclosed herein is considerably finer than API barite. This is
graphically shown in FIG. 1 which shows the particle distributions
of API barite and a barite ground in accordance with the teachings
of the present invention (Barite A).
[0037] One may obtain particles of the dimensions disclosed herein
in several manners. One may purchase, commercially, these sized
particles, such as for example, a suitable barite product having
similar dimensions as disclosed herein. Of course, one may also
obtain a coarser ground suitable material and then proceed to
implement any known technique to further grind the material to the
desired dimensions herein. Such techniques include jet-milling,
high performance dry milling techniques, or any other technique
that is known in the art generally for milling powdered products.
In one preferred embodiment, appropriately sized particles of
barite are selectively removed from the product stream of a
convention barite grinding plant. This may include selectively
removing the fines from a conventional API barite grinding
operation. The fines are often considered a by-product of the
grinding process and conventionally these materials are blended
with courser materials to achieve API grade barite. However, in
accordance with the present disclosure, these by-product fines may
be further process via a air classifier to achieve the particle
size distributions disclosed herein.
[0038] Given the particulate nature of the weighting agents
disclosed herein, one of skill in the art should appreciate that
additional components may be mixed with the weighting agent to
modify various macroscopic properties. For example, anti-caking
agents, lubricating agents, and agents used to mitigate moisture
build-up may be included. Alternatively, solid materials that
enhance lubricity or help control fluid loss may be added to the
weighting agents of the present invention. In one illustrative
examples, finely powdered natural graphite, petroleum coke,
graphitized carbon or mixtures of these are added to enhance
lubricity, rate of penetration and fluid loss as well as other
properties of the drilling fluid. Another illustrative embodiment
utilizes finely ground polymer materials to impart various
characteristics to the drilling fluid. In instances where such
materials are added, it is important to note that the volume of
added material should not have an substantial adverse impact on the
properties and performance of the drilling fluids. In one
illustrative embodiment, polymeric fluid loss materials comprising
less than 5% by weight are added to enhance the properties of the
drilling fluid. Alternatively less than 5% by weight of suitably
sized graphite and petroleum coke are added to enhance the
lubricity and fluid loss properties of the fluid. Finally in
another illustrative embodiment less than 5% by weight of a
conventional anti-caking agent is added to assist in the bulk
storage of the weighting materials.
[0039] The particulate materials as described herein may be added
as a weighting agent in a dry form or concentrated as slurry in
either an aqueous medium or as an organic liquid. As is known, an
organic liquid should have the necessary environmental
characteristics required for additives to oil-based drilling
fluids. With this in mind it is preferred that the oleaginous fluid
have a kinematic viscosity of less than 10 centistokes (10
mm.sup.2/s) at 40.degree. C. and, for safety reasons, a flash point
of greater than 60.degree. C. Suitable oleaginous liquids are for
example diesel oil, mineral or white oils, n-alkanes or synthetic
oils such as alpha-olefin oils, ester oils, mixtures of these
fluids, as well as other similar fluids which should be well known
to one of skill in the art of drilling or other wellbore fluid
formulation. In one illustrative embodiment of the present subject
matters disclosed herein, the desired particle size distribution is
achieve via wet milling of the courser materials in the desired
carrier fluid.
[0040] The particles as described herein may comprise one or a
combination of several known weighting agents. In one illustrative
embodiment, the weighting agent is selected from, but not limited
to, barium sulphate (barite), calcium carbonate, dolomite,
ilmenite, hematite or other iron ores, olivine, siderite, or
strontium sulphate as well as combinations and mixtures of these
and other weighting materials known to one of skill in the art. As
one of skill in the art should realize, many factors may determine
which weighting agent is most appropriate in any given set of
circumstances. Factors such as cost, availability, density, size,
or power required for grinding may influence the choice of product
used.
[0041] The sized particles may further be used in any wellbore
fluid such as drilling, cementing, completion, packing, work-over
(repairing), stimulation, well killing, spacer fluids and other
uses of high density fluids such as in a dense media separating
fluid or in a ship's or other vehicle's ballast fluid. Such
alternative uses, as well as other uses, of the present fluid
should be apparent to one of skill in the art given the present
disclosure.
