U.S. patent application number 14/094346 was filed with the patent office on 2014-04-03 for gravel pack carrier fluids.
This patent application is currently assigned to M-I L.L.C.. The applicant listed for this patent is M-I L.L.C.. Invention is credited to James Fredrick Donham, David P. Kippie.
Application Number | 20140090840 14/094346 |
Document ID | / |
Family ID | 43050889 |
Filed Date | 2014-04-03 |
United States Patent
Application |
20140090840 |
Kind Code |
A1 |
Kippie; David P. ; et
al. |
April 3, 2014 |
GRAVEL PACK CARRIER FLUIDS
Abstract
A method of gravel packing a hole in a subterranean formation
having a filter cake coated on the surface thereof is disclosed.
The method may include: injecting into the hole a gravel pack
composition comprising gravel and a carrier fluid comprising a base
fluid and at least one alkyl glycoside. Also disclosed is a
solution including an aqueous fluid, at least one alkyl glycoside,
and gravel which may be used as a composition for a gravel pack
operation, for example.
Inventors: |
Kippie; David P.; (Dubai,
AE) ; Donham; James Fredrick; (Mangaf, KW) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
M-I L.L.C. |
Houston |
TX |
US |
|
|
Assignee: |
M-I L.L.C.
Houston
TX
|
Family ID: |
43050889 |
Appl. No.: |
14/094346 |
Filed: |
December 2, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
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13526096 |
Jun 18, 2012 |
8596360 |
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14094346 |
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13319099 |
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PCT/US2010/033969 |
May 7, 2010 |
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13526096 |
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61176782 |
May 8, 2009 |
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61177892 |
May 13, 2009 |
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Current U.S.
Class: |
166/278 ;
507/209 |
Current CPC
Class: |
C09K 8/565 20130101;
C09K 8/575 20130101; E21B 33/13 20130101 |
Class at
Publication: |
166/278 ;
507/209 |
International
Class: |
C09K 8/575 20060101
C09K008/575; E21B 33/13 20060101 E21B033/13 |
Claims
1. A method of gravel packing a hole in a subterranean formation
having a filter cake coated on the surface thereof, comprising:
injecting into the hole a gravel pack composition comprising gravel
and a carrier fluid comprising a base fluid and at least one alkyl
glycoside; wherein the carrier fluid has at least one of: a density
of at least 11 pounds per gallon; and a Fann 35 viscometer value of
10 or less when measured at 300 rpm and 120.degree. F.
2. The method of claim 1, wherein the alkyl glycoside has an HLB of
about 9.5 to about 15.
3. The method of claim 1, wherein the alkyl glycoside has the
formula RO--(R'O).sub.xZ.sub.y where the letter O represents an
oxygen atom; R represents a monovalent alkyl radical containing
from 8 to 16 carbon atoms; R' represents a divalent alkyl radical
containing 2 to 4 carbon atoms; x represents the number of
oxy-alkylene units in the alkyl glycoside varying from 0 to about
12; Z represents a saccharide moiety containing 5 or 6 carbon
atoms, and y represents the number of saccharide units in the
glycoside.
4. The method of claim 3, wherein y ranges from 1.3 to 1.8.
5. The method of claim 1, wherein the carrier fluid further
includes a weighting agent that is a high density brine containing
water soluble salts of alkali and alkaline earth metals.
6. The method of claim 5, wherein the high density brine forms the
continuous phase of a direct emulsion fluid.
7. The method of claim 6, wherein the direct emulsion fluid has a
discontinuous phase selected from oleaginous fluids in the group
consisting of diesel oil, mineral oil, synthetic oils, fatty acid
ester based synthetic oils, polyolefin based synthetic oils,
saturated and unsaturated polyalpha olefins, saturated and
unsaturated long chain internal olefins, polydiorganosiloxanes,
siloxanes or organo-siloxanes, and mixtures thereof.
8. (canceled)
9. The method of claim 1, wherein the gravel pack composition is a
stable suspension, exhibiting essentially no phase separation for
at least 120 hours as measured at room temperature and
pressure.
10. The method of claim 1, wherein the carrier fluid further
comprises a scale inhibitor.
11. The method of claim 1, further comprising: allowing the
formation fluids to enter into the well; and producing fluids from
the well.
12. A method of gravel packing a hole in a subterranean formation
having a filter cake coated on the surface thereof, comprising:
injecting into the hole a gravel pack composition comprising gravel
and a carrier fluid comprising: a base fluid having a
non-oleaginous external phase and an oleaginous internal phase; and
at least one surfactant; wherein the carrier fluid has at least one
of: a density of at least 11 pounds per gallon; and a Fann 35
viscometer value of 10 or less when measured at 300 rpm and
120.degree. F.
13. The method of claim 12, wherein the surfactant is at least one
of an alkyl glucoside, alkyl poly glucoside, sorbitan esters,
ethoxylated alcohol, phenols, alkyl alkanolamide ethoxylate, alkyl
poly (ethylene oxide), Alkyl phenol poly (ethylene oxide), fatty
alcohols, cocoamide MEA, or mixtures thereof
14. The method in claim 12 where the surfactant is present at a
concentration of 0.01% to 15% by volume based on a total amount of
the base fluid and the surfactant.
