Note: Descriptions are shown in the official language in which they were submitted.
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PATENT APPLICATION
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CLIENT REF. NO. 81057005US01
NON-TOXIC, SHALE INHIBITIVE WATER-BASED WELLBORE FLUID
BACKGROUND OF INVENTION
Field of the Invention
[00011 Embodiments disclosed herein relate generally to shale hydration
inhibition
agents for use in water-based wellbore fluid. In particular, embodiments
disclosed herein
relate to natural amine shale hydration inhibition agents in wellbore fluids
and their use in
wellbore operations.
Background Art
[00021 To facilitate the drilling of a well, fluid is circulated through the
drill string, out
the bit and upward in an annular area between the drill string and the wall of
the
borehole. Common uses for well fluids include: lubrication and cooling of
drill bit
cutting surfaces while drilling generally or drilling-in (i.e., drilling in a
targeted
petroliferous formation), transportation of "cuttings" (pieces of formation
dislodged by
the cutting action of the teeth on a drill bit) to the surface, controlling
formation fluid
pressure to prevent blowouts, maintaining well stability, suspending solids in
the well,
minimizing fluid loss into and stabilizing the formation through which the
well is being
drilled, fracturing the formation in the vicinity of the well, displacing the
fluid within the
well with another fluid, cleaning the well, testing the well, transmitting
hydraulic
horsepower to the drill bit, fluid used for emplacing a packer, abandoning the
well or
preparing the well for abandonment, and otherwise treating the well or the
formation.
[00031 Drilling fluids are typically classified according to their base
material. The
selection of the type of drilling fluid to be used in a drilling application
involves a careful
balance of both the good and bad characteristics of the drilling fluids in the
particular
application and the type of well to be drilled. In oil-based fluids, solid
particles are
suspended in oil (the continuous phase), and water or brine may be emulsified
with the
oil. In water-based fluids, solid particles are suspended in water or brine
(continuous
phase) including solid particles such as 1) clays and organic colloids added
to provide
necessary viscosity and filtration properties; 2) heavy minerals whose
function is to
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increase the drilling fluid's density; and 3) formation solids that become
dispersed in the
drilling fluid during the drilling operation. Historically, water based
drilling fluids have
been used to drill a majority of wells. Their lower cost and better
environment acceptance
as compared to oil based drilling fluids continue to make them the first
option in drilling
operations. However, as mentioned above, the selection of a fluid frequently
may depend
on the type of formation through which the well is being drilled. Where the
formation
solids are clay minerals that swell, the presence of either type of formation
solids in the
drilling fluid can greatly increase drilling time and costs.
[0004] The types of subterranean formations, intersected by a well, which may
be at least
partly composed of clays, including shales, mudstones, siltstones, and
claystones. In
penetrating through such formations, many problems may be encountered
including bit
balling, swelling or sloughing of the wellbore, stuck pipe, and dispersion of
drill cuttings.
This may be particularly true when drilling with a water-based fluid due to
the high
reactivity of clay in an aqueous environment.
[0005] Clay minerals are generally crystalline in nature. The structure of a
clay's crystals
determines its properties. Typically, clays have a flaky, mica-type structure.
Clay flakes
are made up of a number of crystal platelets stacked face-to-face. Each
platelet is called a
unit layer, and the surfaces of the unit layer are called basal surfaces. Each
unit layer is
composed of multiple sheets, which may include octahedral sheets and
tetrahedral sheets.
Octahedral sheets are composed of either aluminum or magnesium atoms
octahedrally
coordinated with the oxygen atoms of hydroxyls, whereas tetrahedral sheets
consist of
silicon atoms tetrahedrally coordinated with oxygen atoms.
[0006] Sheets within a unit layer link together by sharing oxygen atoms. When
this
linking occurs between one octahedral and one tetrahedral sheet, one basal
surface
consists of exposed oxygen atoms while the other basal surface has exposed
hydroxyls. It
is also quite common for two tetrahedral sheets to bond with one octahedral
sheet by
sharing oxygen atoms. The resulting structure, known as the Hoffman structure,
has an
octahedral sheet that is sandwiched between the two tetrahedral sheets. As a
result, both
basal surfaces in a Hoffman structure are composed of exposed oxygen atoms.
The unit
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layers stack together face-to-face and are held in place by weak attractive
forces. The
distance between corresponding planes in adjacent unit layers is called the d-
spacing. A
clay crystal structure with a unit layer consisting of three sheets typically
has a d-spacing
of about 9.5x10"7 mm.
[0007] In clay mineral crystals, atoms having different valences commonly will
be
positioned within the sheets of the structure to create a negative potential
at the crystal
surface, which causes cations to be adsorbed thereto. These adsorbed cations
are called
exchangeable cations because they may chemically trade places with other
cations when
the clay crystal is suspended in water. In addition, ions may also be adsorbed
on the clay
crystal edges and exchange with other ions in the water.
[0008] The type of substitutions occurring within the clay crystal structure
and the
exchangeable cations adsorbed on the crystal surface greatly affect clay
swelling, a
property of primary importance in the drilling fluid industry. Clay swelling
is a
phenomenon in which water molecules surround a clay crystal structure and
position
themselves to increase the structure's d-spacing thus resulting in an increase
in volume.
Two types of swelling may occur: surface hydration and osmotic swelling.