[0042] The following examples are included to demonstrate
illustrative embodiments of the claimed subject matter; they should
not be construed as limiting the scope of the claimed subject
matter or any claim thereof. Those of skill in the art should
appreciate that the techniques disclosed in the examples that
follow represent techniques discovered by the inventor to function
well in the practice of the claimed subject matter, and thus can be
considered to constitute preferred modes for its practice. However,
in light of the present disclosure, those of skill in the art also
should appreciate that many changes can be made in the specific
disclosed embodiments that still obtain a like or similar result
without departing from the scope of the claimed subject matter.
[0043] All testing was conducted in accordance with American
Petroleum Institute (API) standards. Mixing was performed on a
Silverson L2R Mixer or Hamilton Beach Mixer. The viscosity at
various shear rates (in rotations per minute or rpm's) and other
rheological properties were obtained using a Fann viscometer. Mud
weights were checked using a standard mud scale or an analytical
balance. Fluid loss was measured with a saturated API
high-temperature high-pressure (HTHP) fluid loss cell. The particle
size distributions of the samples were measured on a Malvern
Mastersizer Microplus instrument (by weight measurements) or a
Coulter LS230 (by volume measurements). Dynamic sag measurements
were obtained using a Fann 35 viscometer with a sag shoe insert,
such as disclosed in pending U.S. patent application Ser. No.
10/603849, filed Jun. 25, 2003 and the publication entitled,
"Improved Wellsite Test for Monitoring Barite Sag," AADE Drilling
Fluids Conference, Houston, Tex., Apr. 6-7, 2004, both of which are
incorporated by reference in their entireties. Of course, similar
results would be obtained using Fann 35 viscometer without a sag
shoe insert, and other known methods in the art for measuring
viscosity values. After 30 minutes at a shear rate of 100 rpm at
120.degree. F., measurements were obtained.
[0044] In expressing a metric equivalent, the following U.S. to
metric conversion factors are used: 1 gal=3.785 litres; 1 lb.=0.454
kg; 1 lb/gal=0.1198 g/cm.sup.3; 1 bbl-42 gal; 1 lb/bbl (ppb)=2.835
kg/m.sup.3; 1 lb/100 ft.sup.2=0.4788 Pa.
[0045] In the following illustrative examples, EXMPLE I, II and
III, two weighting agents having different particle size
characteristics were used in the formulation of three drilling
fluids. Two of the drilling fluids have similar densities and
compositions; the third drilling fluid has a density and
composition specifically designed for HTHP application. A
comparison of exemplary performance results for the coarser
weighting agent and the sized weighting agent of one embodiment of
the claimed subject matter is provided in TABLES 2-5 and summarized
below.
EXAMPLE I
[0046] TABLES 2 and 3 show performance data obtained using
substantially similar fluid formulations (MW 13.2 lb/gal and OWR
80/20) and two different barite weighting agents of varying
particle size distribution (PSD), characterized as "coarser" and
"ultra-fine." The coarser PSD is characterized by a D.sub.50 (by
weight) of 7 .mu.m and D.sub.90 (by weight) of 23 .mu.m; the sized
PSD is characterized by D.sub.50 (by weight) of 3 .mu.m and
D.sub.90 (by weight) of 6 .mu.m, however, it should be clear that
the sized PSD is not limited in any manner to these examples
described herein.
[0047] The conventional performance data of TABLE 2 demonstrate
that the rheology of the drilling fluid remains relatively constant
regardless of whether the fluid is formulated with the coarser or
finer barite. In other words, in surprising contrast to the
conventional belief in the art, there is no dramatic increase in
rheological effects due to the introduction of the sized particles
and the concomitant increase in particle-particle interactions.
[0048] Additionally, suitable HTHP filtration properties (ml per 30
minutes), electrical stability, and gel strength, indicating a
suitable mud formulation, were achieved with both the coarser and
finer barite-containing fluids. Electrical Stability (ES) is a
measure of the voltage required to break the emulsion and gives an
indication of the stability of the drilling fluid. It is generally
accepted that the higher the ES value, the more stable the fluid.
Generally, an ES value of 500 or greater indicates a suitable
stability. The ES data shown below indicates stable,
well-emulsified fluids. The rheological property gel strength is
measured when a fluid has been static and has had time to "relax".
