U.S. patent application number 13/966083 was filed with the patent office on 2014-02-27 for materials and methods to prevent fluid loss in subterranean formations.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to MUSTAPHA ABBAD, FRANK F. CHANG.
Application Number | 20140054039 13/966083 |
Document ID | / |
Family ID | 50146993 |
Filed Date | 2014-02-27 |
United States Patent
Application |
20140054039 |
Kind Code |
A1 |
CHANG; FRANK F. ; et
al. |
February 27, 2014 |
MATERIALS AND METHODS TO PREVENT FLUID LOSS IN SUBTERRANEAN
FORMATIONS
Abstract
Methods of preventing fluid loss in a downhole formation may
include preparing an emulsion containing: an oleaginous phase; an
aqueous phase; one or more fibers; injecting the emulsion into the
wellbore; allowing the one or more fibers within the emulsion to
seal a permeable interval of the formation. In another aspect,
methods of stimulating hydrocarbon production in a wellbore may
include: injecting a diverting treatment into a subterranean
formation, the diverting treatment containing: a non-oleaginous
fluid, an oleaginous fluid, and one or more fibers; injecting a
stimulating treatment into the subterranean formation; and
stimulating the production of hydrocarbons.
Inventors: |
CHANG; FRANK F.; (AL-KHOBAR,
SA) ; ABBAD; MUSTAPHA; (AL-KHOBAR, SA) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
|
|
|
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
|
Family ID: |
50146993 |
Appl. No.: |
13/966083 |
Filed: |
August 13, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61692460 |
Aug 23, 2012 |
|
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Current U.S.
Class: |
166/293 ;
166/292 |
Current CPC
Class: |
C09K 8/885 20130101;
C09K 8/76 20130101; E21B 33/138 20130101; C09K 8/516 20130101; C09K
8/502 20130101; C09K 2208/08 20130101; C09K 2208/30 20130101; E21B
21/003 20130101; C09K 2208/18 20130101; C09K 8/92 20130101; C09K
8/508 20130101 |
Class at
Publication: |
166/293 ;
166/292 |
International
Class: |
E21B 33/138 20060101
E21B033/138 |
Claims
1. A method of preventing fluid loss in a downhole formation,
comprising: injecting the emulsion into the wellbore, the emulsion
comprising: an oleaginous phase, an aqueous phase, one or more
fibers; and allowing the one or more fibers within the emulsion to
seal a permeable interval of the downhole formation.
2. The method of claim 1, wherein the emulsion is a water-in-oil
emulsion.
3. The method of claim 1, wherein the emulsion is an oil-in-water
emulsion.
4. The method of claim 1, wherein the average length of the one or
more fibers ranges from 100 .mu.m to 20 mm.
5. The method of claim 1, wherein the one or more fibers are added
at a concentration of 1 ppg to 15 ppg.
6. The method of claim 1, wherein the one or more fibers are
oleophilic.
7. The method of claim 6, wherein the one or more fibers are
selected from a group consisting of homopolymers, copolymers,
multi-block interpolymers, and higher order polymers of ethylene,
tetrafluoroethylene, vinylidene fluoride, propylene, butene,
1-butene, 4-methyl-1-pentene, styrene,
p-phenylene-2,6-benzobisoxazole, aramids, and urethanes.
8. The method of claim 1, wherein the one or more fibers are
hydrophilic.
9. The method of claim 8, wherein the one or more fibers are
selected from a group consisting of polymers, copolymers,
multi-block interpolymers, and higher order polymers of polylactic
acid, polyhydroxyalkanoates, polycaprolactones,
polyhydroxybutyrates, polyethylene terephthalates, polytriphenylene
terephthalate, polybutylene terephthalate, polyvinyl alcohols,
polyacrylamide, partially hydrolyzed polyacrylamide, polyvinyl
acetate, and partially hydrolyzed polyvinyl acetate.
10. The method of claim 1, wherein the one or more fibers are one
or more hydrophilic inorganic fibers selected from a group
consisting of calcium carbonate, calcium/magnesium carbonate,
magnesium carbonate, magnesium oxide, and calcium oxide.
11. The method of claim 1, wherein the one or more fibers are high
surface area fibers.
12. The method of claim 1, further comprising injecting an acid to
dissolve the one or more fibers, thereby stimulating production of
hydrocarbons.
13. The method of claim 1, wherein the emulsion further comprises
one or more particulate weighting agents.
14. The method of claim 13, wherein the particulate weighting
agents are acid soluble.
15. The method of claim 13, wherein the particulate weighting
agents have an average particle size (d.sub.50) that ranges from
100 nm to 100 .mu.m.
16. The method of claim 13, wherein the particulate weighting
agents are added at a concentration that ranges from 1 ppg to 20
ppg.
17. A method of stimulating hydrocarbon production in a wellbore
comprising: injecting a diverting treatment into a subterranean
formation, the diverting treatment comprising: a non-oleaginous
fluid, an oleaginous fluid, and one or more fibers; injecting a
stimulating treatment into the subterranean formation; and
stimulating the production of hydrocarbons.
18. The method of claim 17, wherein the diverting treatment further
comprises at least one particulate solid.
19. The method of claim 17, wherein the diverting treatment is an
invert emulsion.
20. The method of claim 17, wherein the stimulating treatment is an
acid wash.
Description
CROSS REFERENCE TO RELATED APPLICATION
[0001] This patent application claims the benefit of: U.S.
