Note: Descriptions are shown in the official language in which they were submitted.
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
Insulating Annular Fluid
Background of Invention
Field of the Invention
[00011 The invention relates generally to viscosifiable, low thermal
conductivity
annular fluids and methods of viscosifying, emplacing, and removing the
fluids.
Background Art
[00021 Annular fluids or packer fluids are liquids which are pumped into
annular
openings such as, for example, (1) between a wellbore wall and one or more
casing
strings of pipe extending into a wellbore, or (2) between adjacent, concentric
strings
of pipe extending into a wellbore, or (3) in one or both of an A- or B-annulus
in a
wellbore comprising at least an A- and B-annulus with one or more inner
strings of
pipe extending into a said wellbore, which may be running in parallel or
nominally
in parallel with each other and may or may not be concentric or nominally
concentric with the outer casing string, or (4) in one or more of an A-, B- or
C-
annulus in a wellbore comprising at least an A-, B- and C-annulus with one or
more
inner strings of pipe extending into a said wellbore, which may be running in
parallel or nominally in parallel with each other and may or may not be
concentric or
nominally concentric with the outer casing string.
[0003] Yet alternatively, said one or more strings of pipe may simply run
through a
conduit or outer pipe(s) to connect one or more wellbores to another wellbore
or to
lead from one or more wellb ores to a centralized gathering or processing
center; and
said annular fluid may have been emplaced within said conduit or pipe(s) but
external to said one or more strings of pipe therein. Insulating annular
fluids or
insulating packer fluids are annular fluids or packer fluids used to control
heat loss ¨
both conductive and convective heat losses. These insulating annular or packer
fluids are especially necessary in oil or gas well construction operations
conducted
in low temperature venues of the world, for example, those areas having
permafrost
[0004] Permafrost is a thick layer of frozen surface ground found often in
arctic or
antarctic regions, which frozen ground may be several hundred feet thick and
1
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
presents a great obstacle to the removal of relatively warm fluids through a
well pipe
penetrating said frozen ground. Particularly, warm fluid in the well pipe
causes
thawing of the permafrost in the vicinity of the well resulting in subsidence
which
can irreparably impair the permafrost environment and impose compressive
and/or
tension loads high enough to rupture or collapse the well casing and hence
allow the
escape of well fluids. In addition, the warm gas or oil coming to the surface
in the
well pipe becomes cooled by giving up its heat to the permafrost. Further, gas
hydrate crystals .may form, which can freeze together and block the well pipe;
alternatively, wax or asphaltenes may form, which can agglomerate and block
the
well pipe. Generally, except for a tiny contribution from radiation, annular
heat loss
is due to convection and to conduction.
[0005] Heavy oil production is another operation which often can benefit
from the use
of an insulating annular fluid. In heavy oil production, a high-pressure steam
or hot
water is injected into the well and the oil reservoir to heat the fluids in
the reservoir,
causing a thennal expansion of the crude oil, an increase in reservoir
pressure and a
decrease of the oil's viscosity. In this process, damage to the well casing
may occur
when heat is transferred through the annulus between the well tubing and the
casing.
The resulting thermal expansion of the casing can break the bond between the
casing
and the surrounding cement, causing leakage. Accordingly, an insulating medium
such as a packer fluid may be used to insulate or to help insulate the well
tubing.
The packer fluid also reduces heat loss and saves on the energy requirements
in
stimulation using hot-water or steam (huff-n-puff) or in hot-water- or steam-
flooding.
[0006] In addition to steam injection processes and operations which
require
production through a peiniafrost layer, subsea fields ¨ especially, subsea
fields in
deep water, 1,500 to more than 6,000 feet deep ¨ require specially designed
systems,
which typically require an insulating annular or packer fluid. For example, a
subsea
oil reservoir temperature may be between about 120 F and 250 F, while the
temperature of the water through which the oil must be conveyed is often as
low as
32 F to 50 F. Conveying the high temperature oil through such a low
temperature
environment can result in oil temperature reduction and consequently the
separation
of the oils into various hydrocarbon fractions and the deposition of
paraffins, waxes,
2
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
asphaltenes, and gas hydrates. The agglomeration of these oil constituents can
cause
blocking or restriction of the wellbore, resulting in significant reduction or
even
catastrophic failure of the production operation.
[0007] To meet the above-discussed insulating demands, a variety of packer
fluids
have been developed. For example, U.S. Pat. No. 3,613,792 describes an early
method of insulating wellbores. In the 3,613,792 patent, simple fluids and
solids are
used as the insulating medium. U.S. Pat. No. 4,258,791 improves on these
insulating materials by disclosing an oleaginous liquid such as topped crude
oils, gas
oils, kerosene, diesel fluids, heavy alkylates, fractions of heavy alkylates
and the like
in combination with an aqueous phase, lime, and a polymeric material. U.S.