Gel strength measurements indicate whether particles within a fluid
have formed an association, giving an indication as to the
suitability of the mud formulation. High gel strength tends to be
undesirable as it means greater shearing stress is necessary to
deform the gel, while low gel strengths are also considered
undesirable due to their poor affinity for solids bearing. The gel
strengths shown are acceptable in that they are not very low and
they are not progressive with time. TABLE-US-00002 TABLE 2
Conventional Performance Data Fluid 1: MW 13.2 lb/gal; OWR 80/20
10'/10'' VG Fann35 Rheology at Gel 120.degree. F.Viscosity at
various shear Strength Weight PSD rates (rpm of agitation) (lb/ ES
HTHP Material (by weight) Fluid 600 300 200 100 6 3 100 ft.sup.2)
(v) @250.degree. F. Coarser D.sub.50 - 7 D.sub.90 - 23 1 46 29 23
16 7 5 7/10 686 3.2 Barite 2 66 39 29 19 7 6 8/12 790 0.8 3 58 35
27 19 7 6 7/11 684 2.4 4 51 30 23 15 6 5 8/8 683 2.8 Finer D.sub.50
- 3 D.sub.90 - 6 1 42 27 21 15 6 5 7/8 749 3.6 Barite 2 66 40 31 20
7 6 7/8 985 1.0 3 60 39 31 21 9 8 9/10 714 3.6 4 50 31 24 17 7 5
6/12 667 3.6
[0049] The data presented in TABLE 3 shows the sag benefits
achievable with the finer barite exemplary of one embodiment of the
claimed subject matter. Over a range of comparable rheologies, the
dynamic and static sag performance of the fluid formulated with the
sized weighting agent is superior to the fluid formulated with the
coarser weighting agent. As shown on TABLE 3, use of the sized
weighting agent results in (1) a lower density difference between
the top and bottom of the fluid column, as demonstrated by a lower
sag index during a static sag test, and (2) a much lower dynamic
sag. This means that using an sized weighting agent, in this case
barite, offers greater scope for fluid optimization in order to
achieve both the desired sag and rheological properties.
TABLE-US-00003 TABLE 3 Sag Performance Data Fluid 1: MW 13.2
lb/gal; OWR 80/20 Dynamic Sag 3 rpm at 120.degree. F. Static Sag
Weight Rheology (lb/gal change after 60 hrs at 250.degree. F.
Material at 120.degree. F. per 30 min) Sag Index Free Oil (ml)
Coarser barite 3 0.598 83 (by weight) 3 0.620 90 D.sub.50 = 7 6
0.99 0.552 28 D.sub.90 = 23 6 1.14 0.561 13 5 1.34 0.550 5 Finer
barite 4 0.07 0.527 60 (by weight) 4 0.00 0.546 44 D.sub.50 = 3 5
0.07 0.522 24 D.sub.90 = 6 8 0.09 0.520 14 6 0.04 0.512 6
[0050] Upon consideration of the above data, one of skill in the
art should appreciate that use of the finer barite resulted in an
observable improvement in the sag index and a dramatic improvement
in the dynamic sag potential with no appreciable change in
rheological properties from those obtained using the coarser
weighting agent. That is to say, the use of fine barite in and of
itself provides a beneficial effect on the sag potential, both
static and dynamic, of the drilling fluid. This is in stark
contrast to what has been the prevalent view in the art on the use
of finer particles in wellbore fluid weighting agents.
EXAMPLE II
[0051] TABLE 4 shows a similar set of data for another fluid having
the same MW 13.2 lb/gal and OWR 80/20 as in Example I above.
However, while the finer PSD remains at D.sub.50 (by weight) of 3
.mu.m and D.sub.90 (by weight) of 6 .mu.m, the coarser PSD is
characterized by a larger diameter D.sub.50 (by weight) of 9 .mu.m
and D.sub.90 (by weight) of 38 .mu.m.