[0009] Surface hydration is one type of swelling in which water molecules are
adsorbed
on crystal surfaces. Hydrogen bonding holds a layer of water molecules to the
oxygen
atoms exposed on the crystal surfaces. Subsequent layers of water molecules
align to
form a quasi-crystalline structure between unit layers, which results in an
increased d-
spacing. Virtually all types of clays swell in this manner.
[00101 Osmotic swelling is a second type of swelling. Where the concentration
of
cations between unit layers in a clay mineral is higher than the cation
concentration in the
surrounding water, water is osmotically drawn between the unit layers and the
d-spacing
is increased. Osmotic swelling results in larger overall volume increases than
surface
hydration. However, only certain clays, like sodium montmorillonite, swell in
this
manner.
[0011] Exchangeable cations found in clay minerals are reported to have a
significant
impact on the amount of swelling that takes place. The exchangeable cations
compete
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with water molecules for the available reactive sites in the clay structure.
Generally
cations with high valences are more strongly adsorbed than ones with low
valences.
Thus, clays with low valence exchangeable cations will swell more than clays
whose
exchangeable cations have high valences.
[0012] Clay swelling during the drilling of a subterranean well can have a
tremendous
adverse impact on drilling operations. The overall increase in bulk volume
accompanying clay swelling impedes removal of cuttings from beneath the drill
bit,
increases friction between the drill string and the sides of the borehole, and
inhibits
formation of the thin filter cake that seals formations. Clay swelling can
also create other
drilling problems such as loss of circulation or stuck pipe that slow drilling
and increase
drilling costs. Thus, given the frequency in which gumbo shale is encountered
in drilling
subterranean wells, the development of a substance and method for reducing
clay
swelling remains a continuing challenge in the oil and gas exploration
industry.
[0013] One method to reduce clay swelling is to use salts in drilling fluids.
Salts
generally reduce the swelling of clays; however, salts can flocculate the
clays resulting in
both high fluid losses and an almost complete loss of thixotropy. Further,
increasing
salinity often decreases the functional characteristics of drilling fluid
additives.
[0014] Another method for controlling clay swelling is to use organic shale
inhibitor
molecules in drilling fluids. It is believed that the organic shale inhibitor
molecules are
absorbed on the surfaces of clays with the added organic shale inhibitor
completing with
water molecules for clay reactive sites and thus serve to reduce clay
swelling. Organic
shale inhibitors can be cationic, anionic, or nonionic. Cationic organic shale
inhibitors
dissociate into organic cations and inorganic anions, while anionic organic
shale
inhibitors dissociate into inorganic cationic and organic anions. Nonionic
shale inhibitor
molecules do not dissociate.
[0015] In the oil and gas industry, it is desirable that additives (shale
inhibitors as well as
any other additives) work both onshore and offshore and in fresh and salt
water
environments. In addition, as drilling operations and drilling waste disposal
impact plant
and animal life and water sources, drilling fluid additives should have low
toxicity levels.
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If a wellbore fluid (and all of its component parts) is non-toxic or has
extremely low
toxicity (below governmental requirements) disposal options may include pump-
off, land
spreading, land spraying, etc., which are not available for fluids having
higher toxicity
levels. For example, in Canada, fluids may only be disposed by such means if
the fluid
(and/or each of its components) has an EC50 (effective concentration causing a
maximum 50% response from microorganisms) greater than 75 (a valued between 75
and
90 is slightly toxic, but still disposable, while a value greater than 90 is
non-toxic) for a
particular microtoxicity assay measuring the light reduction from fluid
samples having
microorganisms contained therein.
[0016] Accordingly, there exists a continuing need for developments in shale
hydration
inhibition agents for water based fluids, and in particular shale inhibitive
water-based
fluids that have low toxicity.
SUMMARY OF INVENTION
[0017] In one aspect, embodiments disclosed herein relate to a wellbore fluid
that
includes an aqueous base fluid; a natural amine having at least one amine
group and at
least a C3 oleophilic backbone; and an unmodified biopolymer viscosifier,
wherein the
natural amine and the biopolymer viscosifier are present in an amount such
that at least
75% of the original concentration of each of the natural amine and the
biopolymer results
in a 50% decrease in light output of Vibrio fischeri upon exposure to the
natural amine
and the biopolymer viscosifier or the greatest percentage of effect in light
output of
Vibrio fischeri is a reduction that is less than a 50% decrease in light
output, or the
natural amine or biopolymer trigger hormesis.
[0018] In another aspect, embodiments disclosed herein relate to a method of
drilling,
that includes circulating a wellbore fluid into a wellbore, the wellbore fluid
comprising:
an aqueous base fluid; a natural amine having at least one amine group and at
least a C3
oleophilic backbone; andan unmodified biopolymer viscosifier, wherein the
natural
amine and the biopolymer viscosifier are present in an amount such that at
least 75% of
the original concentration of each of the natural amine and the biopolymer
results in a
50% decrease in light output of Vibrio fischeri upon exposure to the natural
amine and
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the biopolymer viscosifier or the greatest percentage of effect in light
output of Vibrio
fischeri is a reduction that is less than a 50% decrease in light output, or
the natural amine
or biopolymer trigger hormesis; where the method also includes collecting the
wellbore
fluid and drilled cuttings from the wellbore; and disposing of at least one of
the wellbore
fluid or drilled cuttings by one of disposed of mix-bury-cover, land-
spreading, pump-off,
or land-spraying.