Provisional Patent Application Ser. No. 61/692460 filed Aug. 23,
2012, which is incorporated herein by reference in its
entirety.
BACKGROUND
[0002] 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 the
wellbore to the surface. During this circulation, the drilling
fluid may act to remove drill cuttings from the bottom of the hole
to the surface, to suspend cuttings and weighting material when
circulation is interrupted, to control subsurface pressures, to
maintain the integrity of the wellbore until the well section is
cased and cemented, to isolate the fluids from the formation by
providing sufficient hydrostatic pressure to prevent the ingress of
formation fluids into the wellbore, to cool and lubricate the drill
string and bit, and/or to maximize penetration rate.
[0003] Wellbore fluids are circulated downhole to remove rock, and
may deliver agents to combat the variety of issues described above.
Fluid compositions may be water- or oil-based and may comprise
weighting agents, surfactants, proppants, viscosifiers, fluid loss
additives and polymers. However, for a wellbore fluid to perform
all of its functions and allow wellbore operations to continue, the
fluid must stay in the borehole.
[0004] Frequently, undesirable formation conditions are encountered
in which substantial amounts or, in some cases, practically all of
the wellbore fluid may be lost to the formation. For example,
wellbore fluid can leave the borehole through large or small
fissures or fractures in the formation or through a highly porous
rock matrix surrounding the borehole. Lost circulation is a
recurring problem, characterized by loss of wellbore fluids into
downhole formations. Fluid losses affect a number of stages in
hydrocarbon production including drilling, completions and
production operations, for example. Wellbore fluid loss can occur
naturally in earthen formations that are fractured, highly
permeable, porous, cavernous or vugular. These earth formations can
include shale, sands, gravel, shell beds, reef deposits, limestone,
dolomite and chalk, among others.
[0005] In some applications, controlling the proper placement of
wellbore fluid treatments is of particular significance because
injected fluids tend to migrate to higher permeability zones, or
"thief zones," rather than to those having lower permeability. This
can present difficulties for fluid treatments that are intended to
target low permeability zones. For example, in production and
completion operations, acid washes may be used downhole to degrade
an acid-sensitive matrix like limestone or dolomite. Due to
variations in the permeability of a producing formation, an acid
treatment enters the most permeable intervals of the wellbore,
which can further increase the interval's permeability and capacity
to hold treatment fluids. In order to prevent this uneven
distribution, acid must be diverted from the most permeable
intervals of the formation into the less permeable intervals. Thus,
prior to the introduction of treatment fluids, it may be
advantageous to selectively plug high permeability regions of the
formation so that the treating solution remains in contact with
lower permeability regions.
[0006] A number of techniques have been developed to control fluid
placement, diverting the fluids from high permeability zones to
regions of interest, particularly by using a lost circulation
material (LCM) to seal or block further loss of circulation into
thief zones. These LCMs may generally be classified by their
mechanism of action such as surface plugging or interstitial
bridging, for example. In addition to traditional LCMs, polymers
that crosslink or absorb fluids and cement or gunk squeezes have
also been employed to reduce or stop the flow of fluids into
loosely consolidated formations.
[0007] Wellbore fluids containing LCMs are useful for a variety of
wellbore operations. For example, in drilling and completion
operations, sealing thief zones prevents lost circulation of
wellbore fluids and decreases the volume of fluid required. In
stimulation and production, LCM fluids decrease fluid flow to
highly permeable intervals, enabling the direction of subsequently
injected treatments to low permeability intervals and improving
uniform contact between the formation and the treatment fluid.
[0008] Sealing thief zones optimizes wellbore operations in the
short term and maximizes hydrocarbon extraction and overall
economic output in the long term. However, if not properly
designed, treatments injected into the well can fail to seal the
thief zones or, in some cases, hamper operations by decreasing or
stopping production by damaging formation permeability.
BRIEF DESCRIPTION OF THE DRAWINGS
[0009] The subject disclosure is further described in the detailed
description which follows, in reference to the noted plurality of
drawings by way of non-limiting examples of embodiments of the
subject disclosure, in which like reference numerals represent
similar parts throughout the several views of the drawings, and
wherein:
[0010] FIGS. 1-3 illustrate the collected mass versus time for
various embodiments of the present disclosure.
[0011] FIG. 4 illustrates shear rate versus viscosity for various
embodiments of the present disclosure.
[0012] FIG. 5 illustrates the collected mass versus time for
embodiments of the present disclosure.
SUMMARY
[0013] This summary is provided to introduce a selection of
concepts that are further described below in the detailed
description. This summary is not intended to identify key or
essential features of the claimed subject matter, nor is it
intended to be used as an aid in limiting the scope of the claimed
subject matter.
[0014] In one aspect, embodiments of the instant disclosure are
directed to methods of preventing fluid loss in a downhole
formation that include injecting the emulsion into the wellbore,
the emulsion containing: an oleaginous phase; an aqueous phase; one
or more fibers; and allowing the one or more fibers within the
emulsion to seal a permeable interval of the formation.
[0015] In another aspect, embodiments of the instant disclosure are
directed to methods of stimulating hydrocarbon production in a
wellbore that include: injecting a diverting treatment into a
subterranean formation, the diverting treatment containing: a
non-oleaginous fluid, an oleaginous fluid, and one or more fibers;
injecting a stimulating treatment into the subterranean formation;
and stimulating the production of hydrocarbons.