Pat.
No. 4,528,104 teaches a packer fluid comprised of an oleaginous liquid such as
diesel oil, kerosene, fuel oil, lubricating oil fractions, heavy naphtha and
the like in
combination with an organophillic clay gellant and a clay dispersant such as a
polar
organic compound and a polyfunctional amino-silane.
[0008] Gelled hydrocarbons have been successfully used as packer fluids
because the
hydrocarbon fluids have low thermal conductivities, while gel formation
increases
the viscosities of the fluids. The increased viscosity minimizes fluid
movement in
packer fluids, leading to reduced or minimized convective heat loss.
[0009] Polyvalent metal (typically, ferric iron or aluminum) salts of
phosphoric acid
esters have been successfully used as gelling agents for forming high
viscosity
gelled hydrocarbon fluids. Description of these fluids and their uses can be
found in
U.S. Patent Nos. 4,507,213 issued to Daccord et al., 4,622,155 issued to
Harris et
al., 5,190,675 issued to Gross, and 5,846,915 issued to Smith et al. More
recently,
U.S. Patent No. 6,511,944 issued to Taylor et al. discloses gelled hydrocarbon
fracture fluids that include ferric iron or aluminum polyvalent metal salts of
phosphonic acid esters, instead of phosphoric acid esters.
[0010] Another short-coming of hydraulic fracturing fluids has been their
limited
stability ¨ after all, they need only last a matter of hours, since even a
massive
hydraulic fracturing job involving 2,000,000 pounds of proppant is typically
concluded in less than 8 hours. Although these fluids have worked well in the
hydraulic fracturing application, there is still a need for insulating annular
or packer
3
CA 02694951 2014-10-08
,
77680- 1 3 1
fluids that are stable for extended periods, low in thermal conductivity, and
simultaneously
inhibitive of convective heat loss.
Summary of Invention
[0011] In one aspect, the present disclosure relates to a method of
preventing hydrate
formation during oil production through a subsea field or permafrost layer,
comprising:
preparing the packer fluid comprising: a hydrocarbon fluid, and a micronized
weighting agent,
wherein the micronized weighting agent has a particle size d90 of less than 20
microns, and
wherein the micronized weighting agent is present at a concentration of 60-90
w/w%;
pumping the packer fluid into an annulus; and producing an oil from a
formation through a
pipe extending through the packer fluid.
[0012] In another aspect, the present disclosure relates to a method
for stimulating a
well, comprising preparing the packer fluid comprising: a hydrocarbon fluid,
and a coated
micronized weighting agent, wherein the micronized weighting agent has a
particle size d90 of
less than 20 microns, and wherein the micronized weighting agent is present at
a
concentration of 60-90 w/w%; pumping the packer fluid into an annulus; and
injecting hot-
water or steam through a pipe extending through the packer fluid.
[0013] Other aspects and advantages of the invention will be apparent
from the
following description and the appended claims.
4
CA 02694951 2012-04-03
77680-131
Detailed Description
[0014] Embodiments of the present disclosure relate to insulating
packer fluids
and methods of preparing and emplacing such fluids. Packer fluids according to
the
present disclosure have good long-term insulation properties, because they
resist
syneresis and separation of various components into separate phases, and have
low thermal conductivities and unique rheological properties that minimize
their
movement once they are emplaced - and this minimization of movement, in turn,
minimizes convective heat loss.
[0015] A majority of annular heat loss is due to convection and
conduction.
Heat loss due to thermal conductivity may be controlled by proper selection of
fluids,
i.e., fluids with low thermal conductivities, while heat loss due to
convection can be
arrested or substantially diminished by increased viscosities of the fluids.
For
example, thermal conductivities as low as 0.07 btu/(hr=ft. F) can be obtained
with
gelled diesel or other hydrocarbon-based insulating annular fluid.
[0016] In certain aspects, disclosed embodiments relate to insulating
packer
fluids, and methods of emplacing and subsequently removing such fluids. Packer
fluids according to embodiments disclosed herein may have relatively high
densities,
and may be adapted to survive in high temperature and/or high pressure wells.
[0017] More specifically, insulating packer fluids in accordance with
disclosed
embodiments comprise oil-based (hydrocarbon-based) fluids, comprising
micronized
weighting agents, because oil-based fluids typically have very low thermal
conductivities. For example, thermal conductivities as low as 0.07 btu/(hr=ft.
F) can
be obtained with gelled diesel or other hydrocarbon-based insulating annular
fluids.