15. A solution, comprising: an aqueous fluid; at least one alkyl
glycoside; and gravel; wherein the aqueous fluid has at least one
of: a density of at least 11 pounds per gallon; and a Fann 35
viscometer value of 10 or less when measured at 300 rpm and
120.degree. F.
16. The solution of claim 15, further comprising a weighting
agent.
17. The solution of claim 15, further comprising: at least one
selected from a wetting agent, a cleaning agent, a viscosifying
agent, a fluid loss control agent, a dispersant, an interfacial
tension reducer, a pH buffer, a thinner, defoamer, bactericide, and
a surfactant.
18. The solution of claim 15, wherein the aqueous fluid is selected
from fresh water, sea water, a brine containing organic and/or
inorganic dissolved salts, liquids containing water-miscible
organic compounds and combinations thereof.
19. The solution of claim 15, wherein the aqueous fluid forms the
continuous phase of a direct emulsion fluid.
20. The solution of claim 19, wherein the direct emulsion fluid has
a discontinuous phase selected from oleaginous fluids in the group
consisting of diesel oil, mineral oil, synthetic oils, fatty acid
ester based synthetic oils, polyolefin based synthetic oils,
saturated and unsaturated polyalpha olefins, saturated and
unsaturated long chain internal olefins, polydiorganosiloxanes,
siloxanes or organo-siloxanes, and mixtures thereof.
21. A solution, comprising: an aqueous fluid; at least one alkyl
glycoside; and a proppant; wherein the aqueous fluid has at least
one of: a density of at least 11 pounds per gallon and a Farm 35
viscometer value of 10 or less when measured at 300 rpm and
120.degree. F.
22. The solution of claim 21, wherein the proppant comprises at
least one of sand and a ceramic.
Description
BACKGROUND OF DISCLOSURE
[0001] 1. Field of the Disclosure
[0002] Embodiments disclosed herein relate generally to
compositions and methods used in completing a well. In particular,
embodiments disclosed herein relate to compositions and methods
used in gravel packing operations.
[0003] 2. Background
[0004] During the drilling of a wellbore, various fluids are
typically used in the well for a variety of functions. The fluids
may be circulated through a drill pipe and drill bit into the
wellbore, and then may subsequently flow upward through wellbore to
the surface. 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 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, emplacing a packer, abandoning the well or preparing
the well for abandonment, and otherwise treating the well or the
formation.
[0005] Once the well has been drilled and a target reservoir has
been encountered, the well is ready to be completed. Typically,
target formations are completed in one of two ways: cased hole
completion technique or an uncased completion technique. The
technique for completing a well is dependent on several factors,
which are known to those skilled in the art of completing target
reservoirs. For an cased hole completion, it is common practice to
run a string of casing into the well bore, cement the casing to the
target reservoir, displace the drilling fluid to a clear,
solid-free, non-damaging completion fluid by using a series of
wash/dispersing chemicals, and then run the production tubing
inside the casing. Once the casing is clean from solids/debris and
filled with completion fluid, perforations are typically created to
extend through the casing string, through the cement that secures
the casing string in place, and a short distance into the
formation. These perforations may be created by detonating shaped
charges carried in a perforating gun. The perforations created
cross one or more target zones to allow fluids to enter the
interior of the wellbore (in the case of a production well) or be
injected down the production tubing and into the reservoir (in the
case of an injection well).
[0006] After the well is perforated, a stimulation or sand control
treatment process may be performed. Sand control processes may
prevent, after the well is completed and placed in production,
formation sand from unconsolidated formations being swept into the
flow path along with formation fluid, which erodes production
components in the flow path. Similarly, in uncased boreholes or
openhole completions, where an open face is established across the
target zone, formation sand from unconsolidated formations may also
be swept into the flow path along with formation fluid.
[0007] Thus, with either cased or uncased well bores, one or more
sand screens may be installed in the flow path between the
production tubing and the rock face in the producing reservoir.
Additionally, the annulus around the screen may be packed with a
relatively coarse sand or gravel into the void between the
reservoir rock and the outside of the screen, to act as a filter to
reduce the amount of fine formation sand reaching the screen, to
support the porous medium of the producing reservoir so that it
will not collapse into the void between the reservoir rock and the
outside of the screen and to seal off the annulus in the producing
zone from non-producing formations. When the sand tries to move
through the gravel, it is filtered and held back by the gravel
and/or screen, but formation fluids continue to flow unhindered (by
either the gravel or screen) into the production string.
[0008] In deep wells, reliability of the sand face completion is
very important, due to the prohibitively high cost of intervention.
Further, as many such wells are completed open hole and in
relatively incompetent rock, gravel packing of open-hole horizontal
wells is increasingly becoming a standard practice in the
deep-water, sub-sea completion environment. The gravel packing
process involves mixing gravel with a carrier fluid, and pumping
the slurry down the tubing and through the cross-over, thereby
flowing into the annulus between the screen and the wellbore. The
carrier fluid in the slurry leaks off into the formation and/or
through the screen. The screen is designed to prevent the gravel in
the slurry from flowing through it and entering the production
tubing. As a result, the gravel is deposited in the annulus around
the screen where it becomes tightly packed, forming a "gravel
pack." Thus, gravel is deposited adjacent an open hole where it
serves to prevent sand and other formation fines from flowing into
the wellbore.