[0016] Other aspects and advantages of the invention will be
apparent from the following detailed description and the appended
claims.
DETAILED DESCRIPTION
[0017] Embodiments disclosed herein relate to methods of reducing
fluid flow into highly permeable or loosely consolidated formations
during wellbore operations in subterranean formations. Materials
and methods described herein may be applied in hydrocarbon
exploration, production, and recovery processes, such as drilling,
well completions, and production.
[0018] In one or more embodiments, an emulsion containing fibers
and/or other solids of various shapes and chemical properties may
be used to effectively plug thief zones. For example, wellbore
fluids may contain solids having various shapes, sizes and
rigidity, including, but not limited to, fibers, spheres, flakes,
and irregular shapes to plug high permeability paths present in oil
and gas reservoirs. High permeability paths may be naturally formed
fractures, hydraulically induced man-made fractures, dissolved
channels or cavities in carbonate rocks, or large and well
connected interstices existing among the rock grains.
[0019] In certain embodiments, emulsions and solids interact with
each other to create a mass that is resistant to flow in large
openings such as fractures, channels and cavities in subterranean
formations. The interactions between the emulsion and solids may
include: (1) forming a pseudo-rigid lump by the interfacial
force--the droplets from the emulsion pull the solids close to one
another by the wetting characteristics of the solids; (2) the
solids or mixtures of solids aggregate into a porous network which
provides high resistance to emulsion flow through such a network;
and/or (3) a combination of the two interacting mechanisms.
[0020] In some embodiments, wellbore fluids of the present
disclosure may be formulated as a drill-in fluid that enters the
formation to seal thief zones. In other embodiments, wellbore
fluids may be used as completion fluids, work-over fluids, spacer
fluids and liquid plugs. For example, as completion fluids,
wellbore fluids described herein may be placed in the well or
annulus thereof to temporarily or permanently seal thief zones in
order to facilitate final operations prior to initiation of
production. In one or more embodiments, placement of the wellbore
fluid may precede a treatment such as an acid treatment or
steamflooding to initiate hydrocarbon production, where the
wellbore fluid may be added into an injection well or a production
well. In other embodiments, when a formation is to be fractured by
a fracturing fluid, the wellbore fluid may be used to seal thief
zones (prior to the introduction of the fracturing fluid, for
example) to decrease the loss of fluid into the formation and
increase hydraulic pressure in the region of the well desired to be
fractured.
[0021] In other embodiments, when multiple fractures are to be
created by a fracturing fluid along a single horizontal well
penetrating through a formation, the wellbore fluid may be used to
seal the fractures created in earlier fluid injection stages to
decrease the loss of fluid into the earlier fractures and increase
hydraulic pressure in the region of the well desired to be
fractured.
[0022] In one or more embodiments, wellbore fluids in accordance
with the present disclosure may include a combination of one or
more fiber components and/or at least one particulate weighting
agent. In other embodiments, wellbore fluids may include a number
of other additives known to those of ordinary skill in the art of
wellbore fluid formulations, such as wetting agents, viscosifiers,
surfactants, dispersants, interfacial tension reducers, pH buffers,
mutual solvents, thinners, thinning agents, rheological additives
and cleaning agents.
Fiber Component
[0023] By plugging porous or vugular zones of the formation, fluid
loss compositions containing engineered combinations of solid
materials may provide an immediate blockage, preventing fluid flow
therethrough and facilitating further wellbore operations,
including drilling, completion, stimulation, or production
operations. In particular embodiments, by utilizing the unique
properties of three-dimensional shapes of fibrous materials and/or
combinations of fiber types, such materials may interact
synergistically to form a seal that arrests the flow of wellbore
fluids into or through the formation. The volume fraction of each
component in the emulsion-solids mixture is formulated and altered
based on the size and shape of the opening to be plugged.
[0024] As used herein, the terms "fiber" and "fibrous" are used to
denote a high aspect ratio molecular or macromolecular structure,
which may have a length greater than either its diameter or width
(i.e., a length that is greater than the other two dimensions).
Without being limited by any particular theory, it is believed that
as fibers present in a wellbore fluid enter fractures in the
formation, the fibers trap and entangle other particles present in
the surrounding fluid, creating an impermeable barrier that
prevents further fluid flow therethrough. The fiber component of a
selected wellbore fluid may also act to create a heterogeneous
three-dimensional network that can trap particulates of varying
sizes, generating a mass that prevents fluid flow therethrough. In
addition, the shape of the fiber component may also be varied
depending on the downhole conditions. In some embodiments, the
fiber component may include fibers of various shapes such as, for
example, multi-lobed, curved, hooked, tapered, or dumbbell. In
other embodiments, high-surface area "hairy" fibers may be
incorporated into wellbore fluid formulations to provide a fiber
component that may aggregate more efficiently and improve stability
in certain emulsion states.
[0025] In one or more embodiments, a fiber component in a wellbore
fluid may degrade under downhole conditions in a duration that is
suitable for the selected operation. Degradation of the fibers may
be assisted or accelerated by a wash containing an appropriate
dissolver or a wash or additive that changes the pH or salinity of
the surrounding wellbore fluid. The degradation may also be
assisted by an increase in temperature, such as when the treatment
is performed before enhanced recovery techniques such as
steamflooding. For example, a diverting or fluid loss composition
may have a relatively low acid solubility at room temperature, but
upon exposure to elevated temperatures, such as 100.degree. C. and
greater, the solubility of a fiber component of the fluid loss
composition may be increased to substantially or completely
soluble.