[0019] Other aspects and advantages of the invention will be apparent from the
following
description and the appended claims.
DETAILED DESCRIPTION
[0020] In one aspect, embodiments disclosed herein relate to a water-based
wellbore
fluid for use in drilling wells through a formation containing shale that
swells in the
presence of water. Generally the wellbore fluids of the present disclosure may
be
formulated to include an aqueous continuous phase, a natural amine, and an
unmodified
biopolymer viscosifier, and such formulations may be considered non-toxic or
have
extremely low toxicity.
[0021] Toxicity, as referred to in the present disclosure, may be measured by
a bioassay-
based toxicity assessment known as MICROTOX (Strategic Diagnostics, Inc.,
Newark
DE) to screen for the presence of components that are toxic to life forms,
including
microorganisms, macroorganisms, and vegetation. While trout and shrimp assays
have
historically been used to evaluate toxicity, the MICROTOX test is based on
monitoring
changes in the level of light emission from a marine luminescent bacterium
(Vibrio
fischeri) when exposed to a toxic substance or sample containing toxic
materials, and
may be used to provide a more rapid, real-time measurement of acute toxicity.
The
MICROTOX test may use a MICROTOX 500 Analyze, which is a very sensitive
analyzer for the measurement of light from a luminescent bacterial reagent.
The
Analyzer offers a wide dynamic test range of light measurement (from 0 to
approximately 120,000,000 photon counts), which are automatically selected and
calibrated for high accuracy readings. The instrument reads light produced by
luminescent bacteria (Vibrio fischeri) after exposure to a test sample and
compares it to
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the light output of a control (reagent blank). The degree of percent light
loss (an
indication of metabolic inhibition in the test organisms) indicates the
relative toxicity of
the sample.
[00221 In accordance with embodiments of the present disclosure, each of the
fluid's
components may have a MICROTOX EC50 (or IC50) value of at least 75%, and at
least 90% in yet another embodiment over a 15 minute test period at 15C. An
EC50
value refers to the effective concentration (or inhibitory concentration for
an IC50) of a
sample that reduces light emission of the test organism by 50% over the test
period. The
results of the MICROTOX test are given as a percentage of the original
sample, i.e., the
EC50 value for the sample is a concentration that is at least 75% (or at least
90%) of the
concentration of the original sample. In other words, an EC50 value of 75%
means that
75% of the original concentration of the sample results in a 50% decrease in
light output.
In some instances, however, an EC50 value cannot be determined because a 50%
reduction in light output is not achieved. In such instances, the highest
percent effect, or
the greatest decrease in light that was observed during the test (often at
81.9% of the
original test concentration) may be recorded. If the greatest decrease is less
than a 50%
reduction in light, then a lesser amount of metabolic inhibition in the test
organisms is
indicated than if an EC50 value could be calculated. Thus, if the greatest
decrease is less
than 50%, a sample may be considered non-toxic. In a more particular
embodiment, one
or more of the fluid components may have a negative gamma value (ratio of
light lost to
light remaining), i.e., the sample stimulated bacterial light output,
indicating that the
bacterium is experiencing hormesis, or a generally-favorable biological
response causing
the bacterium to grow or flourish.
[00231 It is noted that the particular test used to ensure sufficiently low
toxicity for the
wellbore fluid (and/or its components) is not a limitation on the present
disclosure, but if
the MICROTOX test were applied to the wellbore fluid (and/or its components),
the
fluid (and/or fluid components) would have the requisite EC50 values when
tested in line
with the specifications set forth in Appendix 4 of Guide 50: Drilling Waste
Management,
October 1996 (Alberta Energy and Utilities Board) ("Directive 50"), which is
herein
incorporated by reference in its entirety. Further, it is also noted that a
sample that
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"passes" one particular toxicity test may not necessarily "pass" a different
test because
different toxicants may affect one bioassay differently than the other. For
example,
hydrocarbons exhibit a strong toxic response within the MICROTOX test, but
may
have little effect on other bioassays such as the rainbow trout test, whereas
ammonia may
have a stronger toxic response within the rainbow trout test, as compared to
the
MICROTOX test.
[00241 In various embodiments, the shale inhibitor and the biopolymer
viscosifier
selected for use in the wellbore fluids of the present disclosure may each
have an
MICROTOX EC50 value (according to the specifications set forth in Directive
50) of at
least 75%. In a more particular embodiment, at least one of the shale
inhibitor and the
biopolymer viscosifier may have a MICROTOX EC50 value of at least 90%. In an
even more particular embodiment, at least one of the shale inhibitor and the
biopolymer
viscosifier may each trigger hormesis under the MICROTOX test.
[00251 A natural amine shale hydration inhibition agent is included in the
formulation of
the wellbore fluids of the present disclosure so that the hydration of shale
and shale like
formations is inhibited. In accordance with various embodiments of the present
disclosure, the natural amine shale inhibitor may be a naturally occurring
amine having
an oleophilic backbone component, and a naturally occurring polyamine in more
particular embodiments. In various embodiments, the shale inhibitors may
include from
I to 7 amine groups, but may include more in other embodiments. The oleophilic
backbone of the amine may be a linear, branched alkyl group, cyclic alkyl, or
heterocyclic aromatic groups, and in particular embodiments, may be at least a
C3 group.
