U.S. patent application number 11/741199 was filed with the patent office on 2008-03-13 for dispersant coated weighting agents.
This patent application is currently assigned to M-I LLC. Invention is credited to Jarrod Massam.
Application Number | 20080064613 11/741199 |
Document ID | / |
Family ID | 38820321 |
Filed Date | 2008-03-13 |
United States Patent
Application |
20080064613 |
Kind Code |
A1 |
Massam; Jarrod |
March 13, 2008 |
DISPERSANT COATED WEIGHTING AGENTS
Abstract
A method of formulating a wellbore fluid that includes providing
a base fluid; and adding a sized weighting agent coated with a
dispersant made by the method of dry blending a weighting agent and
a dispersant to form a sized weighting agent coated with the
dispersant is disclosed.
Inventors: |
Massam; Jarrod; (Scotland,
GB) |
Correspondence
Address: |
OSHA LIANG/MI
ONE HOUSTON CENTER, SUITE 2800
HOUSTON
TX
77010
US
|
Assignee: |
M-I LLC
Houston
TX
|
Family ID: |
38820321 |
Appl. No.: |
11/741199 |
Filed: |
April 27, 2007 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
60825156 |
Sep 11, 2006 |
|
|
|
Current U.S.
Class: |
507/137 ;
507/100; 507/138 |
Current CPC
Class: |
C09K 8/032 20130101;
C09K 8/32 20130101; C09K 2208/18 20130101; C09K 8/03 20130101 |
Class at
Publication: |
507/137 ;
507/100; 507/138 |
International
Class: |
C09K 8/22 20060101
C09K008/22; C09K 8/32 20060101 C09K008/32 |
Claims
1. A method of formulating a wellbore fluid comprising: providing a
base fluid; and adding a sized weighting agent coated with a
dispersant made by the method comprising: dry blending a weighting
agent and a dispersant to form a sized weighting agent coated with
the dispersant.
2. The method of claim 1, wherein the weighting agent is at least
one selected from barite, calcium carbonate, dolomite, ilmenite,
hematite, olivine, siderite, manganese oxide, and strontium
sulfate.
3. The method of claim 1, wherein the weighting agent is sized by
the process of dry blending.
4. The method of claim 1, wherein the dry blending comprises dry
blending a sized weighting agent and a dispersant.
5. The method of claim 1, wherein the sized weighting agent has a
particle distribution given by d.sub.90 ranging from 2 to 8
.mu.m.
6. The method of claim 1, wherein the sized weighting agent has a
particle distribution given by d.sub.50 ranging from 0.5 to 4
.mu.m.
7. The method of claim 1, wherein the dispersant comprises at least
one selected from oleic acid, polybasic fatty acids, alkylbenzene
sulfonic acids, alkane sulfonic acids, linear alpa olefins sulfonic
acid, alkaline earth metal salts thereof, and phospholipids.
8. The method of claim 1, wherein the dispersant comprises
polyacrylate esters.
9. The method of claim 8, wherein the polyacrylate ester is at
least one selected from polymers of stearyl methacrylate,
butylacrylate, and acrylic acid.
10. The method of claim 1, wherein the base fluid is one selected
from a water-based fluid, an oil-based fluid, and an invert
emulsion.
11. The method of claim 1, wherein the wellbore fluid further
comprises a colloidal coated weighting agent.
12. A wellbore fluid comprising: a base fluid; and a sized
weighting agent coated with a dispersant made by the method
comprising: dry blending a weighting agent and a dispersant to form
a sized weighting agent coated with the dispersant.
13. The wellbore fluid of claim 12, wherein the base fluid is one
selected from a water-based fluid, an oil-based fluid, and an
invert emulsion.
14. The wellbore fluid of claim 12, wherein the wellbore fluid
further comprises: a colloidal coated weighting agent.
15. The wellbore fluid of claim 12, wherein the weighting agent is
at least one selected from barite, calcium carbonate, dolomite,
ilmenite, hematite, olivine, siderite, manganese oxide, and
strontium sulfate.
16. The wellbore fluid of claim 12, wherein the sized weighting
agent has a particle distribution given by d.sub.90 ranging from 2
to 8 .mu.m.