[0009] Proper selection of the carrier fluid is essential to a
gravel packing process. Ideally, the carrier fluid shall not cause
any permeability reduction of the formation. When viscous fluids
are used, carrier fluid must also have sufficient viscosity to
suspend and carry the gravel during placement. Carrier fluids are
either considered "water-based" or "oil-based" depending on the
constituency of their external continuous phase. Aqueous-base
fluids can be tailored to be compatible with most formations simply
by including salts such as potassium chloride, ammonium chloride,
or tetramethyl ammonium chloride. Consequently, to date, the
convention in gravel-packing horizontal wells has been water
packing or shunt-packing with water-based viscous fluids comprising
a brine, a gelling agent such as hydroxyethylcellulose (HEC), gums
(xanthan or guar), or a viscoelastic surfactant, and breakers to
minimize the pressure required to move the fluid back to the
wellbore.
[0010] Accordingly, there exists a continuing need for developments
in carrier fluids for gravel packing processes.
[0011] SUMMARY OF THE DISCLOSURE
[0012] In one aspect, embodiments disclosed herein relate to a
method of gravel packing a hole in a subterranean formation having
a filter cake coated on the surface thereof. The method may
include: injecting into the hole a gravel pack composition
comprising gravel and a carrier fluid comprising a base fluid and
an alkyl glycoside.
[0013] In another aspect, embodiments disclosed herein relate to a
method of gravel packing a hole in a subterranean formation having
a filter cake coated on the surface thereof. The method may
include: injecting into the hole a gravel pack composition
comprising gravel and a carrier fluid comprising: a base fluid
having a non-oleaginous external phase and an oleaginous internal
phase; and at least one surfactant.
[0014] In another aspect, embodiments disclosed herein relate to a
solution, including an aqueous fluid, at least one alkyl glycoside,
and gravel. The solution may be used as a composition for a gravel
pack operation, for example.
[0015] Other aspects and advantages will be apparent from the
following description and the appended claims.
DETAILED DESCRIPTION
[0016] Embodiments disclosed herein relate generally to
compositions and methods used in completing a well. In particular,
embodiments disclosed herein relate to compositions and methods
used in gravel packing operations and/or proppant transport
operations, where the proppant may include sand or ceramic
proppants, among others.
[0017] Carrier Fluid
[0018] The carrier fluids of the present disclosure may include a
base fluid and at least surfactant, such as an alkyl glycoside.
Alkyl glycosides are non-ionic, generally biodegradable
surfactants. Glycosides are substituted saccharides in which the
substituent group is attached, through an oxygen atom, to the
aldehyde or ketone carbon. Accordingly, glycosides are considered
acetals. As with the term "saccharide," the term "glycoside"
defines neither the number nor the identity of the saccharide units
in the molecule. To describe the identity of the saccharide units,
it is common to modify the name of the saccharide unit by adding
the ending "-side." For example, a glucoside is a glycoside having
one or more glucose units and a fructoside is a glycoside having
one or more fructose units. Surfactants may be used, for example,
at a concentration in the range from about 0.01% to about 15% by
volume, based on a total amount of the base fluid and the
surfactant, and may promote the formation of a stable emulsion or
suspension.
[0019] Alkyl glycoside nonionic surfactants used as a cleaning
agent in accordance with the present disclosure may have the
formula RO--(R'O).sub.xZ.sub.y where the letter O represents an
oxygen atom and R, R', x, Z, and y are as described below:
[0020] R represents a monovalent alkyl radical containing from 6 to
25 carbon atoms. The term "alkyl radical" is used herein to include
aliphatic or alicyclic. In other words, the alkyl radical may be
straight-chain or branched, saturated or unsaturated, and may
contain carbon, hydrogen, oxygen, etc. In a particular embodiment,
the alkyl groups are straight-chain saturated hydrocarbon radicals
containing 8 to 16 carbon atoms.
[0021] R' represents a divalent alkyl radical containing 2 to 4
carbon atoms where the term "alkyl radical" is used as discussed
above. The group (R'O) represents an oxy-alkylene repeating unit
derived generally from ethylene oxide, propylene oxide, or butylene
oxide.
[0022] The letter x represents the number of oxy-alkylene units in
the alkyl glycoside, and may vary from 0 to about 12. Oxy-alkylene
units may be added to an alcohol prior to reaction with the
saccharide (discussed below) as a way to obtain or vary the desired
chain length for the alkyl portion of the glycoside.
[0023] Z represents a reducing saccharide moiety containing 5 or 6
carbon atoms, and y represents the number of saccharide units in
the glycoside. The length of a saccharide chain is commonly
described either by adding a descriptive prefix to its name (e.g.,
monosaccharide, disaccharide, etc.) or by stating the chain's
"degree of polymerization" (abbreviated as DP) as a numerical value
representing the number of saccharide units bonded together to form
a chain. Monosaccharides are polyhydroxy aldehydes and polyhydroxy
ketones which, when unsubstituted, have the chemical formula
C.sub.nH.sub.2nO.sub.n. Monosaccharides can join together or
polymerize, with the loss of water, to form chains of varying
lengths and saccharide units. For example, glucose (also known as
dextrose) is a monosaccharide (DP=1); sucrose and maltose are
disaccharides (DP=2); and starch and cellulose are polysaccharides
having (DP=1000 or more).