In a particular embodiment, the natural amine shale inhibitors of the present
disclosure
may be relatively small molecules, having a molecular weight of less than 700,
or a
molecular weight of less than 500, or 250 in more particular embodiments. The
inventors
of the present disclosure theorize that the shale inhibition occurs by the
interaction of the
nitrogen atoms from the amine(s) with the active groups on the clay surface in
combination with the carbon backbone of the oleophilic portion of the amine
repelling
water from interacting with the clay surface. Thus, the natural amine should
be present in
sufficient concentration to reduce either or both the surface hydration based
swelling
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and/or the osmotic based swelling of the shale clay. When drilling through a
formation
having water-swellable clays therein, a wellbore fluid having the additives of
the present
disclosure may be circulated therein to reduce the swelling of clays or shale
hydration.
[00261 Various embodiments may include at least one amino acid or at least one
naturally occurring species based on an amino acid (such as folic acid, etc).
In a
particular embodiment, the shale inhibitor may include one or more of
pantothenic acid,
folic acid, biotin, niacin, L-arginine, L-lysine, asparagine, glutamine,
histadine, aspartic
acid, glutamic acid, 5-hydroxytryptophan, tryptophan, serotonin, and beta-
alanine.
However, other natural amines may also be used.
[00271 In particular embodiments, the amine shale inhibitor of the present
disclosure may
be non-ionic, the amine(s) being a primary, secondary, or tertiary amine(s).
Many
conventional shale hydration inhibition agents rely on a cationic character so
that the
cationic character may exchange with exchangeable cations found on the surface
of the
shale or other swellable clay. While such mechanism for shale hydration may be
suitable
for some wells (such as off-shore wells), land-based drilling presents a need
for low
electrical conductivity fluids. The use of quaternary amines results in the
inclusion of an
anionic species (often inorganic halides), thus increasing the electrical
conductivity of the
fluid. Specifically, low conductivity may be desired for certain disposal
options of
cuttings on-shore. On the type of disposal, land disposal of water-based
fluids and
cuttings is an environmental concern due to a potential for high
conductivity/salinity
which cause a possibility of leaching and groundwater contamination. Salt,
unlike
hydrocarbons, cannot biodegrade but may accumulate in soils, which have a
limited
capacity to accept salts. If salt levels become too high, the soils may be
damaged and the
soil's ability to naturally degrade organic materials by microorganisms
present in the soil
can be inhibited. However, in another embodiment, if a quaternary amine is
used, an
organic salt (such as citrate, etc.) may be preferred to reduce the presence
of inorganic
anions such as halides.
[00281 Using natural amines of the present disclosure that are also non-ionic,
shale
hydration inhibition may be achieved without increasing the electrical
conductivity of the
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wellbore fluid. Thus, such fluids may be classified as low electrical
conductivity fluids.
As used herein, a "low electrical conductivity fluid" refers to a fluid having
an electrical
conductivity of no more than 10,000 S/cm. However, in accordance with
particular
embodiments of the present disclosure, fluids having electrical conductivities
of less than
about 3000 S/cm may be achieved, and less than about 2000 S/cm in more
particular
embodiments.
[0029] The natural amines of the present disclosure may be added to a wellbore
fluid in
concentrations sufficient to deal with the clay swelling problems at hand.
Concentrations
between about 0.5 pounds per barrel (ppb) and 10 ppb are contemplated and are
considered to be functionally effective to reduce swelling. of clays which
swell in the
presence of water.
[0030] The wellbore fluids may also include a biopolymer viscosifying agent in
order to
alter or maintain the rheological properties of the fluid. The primary purpose
for such
viscosifying agents is to control the viscosity and potential changes in
viscosity of the
drilling fluid. Viscosity control is particularly important because often a
subterranean
formation may have a temperature significantly higher than the surface
temperature.
Thus a wellbore fluid may undergo temperature extremes of nearly freezing
temperatures
to nearly the boiling temperature of water or higher during the course of its
transit from
the surface to the drill bit and back. One of skill in the art should know and
understand
that such changes in temperature can result in significant changes in the
rheological
properties of fluids. Thus in order to control and/or moderate the rheology
changes,
viscosity agents and rheology control agents may be included in the
formulation of the
wellbore fluid.
[0031] Viscosifying agents suitable for use in the formulation of the fluids
of the present
disclosure may be generally selected from any type of natural biopolymer
suitable for use
in aqueous based drilling fluids. Exemplary biopolymers may include starches,
celluloses, and various gums, such as xanthan gum, gellan gum, welan gum, and
schleroglucan gum. Such starches may include potato starch, corn starch,
tapioca starch,
wheat starch and rice starch, etc. In accordance with various embodiments of
the present
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disclosure, the biopolymer viscosifying agents may be unmodified (i.e.,
without
derivitization). Additionally, within particular embodiments, the biopolymer
viscosifiers
may have an H2S content of less than 0.1 mg/L, and less than 0.05 mg/L in more
particular embodiments. Hydrogen sulfide is often used in the packaging of
biopolymers
to kill any bacteria; however, the presence of such a bactericide during the
wellbore
formulation may render an otherwise non-toxic component relatively toxic.