5
CA 02694951 2012-04-03
77680-131
[0018] Micronized Weighting Agent
[0019] Fluids used in embodiments disclosed herein may include micronized
weighting agents. In some embodiments, the micronized weighting agents may be
uncoated. In other embodiments, the micronized weighting agents may be coated
with a dispersant. For example, fluids used in some embodiments disclosed
herein
may include dispersant coated micronized weighting agents. The coated
weighting
agents may be formed by either a dry coating process or a wet coating process.
Weighting agents suitable for use in other embodiments disclosed herein may
include those disclosed in U.S. Patent Application Publication Nos.
20040127366,
20050101493, 20060188651, U.S. Patent Nos. 6,586,372; 7,176,165; and
7,918,289.
[0020] ]Micronized weighting agents used in some embodiments disclosed
herein may
include a variety of compounds well known to one of skill in the art. In a
particular
embodiment, the weighting agent may be selected from one or more of the
materials
including, for example, barium sulphate (barite), calcium carbonate (calcite),
dolomite, ilmenite, hematite or other iron ores, olivine, siderite, manganese
oxide,
and strontium sulphate. One having ordinary skill in the art would recognize
that
selection of a particular material may depend largely on the density of the
material
as typically, the lowest wellbore fluid viscosity at any particular density is
obtained
by using the highest density particles. However, other considerations may
influence
the choice of product such as cost, local availability, the power required for
grinding, and whether the residual solids or filter cake may be readily
removed from
the well.
5a
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
100211 In
one embodiment, the micronized weighting agent may have a d90 ranging
from 1 to 25 microns and a d50 ranging from 0.5 to 10 microns. In another
embodiment, the micronized weighting agent includes particles having a d90
ranging
from 2 to 8 microns and a d50 ranging from 0.5 to 5 microns. One of ordinary
skill
in the art would recognize that, depending on the sizing technique, the
weighting
agent may have a particle size distribution other than a monomodal
distribution.
That is, the weighting agent may have a particle size distribution that, in
various
embodiments, may be rnonomodal, which may or may not be Gaussian, bimodal, or
polymodal.
[0022] It
has been found that a predominance of particles that are too fine (i.e. below
about 1 micron) results in the formation of a high rheology paste. Thus, it
has been
unexpectedly found that the weighting agent particles must be sufficiently
small to
avoid issues of sag, but not so small as to have an adverse impact on
rheology. Thus
weighting agent (barite) particles meeting the particle size distribution
criteria
disclosed herein may be used without adversely impacting the 'theological
properties
of the wellbore fluids.
[0023] In
one embodiment, a micronized weighting agent is sized such that: particles
having a diameter less than 1 microns are 0 to 15 percent by volume; particles
having a diameter between 1 microns and 4 microns are 15 to 40 percent by
volume;
particles having a diameter between 4 microns and 8 microns are 15 to 30 by
volume; particles having a diameter between 8 microns and 12 microns are 5 to
15
percent by volume; particles having a diameter between 12 microns and 16
microns
are 3 to 7 percent by volume; particles having a diameter between 16 microns
and 20
microns are 0 to 10 percent by volume; particles having a diameter greater
than 20
microns are 0 to 5 percent by volume. In another embodiment, the micronized
weighting agent is sized so that the cumulative volume distribution is: less
than 10
percent or the particles are less than 1 microns; less than 25 percent are in
the range
of 1 microns to 3 microns; less than 50 percent are in the range of 2 microns
to 6
microns; less than 75 percent are in the range of 6 microns to 10 microns; and
less
than 90 percent are in the range of 10 microns to 24 microns.
[0024] The
use of micronized weighting agents has been disclosed in U.S. Patent
Application Publication No. 20050277553 assigned to the assignee of the
current
6
CA 02694951 2012-04-03
77680-131
application.
Particles having these size distributions may be obtained by
several means. For
example, sized particles, such as a suitable
barite product having similar particle size distributions as disclosed
herein, may be commercially purchased. A coarser ground suitable material may
be
obtained, and the material may be further ground by any known technique to the
desired particle size. Such techniques include jet-milling, ball milling, high
performance wet and dry milling techniques, or any other technique that is
known in
the art generally for milling powdered products.
[0025] In
one embodiment, appropriately sized particles of barite may be selectively
removed from a product stream of a conventional barite grinding plant, which
may
include selectively removing the fines from a conventional API-grade barite
grinding operation. 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 processed via an air classifier to achieve the
particle
size distributions disclosed herein. In yet another embodiment, the micronized
weighting agents may be formed by chemical precipitation. Such precipitated
products may be used alone or in combination with mechanically milled
products.