17. The wellbore fluid of claim 12, wherein the sized weighting
agent has a particle distribution given by d.sub.50 ranging from
0.5 to 4 .mu.m.
18. The wellbore fluid of claim 12, wherein the dispersant
comprises at least one selected from oleic acid, polybasic fatty
acids, alkylbenzene sulfonic acids, alkane sulfonic acids, linear
alpa olefins sulfonic acid, alkaline earth metal salts thereof, and
phospholipids.
19. The wellbore fluid of claim 12, wherein the dispersant
comprises polyacrylate esters.
20. The wellbore fluid of claim 19, wherein the polyacrylate ester
is at least one selected from polymers of stearyl methacrylate,
butylacrylate, and acrylic acid.
21. The wellbore fluid of claim 12, wherein the weighting agent has
a particle size distribution selected from at least one of a
monomodal, bimodal, or polymodal distribution.
Description
CROSS-REFERENCE TO RELATED APPLICATION
[0001] This application claims priority to U.S. Provisional Patent
Application No. 60/825,156, filed Sep. 11, 2006, the disclosure of
which is incorporated herein by reference.
BACKGROUND OF INVENTION
[0002] 1. Field of the Invention
[0003] The invention relates generally to fluids and surface coated
solid materials for use in a wellbore fluid.
[0004] 2. Background Art
[0005] When drilling or completing wells in earth formations,
various fluids typically are used in the well for a variety of
reasons. 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.
[0006] In general, drilling fluids should be pumpable under
pressure down through strings of drilling pipe, then through and
around the drilling bit head deep in the earth, and then returned
back to the earth surface through an annulus between the outside of
the drill stem and the hole wall or casing. Beyond providing
drilling lubrication and efficiency, and retarding wear, drilling
fluids should suspend and transport solid particles to the surface
for screening out and disposal. In addition, the fluids should be
capable of suspending additive weighting agents (to increase
specific gravity of the mud), generally finely ground barites
(barium sulfate ore), and transport clay and other substances
capable of adhering to and coating the borehole surface.
[0007] Drilling fluids are generally characterized as thixotropic
fluid systems. That is, they exhibit low viscosity when sheared,
such as when in circulation (as occurs during pumping or contact
with the moving drilling bit). However, when the shearing action is
halted, the fluid should be capable of suspending the solids it
contains to prevent gravity separation. In addition, when the
drilling fluid is under shear conditions and a free-flowing
near-liquid, it must retain a sufficiently high enough viscosity to
carry all unwanted particulate matter from the bottom of the well
bore to the surface. The drilling fluid formulation should also
allow the cuttings and other unwanted particulate material to be
removed or otherwise settle out from the liquid fraction.
[0008] There is an increasing need for drilling fluids having the
Theological profiles that enable these wells to be drilled more
easily. Drilling fluids having tailored Theological properties
ensure that cuttings are removed from the wellbore as efficiently
and effectively as possible to avoid the formation of cuttings beds
in the well which can cause the drill string to become stuck, among
other issues. There is also the need from a drilling fluid
hydraulics perspective (equivalent circulating density) to reduce
the pressures required to circulate the fluid, this helps to avoid
exposing the formation to excessive forces that can fracture the
formation causing the fluid, and possibly the well, to be lost. In
addition, an enhanced profile is necessary to prevent settlement or
sag of the weighting agent in the fluid, if this occurs it can lead
to an uneven density profile within the circulating fluid system
which can result in well control (gas/fluid influx) and wellbore
stability problems (caving/fractures).
[0009] To obtain the fluid characteristics required to meet these
challenges, the fluid must be easy to pump so it requires the
minimum amount of pressure to force it through restrictions in the
circulating fluid system, such as bit nozzles or down-hole tools.
Or in other words, the fluid must have the lowest possible
viscosity under high shear conditions. Conversely, in zones of the
well where the area for fluid flow is large and the velocity of the
fluid is slow or where there are low shear conditions, the
viscosity of the fluid needs to be as high as possible in order to
suspend and transport the drilled cuttings. This also applies to
the periods when the fluid is left static in the hole, where both
cuttings and weighting materials need to be kept suspended to
prevent settlement. However, it should also be noted that the
viscosity of the fluid should not continue to increase under static
conditions to unacceptable levels. Otherwise when the fluid needs
to be circulated again this can lead to excessive pressures that
can fracture the formation or alternatively it can lead to lost
time if the force required to regain a fully circulating fluid
system is beyond the limits of the pumps.