[0026] In some embodiments, the surface area of the fiber component
of the fluid loss composition may be used to tune properties that
include the susceptibility of the fiber component to dissolve in
acids or solvents. As a matter of practical application, the
diameter of the fiber may be used as a parameter that determines
both the performance of the fiber as a lost circulation material
and the rate at which the fiber degrades when exposed to acids and
solvents at a particular temperature. In some embodiments, it may
also be desirable that the fibers be able to pass through a gravel
or sand pack so as to permit effective treatment of a formation
located behind the pack.
[0027] The hydrophobicity and/or hydrophilicity may also be used to
tune the stability of the fiber component in a particular emulsion.
Depending on the composition of the emulsion and the overall
hydrophobicity or hydrophilicity of the fiber component of the
wellbore fluids, the fiber component may have increased or
decreased aggregation properties that vary with the composition of
the surrounding emulsions. For example, hydrophilic fibers may tune
the flocculation of fibers in a water-in-oil emulsion, while
hydrophobic fibers may increase aggregation in water-in-oil
emulsions. In some embodiments, a blend of hydrophobic and
hydrophilic fibers may be added to a diverting or fluid loss
composition to tune the flocculation properties and stability of
the fiber component in the emulsion, in addition to modifying the
sealing properties of the fluid loss composition.
[0028] In one or more embodiments, the fiber component added to the
wellbore fluid compositions of the present disclosure may include
hydrophobic (or equivalently oleophilic) polymeric fibers that may
be selected from, for example, polyolefins and polyaromatics that
may include homopolymers, copolymers, and multi-block interpolymers
of ethylene, tetrafluoroethylene, vinylidene fluoride, propylene,
butene, 1-butene, 4-methyl-1-pentene, styrene,
p-phenyene-2,6-benzobisoxazole, aramids, and the like. In other
embodiments, the hydrophobic polymeric fibers may be selected from
polyurethanes such as those formed from the reaction of
diisocyanate and a polyol, polyester, polyether, or polycarbonate
polyol.
[0029] In some embodiments, fibers may be selected from hydrophilic
fibers composed of polymers or co-polymers of esters, amides, or
other similar materials. Examples include polylactic acid,
polyhydroxyalkanoates, polycaprolactones, polyhydroxybutyrates,
polyethylene terephthalates, polytriphenylene terephthalate,
polybutylene terephthalate, polyvinyl alcohols, polyacrylamide,
partially hydrolyzed polyacrylamide, polyvinyl acetate, partially
hydrolyzed polyvinyl acetate, and copolymers or higher order
polymers (terpolymers, quaternary polymers, etc.) of these
materials. In some embodiments, the fiber component may be an acid
soluble fiber that may include polyamides such as nylon 6, nylon
6,6, and combinations thereof. In other embodiments, the
hydrophilic fiber component may be at least one of polymers or
co-polymers of esters that include, for example, substituted and
unsubstituted polylactide, polyglycolide, polylactic acid,
poly(lactic-co-glycolic acid), and polyglycolic acid,
poly(.epsilon.-caprolactone), and combinations thereof. Suitable
hydrophilic fibers may also be selected from celluloses and
cellulose derivatives such as hydroxypropyl cellulose, hydroxyethyl
cellulose, and carboxymethyl cellulose.
[0030] In one or more embodiments, the fiber component may be
selected from hydrophilic inorganic fibers that include glasses or
acid soluble minerals such as calcium carbonate (e.g., calcite,
vaterite, aragonite, limestone), magnesium carbonate (e.g.,
magnesite), calcium/magnesium carbonates (e.g., dolomite), calcium
oxide, and magnesium oxide. In particular embodiments, inorganic
fibers may have high aspect ratio crystal habits or acicular form.
In particular embodiments, the fiber component may be MaxCO3.TM.
available commercially from Schlumberger Technology Corporation
(Houston, Tex.). A further description of wellbore fluids
containing fibers that may be used with embodiments of the present
disclosure is discussed in U.S. Pat. Nos. 7,833,950 and 7,275,596
assigned to the assignee of the present application, and
incorporated by reference herein.
[0031] In one or more embodiments, various fibers may be added to
wellbore fluids in accordance with this disclosure in an amount
ranging from a lower limit equal or greater than 0.01 ppg, 0.1 ppg,
0.5 ppg, 1 ppg, and 5 ppg, to an upper limit of 0.5 ppg, 1 ppg, 5
ppg, 10 ppg, and 15 ppg, where the concentration of the fiber
component, or combinations thereof, may range from any lower limit
to any upper limit. In some applications, it also may be desirable
for the amounts of each fiber type to be in excess of the ranges
described above. Moreover, it is within the scope of the present
disclosure for any of the above described fibers to be combined as
required by downhole conditions.
[0032] In embodiments, the fibers may have lengths within the range
of 100 .mu.m to 20 mm. In other embodiments, the fibers may have
lengths within the range of 500 .mu.m to 15 mm.
[0033] In embodiments, the diameter of the fibers may fall within
the range of 0.1 .mu.m to 60 .mu.m. In yet another embodiment, the
diameter of the fibers may be within the range of 0.5 .mu.m to 50
.mu.m. In particular embodiments, a fiber having a diameter in the
range of 20 .mu.m to 50 .mu.m may be used, and a fiber having a
diameter of 1 to 15 .mu.m may be used.