[0024] Thus, glycosides encompass unsubstituted and substituted
molecules of any chain length. such as, for example, glucose,
galactose, mannose, xylose, arabinose, fructose, etc. as well as
materials which are hydrolyzable to form monosaccharides such as
lower alkyl glycosides (e.g. a methyl glycoside, an ethyl
glycoside, a propyl glycoside, a butyl glycoside, etc.),
oligosaccharides (e.g. sucrose, maltose, maltotriose, lactose,
xylobiose, melibiose, cellobiose, raffinose, stachyose, etc.) and
other polysaccharides. However, the degree of polymerization
affects the surface activity of the glycoside (by increasing the
hydrophilic portion of the molecule). Generally, surface activity
of an alkyl glycoside is maximized when the hydrophilicity of the
saccharide chain balances the lipophilicity of the alkyl chain
Thus, in a particular embodiment in which the alkyl groups have 10
to 16 carbon atoms, the average DP may be selected to range from
about 1.0 to 5.0, from about 1.2 to 3.0 in another embodiment, and
from about 1.3 to 1.8 in yet another embodiment.
[0025] Alkyl glycosides may be prepared by reacting an alcohol of
the type and chain length which is desired to form the "alkyl"
portion of the glycoside of interest with a saccharide reactant
(e.g., a monosaccharide such as glycose, xylose, arabinose,
galactose, fructose, etc., or a polysaccharide such as starch,
hemicellulose, lactose, maltose, melibiose, etc.) or with a
glycoside starting material wherein the aglycone portion thereof is
different from the alkyl substituent desired for the ultimate alkyl
glycoside product of interest. Typically, such reaction is
conducted at an elevated temperature and in the presence of an acid
catalyst. An example reaction pathway for formation of an alkyl
polyglucoside is shown below:
##STR00001##
[0026] The molar ratio of alcohol to monosaccharide in the reaction
mixture can vary widely but is typically between about 1.5:1 to
about 10:1, and preferably between about 2.0:1 to about 6.0:1. The
particular molar ratio chosen depends upon the desired average
degree of polymerization (DP) of the monosaccharide reacted with
the alcohol. Preferably, the ratio of alcohol to monosaccharide
will be chosen to allow the production of an alkyl glycoside
product having a DP between about 1.0 to about 5.0, from about 1.2
to about 3.0 in another embodiment, and from about 1.3 to about 1.8
in yet another embodiment.
[0027] The term "HLB" (Hydrophilic Lipophilic Balance) refers to
the ratio of the hydrophilicity of the polar groups of the
surface-active molecules to the hydrophobicity of the lipophilic
part of the same molecules. An HLB value of 0 corresponds to a
completely hydrophobic molecule, and a value of 20 would correspond
to a molecule made up completely of hydrophilic components. Thus,
depending on the alkyl chain length and the DP selected, the HLB
may correspondingly vary. In a particular embodiment, the HLB value
of the surfactant may range from 9.5 to 15 (and from about 11 to 14
in another embodiment) for desired cleaning action of the borehole
surface and to render the borehole surface water-wet (when
transitioning to a water-based fluid).
[0028] In addition to alkyl glycosides, other surfactants that may
be suitable for use in the gravel pack carrier fluids of the
present disclosure include sorbitan esters, ethoxylated alcohol,
phenols, alkyl alkanolamide ethoxylate, alkyl poly (ethylene
oxide), alkyl phenol poly (ethylene oxide), fatty alcohols,
cocoamide MEA or mixtures thereof.
[0029] In different embodiments of the present disclosure, the
gravel pack carrier fluid may be a water-in-oil emulsion (also
referred to as an invert emulsion), an oil-in-water emulsion (also
referred to as a direct emulsion) or water based. In a particular
embodiment, the gravel pack carrier fluid may be an oil-in-water or
direct emulsion. Preferably the gravel pack carrier fluids may have
a density that is sufficient to allow the fluid to control the well
during well completion operations, since open-hole gravel packing
is done almost exclusively in circulating position. Typical fluid
densities for the carrier fluid are from about 6.0 ppg (pounds per
gallon) up to about 19.2 ppg, more preferably about 6.0 ppg up to
14.2 ppg. In a particular embodiment, the carrier fluid may have a
density of at least 11 ppg.
[0030] Rheology of the gravel pack carrier fluid may also be an
important variable when selecting the carrier fluids. Rhelogical
properties of carrier fluids may be measured using a Fann 35
viscometer, and when measured at 300 rpm and 120.degree. F.,
carrier fluids according to embodiments disclosed may have a
measured value of 15 or less; 12 or less in other embodiments; 11
or less in other embodiments; and 10 or less in yet other
embodiments.