[0010] Wellbore fluids must also contribute to the stability of the
well bore, and control the flow of gas, oil or water from the pores
of the formation in order to prevent, for example, the flow or blow
out of formation fluids or the collapse of pressured earth
formations. The column of fluid in the hole exerts a hydrostatic
pressure proportional to the depth of the hole and the density of
the fluid. High-pressure formations may require a fluid with a
specific gravity as high as 3.0.
[0011] A variety of materials are presently used to increase the
density of wellbore fluids. These include dissolved salts such as
sodium chloride, calcium chloride and calcium bromide.
Alternatively, powdered minerals such as barite, calcite and
hematite are added to a fluid to form a suspension of increased
density. The use of finely divided metal, such as iron, as a weight
material in a drilling fluid wherein the weight material includes
iron/steel ball-shaped particles having a diameter less than 250
.mu.m and preferentially between 15 and 75 .mu.m has also been
described. The use of finely powdered calcium or iron carbonate has
also been proposed; however, the plastic viscosity of such fluids
rapidly increases as the particle size decreases, limiting the
utility of these materials.
[0012] One requirement of these wellbore fluid additives is that
they form a stable suspension and do not readily settle out. A
second requirement is that the suspension exhibit a low viscosity
in order to facilitate pumping and to minimize the generation of
high pressures. Finally, the wellbore fluid slurry should also
exhibit low fluid loss.
[0013] Conventional weighting agents such as powdered barite
exhibit an average particle diameter (d.sub.50) in the range of
10-30 .mu.m. To adequately suspend these materials requires the
addition of a gellant such as bentonite for water-based fluids, or
organically modified bentonite for oil-based fluids. A soluble
polymer viscosifier such as xanthan gum may be also added to slow
the rate of the sedimentation of the weighting agent. However, as
more gellant is added to increase the suspension stability, the
fluid viscosity (plastic viscosity and/or yield point) increases
undesirably resulting in reduced pumpability. This is also the case
if a viscosifier is used to maintain a desirable level of solids
suspension.
[0014] The sedimentation (or "sag") of particulate weighting agents
becomes more critical in wellbores drilled at high angles from the
vertical, in that a sag of, for example, one inch (2.54 cm) can
result in a continuous column of reduced density fluid along the
upper portion of the wellbore wall. Such high angle wells are
frequently drilled over large distances in order to access, for
example, remote portions of an oil reservoir. In such instances it
is important to minimize a drilling fluid's plastic viscosity in
order to reduce the pressure losses over the borehole length. At
the same time a high density also should be maintained to prevent a
blow out. Further, as noted above with particulate weighting
materials the issues of sag become increasingly important to avoid
differential sticking or the settling out of the particulate
weighting agents on the low side of the wellbore.
[0015] Being able to formulate a drilling fluid having a high
density and a low plastic viscosity is also important in deep high
pressure wells where high-density wellbore fluids are required.
High viscosities can result in an increase in pressure at the
bottom of the hole under pumping conditions. This increase in
"Equivalent Circulating Density" can result in opening fractures in
the formation, and serious losses of the wellbore fluid into the
fractured formation. Again the stability of the suspension is
important in order to maintain the hydrostatic head to avoid a blow
out. The goal of high-density fluids with low viscosity plus
minimal sag of weighting material continues to be a challenge.
Thus, there is a need for materials that increase fluid density
while simultaneously providing improved suspension stability and
minimizing both fluid loss and increases in viscosity.
SUMMARY OF INVENTION
[0016] In one aspect, embodiments disclosed herein relate to a
method of formulating a wellbore fluid that includes providing a
base fluid; and adding a sized weighting agent coated with a
dispersant made by the method of dry blending a weighting agent and
a dispersant to form a sized weighting agent coated with the
dispersant.
[0017] In another aspect, embodiments disclosed herein relate to a
wellbore fluid that includes a base fluid; and a sized weighting
agent coated with a dispersant made by the method of dry blending a
weighting agent and a dispersant to form a sized weighting agent
coated with the dispersant.