Particulate Weighting Agents
[0034] Wellbore fluids in accordance with the present disclosure
may also include one or more particulate weighting agents.
Particulate-based wellbore fluid formulations may include use of
particles frequently referred to in the art as weighting materials,
or materials that aid in weighting up a fluid to a desired density.
Particulate weighting agents may incorporate into interstitial
spaces present in the three dimensional network formed by the
fibers, increasing the strength of the seal formed by the fiber and
particulate plug. In some embodiments, the fiber component and the
particulate weighting agents may act synergistically to form a
plug, decreasing the total amount of either component required.
Additional discussion of fluid loss compositions containing
mixtures of fibers and particulates is presented in U.S. Patent
Publication 2010/0152070 assigned to the assignee of the present
application, and incorporated by reference herein.
[0035] Examples of particulate weighting agents suitable for use in
the present disclosure include graphite, celluloses, micas,
proppant materials such as sands or ceramic particles and
combinations thereof. In other embodiments, particulate weighting
agents may be selected from one or more of the materials including,
for example, barium sulfate (barite), ilmenite, hematite or other
iron ores, olivine, siderite, and strontium sulfate. In yet other
embodiments, particulate weighting agents may be one or more
selected from materials that dissolve in response to pH such as
magnesium oxide, calcium carbonate (e.g., calcite, marble,
aragonite), dolomite (MgCO.sub.3.CaCO.sub.3) and the like.
[0036] In some embodiments, surface-modified particulate weighting
agents may be used. For example, the surface-modified particulate
weighting agents may include a hydrophobic or hydrophilic coating
to control fluid rheology and the overall plugging properties of
the wellbore fluid composition. In some embodiments, the surface of
the particulate weighting agents may be chemically modified by a
number of synthetic techniques. Surface functionality of the
particles may be tailored to improve solubility, dispersibility, or
introduce reactive functional groups. This may be achieved by
reacting the particulate weighting agents with organosilanes or
siloxanes, in which reactive silane groups present on the molecule
may become covalently bound to the surface of the particles.
Non-limiting examples of compounds that may be used to
functionalize the particulate weighting agents include
aminoalkylsilanes such as aminopropyltriethoxysilane,
aminomethyltriethoxysilane,
trimethoxy[3-(phenylamino)propyl]silane, and
trimethyl[3-(triethoxysilyl)propyl]ammonium chloride;
alkoxyorganomercapto silanes such as
bis(3-(triethoxysilylpropyl)tetrasulfide,
bis(3-(triethoxysilylpropyl) disulfide, vinyltrimethoxy silane,
vinyltriethoxy silane, 3-mercaptopropyltrimethoxy silane;
3-mercaptopropyltriethoxy silane; 3-aminopropyltriethoxysilane and
3-aminopropyltrimethoxysilane; alkoxysilanes, diethyl
dichlorosilane, phenyl ethyl diethoxy silane, methyl phenyl
dichlorosilane, vinyl silane, 3,3,3-trifluoropropylmethyl
dichlorosilane, trimethylbutoxy silane, sym-diphenyltetramethyl
disiloxane, octamethyl trisiloxane, octamethyl cyclotetrasiloxane,
hexamethyl disiloxane, pentamethyl dichlorosilane, trimethyl
chlorosilane, trimethyl methoxysilane, trimethyl ethoxysilane,
methyl trichlorosilane, methyl triethoxysilane, methyl
trimethoxysilane, hexamethyl cyclotrisiloxane,
hexamethyldisiloxane, gamma-methacryloxypropyl trimethoxy silane,
hexaethyldisiloxane, dimethyl dichlorosilane, dimethyl dimethoxy
silane, and dimethyl diethoxysilane.
[0037] In other embodiment, silicone polymers that contain reactive
end groups may be covalently linked to the surface of the
particulate weighting agents. Reactive silicone polymers may
include, for example,
bis-3-methacryloxy-2-hydroxypropyloxypropyl-polydimetllylsiloxane,
polydimethylsiloxanes comprising 3 to 200 dimethylsiloxy units,
trimethyl siloxy or hydroxydimethylsiloxy end blocked
poly(dimethylsiloxane) polymer, polysiloxanes, and mixtures
thereof.
[0038] The particle size of the particulate agents may be selected
depending on the target application, the level of fluid loss,
formation type, and/or the size of fractures predicted for a given
formation. In addition, the three dimensional structure of the
particulate weighting agents may be used to tune the overall
performance of the wellbore fluid compositions of the present
disclosure. For example, depending on the application, the
particulate weighting agent may be spherical or pseudo-spherical,
or be in the form of powder, beads, chips, platelets, flakes or
combinations of any of the above. In some embodiments, the average
particle size (d.sub.50) of the particulate agents may range from a
lower limit of greater than 5 nm, 10 nm, 30 nm, 50 nm, 100 nm, 200
nm, 500 nm, 700 nm, 0.5 micron, 1 micron, 1.2 microns, 1.5 microns,
3 microns, 5 microns, or 7.5 microns to an upper limit of less than
500 nm, 700 microns, 1 micron, 3 microns, 5 microns, 10 microns, 15
microns, 20 microns, 100 microns, where the particles may range
from any lower limit to any upper limit. The above described
particle ranges may be achieved by grinding down the materials to
the desired particle size or by precipitation of the material from
a bottoms up assembly approach. 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.