[0026] In
some embodiments, the micronized weighting agents include solid colloidal
particles having a deflocculating agent or dispersant coated onto the surface
of the
particle. Further, one of ordinary skill would appreciate that the term
"colloidal"
refers to a suspension of the particles, and does not impart any specific size
limitation. Rather, the size of the micronized weighting agents of the present
disclosure may vary in range and are only limited by the claims of the present
application. The micronized particle size generates high density suspensions
or
slurries that show a reduced tendency to sediment or sag, while the dispersant
on the
surface of the particle controls the inter-particle interactions resulting in
lower
rheological profiles. Thus, the combination of high density, fine particle
size, and
control of colloidal interactions by surface coating the particles with a
dispersant
reconciles the objectives of high density, lower viscosity and minimal sag.
[0027] In
some embodiments, a dispersant may be coated onto the particulate
weighting additive during the comminution (grinding) process. That is to say,
7
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
coarse weighting additive is ground in the presence of a relatively high
concentration of dispersant such that the newly formed surfaces of the fine
particles
are exposed to and thus coated by the dispersant. It is speculated that this
allows the
dispersant to find an acceptable conformation on the particle surface thus
coating the
surface. Alternatively, it is speculated that because a relatively higher
concentration
of dispersant is in the grinding fluid, as opposed to that in a drilling
fluid, the
dispersant is more likely to be absorbed (either physically or chemically) to
the
particle surface.
[0028] As that term is used in herein, "coating of the surface" is
intended to mean that
a sufficient number of dispersant molecules are absorbed (physically or
chemically)
or otherwise closely associated with the surface of the particles so that the
fine
particles of material do not cause the rapid rise in viscosity observed in the
prior art.
By using such a definition, one of skill in the art should understand and
appreciate
that the dispersant molecules may not actually be fully covering the particle
surface
and that quantification of the number of molecules is very difficult.
[0029] Therefore, by necessity, reliance is made on a results oriented
definition. As a
result of the process, one can control the colloidal interactions of the fine
particles
by coating the particle with dispersants prior to addition to the drilling
fluid. By
doing so, it is possible to systematically control the rheological properties
of fluids
containing in the additive as well as the tolerance to contaminants in the
fluid in
addition to enhancing the fluid loss (filtration) properties of the fluid.
[0030] In some embodiments, the weighting agents include dispersed solid
colloidal
particles with a weight average particle diameter (d50) of less than 10
microns that
are coated with a polymeric deflocculating agent or dispersing agent. In other
embodiments, the weighting agents include dispersed solid colloidal particles
with a
weight average particle diameter (d50) of less than 8 microns that are coated
with a
polymeric deflocculating agent or dispersing agent; less than 6 microns in
other
embodiments; less than 4 microns in other embodiments; and less than 2 microns
in
yet other embodiments.
[0031] The fine particle size will generate suspensions or slurries that
will show a
reduced tendency to sediment or sag, and the polymeric dispersing agent on the
surface of the particle may control the inter-particle interactions and thus
will
8
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
produce lower rheological profiles. It is the combination of fine particle
size and
control of colloidal interactions that reconciles the two objectives of lower
viscosity
and minimal sag. Additionally, the presence of the dispersant in the
comminution
process yields discrete particles which can form a more efficiently packed
filter cake
and so advantageously reduce filtration rates.
10032] Coating of the micronized weighting agent with the dispersant may
also be
performed in a dry blending process such that the process is substantially
free of
solvent. The process includes blending the weighting agent and a dispersant at
a
desired ratio to form a blended material. In one embodiment, the weighting
agent
may be un-sized initially and rely on the blending process to grind the
particles into
the desired size range as disclosed above. Alternatively, the process may
begin with
sized weighting agents. The blended material may then be fed to a heat
exchange
system, such as a thermal desorption system.
[0033] The mixture may be forwarded through the heat exchanger using a
mixer, such
as a screw conveyor. Upon cooling, the polymer may remain associated with the
weighting agent. The polymer/weighting agent mixture may then be separated
into
polymer coated weighting agent, unassociated polymer, and any agglomerates
that
may have formed. The unassociated polymer may optionally be recycled to the
beginning of the process, if desired. In another embodiment, the dry blending
process alone may serve to coat the weighting agent without heating.
[0034] Alternatively, a sized weighting agent may be coated by thermal
adsorption as
described above, in the absence of a dry blending process. In this embodiment,
a
process for making a coated substrate may include heating a sized weighting
agent
to a temperature sufficient to react monomeric dispersant onto the weighting
agent
to form a polymer coated sized weighting agent and recovering the polymer
coated
weighting agent. In another embodiment, one may use a catalyzed process to
form
the polymer in the presence of the sized weighting agent. In yet another
embodiment, the polymer may be preformed and may be thermally adsorbed onto
the sized weighting agent.
[0035] In some embodiments, the micronized weighting agent may be formed
of
particles that are composed of a material of specific gravity of at least 2.3;
at least
2.4 in other embodiments; at least 2.5 in other embodiments; at least 2.6 in
other
9
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
embodiments; and at least 2.68 in yet other embodiments. For example, a
weighting
agent formed of particles having a specific gravity of at least 2.68 may allow
wellbore fluids to be formulated to meet most density requirements yet have a
particulate volume fraction low enough for the fluid to be pumpable.