[0018] Other aspects and advantages of the invention will be
apparent from the following description and the appended
claims.
BRIEF SUMMARY OF DRAWINGS
[0019] FIG. 1 shows a flow diagram of a dry blending process in
accordance with one embodiment disclosed herein.
DETAILED DESCRIPTION
[0020] In one aspect, embodiments disclosed herein relate to
dispersant coatings on weighting agents used in wellbore fluids. In
another aspect, embodiments disclosed herein relate to the
formulation of wellbore fluids that include dispersant coated
weighting agents.
[0021] In one embodiment, a weighting agent may be coated with a
dispersant by a dry blending process. The resultant coated
weighting agent may be added in new drilling fluid formulations or
added to existing formulations. The term "dry blending" refers to a
process in which the weighting agent is mixed and coated with a
dispersant in the absence of a solvent. An analogous process in the
presence of solvent generating colloidal coated particles has been
disclosed in U.S. Patent Application No. 20040127366 assigned to
the assignee of the present application, which is herein
incorporated by reference. As used herein the term "sized weighting
agent" refers to weighting agents having particle size distribution
reduced below conventional API specified distribution. Finally, one
skilled in the art would recognize that the weighting agent may be
dry blended with the dispersant in a comminution process (grinding)
process or by other means such as, for example, thermal
desorption.
[0022] Weighting Agent
[0023] Weighting agents used in 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 materials including, for example, barium sulphate
(barite), calcium carbonate, dolomite, ilmenite, hematite, 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.
[0024] In one embodiment, the weighting agent may be a sized
weighting agent having a d.sub.90 ranging from 1 to 25 .mu.m and a
d.sub.50 ranging from 0.5 to 10 .mu.m. In another embodiment, the
sized weighting agent includes particles having a d.sub.90 ranging
from 2 to 8 .mu.m and a d.sub.50 ranging from 0.5 to 4 .mu.m. 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 monomodal, which may or may not be
Gaussian, bimodal, or polymodal.
[0025] The use of sized weighting agents has been disclosed in U.S.
Patent Application No. 20050277553 assigned to the assignee of the
current application, which is herein incorporated by reference.
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, high performance dry milling
techniques, or any other technique that is known in the art
generally for milling powdered products. 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 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 sized weighting agents may
be formed by chemical precipitation. Such precipitated products may
be used alone or in combination with mechanically milled
products.
[0026] Dispersant
[0027] 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 acid,
phospholipids such as lecithin, including salts thereof and
including mixtures therof. Synthetic polymers may also be utilized
such as HYPERMER OM-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.
[0028] When the additive is to be used in water-based fluids, a
water soluble polymer of molecular weight of at least 2000 Daltons
may be used in a particular embodiment. Examples of such water
soluble polymers may include a homopolymer or copolymer of any
monomer selected from acrylic acid, itaconic acid, maleic acid or
anhydride, hydroxypropyl acrylate vinylsulphonic acid, acrylamido
2-propane sulphonic acid, acrylamide, styrene sulphonic acid,
acrylic phosphate esters, methyl vinyl ether and vinyl acetate or
salts thereof.
[0029] 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.
[0030] Further, it is specifically within the scope of the
embodiments disclosed herein that the polymeric dispersant be
polymerized prior to or simultaneously with the dry blending
processes disclosed herein. Such polymerizations may involve, for
example, thermal polymerization, catalyzed polymerization or
combinations thereof.
[0031] Coating Process
[0032] Coating of the weighting agent with the dispersant may be
performed in a dry blending process such that the process is
substantially free of solvent. With reference to FIG. 1, one
embodiment for producing a coated weighting agent is illustrated.
The process includes blending the weighting agent 10 and a
dispersant 12 at a desired ratio to form a blended material. In one
embodiment, the weighting agent 10 may be unsized 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.