Thus, it may
be desirable to wash any residual H2S from the biopolymers prior to
incorporation of the
component into the wellbore fluid. Generally, the biopolymers may be present
in an
amount ranging from 0.5 to 5 pounds per barrel (1.43 to 14.27 kg/m3); however,
more or
less may be used depending on the particular wellbore diameter, annular
velocity, cutting
carrying capacity, quiescent time expected or desired.
100321 The aqueous based continuous phase may generally be any water based
fluid
phase that is compatible with the formulation of a drilling fluid and is
compatible with
the shale hydration inhibition agents disclosed herein. In a particular
embodiment, the
aqueous based continuous phase may include fresh water. However, in
alternative
embodiments, the fluid may include at least one of fresh water, mixtures of
water and
water soluble organic compounds and mixtures thereof. In a particular
embodiment, the
aqueous fluid may be selected to be within the electrical conductivity limits
described
above. One skilled in the art would appreciate that conductivity requirements
of a fluid
may depend on the regulatory requirements for disposal of fluids/cuttings in a
particular
jurisdiction, and thus, for jurisdictions having relatively higher
conductivity limits,
inclusion of some salt in the fluid may be provided. In such instances, for
example, the
aqueous fluid may be formulated with mixtures of desired salts in fresh water.
Such salts
may include, but are not limited to alkali metal chlorides, hydroxides, or
carboxylates, for
example. In various embodiments of the drilling fluid disclosed herein, the
brine may
include seawater, aqueous solutions wherein the salt concentration is less
than that of sea
water, or aqueous solutions wherein the salt concentration is greater than
that of sea
water. Salts that may be found in seawater include, but are not limited to,
sodium,
calcium, aluminum, magnesium, potassium, strontium, lithium, and salts of
chlorides,
bromides, carbonates, iodides, chlorates, bromates, formates, nitrates,
oxides, sulfates,
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phosphates, silicates and fluorides. Salts that may be incorporated in a given
brine
include any one or more of those present in natural seawater or any other
organic or
inorganic dissolved salts. Additionally, brines that may be used in the
drilling fluids
disclosed herein may be natural or synthetic, with synthetic brines tending to
be much
simpler in constitution. One of ordinary skill would appreciate that the above
salts may
be present in the base fluid, or alternatively, may be added according to the
method
disclosed herein. Further, the amount of the aqueous based continuous phase
should be
sufficient to form a water based drilling fluid. This amount may range from
nearly 100%
of the wellbore fluid to less than 30% of the wellbore fluid by volume.
Preferably, the
aqueous based continuous phase may constitute from about 95 to about 30% by
volume
and preferably from about 90 to about 40% by volume of the wellbore fluid.
[0033] The wellbore fluids of the present disclosure may include a weight
material or
weighting agent in order to increase the density of the fluid. The primary
purpose for
such weighting materials is to increase the density of the fluid so as to
prevent kick-backs
and blow-outs. Thus the weighting agent may be added to the drilling fluid in
a
functionally effective amount largely dependent on the nature of the formation
being
drilled. Weighting agents or density materials suitable for use the fluids
disclosed herein
include galena, hematite, magnetite, iron oxides, illmenite, barite, siderite,
celestite,
dolomite, calcite, and the like, mixtures and combinations of these compounds
and
similar such weight materials that may be used in the formulation of wellbore
fluids.
The quantity of such material added, if any, may depend upon the desired
density of the
final composition. Typically, weighting agent is added to result in a drilling
fluid density
of up to about 24 pounds per gallon. The weighting agent may be added up to 21
pounds
per gallon in one embodiment, and up to 19.5 pounds per gallon in another
embodiment.
[0034] In addition to the other components previously noted, materials
generically
referred to as thinners and fluid loss control agents may also optionally
added to water-
based wellbore fluid formulations. Of these additional materials, each may be
added to
the formulation in a concentration as rheologically and functionally required
by drilling
conditions.
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[0035] In certain embodiments, the methods of the present disclosure comprise
providing
a wellbore fluid (e.g., a drilling fluid, reservoir drill-in fluid, fracturing
fluid, etc.) of the
present disclosure that comprises an aqueous base fluid, a natural amine shale-
inhibiting
component, and a natural viscosifier; and placing the wellbore fluid in a
subterranean
formation. The shale-inhibiting component and viscosifier may be added to the
wellbore
fluid individually or as a pre-mixed additive that comprises the shale-
inhibiting
component and/or viscosifier, as well as other optional components. The shale-
inhibiting
component and/or viscosifier may be added to the wellbore fluid prior to,
during, or
subsequent to placing the wellbore fluid in the subterranean formation.
[0036] A wellbore fluid according to the disclosure may be used in a method
for drilling
a well into a subterranean formation in a manner similar to those wherein
conventional
wellbore fluids are used. In the process of drilling the well, a wellbore
fluid is circulated
through the drill pipe, through the bit, and up the annular space between the
pipe and the
formation or steel casing to the surface. The wellbore fluid performs several
different
functions, such as cooling the bit, removing drilled cuttings from the bottom
of the hole,
suspending the cuttings and weighting the material when the circulation is
interrupted.
[0037] The natural amine shale inhibitor and/or biopolymer viscosifier may be
added to
the base fluid on location at the well-site where it is to be used, or it can
be carried out
at another location than the well-site. If the well-site location is selected
for carrying
out this step, then the natural amine and the biopolymer may immediately be
dispersed
in an aqueous fluid, and the resulting wellbore fluid may immediately be
emplaced in
the well using techniques known in the art.