[0052] In this case, as in Example 1, the fluids were found to have
similar rheological profiles, and there was no significant
difference in the gel strengths observed. And in this case, as in
Example I, the dynamic sag performance for the fluid containing the
sized weighting agent significantly exceeds that performance of the
fluid containing the coarser weighting agent. TABLE-US-00004 TABLE
4 Conventional and Dynamic Sag Performance Data Fluid 2: MW 13.2
lb/gal; OWR 80/20 VG Fann35 Rheology at 120.degree. F. 10'/10''
(rpm) Gel Viscosity at various shear rates Strength Dynamic Weight
PSD (rpm of agitation) (lb/ Sag Material (by weight) Fluid 600 300
200 100 6 3 100 ft.sup.2) (dMW) Coarser Barite D.sub.50 - 9
D.sub.90 - 38 Base 56 34 27 18 8 7 7/10 3.17 SIZED Barite D.sub.50
- 3 D.sub.90 - 6 Base 52 34 27 19 9 8 8/12 0.08
EXAMPLE III
[0053] The exemplary data shown in TABLE 5 were obtained for a
so-called HTHP drilling fluid formulation (MW 17 lb/gal and OWR
90/10) using the two different barite-weighting agents, identified
as "coarser" and "finer." As in the preceding example, the coarser
PSD is characterized by D.sub.50 (by weight) of 9 .mu.m and
D.sub.90 (by weight) of 38 .mu.m, and the finer PSD is
characterized by D.sub.50 (by weight) of 3 .mu.m and D.sub.90 (by
weight) of 6 .mu.m. In this case, the effects of contamination are
compared with both fluids. Generally, when a substance, such as
clay, contaminates a wellbore fluid the rheology of the fluid
greatly increases. As demonstrated in Table 5, the rheology of the
fluid containing finer weight material does increase, but not
significantly more than the fluid containing coarser weight
material. TABLE-US-00005 TABLE 5 Conventional and Dynamic Sag
Performance Data Fluid 3: MW 17 lb/gal; OWR 90/10 VG Fann35
Rheology at 10'/10'' 120.degree. F. Gel Viscosity at various shear
Strength Dynamic Weight PSD rates (rpm of agitation) (lb/ Sag
Material (by weight) Fluid 600 300 200 100 6 3 100 ft.sup.2) (dMW)
Coarser D.sub.50 - 9 D.sub.90 - 38 Base 79 42 31 20 7 6 7/21 2.22
Barite 20 ppb OCMA clay 129 71 52 32 8 7 8/37 10 v/v % Seawater 140
83 63 40 13 9 12/33 Finer D.sub.50 - 3 D.sub.90 - 6 Base 66 39 29
19 7 6 10/18 0.02 Barite 20 ppb OCMA clay 126 75 56 36 12 11 17/35
10 v/v % Seawater 102 64 49 34 13 12 16/30
[0054] Once again, the data demonstrate very similar rheological
properties for the two fluid formulations, even after the addition
of non-reactive clay, which was used to simulate the contamination
of drill solids and seawater. And once again, the data clearly show
the superior dynamic sag performance achieved using the finer
barite, rather than the conventionally employed coarser barite, as
the weighting agent.
EXAMPLE IV
[0055] In the following illustrative example, drilling fluid were
formulated utilizing commercially available API grade barite, a
sized barite weighting agent in accordance with the present
disclosure (Barite A), a sized barite weighting agent with a fine
grind distribution (Barite B), and a polymer coated sized barite
weighting agent (Barite C) made in accordance with the disclosure
of published U.S. Application No. 20040127366 the contents of which
are incorporated herein by reference.
[0056] The particle diameter distribution for each weighting agent
was measured on a by volume basis and exemplary data is provided in
FIG. 1. The fluids were formulated to minimize any differences in
chemistry for formulation except for the weighting agent. All of
the fluids had an identical Synthetic Oil (C16 to C18 internal
olefin) to Water ratio of 80 to 20 and an overall density of 13
ppb. The following Table 6 provides the specifics of the fluid
formulations: TABLE-US-00006 TABLE 6 API Fluid Formulation Barite
Barite A Barite B Barite C IO C16-C18 (base fluid) As required VG
PLUS, ppb 1.70 1.70 1.70 1.70 VG SUPREME, ppb 0.80 0.80 0.80 0.80
Lime, ppb 3.0 3.0 3.0 3.0 SUREMUL, ppb 7.0 7.0 7.0 7.0 SUREWET, ppb
2.0 2.0 2.0 2.0 Brine 25% wgt CaCl.sub.2, 18.04 18.04 18.04 11.95
ppb* Water, bbl 0.145 0.145 0.145 0.095 ECOTROL, ppb 0.50 0.50 0.50
0.50 Weighting Agent, ppb 283.01 283.01 283.01 375.98 Drill solids,
ppb** 15.0 15.0 15.0 15.0 RHEFLAT, ppb 1.25 1.25 1.25 1.25 RHETHIK,
ppb 0.75 0.75 0.75 0.75
[0057] The base fluids were mixed in the order listed on a
Silverson mixer at 6000 rpm over an hour while maintaining the
temperature below 150.degree. F.