[0033] The blended material 14 may then be fed to a heat exchange
system 16, such as a thermal desorption system. The mixture may be
forwarded through the heat exchanger using a mixer 18, such as a
screw conveyor. Upon cooling, the polymer may remain associated
with the weighting agent. The polymer/weighting agent mixture 20
may then be separated into polymer coated weighting agent 22,
unassociated polymer 24, and any agglomerates 26 that may have
formed. The unassociated polymer 24 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 a monomeric dispersant as described
above 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] According to yet another embodiment, the dispersant is
coated onto the weighting agent during the grinding process. That
is to say, coarse weighting agent 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 in the
grinding fluid, as opposed to that in a drilling fluid, the
dispersant is more likely to be adsorbed (either physically or
chemically) to the particle surface. 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.
[0036] One of ordinary skill in the art would appreciate that the
dry coated particles may be obtained from an oil-based slurry
through methods such as spray drying and thermal desorption, for
example.
[0037] In one embodiment, the dispersant may comprise from about 1%
to about 10% of the total mass of the dispersant plus weighting
agent.
[0038] Use in Wellbore Formulations.
[0039] In accordance with one embodiment, the dry coated weighting
agent may be used in a wellbore fluid formulation. The wellbore
fluid may be a water-based fluid, an invert emulsion or an
oil-based fluid.
[0040] Water-based wellbore fluids may have an aqueous fluid as the
base solvent and a dispersant coated weighting agent. The aqueous
fluid may include at least one of fresh water, sea water, brine,
mixtures of water and water-soluble organic compounds and mixtures
thereof. 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, sulfur, aluminum,
magnesium, potassium, strontium, silicon, lithium, and phosphorus
salts of chlorides, bromides, carbonates, iodides, chlorates,
bromates, fonnates, nitrates, oxides, 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. In one
embodiment, the density of the drilling fluid may be controlled by
increasing the salt concentration in the brine (up to saturation).
In a particular embodiment, a brine may include halide or
carboxylate salts of mono- or divalent cations of metals, such as
cesium, potassium, calcium, zinc, and/or sodium.
[0041] The oil-based/invert emulsion wellbore fluids may include an
oleaginous continuous phase, a non-oleaginous discontinuous phase,
and a dispersant coated weighting agent. One of ordinary skill in
the art would appreciate that the dispersant coated weighting
agents described above may be modified in accordance with the
desired application. For example, modifications may include the
hydrophilic/hydrophobic nature of the dispersant.
[0042] The oleaginous fluid may be a liquid and more preferably is
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 poly(alpha-olefins), linear and branch olefins and the
like, polydiorganosiloxanes, sitoxanes, or organosiloxanes, esters
of fatty acids, specifically straight chain, branched and cyclical
alkyl ethers of fatty acids, mixtures thereof and similar compounds
known to one of skill in the art; and mixtures thereof. The
concentration of the oleaginous fluid should be sufficient so that
an invert emulsion forms and may be less than about 99% by volume
of the invert emulsion. In one embodiment, the amount of oleaginous
fluid is from about 30% to about 95% by volume and more preferably
about 40% to about 90% by volume of the invert emulsion fluid. The
oleaginous fluid, in one embodiment, may include at least 5% by
volume of a material selected from the group including esters,
ethers, acetals, dialkylcarbonates, hydrocarbons, and combinations
thereof.
[0043] The non-oleaginous fluid used in the formulation of the
invert emulsion fluid disclosed herein is a liquid and may be an
aqueous liquid. In one embodiment, the non-oleaginous liquid may be
selected from the group including sea water, a brine containing
organic and/or inorganic dissolved salts, liquids containing
water-miscible organic compounds and combinations thereof. The
amount of the non-oleaginous fluid is typically less than the
theoretical limit needed for forming an invert emulsion Thus, in
one embodiment, the amount of non-oleaginous fluid is less that
about 70% by volume and preferably from about 1% to about 70% by
volume. In another embodiment, the non-oleaginous fluid is
preferably from about 5% to about 60% by volume of the invert
emulsion fluid. The fluid phase may include either an aqueous fluid
or an oleaginous fluid, or mixtures thereof. In a particular
embodiment, coated barite or other weighting agents may be included
in a wellbore fluid comprising an aqueous fluid that includes at
least one of fresh water, sea water, brine, and combinations
thereof
[0044] The fluids disclosed herein are especially useful in the
drilling, completion and working over of subterranean oil and gas
wells. In particular the fluids disclosed herein may find use in
formulating drilling muds and completion fluids that allow for the
easy and quick removal of the filter cake. Such muds and fluids are
especially useful in the drilling of horizontal wells into
hydrocarbon bearing formations.