[0039] The amount of particulate weighting agent present in the
wellbore fluid may depend on the fluid loss levels, the anticipated
fractures, the density limits for the fluid in a given wellbore
and/or pumping limitations, etc. In one or more embodiments, one or
more particulate weighting agents may be added to wellbore fluids
in accordance with this disclosure in an amount ranging from a
lower limit equal or greater than 0.1 ppg, 0.5 ppg, 1 ppg, 5 ppg,
and 10 ppg, to an upper limit of 1 ppg, 5 ppg, 10 ppg, 20 ppg, and
25 ppg, where the concentration of the particulate weighting agent,
or combinations thereof, may range from any lower limit to any
upper limit. In some embodiments, the ratio of fibers to
particulates may range from 100/1 to 1/100 ratio by weight
(wt/wt).
Emulsions
[0040] In one or more embodiments, wellbore fluids in accordance
with the present disclosure may contain an invert emulsion, such as
a water-in-oil emulsion, having a discontinuous aqueous phase and a
continuous oleaginous phase. In other embodiments, wellbore fluids
may be an emulsion having an aqueous continuous phase and an
oleaginous discontinuous phase such as an oil-in-water emulsion. It
is also within the scope of this disclosure that a wellbore fluid
is formulated to contain a high-internal phase ratio (HIPR)
emulsion, such that the overall volume of the internal
discontinuous phase of the emulsion is greater than that of the
continuous phase.
[0041] Oil-in-water emulsions are stabilized by both electrostatic
stabilization (electric double layer between the two phases) and
steric stabilization (van der Waals repulsive forces), whereas
invert emulsions (water-in-oil) are stabilized by steric
stabilization. Because only one mechanism can be used to stabilize
an invert emulsion, invert emulsions may be more difficult to
stabilize, particularly at higher levels of the internal phase, and
may become more viscous.
[0042] In one or more embodiments, wellbore fluids may include an
aqueous phase that contains at least one of fresh water, sea water,
brine, mixtures of water and water-soluble organic compounds and
mixtures thereof. For example, the aqueous phase may be formulated
with mixtures of desired salts in fresh water. Such salts may
include, but are not limited to alkali metal chlorides, hydroxides
or carboxylates, for example. In various embodiments of the
drilling fluid disclosed herein, the brine may include seawater,
aqueous solutions wherein the salt concentration is less than that
of sea water, or aqueous solutions wherein the salt concentration
is greater than that of sea water. Salts that may be found in
seawater include, but are not limited to, sodium, calcium,
aluminum, magnesium, potassium, strontium, and lithium, salts of
chlorides, bromides, carbonates, iodides, chlorates, bromates,
formates, nitrates, oxides, phosphates, sulfates, silicates, and
fluorides. Salts that may be incorporated in 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 pills disclosed herein may be natural or synthetic, with
synthetic brines tending to be much simpler in constitution. In one
embodiment, the density of the pill 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.
[0043] Wellbore fluids in accordance with the present disclosure
may contain an oleaginous phase that includes one or more
oleaginous liquids such as natural or synthetic oils; diesel oils;
mineral oil; 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. Selection between an
aqueous fluid and an oleaginous fluid may depend, for example, on
the type of drilling fluid being used in the well when the lost
circulation event occurs. Use of the same fluid type may reduce
contamination and allow drilling to continue upon plugging of the
formation fractures/fissures, etc.
[0044] In one or more embodiments, wellbore fluids of the present
disclosure may possess a high shear viscosity of less than 500
centipoise (cp) at 100 sec-1, and a low shear viscosity of less
than 1000 cp at 25 sec-1 at reservoir temperature.
Stimulating Treatments
[0045] Following placement of a diverting treatment formulated in
accordance with the present disclosure, fluid flow into thief zones
may be decreased or stopped, which may allow for more uniform
contact between less permeable intervals and any subsequent
wellbore treatments or stimulating treatments known in the art.
[0046] In some embodiments, by sealing higher permeability regions
or intervals of the wellbore, one or more stimulating treatment may
be applied to increase the porosity and permeability of targeted
intervals in order to increase the production of hydrocarbons. In
one or more embodiments, the stimulating treatment may be an acid
wash containing one or more acids such as mineral acids that
include hydrochloric acid, hydrofluoric acid, nitric acid,
phosphoric acid and sulfuric acid, or organic acids such as formic
acid, acetic acid, glycolic acid, citric acid and phosphonic
acid.
[0047] As another example, plugging thief zones may increase the
effectiveness of enhanced oil recovery techniques like steam
flooding. In steam flooding, steam is injected into a neighboring
injection well. When steam enters the reservoir, it heats up the
crude oil and reduces its viscosity. The hot water that condenses
from the steam and the steam itself generate an artificial drive
that sweeps oil toward producing wells. The driving force of the
steam flood is then used to drive hydrocarbons into the production
well.
Application
[0048] When formulated as a fluid loss pill or diverting treatment,
wellbore fluids in accordance with the present specification may be
injected into a work string, flow to bottom of the wellbore, and
then out of the work string and into the annulus between the work
string and the casing or wellbore. The pill may be pushed by
injection of other completion fluids to a position within the
wellbore which is immediately above a portion of the formation
where fluid loss is suspected. Injection of fluids into the
wellbore is then stopped, and fluid loss will then move the pill
toward the fluid loss location. Positioning the pill in a manner
such as this is often referred to as "spotting" the pill. The fluid
loss pill or diverting treatment may then react with the brine to
form a plug near the wellbore surface, to reduce fluid flow into
the formation.