[0058] In formulating the above fluids the following commercially
available products all available from M-I SWACO, Houston Tex. were
utilized: TABLE-US-00007 Material VG PLUS, ppb Organophilic
bentonite clay VG SUPREME, ppb Organophilic bentonite clay SUREMUL,
ppb Fatty acid based emulsifier SUREWET, ppb Amido-amine based
wetting agent ECOTROL, ppb Polymeric fluid lose control agent
RHEFLAT, ppb Proprietary mixture of poly fatty acids RHETHIK, ppb
Polymeric Thickening agent
[0059] The simulated drill solids used were from Petrohunt,
Marcantal #1-LM#20043541. The solids were ground up and used in
lieu of lab contaminates such as Rev Dust or OCMA Clay.
[0060] It should be noted that attempts to formulate a drilling
fluid utilizing Barite B were unsuccessful and resulted in a fluid
having paste like consistency. Thus it was not possible to obtain
meaningful rheological properties. One of skill in the art would
immediately understand and appreciate that such a formulation is
not useful as a wellbore fluid using current state of the art
drilling practices and methods.
[0061] The following Table 7 provides exemplary rheological data
for each mud formulation. TABLE-US-00008 TABLE 7 Initial Rheology
API Mud Barite Properties Initial Barite A Barite C Oil:Water 80:20
80:20 80:20 Ratio Mud 13.0 13.0 13.0 Weight, ppg Rheo 40 100 150 40
100 150 40 100 150 Temp, .degree. F. 600 rpm 118 72 58 120 74 58
140 65 48 300 rpm 69 45 39 72 49 40 80 40 30 200 rpm 51 35 30 55 40
35 56 30 23 100 rpm 32 24 21 32 30 27 33 18 15 6 rpm 11 12 11 16 17
17 5 4 4 3 rpm 10 11 11 16 17 17 4 4 4 PV, cps 49 27 19 48 25 18 60
25 18 YP, lbs/100 ft.sup.2 20 18 20 24 24 22 20 15 12 10 Second 12
13 13 19 20 18 4 3 4 Gel 10 Minute 39 31 36 36 40 33 37 30 36 Gel
HTHP @ 3.4 3.6 4.0 250.degree. F., ml E.S., Vts @ 782 891 1060
120.degree. F.
[0062] A sample of each initial mud formulation was subjected
rolling heat aging at 150 F for 16 hours. The following Table 8
provides exemplary rheological data for each mud formulation.
TABLE-US-00009 TABLE 8 Rheology After Dynamic (Rolling) Heat Aging
at 150.degree. F. for 16 hours API Mud Barite Properties AHR Barite
A Barite C Oil:Water 80:20 80:20 80:20 Ratio Mud 13.0 13.0 13.0
Weight, ppg Rheo 40 100 150 40 100 150 40 100 150 Temp, .degree. F.
600 rpm 157 74 55 110 91 63 150 94 63 300 rpm 89 44 35 68 56 41 89
54 37 200 rpm 65 34 26 50 43 32 58 38 28 100 rpm 40 22 18 34 28 23
30 21 16 6 rpm 13 10 10 14 12 12 5 5 5 3 rpm 12 10 10 13 11 11 5 4
4 PV, cps 68 30 20 42 35 22 61 40 26 YP, lbs/100 ft.sup.2 21 14 15
26 21 19 28 14 11 10 Second 12 15 13 23 23 22 6 4 7 Gel 10 Minute
34 31 30 39 36 32 24 21 15 Gel HTHP @ 4.2 6.8 5.4 250.degree. F.,
ml E.S., Vts @ 398 523 798 120.degree. F.
[0063] A sample of each initial mud formulation was contaminated
with an additional 3% drill solids mixed on a Hamilton Beach mixer.