[0036] As
mentioned above, embodiments of the micronized weighting agent may
include a deflocculating agent or a dispersant. In one embodiment, the
dispersant
may be selected from carboxylic acids of molecular weight of at least 150
Daltons,
such as oleic acid and polybasic fatty acids, alkylbenzene sulphonic acids,
alkane
sulphonic acids, linear alpha-olefin sulphonic acids, phospholipids such as
lecithin,
including salts thereof and including mixtures thereof. Synthetic polymers may
also
be used, such as HYPERMER 0M-1 (Imperial Chemical Industries, PLC, London,
United Kingdom) or polyacrylate esters, for example. Such polyacrylate esters
may
include polymers of stearyl methacrylate and/or butylacrylate. In
another
embodiment, the corresponding acids methacrylic acid and/or acrylic acid may
be
used. One skilled in the art would recognize that other acrylate or other
unsaturated
carboxylic acid monomers (or esters thereof) may be used to achieve
substantially
the same results as disclosed herein.
[0037] The
polymeric dispersant may have an average molecular weight from about
10,000 Daltons to about 300,000 Daltons in one embodiment, from about 17,000
Daltons to about 40,000 Daltons in another embodiment, and from about 200,000-
300,000 Daltons in yet another embodiment. One of ordinary skill in the art
would
recognize that when the dispersant is added to the weighting agent during a
grinding
process, intermediate molecular weight polymers (10,000-300,000 Daltons) may
be
used.
[0038]
Further, it is specifically within the scope of the embodiments disclosed
herein
that the polymeric dispersant be polymerized prior to or simultaneously with
the wet
or dry blending processes disclosed herein. Such polymerizations may involve,
for
example, thermal polymerization, catalyzed polymerization, initiated
polymerization
or combinations thereof.
100391
Given the particulate nature of the micronized and dispersant coated
micronized weighting agents disclosed herein, one of skill in the art should
appreciate that additional components may be mixed with the weighting agent to
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
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 and drilling fluid disclosed herein. In one
illustrative
example, 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.
100401
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 a
substantial adverse impact on the properties and performance of the drilling
fluids.
In one illustrative embodiment, polymeric fluid loss materials comprising less
than 5
percent by weight are added to enhance the properties of the drilling fluid.
Alternatively, less than 5 percent 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 percent by weight of
a
conventional anti-caking agent is added to assist in the bulk storage of the
weighting
materials.
[00411 The
particulate materials as described herein (i.e., the coated and/or uncoated
micronized weighting agents) may be added to a drilling fluid as a weighting
agent
in a dry form or concentrated as slurry in 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, the oleaginous fluid may have
a
kinematic viscosity of less than 10 centistokes (10 mm2/s) at 40 C and, for
safety
reasons, a flash point of greater than 60 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 known
to one of skill in the art of drilling or other wellbore fluid formulation. In
one
embodiment, the desired particle size distribution is achieved via wet milling
of the
courser materials in the desired carrier fluid.
11
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
100421 Wellbore Fluid Formulation
[0043] The sized particles described above (i.e., the micronized
weighting agents
(coated or uncoated) are combined in an oleaginous fluid (oil-based) wellbore
fluid,
as outlined below, along with other additives to create insulating packer
fluids in
accordance with described embodiments.
[00441 The oleaginous fluid may be a liquid, more preferably a natural or
synthetic
oil, and more preferably the oleaginous fluid is selected from the group
including
diesel oil; mineral oil; a synthetic oil, such as hydrogenated and
unhydrogenated
olefins including polyalpha olefins, linear and branch olefins and the like,
polydiorganosiloxanes, siloxanes, or organosiloxanes, esters of fatty acids,
specifically straight chain, branched and cyclical alkyl ethers of fatty
acids; similar
compounds known to one of skill in the art; and mixtures thereof.
[0045] Conventional methods can be used to prepare the drilling fluids
disclosed
herein in a manner analogous to those normally used, to prepare oil-based
drilling
fluids. In one embodiment, a desired quantity of oleaginous fluid such as a
base oil,
and a suitable amount of one or more micronized weighting agents are mixed
together and any remaining components are added sequentially with continuous
mixing.
[0046] By formulating annular fluids in this manner, the present
inventors have
discovered that annular packer fluids may be formulated having densities up to
about 20 ppg. Through the addition of other weighting agents, such as Fe03, it
is
possible to raise the density beyond this point. Typical prior art annular
fluids, have
significantly lower densities, such as about 8 ppg.
