Note: Descriptions are shown in the official language in which they were submitted.
2~383~6
WELL TREATING METHODS AN-D DEVICES
USING PARTICULATE RT.T~ns
FIELD OF THE lNV~N-llON
In one aspect, the present invention relates to
fracturing, frac-pack, gravel packing, and similar methods for
treating wells. In another aspect, the present invention
relates to prepacked screening devices.
R~CRGROUN-D OF THE lNV~NllON
When producing oil and/or gas from an unconsolidated
subterranean formation, some type of particulate control
procedure may be required in order to prevent sand grains
and/or other formation fines from migrating into the wellbore
and being produced from the well. The production of such
particulate materials can reduce the rate of hydrocarbon
production from the well and can cause serious damage to well
tubulars and to well surface equipment.
Those skilled in the art have commonly used gravel packs
to control particulate migration in producing formations. A
gravel pack will typically consist of a mass of particulate
material which is packed around the exterior of a screening
device, said screening device being positioned in an open hole
or inside a well casing. Examples of typical screening
devices include wire-wrapped screens and slotted liners. The
screening device will typically have very narrow slots or very
small holes formed therein. These holes or slots are large
enough to permit the flow of formation fluid into the
screening device but are too small to allow the particulate
packing material to pass therethrough. In conjunction with
2~3834~
the operation of the holes or slots formed in the screening
device, the particulate packing material operates to trap, and
thus prevent the further migration of, formation sand and
fines which would otherwise be produced along with the
formation fluid.
Hydraulic fracturing techniques are commonly used to
stimulate subterranean formations in order to enhance the
production of fluids therefrom. In a conventional hydraulic
fracturing procedure, a fracturing fluid is pumped down a
wellbore and into a fluid-bearing formation. The fracturing
fluid is pumped into the formation under a pressure sufficient
to enlarge natural fissures in the formation and/or open up
new fissures in the formation. Packers can be positioned in
the wellbore as necessary to direct and confine the fracturing
fluid to the portion of the well which is to be fractured.
Typical fracturing pressures range from about 1,000 psi to
about 15,000 psi depending upon the depth and the nature of
the formation being fractured.
Fracturing fluids used in conventional hydraulic
fracturing techniques include: fresh water; brine; liquid
hydrocarbons (e.g., gasoline, kerosene, diesel, crude oil, and
the like) which are viscous or have gelling agents
incorporated therein; gelled water; and gelled brine. The
fracturing fluid will also typically contain a particulate
proppant material. The proppant flows into and remains in the
fissures which are formed and/or enlarged during the
fracturing operation. The proppant operates to prevent the
21383~
fissures from closing and thus facilitates the flow of
formation fluid through the fissures and into the wellbore.
Frac-pack operations are primarily used in highly
unconsolidated and semi-consolidated formations to facilitate
fluid recovery while preventing particulate migration. A
frac-pack operation typically embodies the features of both a
fracturing operation and a gravel packing operation.
Preferably, the unconsolidated formation is initially
fractured using a proppant-laden fracturing fluid. The
proppant material deposits in the fractures which are formed
during the fracturing operation. Due to the unconsolidated
nature of the formation, the fractures produced during the
fracturing step will typically be substantially wider and
shorter than the fractures produced when fracturing
consolidated formations. After a desired degree of fracturing
is achieved, additional proppant material is tightly packed in
the wellbore. The additional proppant material will typically
be held in place in the wellbore by (a) packing the proppant
material around a gravel packing screen and/or (b)
consolidating the proppant material by means of a resin
coating.
Examples of particulate materials commonly used for
gravel packing and frac-pack operations and as fracturing
proppants include: sand; glass beads; nut shells; metallic
pellets or spheres; gravel; synthetic resin pellets or
spheres; gilsonite; coke; sintered alumina; mullite; like
materials; and combinations thereof.
21383~
Consolidatable resin-coated particulate materials have
been used heretofore in various well treatment operations.
Consolidatable resin-coated sands have been used, for example,
for gravel packing, for frac-pack operations, and as proppant
materials in formation fracturing operations. Due to their
desirable permeability and compressive strength
characteristics, resin-coated particulate materials are
especially well-suited for treating semiconsolidated and
unconsolidated formations which contain loose or unstable
sands.
As used herein, the term "consolidatable resin-coated
particulate material" refers to a particulate material (e.g.,
a proppant, a particulate gravel packing material, or a
particulate material used for frac-pack operations) which is
coated with a bonding-type resin composition (e.g., an epoxy
resin composition, a phenol/aldehyde type resin composition,
etc.). Typically, the consolidatable resin-coated composition
particulate material will be injected into a subterranean zone
using procedures whereby the resin does not substantially
harden until after the particulate material has been delivered
to a desired location within the formation. The hardening of
the resin consolidates the particulate material to yield a
hard, consolidated, permeable mass.
Well treatment methods utilizing consolidatable epoxy
resin-coated particulate materials are disclosed, for example,
in U.S. Patent No. 5,128,390. Well treatment methods
utilizing co~solidatable resole-type phenolic resin-coated
213834~
particulate materials are disclosed, for example, in U.S.