[0038] Another embodiment of the present method includes a method of reducing
the
swelling of shale in a well whereby a water-base fluid formulated in
accordance with the
teachings of this disclosure is circulated in a well. The methods and fluids
of the present
disclosure may be utilized in a variety of subterranean operations that
involve
subterranean drilling, drilling-in (without displacement of the fluid for
completion
operations) and fracturing. Examples of suitable subterranean drilling
operations include,
but are not limited to, water well drilling, oil/gas well drilling, utilities
drilling, tunneling,
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construction/installation of subterranean pipelines and service lines, and the
like. These
subterranean drilling operations may be utilized, inter alia, to drill a well
bore in a
subterranean formation, or to stimulate the production of fluids from a
subterranean
formation, as well as or for a number of other purposes. In certain
embodiments, the
present disclosure provides methods of drilling at least a portion of a well
bore to
penetrate a subterranean formation.
[00391 Further, because of the low or non-toxic nature of the fluid, upon
circulation in
the well, the fluid may be collected at the rig surface and disposed of by any
one of mix-
bury-cover, land-spreading, pump-off, and/or land spraying. Mix-Bury-Cover is
a
disposal method in which the drilling waste solids and/or fluids are mixed
into subsoil
below the rooting zone and above the water table, and then covered with clean
subsoil
and topsoil. In addition to toxicity requirements, Mix-Bury-Cover also
possesses trace
element and nitrogen limits, maximum chloride concentration, and maximum
hydrocarbon content.
[00401 Landspreading is a disposal method whereby the drilling waste is spread
on-site
and incorporated into the subsoil. Landspraying is a disposal method in which
the waste
sprayed off-site on to topsoil (can, but not necessarily, be incorporated
therein). In
addition to toxicity requirements, Landspreading and Landspraying also possess
trace
element and nitrogen limits, maximum chloride and sodium concentrations,
maximum
hydrocarbon and total dissolved solids contents, and electrical conductivity
limits.
[00411 Pump-off is a disposal method for clear liquids from the drilling
waste, in which
the clear liquids are applied off-site, such as on to vegetated land, through
hoses or
irrigation equipment while the solid components of the waste may be disposed
of by any
other method. In addition to toxicity and clear liquid requirements, Pump-off
also
possess trace element and nitrogen limits, maximum chloride and sodium
concentrations,
and maximum hydrocarbon and total dissolved solids contents.
[00421 Further, depending on the formulation of the fluid (and preexisting
MICROTOX or other bioassays for each fluid additive), additional screening
(MICROTOX or otherwise) may be necessary for the collected waste fluid prior
to
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disposal. If a fluid is over the governmental requirements for disposal (such
as by
incorporation of bactericide, corrosion inhibitor, etc.), reduction of the
toxicity may be
achieved by one or more of aeration, pH adjustment, charcoal addition,
flocculation,
centrifugation, filtration, chemical precipitation, chemical oxidation, and/or
natural
biodegradation so that the toxicity requirements may be met for waste disposal
by one of
the above-described methods. Such disposal may occur after one or more waste
reduction treatments that include dewatering, hydrocarbon separation,
activated carbon
treatment, precipitation of heavy metals, or any other remedial measure to
meet the
disposal requirements. Removal of hydrocarbons may be particularly desirable
if the
drilling operation involved any of disposal of drill stem testing wastes to
the sump,
freeing of stuck pipe using hydrocarbons, a kick, blow, or well flow,
horizontal drilling,
or drilling of an underbalanced well.
[00431 EXAMPLES
[00441 Example 1
[00451 Various natural amines were tested at l0kg/m3 in distilled water in
accordance
with the MICROTOX test described in Directive 50, and various starches were
tested in
distilled water at various concentrations. The starches included E5829A and
E5829B
potato starches from ChemStar (Minneapolis, MN) and Fleischmann's corn starch
(ConAgra Foods, Inc., Omaha, NE). The EC50 results are shown below in Table IA
and
1B, respectively.
Table 1 A
Sample pH Treatment EC50 (15min) Highest Result
k /m3 Initial/adjusted % Effective Conc.
Folic Acid 6.94/- N/A >100 -- Pass
Pantothenic acid 6.07/- N/A >100 - Pass
L-lysine 6.19/- N/A Hormesis -- Pass
5-HTP 6.3/- N/A -- 28.13* Pass
Biotin 7.20 N/A Hormesis -- Pass
Table 1 B
Sample Concentration pH Initial/adjusted Treatment EC50 (15min)
[kg/M3]
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E5829A 15 10.47/6.95 Centrifuged 90.35
E5829B 15 10.49/6.4 Centrifuged 171.7
Corn Starch 2 7.5/- Centrifuged >100%
Corn Starch 4 7.5/- Centrifuged Hormesis
[00461 Example 2
[00471 Various amines were formulated at a concentration of 10 kg/m3 in
combination
with 1kg/m3 soda ash and 25 kg/m3 bentonite in water. Rheological measurements
were
taken at room temperature on a Fann 35 Viscometer (Fann Instrument Company)
before
and after aging at room temperature for 20 hours. Bentonite is 100% smectite,
and the
shale inhibitive effect of the amines may be determined by comparing the
rheological
properties of a baseline fluid (soda ash and bentonite in water) to the fluid
samples
incorporating an amine. Lower rheological properties indicates an inhibitive
effect. The
results are shown in Tables 2A and 2B below.