[0047] Other additives that may be included in the wellbore fluids
disclosed herein
include, for example, gelling agents, wetting agents, organophilic clays,
viscosifiers,
surfactants, dispersants, interfacial tension reducers, pH buffers, mutual
solvents,
thinners, thinning agents, rheological additives and cleaning agents. The
addition of
such agents should be well known to one of ordinary skill in the art of
formulating
drilling fluids and muds.
10048] One issue in formulating annular fluids is that oil phase
separation can occur.
This phenomenon is known as "top oil loss" or "top oil separation", and can be
12
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
combated through the use of gelling agents. Specifically, by mixing gelling
agents
in with the base fluid and micronized weighting agent, the oil, which would
otherwise phase separate, can be gelled, preventing this phenomenon.
Typically,
gelling agents may be added in an amount of 0.1% by weight up to about 5% by
weight or preferably 0.5% by weight up to about 3.5% by weight or more
preferably
1% by weight up to about 2% by weight.
[0049] Gelling Agent
[0050] In accordance with some embodiments of the present disclosure, a
packer fluid
comprises a theological additive, as noted above, added to a hydrocarbon fluid
that
includes one or more gelling agents, such as phosphoric acid esters in the
presence
of a ferric or aluminum compound. The hydrocarbons, for example, may be
diesels,
paraffin oils, crude oils, kerosene, or mixtures thereof. The phosphoric acid
esters
may have same or different alkyl groups, having various lengths. In accordance
with embodiments of the invention, the alkyl groups (i.e., the ester parts) of
the
phosphoric acid esters have two or more carbon atoms, and preferably at least
one of
the alkyl groups has 3 to 10 carbon atoms. The ferric or aluminum compounds
may
be organic or inorganic compounds, such as aluminum chloride, aluminum
alkoxide,
ferric chloride, organometallic complexes of aluminum or iron(III), amine
carboxylic acid salts of aluminum or iron(III), etc.
[0051] The phosphoric acid esters having a desired alkyl group may be
prepared
using phosphorous pentaoxide and triethyl phosphate (TEP) (or other similar
phosphate triesters) in the presence of a trace amount of water:
Trace H20
P205 TEP 13205 + (Et0)2P(0)0H + TEP
50 "C
(Et0)2P(0)0H + ROH (R0)2P(0)0-H + Et0H
[0052] In the reactions shown above, the tri-ethyl phosphate ester (TEP)
is partially
hydrolyzed to produce a phosphoric acid diethyl ester. The phosphoric acid
diethyl
ester is then transesterified with a selected alcohol (ROH) to regenerate a
phosphoric
acid dialkyl ester having at least one and often two ester alkyl groups
derived from
the ROH.
[0053] The alcohol (ROH), i.e., the length of the alkyl chain R, may be
selected to
provide the desired hydrophobicity. In accordance with embodiments of the
13
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
invention, the alcohols (ROH) have 2 or more carbons (i.e., ethanol or
higher), and
preferably, 2 to 10 carbons, which may be straight or branched chains. The
phosphoric acid dialkyl esters having the alkyl chain of 2-10 carbons long may
be
obtained from M-I L.L.C. (Houston, TX) under the trade name of ECF-976. In
accordance with some embodiments of the invention, the R group may include
aromatic or other functional groups, as long as it can still provide proper
solubility in
the hydrocarbon base fluids.
[0054] One of ordinary skill in the art would appreciate that various
other reactions
may be used to prepare the desired phosphoric esters without departing from
the
scope of the invention. For example, phosphoric acid esters may be prepared
using
phosphorous hemipentaoxide (or phosphorous pentaoxide P205) and a mixture of
long chain alcohols, as disclosed in U.S. Patent No. 4,507,213:
0
P4010 + 3 ROH + 3 ROH->R0-P-OH +
OH
0 0
II 11
R0-P-OH + 2 RD-P-OR
1 1
011 OH
[0055] This reaction produces a mixture of phosphoric acid mono esters and
diesters.
Furthermore, while the above reaction is shown with two different alcohols,
the
same reaction may also be perfumed with one kind of alcohol to simplify the
product composition. Note that embodiments of the invention may use a mixture
of
phosphoric acid esters, i.e., not limited to the use of a pure phosphoric acid
ester. As
used herein, "phosphoric acid esters" include mono acid di-esters and di-acid
mono esters.
[0056] Furtheimore, instead of or in addition to phosphoric esters,
embodiments
disclosed herein may also use phosphonic acid esters, as disclosed in U.S.
Patent
No. 6,511,944 issued to Taylor et al. A phosphonic acid ester has an alkyl
group
directly bonded to the phosphorous atom and includes one acid and one ester
group.