Patent No. 4,336,842. The entire disclosures of U.S. Patents
4,336,842 and 5,128,390 are incorporated herein by reference.
U.S. Patent No. 5,128,390 discloses a method for
continuously forming and transporting consolidatable resin-
coated particulate materials. In the method of U.S. Patent
No. 5,128,390, a particulate material (e.g., sand) and a
hardenable epoxy resin system are continuously mixed with a
stream of gelled carrier liquid. The resulting continuous
composition is delivered to and/or injected into a desired
subterranean zone. As the continuous mixture flows down the
well tubing toward the subterranean zone, the composition
ingredients are mixed such that the gel-suspended particulate
material is thoroughly coated with the hardenable epoxy resin
system. After being placed in the subterranean zone, the
epoxy resin composition is allowed to harden whereby the
resin-coated particulate material forms a hard, permeable,
consolidated mass.
The hardenable epoxy resin composition used in the method
of U.S. Patent No. 5,128,390 is generally composed of: a
polyepoxide resin carried in a solvent system; a hardening
agent; a coupling agent; and a hardening rate controller.
U.S. Patent No. 4,336,842 disclosed methods for treating
wells using resin-coated particles. As indicated above, the
methods of U .S. Patent No. 4,336,842 preferably utilize one-
step phenolic resins which are prepared by reacting phenolic
compounds with aldehydes in the presence of alkaline
213~3~6
catalysts. Such resins are commercially available in both
powder and liquid form. Examples of suitable phenolic
compounds include: phenol; resorcinol; alkyl substituted
phenols (e.g., cresol and p-tert-butyl phenol) and cardanol.
Examples of suitable aldehyde compounds include:
formaldehyde; acetaldehyde; and furfuraldehyde. The specific
resin-coated particulate materials disclosed in U.S. Patent
No. 4,336,842 are free-flowing, pre-coated particulate
materials. Such pre-coated particulate materials can be
prepared, for example, by (a) dissolving the powdered phenolic
resin in a solvent, mixing the particulate material with the
resulting resin solution, and then evaporating the solvent or
(b) using a heat coating process wherein the particulate
substrate material is heated and then mixed with the powdered
resin.
In one embodiment of the methods of U.S. Patent No.
4,336,842, a pre-coated particulate material of the type just
described is used in a formation fracturing operation. The
formation fracturing operation includes the steps of:
generating a fracture in the formation by pumping a viscous
fluid into the formation at a pressure and at a rate
sufficient to fracture the formation; continuing the viscous
fluid pumping step until a desired fracture geometry is
obtained; mixing the pre-coated particulate material with a
carrier fluid; pumping the carrier/particulate mixture into
the formation such that the pre-coated particulate material
deposits in and fills the fracture; pumping a curing solution
- 213839~
into the formation such that the curing solution contacts the
pre-coated particulate material; and then allowing the resin
coating to fuse and cure at the elevated temperature
conditions existing in the formation. Upon curing, the resin
coated particulate material forms a hard, permeable mass. The
curing solution used in U.S. Patent No. 4,336, 842 includes a
resin softening agent capable of lowering the fusion
temperature of the resin coating. Examples of suitable
softening agents include: alcohols which are at least
partially soluble in the resin; nonionic surfactants; and
combinations thereof.
In other embodiments of the methods of U.S. Patent No.
4,336,842, pre-coated particulate materials of the type
described above are used in conventional gravel packing
operations. Examples include open-hole gravel packs, inside-
the-casing gravel packs, and linerless gravel packs. After
the gravel pack is in place, a curing solution of the type
described above is pumped into the formation such that the
solution contacts the pre-coated particulate material. The
well is then shut-in order to allow the resin coating to fuse
and cure at the elevated temperature conditions existing in
the formation.
Heretofore, in conducting a fracturing, gravel packing,
frac-pack, or similar well treating operation, the particulate
material used has typically consisted of particles lying
within a single, relatively narrow size range (e.g., 20/40
mesh, 40/60 mesh, or 50/70 mesh). As used herein and in the
21383 4G
claims, a term such as ~20/40 mesh" refers to a material
having a particle size distribution lying entirely within the
range of from 20 to 40 mesh, U.S. sieve series. Thus, the
particles of a 20/40 mesh material would be smaller than 20
mesh, U.S. sieve series, but not smaller than 40 mesh, U.S.
sieve series.
The specific particle size selected for use in a given
application has primarily depended upon (a) the degree of
unconsolidation existing in the formation (i.e., the degree to
which the formation contains loose sand and fine materials
which would otherwise migrate through the formation and into
the well tubing), (b) the particle size distribution of the
natural sand and fine materials comprising the formation, and
(c) the desired product flow rate to be obtained from the
formation.
Heretofore, the selection of an appropriately sized
particulate material for treating an unconsolidated or semi-
consolidated formation has involved an undesirable trade-off.