[0045] Conventional methods can be used to prepare the drilling
fluids disclosed herein in a manner analogous to those normally
used, to prepare conventional water- and oil-based drilling fluids.
In one embodiment, a desired quantity of water-based fluid and a
suitable amount of the dispersant coated weighting agent are mixed
together and the remaining components of the drilling fluid added
sequentially with continuous mixing. In another embodiment, a
desired quantity of oleaginous fluid such as a base oil, a
non-oleaginous fluid and a suitable amount of the dispersant coated
weighting agent are mixed together and the remaining components are
added sequentially with continuous mixing. An invert emulsion may
be formed by vigorously agitating, mixing or shearing the
oleaginous fluid and the non-oleaginous fluid.
[0046] Other additives that may be included in the wellbore fluids
disclosed herein include for example, wetting agents, organophilic
clays, viscosifiers, fluid loss control agents, surfactants,
dispersants, interfacial tension reducers, pH buffers, mutual
solvents, thinners, thinning agents 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.
[0047] In yet another embodiment, an existing drilling fluid
formulation may be modified with a dispersant coated weighting
agent. For example, one may add dispersant-coated weighting agents
of the present disclosure to the wellbore fluids disclosed in U.S.
Patent Application 20040127366 (the '366 application) assigned to
the assignee of the present application. The wellbore fluids of the
'366 application contain colloidal coated weighting agent particles
derived from a blending process in the presence of solvent.
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. However, one of ordinary skill in the art would
recognize that the dispersant coated weighting agent of the present
disclosure may be added to any type of existing wellbore fluid
formulation.
EXAMPLES
[0048] The following examples include exemplary coated and uncoated
weighting agents and experimental data showing their fluid loss and
rheological properties. Oil-based drilling fluids were tested over
a mud weight range of 12.5-22.0 ppg and temperatures of
250-350.degree. F. using a polyacrylate polymer coated barite as
the weighting material.
Example 1
[0049] A 14 pounds per gallon (ppg) fluid was formulated with EDC
99DW, a highly hydrogenated mineral oil (M-I LLC, Houston, Tex.),
as the oleaginous phase. For the purpose of comparison, 14 ppg
solutions were formulated with dispersant coated barite as well as
uncoated barite. Quantities of each component are expressed in
pounds per barrel (ppb) as shown in Table 1 below (EMUL HT.TM. and
TRUVIS.TM. are each available from M-I LLC, Houston, Tex.).
TABLE-US-00001 TABLE 1 14 ppg Fluid Formulation Product Purpose ppb
EDC 99DW Base oil 152 Barite Density 354 EMUL HT .TM. Emulsifier 7
TRUVIS .TM. Viscosifier 4 Lime Alkalinity 6 CaCl.sub.2 Brine Brine
65
[0050] Polyacrylate polymer coated barite and uncoated barite in 14
ppg drilling fluids were formulated to an oil/water ratio (OWR) of
80/20 and aged at 250.degree. F. for 16 hours. Rheological
properties were determined using a Fann Model 35 viscometer,
available from Fann Instrument Company. Fluid loss was measured
with a saturated API high temperature, high pressure (HTHP) cell.
Gel strength (i.e., measure of the suspending characteristics or
thixotropic properties of a fluid) was evaluated by the 10 minute
gel strength in pounds per 100 square feet, in accordance with
procedures in API Bulletin RP 1313-2, 1990. Electrical stability
(ES) of the emulsion was measured by the test described in
"Composition and Properties of Drilling and Completion Fluids,"
5.sup.th Ed. H. C. H. Darley, George R. Gray, 1988, p. 116. The
results are shown in Table 2 below.
TABLE-US-00002 TABLE 2 14 ppg Fluid Properties 14 ppg; OWR 80/20;
250.degree. F. Fluid Property Coated Uncoated PV (cP) 17 18 YP
(lb/100 ft.sup.2) 7 15 Fann 35 6/3 rpm 3/2 8/7 10 min Gel (lb/100
ft.sup.2) 6 10 ES (v) 644 770 HTHP Fluid Loss (mL) 3.2 14.4
[0051] The results show an enhanced rheological profile with the
coated barite giving a lower yield point (YP), low-shear rate
viscosities and gel strength. The fluid loss also shows improvement
when using the coated barite.