One of ordinary skill in the art would also recognize that other types of
gelling
agents may be used including anionic polymers, such as poly-(ethylene-co-
14
CA 02694951 2012-04-03
77680-131
chloroethylene-co-[sodium chloroethylene-sulfonatep, or emulsions formed from
an
emulsifier and a water-miscible internal phase.
[0057] Thus, in certain embodiments, a dialkyl diamide and/or a phosphoric
acid ester
(e.g., ECF-976 from M-I L.L.C.) or a phosphonic acid ester complexing with a
multivalent metal ion (e.g., ferric or aluminum ion, or ECF-977 from M-I
L.L.C.)
may be added to disclosed formulations.
[0058] Other gelling agents that may be used include oligovinyl
pyrolidone, an oil
soluble, very mildly cationic ter-polymer, available from International
Specialty
Products. Another suitable additive is EMI-759, available from M-I L.L.C.
[0059] Rheological Additives
[0060] Suitable rheological additives in accordance with embodiments of
the present
disclosure, for example, may include alkyl diamides, such as those having a
general
formula: R1-HN-00-(CH2)n-CO-NH-R2, wherein n is an integer from 1 to 20, more
preferably from 1 to 4, yet more preferably from 1 to 2, and R1 is an alkyl
groups
having from 1 to 20 carbons, more preferably from 4 to 12 carbons, and yet
more
preferably from 5 to 8 carbons, and R2 is hydrogen or an alkyl group having
from 1
to 20 carbons, or more preferably is hydrogen or an alkyl group having from 1
to 4
carbons, wherein R1 and R2 may or may not be identical. Such alkyl diamides
may
be obtained, for example, from M-I L.L.C. (Houston, TX) under the trade name
of
VersaPacTM. Other rheological additives include Bentone 150, TruVis, Garamite
1210, VG SupremeTM, and Laponite, which are organophilic clays, and RheThikTm,
which is a viscosity modifier available, for example, from M-I L.L.C.
(Houston,
TX).
[0061] Various formulations of fluids within the scope of the present
invention are
provided below as examples. However, the present invention is not limited to
the
described embodiments, but is bounded by the claims that follow.
[0062] Examples
[0063] In selected embodiments, OB WARP (which is disclosed
in U.S. Patent No. 6,586,372, assigned to the assignee of the
present invention), may be mixed in concentrations ranging
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
from 10-20 w/w% base oil, 2 ¨ 4 w/w% coating additive/dispersant, 0.1 -1 w/w%
emulsifier/dispersant, 0.1 ¨ 1 w/w% lime and 60-90 w/w% barite/weight
material.
[0064] In one embodiment, a 19.4 ppg folinulation of OB WARP, was
formulated in
accordance with embodiments disclosed in U.S. Patent No. 6,586,372, which is
assigned to the assignee of the present invention. Specifically, in this
embodiment,
the OB WARP was mixed with EDC-99DW, which is a paraffin oil, followed by the
addition of additional base oil, Bentone 150, and sufficient glycerol to
constitute 2%
by volume of the total mixture, on a Hamilton Beach mixer at ambient
temperature.
The resulting solution had a final density of 13.6 ppg. After mixing the
components,
the theological properties of the solution at 170 F were investigated. The
rheological
measurements were made using a Fann 35 viscometer, available from Fann
instrument company.
[0065] Specifically, the apparent viscosity was measured. Viscosity is
the ratio of the
shear stress to the shear rate and is an indication of flow resistance. For
many fluids,
apparent viscosity changes for different values of shear rate, and is measured
in
centipoise (cP). Shear rate is measured in RPM or sec-I. In this embodiment,
the
initial apparent viscosity was measured at six different shear rates: 600 rpm,
300
rpm, 200 rpm, 100 rpm, 6 rpm, and 3 rpm. The results are shown in Table 1,
below.
Table 1
Shear Rate (RPM) Initial
600 80
300 50
200 37
100 23
6 6
3 5
[0066] In a second embodiment, the rheological properties of an OB WARP
concentrate, formulated in accordance with embodiments disclosed in U.S.
Patent
No. 6,586,372 . were investigated at 40 F, 70 F, 120 F, 180 F, 250 F, 300 F,
16
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
350 F, and 400 F, on a Farin 75 viscometer. The results of this testing is
shown in
Table 2 below.
[0067]
"PV" is plastic viscosity (CPS) which is one variable used in the
calculation of viscosity characteristics of a drilling fluid. "YP" is yield
point
(lbs/100 ft2) which is another variable used in the calculation of viscosity
characteristics of drilling fluids.
100681
"GELS" (lbs/100 ft2) is a measure of the suspending characteristics and
the thixotropic properties of a drilling fluid.