Table 2A - Before Aging
Properties Baseline Pantothenic Acid Folic Acid Biotin Niacin L-Arginine L-
Lysine
600 8 2 5 7 3 7 5
300 5 1 3 5 2 5 3
200 4 1 2 3 1 4 3
100 3 1 1 2 1 3 1
6 1 0 0 1 0 1 0
3 1 0 0 0 0 1 0
PV 3 1 2 2 1 2 2
YP 1 0 0.5 1.5 0.5 1.5 0.5
10s 1 0.5 0.5 0.5 0.5 1 0.5
10m 3 0.5 1 3.5 0.5 2 1.5
H 9.95 7.40 9.64 9.61 4.93 10.19 8.66
Table 2B - After Aging
Properties Baseline Pantothenic Acid Folic Acid Biotin Niacin L-Arginine L-
Lysine
600 7 3 5 6 3 6 6
300 5 2 3 3 2 4 4
200 3 1 2 2 1 3 3
100 2 1 1 1 1 2 2
6 0 0 0 0 0 1 1
3 0 0 0 0 0 1 1
PV 2 1 2 3 1 2 2
YP 1.5 0.5 0.5 0 0.5 1 1
10S 0.5 0.5 0.5 0 0.5 0.5 0.5
10m 1.5 0.5 0.5 1 0.5 2.5 1
H 9.79 7.91 9.22 9.45 4.94 10.11 8.82
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[00481 Additional formulations of the amines were formulated at 10 kg/m3 in
combination with soda ash (to reach pH 9.5-10.5 before aging) and 50 kg/m3
bentonite.
The rheological measurements were taken at room temperature before and after
aging at
room temperature for 20 hours. The results are shown in Tables 3A and 3B
below.
Table 3A - Before Aging
Properties Baseline Pantothenic Folic Biotin Niacin L-Arginine L-Lysine
Acid Acid
600 25 14 14 21 12 22 16
300 17 9 8 14 8 16 12
200 14 7 6 11 6 13 10
100 10 5 4 8 4 10 8
6 4 2 1 3 2 4 6
3 4 2 1 3 2 4 6
PV 8 5 6 7 4 6 4
YP 4.5 2 1 3.5 2 5 4
10s 2.5 2.5 1 2.5 2 3 3.5
tom 6.5 4 3 5.5 4 7.5 5
p H 9.64 10.39 9.63 9.74 9.54 10.55 9.41
Table 3B - After Aging
Properties Baseline Pantothenic Folic Biotin Niacin L-Arginine L-Lysine
Acid Acid
600 25 15 13 19 11 24 18
300 17 9 8 12 7 15 13
200 14 7 6 9 6 12 11
100 10 4 3 6 4 8 8
6 3 1 1 2 1 2 6
3 3 1 0 2 1 1 6
PV 8 6 5 7 5 9 5
YP 4.5 1.5 1.5 2.5 1 3 4
10s 2 1.5 0.5 1.5 2.5 1.5 4
10m 5.5 3 3 4 3 5 6.5
pH 9.63 10.12 9.23 9.60 9.49 10.48 9.58
[0049] Example 3
[0050] Various fluid samples having various natural amines in combination with
other
fluid components, including a viscosifier, were formulated as shown in Table
4A below.
The rheological properties of the fluid are shown Table 4A and the MICROTOX
test
results are shown in Table 4B. FEDZAN D is a xanthan gum available and
CalCarb 0
and SAFECARB products are calcium carbonate particles, all of which are
available
from M-I SWACO (Houston, Texas).
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Table 4A
Component Baseline Folic Acid Pantothenic Acid Niacin
Water (D-I) Balance Balance Balance Balance
Soda Ash [kg/m3] 2.8 2.8 2.8 2.8
FedZan D [kg/m3] 2.6 2.6 2.6 2.6
Folic Acid [kg/m3] 10
Corn Starch [kg/m3] 15 15 15 15
Pantothenic Acid [kg/m3] 10
Niacin [kg/m3] 10
CalCarb 0 [kg/m3] 15 15 15 15
SafeCarb 20 [kg/m3] 35 35 35 35
SafeCarb 40 [kg/m3] 15 15 15 15
Bentonite [kg/m3] 25 25 25 25
Measured Properties
600 43 41 49 29
300 31 29 35 22
200 26 24 29 19
100 20 118 22 14
6 9 9 10 7
3 8 7 8 6
PV [mPa*s] 12 12 14 7
YP [Pa] 9.5 8.5 10.5 7.5
Sec Gel 4.5 4.5 5 3.5
10 Min Gel 6 6 7 5
API Fluid Loss (7.5 min x 2) 10 9.6 10 9
Table 4B
Sample pH Initial/adjusted Treatment EC50 (15min) Highest Result
Effective Conc.