The simulated drill solids used were from Petrohunt, Marcantal
#1-LM#20043541. The solids were ground up and used in lieu of lab
contaminates such as Rev Dust or OCMA Clay. These fluids were
subjected rolling heat aging at 150 F for 16 hours. The following
Table 9 provides exemplary rheological data for each mud
formulation. TABLE-US-00010 TABLE 9 Rheology After Dynamic
(Rolling) Heat Aging at 150.degree. F. for 16 hours with 3% wgt
additional drill solids Mud API Properties Barite Barite A Barite C
Oil:Water 80:20 80:20 80:20 Ratio Mud 13.0 13.0 13.0 Weight, ppg
Rheo 40 100 150 40 100 150 40 100 150 Temp, .degree. F. 600 rpm 173
82 57 131 106 72 152 98 65 300 rpm 95 48 34 78 63 44 88 53 36 200
rpm 69 36 26 54 47 34 50 37 26 100 rpm 42 23 19 34 31 24 27 20 15 6
rpm 11 10 10 14 12 11 5 3 3 3 rpm 11 9 9 13 11 11 4 3 3 PV, cps 77
34 23 53 43 28 64 45 29 YP, lbs/100 ft.sup.2 19 14 11 25 20 16 24 8
7 10 Second 12 12 13 21 20 22 4 3 4 Gel 10 Minute 38 32 30 34 37 33
29 23 27 Gel HTHP @ 5.0 8.0 7.0 250.degree. F., ml E.S., Vts @ 404
600 705 120.degree. F.
[0064] A sample of each initial mud formulation was contaminated
with an additional 3% drill solids mixed on a Hamilton Beach mixer.
The simulated drill solids used were from Petrohunt, Marcantal
#1-LM#20043541. The solids were ground up and used in lieu of lab
contaminates such as Rev Dust or OCMA Clay. These fluids were
subjected static heat aging at 150 F for 16 hours. The following
Table 10 provides exemplary rheological data for each mud
formulation. TABLE-US-00011 TABLE 10 After Static Heat Aging at
250.degree. F. for 16 hours Mud Properties API Barite A Barite C
Oil:Water Ratio 80:20 80:20 80:20 Mud Weight, ppg 13.0 13.0 13.0
Rheo Temp, .degree. F. 150 150 150 600 rpm 49 43 47 300 rpm 30 28
30 200 rpm 22 21 22 100 rpm 15 15 14 6 rpm 8 8 5 3 rpm 8 8 5 PV,
cps 19 15 17 YP, lbs/100 ft.sup.2 11 13 13 10 Second Gel 11 15 5 10
Minute Gel 26 24 11
[0065] The variation in the mud weight (.DELTA.MW) for the
statically aged drilling fluid was measured by carefully extracting
samples of the fluid from the top, middle and bottom of the static
fluid. The following Table 11 provides exemplary results.
TABLE-US-00012 TABLE 11 Variation In The Mud Weight (.DELTA.MW) For
The Statically Aged Drilling Fluid .DELTA.MW - Static API Barite A
Barite C Top, ppg 12.92 13.0 13.01 Middle, ppg 13.12 13.12 13.10
Bottom, ppg 14.2 13.21 13.20
[0066] Upon review of the above data, one of skill in the art
should understand and appreciate that a useful wellbore fluid can
be formulated using a sized barite weighting agent that has a
particle size distribution well below the API standard. It should
also be appreciated that by controlling the particle size
distribution of the barite weighting agent of the present
disclosure, rheology can be controlled and a useful wellbore fluid
can be formulated which is in direct contrast to the teachings of
the prior art. Further, it has been unexpectedly found that
drilling fluids formulated with the sized barite weighting agent of
the present disclosure do not exhibit the dynamic and static sag
properties present in fluids formulated with API grade barite.
[0067] One of skill in the art of drilling or other wellbore fluid
formulation will appreciate that it has been the general
understanding that decreasing the particle size in weighting agents
leads to a corresponding increase in viscosity, which is
undesirable in the industry. This was shown in the above example
with a paste forming when using size Barite B. However, as
supported by the above data, the use of sized barite weighting
agent as disclosed herein does not in fact lead to any appreciable
difference in rheological properties from those obtained with
coarser ground weighting agents. And in fact, as supported by the
above data, the use of sized weighting agent results in substantial
and observable improvements in both the static and dynamic sag
potentials of a wellbore fluid.