Table 2
Temp Temp Pressure Pressure 600 300 200 100 6
3 Gel Gel PV VP Ty/YP
Num 10 10
psi bar rpm rpm rpm rpm rpm rpm sec min cp lb/hsf
1 40 4.0 0 0 593 297 184 87 8 5 6
14 296 1
2.33
2 70 21.0 0 0 280 141 92 47 5 3 4 10
139 2 1.06
3 120 49.0 0 0 130 73 51 28 4 2 3
8 57 16 0.05
4 120 49.0 5000 340 217 117 BO 43 5 3 2
10 100 17 0.10
6 120 49.0 10000 680 362 188 126 66 7 5 1
11 174 14 0.21
6 120 49.0 12000 816 444 228 152 78 8
6 1 12 216 12 0.31
7 180 82.0 0 0 81 48 35 21 3 2 3 10
33 15 0.04
8 180 82.0 5000 340 122 71 50 29 4 3 2
11 51 20 0.06
9 180 82.0 10000 680 184 103 73 41 6 4 2
12 81 22 0.09
180 82.0 12000 816 216 120 84 47 6 4 1 13 96 24
0.10..
11 180 82.0 15000 1020 276 150 105 57 7 5
1 13 126 24 0.13
12 180 82.0 20000 1361 415 219 151 80 9 7
1 15 196 23 0,21
13 250 121.0 5000 340 85 51 38 23 4 3 3 16
34 17 0.09
14 250 121.0 10000 680 119 69 51 31 5 4 2
18 50 19 0.12
250 121.0 12000 816 136 78 57 34 6 4 2 18 58 20
0.13
16 250 121.0 15000 1020 166 94 68 40 7 5 2
19 72 22 0.15
17 250 121.0 20000 1361 230 127 92 53 8 7 1
20 103 24 0.19
18 300 149.0 5000 340 74 44 34 22 5 4 4 24
30 14 0.20
19 300 149.0 10000 680 99 58 44 28 6 _ 4 3
25 41 17 0.21
300 149.0 12000 816 112 65 49 30 6 5 3 26 47 18
0.22
21 300 149.0 15000 1020 133 76 57 35 7 6 2
27 57 19 0.24
22 300 149.0 20000 1361 178 100 74 44 8 7 2
29 78 22 0.26
23 350 177.0 5000 340 69 41 32 21 5 4 5.
37 28 13 0.29
24 350 177.0 10000 680 89 52 40 26 6 5 4 39
37 15 0.31
350 177.0 12000 816 99 57 44 28 7 6 4 40 42 15
0.33
26 350 177.0 15000 1020 116 66 50 32 7 7 3
41 50 16 0.35
27 350 177.0 20000 1361 150 84 64 40 9 8 3
43 66 18 0.38
28 400 204.0 5000 340 67 39 31 21 6 6 7 59
28 11 0.49
29 400 204.0 10000 680 84 48 38 25 7 7 6 62
36 12 0.54
400 204.0 12000 816 93 53 41 28 7 7 5 63 40 13
0.53
31 400 204.0 15000 1020 107 60 47 31 9 8 5
65 47 13 0.59
32 400 204.0 20000 1361 135 75 68 37 11 10
4 68 60 15 0.61
17
CA 02694951 2010-01-28
WO 2009/023415 PCT/US2008/071046
[00691 Exemplary Applications
100701 Wellb ore fluids formulated in accordance with embodiments
disclosed herein
may be used in stimulation operations. For example, it is believed that a
fluid may
be useful when injecting CO2 at 400 F into an oil-producing zone.
[0071] In another application, a high density (19.9 ppg) annular fluid
may be used in
connection with a deep well, where a packer has been emplaced. As is known to
those in the art, typical packers employ elastomeric rings to contact the
borehole
wall to hold the packer in place to isolate zones of a well. If large pressure
differentials exist across the packer face, however, the packer will leak or
slide.
This can be a significant issue in certain deep wells. Using typical annular
fluids,
therefore, tends to lead to failures in this type of well, as typical annular
fluids have
a density of only about 8 ppg. Accordingly, a relatively large AP is seen by
the
packer. In order to circumvent this, a high density fluid formulated in
accordance
with an embodiment of the present invention, may "spot" emplaced, as part of a
two
fluid (or more) system, where the high density fluid is placed on top of the
packer in
order to avoid the AP on the packer. In addition, because both of the fluids
can be
formulated as gels, the fluids will not mix with each other.
100721 Those having ordinary skill in the art will appreciate that
embodiments
disclosed herein may be useful in any application where packer fluids may be
used.
[00731 Advantageously, and surprisingly, the present inventors have
discovered that
annular fluids founulated in accordance with the present disclosure, which
have
significantly higher solids content than prior art annular fluids, may be used
in
applications that require higher density than prior art formulations.
Advantageously,
annular fluids formulated in accordance with embodiments disclosed herein have
very good thermal properties while maintaining sufficient rheological
properties.
[0074] 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.
18