Example 2
[0052] In accordance with one embodiment, an existing fluid
formulation may be weighted up with dispersant-coated weighting
agents. The following experiments were carried out with a 16 ppg
oil-based aged at 350.degree. F. Quantities of each component are
expressed in pounds per barrel (ppb) as shown in Table 3 below
(EMUL HT.TM., VERSAGEL.RTM., and VERSATROL.RTM. are each available
from M-I LLC, Houston, Tex.).
TABLE-US-00003 TABLE 3 16 ppg Fluid Formulation Product Purpose
Coated (ppb) Uncoated (ppb) EDC99DW Base oil 150 150 Barite Density
156 135 EMUL HT .TM. Emulsifier 10 10 VERSAGEL .RTM. HT Viscosifier
3 3 VERSATROL .RTM. HT Fluid loss 2.5 2.5 Lime Alkalinity 6 6
CaCl.sub.2 Brine Brine 66 66
[0053] Rheology and fluid loss tests were performed as described
above. Static sag measurements were obtained from aging the
formulated drilling fluid in a static condition at 350.degree. F.
for 16 hours. One skilled in the art will realize that this test
procedure relates to the behavior of the drilling fluid while
static in the well. The measurement records the volume of resulting
free oil on top of the column of drilling fluid as well as the
density of the top layer of the fluid column and the bottom layer
of the fluid column. These densities are used to calculate the
static sag factor, where the static sag
factor=(topSG+botttomSG)/bottomSG. The results are shown below in
Table 4.
TABLE-US-00004 TABLE 4 Weighted Up Fluid 16 ppg; AHR 350 F Fluid
Property Coated Uncoated PV (cP) 34 36 YP (lb/100 ft.sup.2) 8 10 3
rpm reading 3 3 ES (v) 691 631 HTHP Fluid Loss (mL) 5.6 8.4 Static
Sag Factor 0.517 0.531
[0054] Although the results demonstrate comparable rheology, the
dry coated barite gives a better static sag and fluid loss
performance.
Example 3
[0055] A 20 ppg fluid was formulated to an OWR of 90/10 and aged at
350.degree. F. Quantities of each component are expressed in pounds
per barrel (ppb) as shown in Table 5 below (SUREMUL.TM. and
VERSATROL.TM. are each available from M-I LLC, Houston, Tex.;
BENTONE is available from N L Industries, New York, N.Y.).
TABLE-US-00005 TABLE 5 20 ppg Fluid Formulation Product Purpose ppb
EDC99DW Base oil 120 Barite Density 676 SUREMUL .TM. EH Emulsifier
10 BENTONE 150 Viscosifier 0.5 BENTONE 42 Viscosifier 1.0 VERSATROL
.TM. HT Fluid loss 2.5 Lime Alkalinity 6.0 CaCl2 brine brine 24
[0056] Rheology and fluid loss tests were performed as described
above. Fluid loss and rheology measurements are shown in Table 6
below.
TABLE-US-00006 TABLE 6 High Density Fluid Properties 20 ppg; OWR
90/10; 350.degree. F. Fluid Property Coated PV (cP) 42 YP (lb/100
ft.sup.2) 1 3 rpm reading 2 ES (v) 1034 HTHP Fluid Loss (mL) 4.4
Static sag @ 375 F. 0.532
[0057] The results show that dry coated barite may be used to
formulate a very high density drilling fluid without the high
rheology typically associated with them. One of ordinary skill in
the art would appreciate the difficulty in not only obtaining a low
PV with a 20 ppg fluid but also the problems associated in mixing
and dispersing/wetting a fine uncoated weighting agent into an
oil-based fluid.
Example 4
[0058] The mixing, wetting and dispersibility of the barite in the
16 ppg oil-based fluid described above in Example 2 were tested as
summarized in Table 5 below.