[0031] As noted above, in one embodiment the carrier fluid may
contain a base fluid and at least one alkyl glycoside or other
surfactant. The base fluid may contain at least one oleaginous
fluid or non-oleaginous fluid (or aqueous fluid). For example, the
carrier fluid may be a direct emulsion (non-oleaginous external
phase and oleaginous internal phase), an invert emulsion
(oleaginous external phase and non-oleaginous internal phase) or a
water-based fluid (no oleaginous phase). In a particular
embodiment, the carrier fluid may be a direct emulsion, whereby the
surfactant (including an alkyl glycoside) may stabilize the
oleaginous internal phase within the non-oleaginous external phase.
Additionally, the surfactant may also act to generate viscosity to
carry gravel and/or proppant, such as sand or a ceramic proppant,
down a wellbore.
[0032] The oleaginous fluid used for formulating the direct or
invert emulsion fluids of the present disclosure are liquids and
are more preferably a natural or synthetic oil and more preferably,
the oleaginous fluid is selected from the group including diesel
oil, mineral oil, synthetic oils such as ester based synthetic
oils, polyolefin based synthetic oils (i.e., saturated and
unsaturated polyalpha olefin, saturated and unsaturated long chain
internal olefins), polydiorganosiloxanes, siloxanes or
organo-siloxanes, and mixtures thereof and similar compounds that
should be known to one of skill in the art.
[0033] The non-oleaginous fluid used in the formulation of the
invert emulsion based fluids is a liquid and preferably is an
aqueous liquid. The aqueous fluids used in the carrier fluids 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 and
similar compounds that should be known to one of skill in the art.
Brines suitable for use as the base fluid of the carrier fluid
according to various embodiments of the present disclosure 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. The salinity
of seawater may range from about 1 percent to about 4.2 percent
salt by weight based on total volume of seawater. The solutions,
depending on the source of the seawater (ranging, for example, from
the seawater from the Beaufort Sea in summer, when the seawater is
relatively diluted due to melting of first-year ice, to the
seawater from the Arabian Sea in summer, when the seawater is
relatively concentrated due to evaporation of water), typically
contain metal salts, such as but not limited to, transition metal
salts, alkali metal salts, alkaline earth metal salts, and mixtures
thereof Exemplary salts include halides of zinc, calcium, and
mixtures thereof. For example, the solution can include zinc
halide, such as zinc bromide or zinc chloride or both, optionally
in combination with calcium bromide or calcium chloride or both.
Salts that may be found in seawater include, but are not limited
to, sodium, calcium, aluminum, magnesium, potassium, strontium, and
lithium salts of chlorides, bromides, carbonates, iodides,
chlorates, bromates, formates, sulfates, silicates, phosphates,
nitrates, oxides, and fluorides. Salts that may be incorporated in
a 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. The brine solution can include the
salts in conventional amounts, generally ranging from about 1% to
about 80%, and preferably from about 20% to about 60%, based on the
total weight of the solution, although as the skilled artisan will
appreciate, amounts outside of this range can be used as well. In a
particular embodiment, the brine may be a CaCl.sub.2 and/or
CaBr.sub.2 brine.
[0034] Further, embodiments of the present disclosure may further
use "specialty" brines that include at least one alkali metal salt
of a transition metal oxy-anion or polyoxy-anion, such as, for
example, an alkali metal polytungstate, an alkali metal
heteropolytungstate, an alkali metal polymolybdate or an alkali
metal heteropolymolybdate.
[0035] Each of the direct emulsions, the invert emulsion fluids and
water based fluids of the present invention may further contain
additional chemicals depending upon the end use of the fluid so
long as they do not interfere with the functionality of the fluids
described herein. For example, wetting agents, organophilic clays,
viscosifiers, fluid loss control agents, surfactants, dispersants,
interfacial tension reducers, pH buffers, mutual solvents,
thinners, thinning agents, scale inhibition agents, corrosion
inhibition agents, cleaning agents and a wide variety of the other
components known to one of skill in the art may be added to the
fluid compositions of this invention for additional functional
properties. The addition of such agents and the reasons for doing
so should be well known to one of ordinary skill in the art of
formulating drilling fluids (also known as drilling muds),
completion fluids, spacer fluids, clean-up fluids, fracturing
fluids, and other similar wellbore fluids. In selecting these other
components, one must take into account the type of fluid being
created (i.e. water-based v. direct emulsion v. invert emulsion),
the components of any filter cake on the wellbore walls, the
downhole conditions, etc. Routine laboratory testing will provide
guidance as to which components are helpful or detrimental to
achieving the desired results.
[0036] In embodiments where a water soluble polar organic solvent
is utilized, the water soluble polar organic solvent should be at
least partially soluble in an oleaginous fluid, but should also
have partial solubility in an aqueous fluid. The polar organic
solvent component of the present invention may be a mono-hydric,
di-hydric or poly-hydric alcohol or a mono-hydric, di-hydric, or
poly-hydric alcohol having poly-functional groups. Examples of such
compounds include aliphatic diols (i.e., glycols, 1,3-diols,
1,4-diols, etc.), aliphatic poly-ols (i.e., tri-ols, tetra-ols,
etc.), polyglycols (i.e., polyethylenepropylene glycols,
polypropylene glycol, polyethylene glycol, etc.), glycol ethers
(i.e., diethylene glycol ether, triethylene glycol ether,
polyethylene glycol ether, etc.) and other such similar compounds
that may be found useful in the practice of the present invention.