[0068] In view of the above disclosure, a person skilled and
knowledgeable in the art of drilling fluids should understand and
appreciate that one illustrative embodiment of the present
disclosure is a drilling fluid comprising a fluid phase and a solid
phase weight material for increasing the density of the drilling
fluid in which the weight material is a ground particulate material
and has a particle size distribution of at least 50% by weight
particles in the range of about 1 .mu.m to about 5 .mu.m and at
least 90% by weight particles in the range of about 4 .mu.m to
about 8 .mu.m. In one preferred embodiment of the illustrative
fluid the solid phase weight material is selected from the group
including barite, calcite, hematite, ilmenite or combinations
thereof and other similar material well know to one of skill in the
art. The exemplary drilling fluid may be formulated such that the
fluid phase is an oleaginous fluid selected from diesel oil,
mineral oil, synthetic oil such as polyolefins or isomerized
polyolefins, ester oils, glycerides of fatty acids, aliphatic
esters, aliphatic ethers, aliphatic acetals, and combinations
thereof and other similar material well know to one of skill in the
art. Alternatively, the illustrative drilling fluid is formulated
to include a fluid phase that is an invert emulsion in which the
continuous phase is an oleaginous fluid selected from diesel oil,
mineral oil, synthetic oil such as polyolefins or isomerized
polyolefins, ester oils, glycerides of fatty acids, aliphatic
esters, aliphatic ethers, aliphatic acetals, and combinations
thereof and other similar material well know to one of skill in the
art; and the discontinuous phase is a non-oleaginous fluid selected
from fresh water, seawater, brine containing inorganic or organic
dissolved salts, aqueous solutions containing water-miscible
organic compounds and mixtures of these and other similar material
well know to one of skill in the art. Additional additives such as
those selected from additives for filtration control, additives for
high temperature pressure control, additives for rheology control
and combinations thereof and other similar material well know to
one of skill in the art, may optionally be included in the
illustrative drilling fluid. A unique characteristic of the
illustrative drilling fluid is that when the drilling fluid is used
in drilling operation such that sag is eliminated or avoided.
[0069] Another illustrative drilling fluid comprising a fluid phase
and a solid phase weight material for increasing the density of the
drilling fluid, wherein the weight material is a ground particulate
material and has a particle size distribution such that: particles
having a diameter less than 1 .mu.m are 0 to 15% by volume;
particles having a diameter between 1 .mu.m and 4 .mu.m are 15 to
40% by volume; particles having a diameter between 4 .mu.m and 8
.mu.m are 15 to 30 by volume; particles having a diameter between 8
.mu.m and 12 .mu.m are 5 to 15% by volume; particles having a
diameter between 12 .mu.m and 16 .mu.m are 3 to 7% by volume;
particles having a diameter between 16 .mu.m and 20 .mu.m are 0 to
10% by volume; particles having a diameter greater than 20 .mu.m
are 0 to 5% by volume. A third illustrative drilling fluid is
formulated to include a fluid phase and a solid phase weight
material for increasing the density of the drilling fluid, wherein
the solid phase weight material is a ground particulate material
and has a cumulative volume particle distribution such that <10%
is less than 1 .mu.m; <25% is in the range of 1 .mu.m to 3
.mu.m; <50% is in the range of 2 .mu.m to 6 .mu.m; <75% is in
the range of 6 .mu.m to 10 .mu.m; <90% is in the range of 10
.mu.m to 24 .mu.m. In both the two preceding illustrative fluids,
the solid phase weight material is selected from barite, calcite,
hematite, ilmenite or combinations thereof, but is preferably
barite. Optionally the fluid phase of the illustrative drilling
gluids may be an oleaginous fluid selected from diesel oil, mineral
oil, synthetic oil such as polyolefins or isomerized polyolefins,
ester oils, glycerides of fatty acids, aliphatic esters, aliphatic
ethers, aliphatic acetals, and combinations thereof and other
similar material well know to one of skill in the art.
[0070] The present disclosure also encompasses a method of drilling
a subterranean well utilizing a drilling fluids as substantially
described herein. In one such illustrative embodiment, conventional
rotary drilling operation are carried out utilizing a drilling
fluid that is formulated to include a fluid phase and a solid phase
weight material for increasing the density of the drilling fluid,
wherein the weight material is a particulate material and has a
particle size distribution of at least 50% by weight particles in
the range of about 1 .mu.m to about 5 .mu.m and at least 90% by
weight particles in the range of about 4 .mu.m to about 8 .mu.m.