TABLE-US-00007 TABLE 7 Dispersion/Wetting Evaluations 16 ppg Fluid
5 min 10 min 60 min Coated Uncoated Coated Uncoated Coated Uncoated
PV 56 83 55 78 55 66 YP 15 25 15 20 15 19
[0059] The results in Table 5 show that when adding the weight
material to the formulated drilling fluid, the coated barite
readily disperses and achieves its ultimate rheology within the
first 5 minutes, whereas when adding the uncoated barite, it takes
a much longer time to achieve its final rheology.
Example 5
[0060] A 14 pounds per gallon (ppg) fluid was formulated with DFJ
as the oleaginous phase. Three 14 ppg were formulated with
micronized manganese oxide: a mud containing uncoated micronized
manganese oxide, drilling mud including uncoated micronized
manganese oxide and a dispersant (EMI759, available from M-I LLC,
Houston, Tex.), and a dispersant (EMI759) coated manganese oxide.
The manganese oxide had a particle size distribution as follows:
d.sub.10=0.22 microns; d.sub.50=0.99 microns; d.sub.90=2.62
microns. Quantities of each component used in the mud formulations
are given in Table 8 below, expressed in ppb (EMUL HT.TM.,
TRUVIS.TM., and ECOTROL.RTM. are each available from M-I LLC,
Houston, Tex.).
TABLE-US-00008 TABLE 8 14 ppg Fluid Formulation Uncoated Mud w/
Dispersant Coated weighting and uncoated weighting Product Purpose
agent weighting agent agent DF1 Base oil 168.67 157.62 157.03
Manganese Oxide Density 325.44 325.66 340.22 EMUL HT .TM.
Emulsifier 10 10 10 EMI759 Dispersant or Coating 0 10 0 TRUVIS .TM.
Viscosifier 6 6 6 ECOTROL .RTM. Fluid loss additive 1 1 1 Lime
Alkalinity 6 6 6 CaCl.sub.2 Brine Brine 18.66 18.87 17.83 Fresh
Water 52.24 52.85 49.92
[0061] The above described drilling fluids were formulated to an
oil/water ratio (OWR) of 80/20 and aged at 250.degree. F. for 16
hours. Rheological properties were determined using a Fann Model 35
viscometer, available from Fann Instrument Company. Fluid loss was
measured with a saturated API high temperature, high pressure
(HTHP) cell. Gel strength (i.e., measure of the suspending
characteristics or thixotropic properties of a fluid) was evaluated
by the 10 minute gel strength in pounds per 100 square feet, in
accordance with procedures in API Bulletin RP 1313-2, 1990. The
results are shown in Table 9 below.
TABLE-US-00009 TABLE 9 14 ppg Fluid Properties 14 ppg; OWR 80/20;
250.degree. F. Fluid Property Uncoated Dispersant in Mud Coated PV
(cP) 17 16 15 YP (lb/100 ft.sup.2) 11 7 4 Fann 35 6/3 rpm 6/5 4/4
2/2 10 min Gel (lb/100 ft.sup.2) 7/8 5/6 2/5 HTHP Fluid Loss (mL)
7.2 8 2.8 Static Sag Factor 0.527 0.518 0.516
[0062] The results show an enhanced Theological profile with the
coated manganese oxide giving a lower yield point (YP), low-shear
rate viscosities and gel strength. The fluid loss also shows
improvement when using the dispersant coated manganese oxide. The
results in Table 9 also show the benefit of coating the weighting
agent with a dispersant as opposed to only including the dispersant
in the mud formulation.
[0063] Advantageously, the benefits of the coated weight material
may be optimum when a sized weighting agent is used. One skilled in
the art would recognize that there may be benefits realized outside
of a sized particle range, but a sized range may allow both ease of
material dispersion and a requirement of fewer drilling fluid
additives, such as an emulsifier and organoclay, to achieve the
desired fluid properties. At higher mud weights (>16 ppg) there
may be a considerable benefit in the ability of a dry-coated barite
to be mixed and dispersed into the fluid compared with the
difficulty of mixing and dispersing uncoated barite. Additionally,
while conventional fluids do not allow for optimal performance in
each of the aspects sag, rheology, and fluid loss, fluids such as
those disclosed herein may allow optimization in each of those
aspects. Further, because the coated weighting agent is formed in a
dry process, it may be used without requiring additional
weighting-up.
[0064] 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.
* * * * *