In one preferred embodiment, the water soluble organic solvent is a
glycol or glycol ether, such as ethylene glycol mono-butyl ether
(EGMBE). Other glycols or glycol ethers may be used in the present
invention so long as they are at least partially miscible with
water.
[0037] In an illustrative embodiment, an oleaginous-containing
carrier fluid is desired with a higher density than available from
the oleaginous fluid alone. Thus, a weighting agent is utilized to
increase the density of the overall fluid so as to match that of
the drilling fluid and to provide sufficient hydrostatic head so
that the well can remain under control. Preferably a high density
brine containing salts of alkali and alkaline earth metals may be
used to weight-up the fluids disclosed herein. For example, brines
formulated with high concentrations of sodium, potassium, or
calcium salts of the halides, formate, acetate, nitrate, and the
like; cesium salts of formate, acetate, nitrate, and the like, as
well as other compounds that should be well known to one of skill
in the art, can be used as solids free weighting agents. The
selection of a weighting agent may partially depend upon the
desired density of the carrier fluid, as known by one of ordinary
skill in the art.
[0038] The carrier fluids of the present disclosure may optionally
include a visocisifiers, including natural or biopolymers in
addition to synthetic polymer. Such "natural" polymers include HEC,
derivatized HEC, guars, derivatized guars, starches, derivatized
starches, scleroglu cans, wellan gums, locust bean gum, karaya gum,
gum tragacanth, carrageenans, alginates, gum arabic, and
biopolymers, such as, for example that derived from fermentation
with xanthomonas campestris, and other similar polymers including
ECF-612, which is commercially available from M-I LLC, Houston,
Tex., and described in U.S. Patent Application Ser. No. 60/894,363,
which is assigned to the present assignee and herein incorporated
by reference in its entirety.
[0039] Further, embodiments of the present disclosure may also use
a number of "synthetic" polymers, either exclusive of the
aforementioned "natural" polymers or in combination therewith.
"Synthetic" polymers include poly(ethylene glycol) (PEG),
poly(diallyl amine), poly(acrylamide), poly(acrylonitrile),
poly(vinyl acetate), poly(vinyl alcohol),
poly(aminomethylpropylsulfonate[AMP]), poly(vinyl amine),
poly(vinyl sulfonate), poly(styryl sulfonate), poly(acrylate),
poly(methyl acrylate), poly(methacrylate), poly(methyl
methacrylate), poly(vinylpyrrolidone), poly(vinyl lactam), co-,
ter-, and quater-polymers of the following co-monomers: ethylene,
butadiene, isoprene, styrene, divinylbenzene, divinyl amine,
1,4-pentadiene-3-one (divinyl ketone), 1,6-heptadiene-4-one
(diallyl ketone), diallyl amine, ethylene glycol, acrylamide, AMPS,
acrylonitrile, vinyl acetate, vinyl alcohol, vinyl amine, vinyl
sulfonate, styryl sulfonate, acrylate, methyl acrylate,
methacrylate, methyl methacrylate, vinylpyrrolidone, vinyl lactam
and other similar polymers.
[0040] Organophilic clays, normally amine treated clays, may be
useful as viscosifiers and/or emulsion stabilizers in the fluid
composition of the present invention. Other viscosifiers, such as
oil soluble polymers, polyamide resins, polycarboxylic acids and
soaps may also be useful. The amount of viscosifier used in the
composition can vary upon the end use of the composition. However,
normally about 0.1% to 6% by weight range is sufficient for most
applications. VG69.TM. and VG-PLUS.TM. and VG-Supreme are
organoclay materials distributed by M-I, L.L.C., Houston, Texas,
and Versa-HRP.TM. is a polyamide resin material manufactured and
distributed by M-I, L.L.C., that may be used in this invention.
Other examples of commercially available compounds include the
Bentone.TM. line of products produced by Rheox as well as similar
such materials widely known and available in the drilling fluids
industry.
[0041] Wetting agents that may be suitable for use in this
invention include crude tall oil, oxidized crude tall oil,
surfactants, organic phosphate esters, modified imidazolines and
amidoamines, alkyl aromatic sulfates and sulfonates, and the like,
and combinations or derivatives of these and similar such compounds
that should be well known to one of skill in the art. However, when
used with the invert emulsion fluids that undergo a pH controlled
phase change, the use of fatty acid wetting agents should be
minimized so as to not adversely affect the reversibility of such
invert emulsions as disclosed herein. Faze-Wet.TM., VersaCoat.TM.,
SureWet.TM., Versawet.TM. and Versawet.TM. NS are examples of
commercially available wetting agents manufactured and distributed
by M-I L.L.C. that may be used in the fluids disclosed herein.
Silwet L-77, L-7001, L7605, and L-7622 are examples of commercially
available surfactants and wetting agents manufactured and
distributed by General Electric Company (Wilton, Conn.).