Baseline 10.55/6.74 Centrifuged -- 24.17* Pass
Folic Acid 10.31t8.52 Centrifuged -- 38.91 * Pass
Pantothenic acid 9.73/6.67 Centrifuged -- 34.67* Pass
Niacin 7.60/- Centrifuged -- 27.48* Pass
[00511 Example 4
[00521 The first step was to develop a formulation that provided the rheology
and fluid
loss control sought in the objective using Xanthan Gum (Fedzan D) to raise low
end
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rheology and Starch (E5829A) to aid in fluid loss control. KLA-GARD B is an
amine
shale inhibitor available from M-I SWACO (Houston, Texas). The product
components
used in the samples include the following components at the respective
concentrations:
= Xanthan Gum - 5 kg/m3
= FEDPAC UL - 5 kg/m3
= Starch - 3 kg/m3
= KLA-GARD B - 30 L/m3 (3%v/v)
= Calcium Carbonate "0" - 15 kg/m3
= SAFECARB 20 - 35 kg/m3
= SAFECARB 40 - 15 kg/m3
= Lime - 0.25 kg/m3
[0053] Eight fluid samples from the above concentrations, comparing equal
concentrations of FEDZAN D vs. Duovis and E5829A vs. E5829B starches, each
with and
without KLA-GARD B, were formulated as shown below in Table 5. Distilled water
was
used for formulating the mud to prevent the chlorine in tap water from
interfering with
MICROTOX testing.
Table 5
Mud Sample #
A B C D E F G H
FEDZAN D 5 5 - 5 5 -
m'
Duovis 5 5 - - 5 5
k m'
FEDPAC UL
[kg/M3] 5 5 5 5 5 5 5 5
E5829A
k m3 3 - 3 3 - 3
E5829B 3 3 3 3
m'
KLA-GARD B 30 30 30 30 - - - -
[LJM3]
Cal Carb "0
[kg/M3] 15 15 15 15 15 15 15 15
SAFECARB 20 35 35 35 35 35 35 35 35
ma
SAFECARB 40
k m' 15 15 15 15 15 15 15 15
Lime m' 0.25 0.25 0.25 0.25 0.5 0.5 0.5 0.5
[0054] Samples A, B, C and D were tested for rheology, API fluid loss, and
MICROTOX 15 Min EC50, the results of which are shown in Table 6 below.
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Table 6
Mud Sample #
A B C D
API FL 10.4 9.4 10.4 9.4
cc 3Omin
600 83 87 75 76
cP
300 62 66 56 58
cP
200 52 55 48 48
cP
100 39 41 36 36
cP
6 15 16 14 14
cP
3 13 13 11 11
cP
Gel 10s/10m 7.5/11.0 8.0/11.0 6.5/9.0 7.0/9.0
Pa
PV 21 21 19 18
mPa=S
YP 20.5 22.5 18.5 20.0
Pa
Microtox 15 min EC50 105.6% 68.1% 181.9% 148.5%
[%] PASS FAIL PASS PASS
Pass/Fail
[00551 Samples E-H were built with no KLA-GARD B, and were used to determine
the
effectiveness of the KLA-GARD B inhibitor. All samples had 50 kg/m3 of Federal
Gel
added to simulate reactive solids. The rheology was checked on each sample
after 15
minutes of mixing, and again after sitting over-night (20 hours). The results
are shown in
Table 7 below.
Table 7
Mud Sample #
A E B F C G D H
15 Minutes
600 85 166 90 179 82 166 82 180
cP
300 64 127 68 134 62 124 62 137
cP
200 54 109 57 115 53 105 53 119
cP
100 41 84 43 89 41 81 41 92
cP
6 17 39 19 40 17 35 17 40
cP
3 15 36 16 36 14 30 15 35
cP
Gel10s/10m 9.0/12.0 18.0/33.5 9.5/13.0 18.5/29.5 8.0/12.5 16.0/26.5 8.0/11.0
18.0128.0
Pa
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PV 21 39 22 45 20 42 20 43
mPa=s
YP 21.5 44.0 23.0 44.5 21.0 41.0 21.0 47.0
Pa
20 Hours
600 102 224 106 231 91 198 91 210
cP
300 76 169 80 171 68 146 69 155
M3 1
200 64 142 67 145 58 125 58 132
cP
100 48 108 50 110 44 96 44 100
cP
6 19 45 20 48 18 40 18 42
I&I
3 16 42 17 41 15 35 15 37
-ICPI
Gel10s/10m 9.5/12.0 20.0/28.5 9.5/13.0 21.0/30.0 8.5/11.5 17.5/26.0 8.5/11.0
18.0/26.0
Pa
PV 26 55 26 60 23 52 22 55
mPas
YP 25.0 57.0 27.0 55.5 22.5 47.0 23.5 50.0
Pa
[0056] Similar formulations are compared side by side with and without KLA-
GARD B
to show the effectiveness of the inhibitor in preventing hydration of reactive
solids.
Samples containing DUOVIS are also shown having thinner high-end rheologies
than the
samples containing FEDZAN D.
[0057] Embodiments of the present disclosure may provide at least one of the
following
advantages. The natural amines of the present disclosure may perform as a
shale
inhibitor to reduce the swelling or hydration of shales during drilling.
Moreover, such
additives possess extremely low toxicity and also do not significantly
contribute to an
increase in the electrical conductivity of the fluid, allowing for broader
applicability for
land disposal due to environmental concerns for disposal of toxic and/or high
conductivity fluids/cuttings.
[0058] While the invention has been described with respect to a limited number
of
embodiments, those skilled in the art, having benefit of this disclosure, will
appreciate
that other embodiments can be devised which do not depart from the scope of
the
invention as disclosed herein. Accordingly, the scope of the invention should
be limited
only by the attached claims.
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