The method is preferably carried out using a the solid phase weight
material selected from barite, calcite, hematite, ilmenite or
combinations thereof. and other similar material well know to one
of skill in the art, but preferably the solid phase weighting
material is barite.
[0071] It should also be appreciated that the present disclosure
encompasses a method of drilling a subterranean well utilizing a
drilling fluid, wherein the drilling fluid is formulated to include
a fluid phase and a solid phase weight material for increasing the
density of the drilling fluid, wherein the weight material is a
particulate material and has a particle size distribution such
that: particles having a diameter less than 1 .mu.m are 0 to 15% by
volume; particles having a diameter between 1 .mu.m and 4 .mu.m are
15 to 40% by volume; particles having a diameter between 4 .mu.m
and 8 .mu.m are 15 to 30 by volume; particles having a diameter
between 8 .mu.m and 12 .mu.m are 5 to 15% by volume; particles
having a diameter between 12 .mu.m and 16 .mu.m are 3 to 7% by
volume; particles having a diameter between 16 .mu.m and 20 .mu.m
are 0 to 10% by volume; particles having a diameter greater than 20
.mu.m are 0 to 5% by volume. Alternatively the present disclosure
encompasses an illustrative embodiment in which a method of
drilling a subterranean well utilizing a drilling fluid, wherein
the drilling fluid comprises a fluid phase and a solid phase weight
material for increasing the density of the drilling fluid, wherein
the solid phase weight material is particulate and has a cumulative
volume particle distribution such that <10% is less than 1
.mu.m; <25% is in the range of 1 .mu.m to 3 .mu.m; <50% is in
the range of 2 .mu.m to 6 .mu.m; <75% is in the range of 6 .mu.m
to 10 .mu.m; <90% is in the range of 10 .mu.m to 24 .mu.m.
[0072] In addition, one of skill in the art should appreciate that
a method of increasing the density of a fluid phase of a drilling
fluid is also an illustrative embodiment of the present disclosure.
One such illustrative includes adding to the fluid phase of the
drilling fluid a solid phase weight material for increasing the
density of the drilling fluid, wherein the solid phase weight
material is a particulate material and has a particle size
distribution of at least 50% by weight particles in the range of
about 1 .mu.m to about 5 .mu.m and at least 90% by weight particles
in the range of about 4 .mu.m to about 8 .mu.m. Alternatively, the
illustrative method may involve increasing the density of the
drilling fluid, wherein the solid phase weight material is
particulate material and has a particle size distribution such
that: particles having a diameter less than 1 .mu.m are 0 to 15% by
volume; particles having a diameter between 1 .mu.m and 4 .mu.m are
15 to 40% by volume; particles having a diameter between 4 .mu.m
and 8 .mu.m are 15 to 30 by volume; particles having a diameter
between 8 .mu.m and 12 .mu.m are 5 to 15% by volume; particles
having a diameter between 12 .mu.m and 16 .mu.m are 3 to 7% by
volume; particles having a diameter between 16 .mu.m and 20 .mu.m
are 0 to 10% by volume; particles having a diameter greater than 20
.mu.m are 0 to 5% by volume. Yet a third variation to the disclosed
illustrative methods is a method of increasing the density of a
fluid phase of a drilling fluid, the method comprising adding to
the fluid phase of the drilling fluid a solid phase weight material
for increasing the density of the drilling fluid, wherein the solid
phase weight material is particulate material and has a cumulative
volume particle distribution such that: <10% is less than 1
.mu.m; <25% is in the range of 1 .mu.m to 3 .mu.m; <50% is in
the range of 2 .mu.m to 6 .mu.m; <75% is in the range of 6 .mu.m
to 10 .mu.m; <90% is in the range of 10 .mu.m to 24 .mu.m.
[0073] All of the methods and compositions disclosed and claimed
herein can be made and executed without undue experimentation in
light of the present disclosure. While the methods and compositions
disclosed herein have been described in terms of preferred
embodiments, it will be apparent to those of skill in the art that
variations may be applied to the methods, and in the steps or in
the sequence of steps of the methods described herein and to the
compositions and in the components of the compositions described
herein. More specifically, it will be apparent that certain agents
which are both chemically and physiologically related may be
substituted for the agents described herein while the same or
similar results would be achieved. All such similar substitutes and
modifications apparent to those skilled in the art are deemed to be
within the scope and concept of the claimed subject matter as
defined by any appended claims.
* * * * *