[0042] Suitable thinners that may be used in the carrier fluids
disclosed herein include, for example, lignosulfonates, modified
lignosulfonates, polyphosphates, tannins, and low molecular weight
polyacrylates. Thinners are typically added to a drilling fluid to
reduce flow resistance and control gelation tendencies. Other
functions performed by thinners include reducing filtration and
filter cake thickness, counteracting the effects of salts,
minimizing the effects of water on the formations drilled,
emulsifying oil in water, and stabilizing fluid properties at
elevated temperatures.
[0043] The inclusion of cleaning agents in the fluids disclosed
herein should be well known to one of skill in the art. A wide
variety of synthetic and natural product derived cleaning agents
may be used. For example, a common natural product derived cleaning
agent is d-limonene. The cleaning ability of d-limonene in well
drilling applications is disclosed in U.S. Pat. No. 4,533,487, and
in combination with various specialty surfactants in U.S. Pat. No.
5,458,197, the contents of which are incorporated herein.
[0044] In a particular embodiment, a water-based carrier fluid may
be prepared by adding water (up to 50 percent by volume of the
final carrier fluid) to a brine (approximately 30 to 60 percent by
volume), an oleaginous fluid (up to 50 percent by volume), then an
alkyl glycoside (up to 20 percent by volume), and optionally an
acidic buffering agent (up to 30 percent by volume). Optionally, a
scale inhibitor may be added either after the acidic buffering
agent or after the emulsifier, and a viscosifier may be added prior
to the acidic buffering agent.
[0045] In other embodiments, the methods used in preparing each of
the water-based, direct, and invert emulsion carrier fluids used in
the methods of the present disclosure are not critical.
Specifically, with respect to the invert emulsion fluids,
conventional methods can be used to prepare the invert emulsion
fluids in a manner analogous to those normally used to prepare
oil-based drilling fluids. In one representative procedure, a
desired quantity of oleaginous fluid, such as C16-C18 internal
olefin, is mixed with the alkyl glycoside, and optional components,
such as a viscosifying agent and a wetting agent. The internal
non-oleaginous phase may be prepared by combining a polar organic
co-solvent, and a hydrolyzable ester into the selected brine with
continuous mixing. An invert emulsion of the present invention is
formed by vigorously agitating, mixing, or shearing the oleaginous
fluid and the non-oleaginous fluid in a conventional manner to form
the invert emulsion.
[0046] Use of Carrier Fluid in Wellbore
[0047] Specific techniques and conditions for pumping a gravel pack
composition into a well are known to persons skilled in this field.
The conditions which can be used for gravel-packing in the present
invention include pressures that are above fracturing pressure,
particularly in conjunction with the Alternate Path Technique,
known for instance from U.S. Pat. No. 4,945,991, and according to
which perforated shunts are used to provide additional pathways for
the gravel pack slurry. Furthermore, certain oil based gravel pack
compositions of the present invention with relatively low volume
internal phases (e.g., discontinuous phases) can be used with
alpha- and beta-wave packing mechanisms similar to water
packing.
[0048] Further, a wellbore contains at least one aperture, which
provides a fluid flow path between the wellbore and an adjacent
subterranean formation. In an open hole completed well, the
wellbore's open end, that is abutted to the open hole, may be the
at least one aperture. Alternatively, the aperture can comprise one
or more perforations in the well casing. At least a part of the
formation adjacent to the aperture has a filter cake coated on it,
formed by drilling the wellbore with either a water- or oil-based
wellbore fluid that deposits on the formation during drilling
operations and comprises residues of the drilling fluid. The filter
cake may also comprise drill solids, bridging/weighting agents,
surfactants, fluid loss control agents, and viscosifying agents,
etc. that are residues left by the drilling fluid.
[0049] Prior to production, breaker fluids may be used in cleaning
the filtercake from a wellbore that has been drilled with either a
water-based drilling mud or an invert emulsion based drilling mud.
Breaker fluid are typically circulated into the wellbore,
contacting the filter cake and any residual mud present downhole,
may be allowed to remain in the downhole environment until such
time as the well is brought into production. The breaker fluids may
also be circulated in a wellbore that is to be used as an injection
well to serve the same purpose (i.e. remove the residual mud and
filter cake) prior to the well being used for injection of
materials (such as water surfactants, carbon dioxide, natural gas,
etc . . . ) into the subterranean formation. Thus, the fluids
disclosed herein may be designed to form two phases, an oil phase
and a water phase, following dissolution of the filtercake which
can easily produced from the wellbore upon initiation of
production. Regardless of the fluid used to conduct the
under-reaming operation, the fluids disclosed herein may
effectively degrade the filtercake and substantially remove the
residual drilling fluid from the wellbore upon initiation of
production.
[0050] As an example of a commercially available oil based drilling
fluid, FAZEPRO.TM. reservoir drilling fluid (available from M-I
LLC, Houston, Tex.) is an oil-external emulsion system that can be
inverted to water-external emulsion if it is exposed to pH less
than about 7 or 8. When the filter cake is exposed, for example, to
an acidic solution, the emulsion inverts and the solid particles
therein (e.g., CaCO.sub.3, barite, etc.) become water-wet and thus
subject to removal through dissolution. Thus, the carrier fluids of
the present disclosure comprising acidic aqueous phases may be used
to pack gravel, while removing at least a portion of a filter cake
that comprises residues of the FAZEPRO.TM. drilling fluid.