[0049] In other embodiments, the wellbore fluids of the present
disclosure may be selectively emplaced in the wellbore, for
example, by spotting the pill through a coil tube or by
bullheading. A downhole anemometer or similar tool may be used to
detect fluid flows downhole that indicate where fluid may be lost
to the formation. The relative location of the fluid loss may be
determined such as through the use of radioactive tags present
along the pipe string. Various methods of emplacing a pill known in
the art are discussed, for example, in U.S. Pat. Nos. 4,662,448,
6,325,149, 6,367,548, 6,790,812, 6,763,888, which are herein
incorporated by reference in their entirety.
EXAMPLES
[0050] The subsequent examples are provided to further illustrate
the application and the use of the methods and compositions in
accordance with the present disclosure.
Example 1
[0051] In the following example, sample formulations were assayed
to determine their effectiveness in blocking the flow into a
cylindrical channel. Samples were prepared and 130 mL of each
sample was applied to a funnel ending in an opening diameter of 1
cm. Where indicated, samples were formulated with a polylactic acid
fiber having a diameter of approximately 50 microns and an
approximate length of 1 cm at concentration of 18 grams per liter
(about 150 ppg). Sample emulsions were formulated with kerosene as
the oil phase. Following preparation, accumulated mass (g) of the
sample compositions were measured and recorded as a function of
time (s) and plotted in FIG. 1, where Sample 1 is a mixture of
fresh water and fibers; Sample 2 is fresh water alone; Sample 3 is
a 30/70 oil-in-water emulsion containing fibers prepared and mixed
at 1000 rpm prior to application; Sample 4 is a 30/70 oil-in-water
emulsion containing fibers prepared and mixed at 2500 rpm prior to
application; Sample 5 is a 50% w/w mixture of honey in water with
fibers; Sample 6 is a mixture of water, a viscoelastic surfactant,
and fibers; and Sample 7 is a 70/30 water-in-oil emulsion prepared
with a 200 kppm brine and fibers that was mixed at 6000 rpm prior
to application.
[0052] In Example 1, the water-in-oil emulsion containing fibers
(Sample 7) performed better plugging/bridging than the other
fluids, which may be explained by the combination of the viscosity
of the base fluid and the flocculation rate of the fibers. For the
fresh water with fibers (Sample 1) and the oil-in-water emulsions
(Samples 3 and 4), fiber flocs were observed at the funnel
entrance, but base fluid remained mobile through the funnel
opening.
[0053] Sample 5 and Sample 6 exhibited high viscosity but did not
produce a plug and fibers were recovered with the sample passed
through the funnel. Thus, it appears that, when fibers are used for
bridging purposes, the high viscosity of the base fluid is
necessary but not sufficient to produce a plug at the entrance of
the funnel and the flocculation rate of the fibers may need to be
adjusted in order to produce a substantial plug.
Example 2
[0054] In a further illustrative example, an embodiment of the
present disclosure was assayed against a series of comparative
samples that were formulated with a viscoelastic surfactant,
fibers, hydrochloric acid, and varying concentrations of calcium
carbonate. Where indicated, samples were formulated with a
polylactic acid fiber having a diameter of approximately 50 microns
and an approximate length of 1 cm at concentration of 18 grams per
liter (about 150 ppg). Sample emulsions were formulated with
kerosene as the oil phase. Samples were assayed using a
pour-in/pour-out test of 150 ml in a funnel with an opening
diameter of 1 cm. The collected mass (g) was measured versus time
(s) and plotted in FIG. 2 for a number of samples. With particular
reference to FIG. 2, Sample 8 is a formulation containing a
viscoelastic surfactant, fibers, hydrochloric acid, and enough
calcium carbonate to neutralize 60% of the hydrochloric acid;
Sample 9 is substantially identical to Sample 8, but without any
added calcium carbonate; Sample 10 is substantially identical to
Sample 8, but with enough calcium carbonate added to neutralize 80%
of the hydrochloric acid; Sample 11 is a 70/30 water-in-oil
emulsion prepared with a 200 kppm brine, kerosene, and fibers that
was mixed at 6000 rpm prior to application.
[0055] For samples, once a plug formed or the flow slowed, 100 ml
of the respective base fluid (without fibers) was added in order to
destabilize the plug. The times corresponding to when the base
fluid was added are shown in FIG. 2 by dashed vertical lines. Here
again water-in-oil (w/o) emulsion (with brine) performs better
plugging of the funnel and, unlike treatments containing
viscoelastic surfactants, does not exhibit a pH dependent maximum
viscosity. The percent acid neutralization was calculated based
upon a calibrated value of 22 g of calcium carbonate to 100 ml of
the solution for 100% neutralization.
Example 3
[0056] In another example, embodiments of the present disclosure
were assayed against a series of comparative samples that were
formulated with a viscoelastic surfactant, fibers, hydrochloric
acid and varying concentrations of calcium carbonate. Where
indicated, samples were formulated with a polylactic acid fiber
having a diameter of approximately 50 microns and an approximate
length of 1 cm at a concentration of 18 g/L. Sample emulsions were
formulated with kerosene as the oil phase. Samples were assayed
using a pour-in/pour-out test of 150 ml in a funnel with an opening
diameter of 1 cm. For samples, once a plug formed, 100 ml of the
base fluid (without fibers) was added to destabilize the plug.