[0051] It should be appreciated that the amount of delay between
the time when a breaker fluid is introduced to a well and the time
when the fluids have had the desired effect of
breaking/degrading/dispersing the filter cake may depend on several
variables. One of skill in the art should appreciate that factors
such as the downhole temperature, concentration of the components
in the breaker fluid, pH, amount of available water, filter cake
composition, etc. may all have an impact. For example downhole
temperatures can vary considerably from 100.degree. F. to over
400.degree. F. depending upon the formation geology and downhole
environment. However, one of skill in the art via trial and error
testing in the lab should easily be able to determine and thus
correlate downhole temperature and the time of efficacy of for a
given formulation of the breaker fluids disclosed herein. With such
information one can predetermine the time period necessary to
shut-in a well given a specific downhole temperature and a specific
formulation of the breaker fluid.
[0052] However it should also be appreciated that the breaker fluid
formulation itself and thus the fluid's chemical properties may be
varied so as to allow for a desirable and controllable amount of
delay prior to the breaking of invert emulsion filter cake for a
particular application. In one embodiment, the amount of delay for
an invert emulsion filter cake to be broken with a water-based
displacement fluid according to the present invention may be
greater than 1 hour. In various other embodiments, the amount of
delay for an invert emulsion filter cake to be broken with a
water-based displacement fluid according to the present invention
may be greater than 3 hours, 5 hours, or 10 hours. Thus the
formulation of the fluid can be varied to achieve a predetermined
break time and downhole temperature.
[0053] One of skill in the art should appreciate that in one
embodiment, the amount of delay for an water based filter cake to
be broken with a water based breaker fluid may be greater than 15
hours. In various other embodiments, the amount of delay for an
water-based filter cake to be broken with a water based breaker
fluid may be greater than 24 hours, 48 hours, or 72 hours. In
second embodiment, the amount of delay for an invert emulsion
filter cake to be broken with a water-based breaker fluid may be
greater than 15 hours. In various other embodiments, the amount of
delay for an invert emulsion filter cake to be broken with a water
based breaker fluid may be greater than 24 hours, 48 hours, or 72
hours. In a third embodiment, the amount of delay for an invert
emulsion filter cake to be broken with an invert emulsion
displacement fluid may be greater than 15 hours. In various other
embodiments, the amount of delay for an invert emulsion filter cake
to be broken with an invert emulsion displacement fluid may be
greater than 24 hours, 48 hours, or 72 hours.
EXAMPLES
[0054] A gravel pack carrier fluid according to embodiments
disclosed herein is prepared by mixing the ingredients as
formulated in Table 1 on a Silverson Mixer at 8000 rpm. ESCAID 110
is a desulfurized hydrogenated kerosene available from Exxon
Company USA (Houston, Tex.). The brine is a potassium formate brine
having a specific gravity of 1,56. The alkyl glycoside is SAFE-SURF
WN, a blend of anionic and non-ionic glucose-based surfactants,
available from M-I LLC (Houston, Tex.).
TABLE-US-00001 TABLE 1 Carrier Fluid Component Amount ESCAID 110 32
volume % Brine 68 volume % Alkyl Glycoside 5% v/v
[0055] The resulting carrier fluid has a density of approximately
11.0 pounds per gallon. The rheology of the resulting carrier fluid
is measured using a Fann 35 viscometer at 120.degree. F. and 300
rpm, resulting in a measured value of about 10. The electrical
stability of the carrier fluid is measured (25 mL CRYSTAL.RTM.),
returning a value of about 5.
[0056] Carrier fluid stability is measured by keeping 50 mL of the
fluid sample under static conditions in a measuring cylinder and
observing the amount of phase separation (defined herein as
separation of the dispersed oil/water phases and/or settling of
suspended particles) over time. Testing of the carrier fluid
indicates that the fluid is a stable suspension for a time period
of at least 120 hours from formation, measured at room temperature
and pressure, the carrier fluid exhibiting essentially no phase
separation during that time period.
[0057] As described above, gravel pack carrier fluids according to
embodiments disclosed herein may provide for efficient deposition
of gravel at or adjacent to the open hole to establish a fluid flow
path between the wellbore and the formation. This method may be
useful in wellbores that are drilled with either water- or
oil-based reservoir drilling fluids. The fluids of the present
disclosure have several benefits as compared to prior art gravel
packing methods and carrier fluids, including excellent stability,
showing no phase separation over times of 120 hours or greater.
Additionally, gravel pack carrier fluids according to embodiments
disclosed herein may enhance wellbore cleanup by introducing an
alkyl glycoside surfactant to the wellbore during the gravel pack
operation.
[0058] While the disclosure includes a limited number of
embodiments, those skilled in the art, having benefit of this
disclosure, will appreciate that other embodiments may be devised
which do not depart from the scope of the present disclosure.
Accordingly, the scope should be limited only by the attached
claims.
* * * * *