Results are shown in FIG. 3 depicting a graph of collected mass (g)
versus time (s). The times corresponding to when the base fluid was
added are indicated in FIG. 3 by dashed vertical lines. Sample 12
is a formulation containing a viscoelastic surfactant, fibers, and
hydrochloric acid; Sample 13 is a formulation containing a
viscoelastic surfactant, fibers, hydrochloric acid, and enough
calcium carbonate to neutralize the hydrochloric acid; Sample 15 is
a formulation containing a viscoelastic surfactant, fibers, and
water; Sample 14 is a formulation containing a 70/30 oil-in-water
emulsion and fibers that was mixed at 6000 rpm prior to
application; and Sample 16 is an 70/30 water-in-oil emulsion
containing fibers that was mixed at 6000 rpm prior to
application.
[0057] For Samples 14, 15 and 16 of Example 3, the rheological
profiles were also studied at 25.degree. C. as illustrated in FIG.
4. It is noted in this Example that the water-in-oil emulsion
(Sample 16) performs better than oil-in-water emulsion (Sample 14)
even though their viscosity is in within the same range.
[0058] Upon inspection of the two types of emulsion under the
microscope (not shown), it was found that the fibers are mostly
oil-wet. In the water-in-oil emulsion, the water droplets are
trapped within the fiber network and plug the space between the
fibers. In the oil-in-water emulsion, oil droplets coalesce and
spread around the fiber. Thus, it is envisioned that modifying the
hydrophobic or hydrophilic character of the fibers may be used in
conjunction with particular emulsions to modify the rheology and
plugging effectiveness of fluid loss compositions for differing
types of emulsions, e.g., water-in-oil or oil-in-water.
Example 4
[0059] In a further example, an experiment was carried out to lower
the fiber concentration in particular embodiments of the present
disclosure. Where indicated, samples were formulated with a
polylactic acid fiber having a diameter of approximately 50 microns
and an approximate length of 1 cm at concentration of 18 g/L.
Sample emulsions were formulated with kerosene as the oil phase.
Samples were assayed using a pour-in/pour-out test of 150 ml of a
selected sample in a funnel with an opening diameter of 1 cm. FIG.
5 depicts a graph of collected mass (g) versus time (s). For
samples, once a plug was formed, 100 ml of the respective base
fluid (without fibers) was added to destabilize the plug. The times
corresponding to the addition of base fluid are represented in FIG.
5 by dashed vertical lines. With particular reference to FIG. 5,
Sample 17 is a 70/30 water-in oil emulsion containing 6 ppg of
Pr100, a proppant having an average particle size of approximately
150 microns (100 mesh); Sample 18 is a formulation containing a
viscoelastic surfactant, fibers, hydrochloric acid, and enough
calcium carbonate to neutralize the hydrochloric acid; Sample 19 is
a 30/70 water-in-oil emulsion containing fibers at a concentration
of 112.5 lbs/1000 gal (13.5 g/L); Sample 20 is a 70/30 water-in-oil
emulsion containing fibers at a concentration of 150 lbs/1000 gal
(18 g/L); and Sample 21 is a 70/30 water-in-oil emulsion containing
fibers at a concentration of 150 lbs/1000 gal (18 g/L) and 6 ppg of
Pr100 particulate weighting agent.
[0060] The results in FIG. 5 indicate that when Pr100 is added at 3
ppg (360 g/L) to the solution of emulsion and fibers, the fluid
loss composition performs better than the equivalent sample
formulation without proppant. When proppant was used with the
emulsion alone (Sample 17), a plug was not formed even with a
concentration of 6 ppg (720 g/L) and the solution flowed out the
funnel. This is mainly due to the size of the proppant which is
very small compared to the funnel diameter, and also due to the
viscosity of the emulsion which is not sufficient to suspend the
proppant. When the fibers are present in the solution, the same
proppant will be trapped in the fiber network.
[0061] In the present disclosure, Applicant has discovered that, by
partitioning a fiber component within an emulsified fluid, the
fiber component may be organized within the discontinuous or
continuous phase depending on the apparent
hydrophobicity/hydrophilicity. The organization of the fiber
component within the emulsion creates a fibrous network that is
more effective in plugging and blocking fissures and crevices
within a wellbore. Moreover, when particulate solids are added to
fibrous fluid loss compositions, the particulate solids may
incorporate into the fibrous network and increase the density and
durability of the resulting seal. Emulsified fluids may also
increase the stability of fibers in solution and decrease sagging
and/or precipitation, which allows the fibers to be delivered into
the fluid loss zone without settling out or agglomerating
prematurely.
[0062] Although only a few example embodiments have been described
in detail above, those skilled in the art will readily appreciate
that many modifications are possible in the example embodiments
without materially departing from this invention. Accordingly, all
such modifications are intended to be included within the scope of
this disclosure as defined in the following claims. Moreover,
embodiments may be performed in the absence of any component not
explicitly described herein.
[0063] In the claims, means-plus-function clauses are intended to
cover the structures described herein as performing the recited
function and not only structural equivalents, but also equivalent
structures. Thus, although a nail and a screw may not be structural
equivalents in that a nail employs a cylindrical surface to secure
wooden parts together, whereas a screw employs a helical surface,
in the environment of fastening wooden parts, a nail and a screw
may be equivalent structures. It is the express intention of the
applicant not to invoke 35 U.S.C. .sctn.112, paragraph 6 for any
limitations of any of the claims herein, except for those in which
the claim expressly uses the words `means for` together with an
associated function.
* * * * *