The use of a large particulate material (e.g., 12/20 mesh or
20/40 mesh) provides a high initial permeability and a
correspondingly high initial production rate. However, the
migration of formation sand and fines into the large material
eventually clogs fluid passageways within the material bed and
thereby reduces the production rate sustainable through the
bed. Additionally, the eventual migration of formation sand
and fines through the bed and into the wellbore can cause
severe damage to the well tubulars and other production
- 213&3q6
equipment. The use of a small particulate material (e.g.,
40/60 mesh, 50/70 mesh, or 60/80 mesh), on the other hand,
substantially prevents the migration of formation sand and
fines into and through the particulate bed. However, small
particulate materials have relatively low permeabilities and
therefore yield substantially reduced production rates.
The most commonly used gravel packing material is
believed to be 20/40 mesh resieved sand.
Thus, a need presently exists for fracturing, frac-pack,
gravel packing, and similar treating techniques wherein the
particulate materials used will both (a) prevent the migration
of formation sand and fines and (b) provide high relative
production rates.
U.S. Patent No. 4,478,282 discloses a hydraulic
fracturing technique wherein adverse vertical height growth of
induced fractures is controlled by the injection of a non-
proppant fluid stage. The non-proppant fluid stage comprises
a transport fluid and a flow blocking material. The flow
blocking material has a particle size distribution which is
sufficient to form a substantially impermeable barrier to
vertical fluid flow. The method of U.S. Patent No. 4,478,282
includes the steps of (a) injecting a fracturing fluid pad
into the formation at a sufficient rate and pressure to open
a fracture in the formation, then (b) injecting the non-
proppant fluid stage into the formation, and then (c)
injecting a proppant-laden slurry into the formation.
The particulate material used in the non-proppant fluid
21383q6
stage of the method of U.S. Patent No. 4,478,282 consists of
a large particulate material (i.e., 10/20 mesh and/or 20/40
mesh) and a very small particulate material (i.e., smaller
than 100 mesh). The large particulate material creates
particle bridges within the formation fracture. The very
small particulate material, on the other hand, fills the gaps
existing between the larger particles and forms a
substantially impermeable barrier to fluid flow.
Thus, the method of U.S. Patent No. 4,478,282 neither
addresses nor resolves the particulate migration and
production rate problems discussed above. Rather, as will be
apparent, U.S. Patent No. 4,478,282 teaches away from the
invention described and claimed herein below.
U.S. Patent No. 4,665,988 discloses a method of filling
a void in a subterranean formation. The method includes the
steps of: (a) admixing a first particulate material, a second
particulate material, and a resin composition with a viscous
carrier fluid; (b) introducing the resulting mixture into the
subterranean formation such that the void is filled by the
mixture; (c) compacting the particulate material in the void
by applying fluid pressure to the mixture; and (d) allowing
the resin composition to harden such that the particulate
materials are consolidated and a permeable mass is formed
within the void. The first particulate material used in the
fill composition has a particle size of no greater than 10
mesh. The second particulate material used in the fill
composition has a median diameter of less than 1/7 the median
213834~
11
diameter of the first particulate material. After the resin
composition hardens, any excess fill material remaining in the
wellbore can be drilled out and a suitable liner is then
installed in the wellbore and cemented in place to thereby
isolate a selected zone of interest.
Thus, U.S. Patent No. 4,665,988 neither discloses nor
suggests a means by which fracturing, gravel packing, frac-
pack, and similar techniques can be improved to (a) provide
high fluid production rates while (b) preventing the migration
of formation particulates into the wellbore. Rather, U.S.
Patent No. 4,665,988 discloses only a secondary or tertiary
production technique wherein existing formation voids adjacent
a wellbore are filled with a permeable mass prior to inserting
a new casing into the wellbore and cementing the casing in
place.
U.S. Patent No. 4,969,523 purports to provide a gravel
packing method wherein equivalent packing efficiency is
obtained in the upper and lower perforations and portions of
the wellbore annulus. The method comprises injecting a
particulate/carrier fluid slurry into the wellbore wherein the
particulate material includes first particles having a density
less than the density of the carrier fluid and second
particles having a density greater than that of the carrier
fluid. U.S. Patent No. 4,969,523 also discloses the
performance of a comparative test which utilized a mixture of
20/40 mesh sand having a density of 2.65 and 18 to 50 mesh
styrenedivinylbenzene beads having a density of 1.05. Thus,
2138~4G
12
U.S. Patent No. 4,969,523 neither addresses nor resolves the
specific particulate migration and production rate problems
discussed above.
SUMMARY OF T~E lNv~r.~lON
The inventive methods described herein utilize a treating
composition comprising a carrier fluid and a particulate
blend. The particulate blend consists essentially of a large
particulate material and a small particulate material. The
large particulate material consists essentially of particles
smaller than about 4 mesh, but not smaller than about 40 mesh.
The small particulate material consists essentially of
particles smaller than about 16 mesh, but not smaller than
about 100 mesh. Substantially all of the particles of the
small particulate material are smaller than substantially all
of the particles of the large particulate material. The small
particulate material is present in the particulate blend in an
amount in the range from about 5~ to about 60~ by weight based
on the amount of large particulate material present in the
particulate blend. The particulate blend is a particulate
blend which has been formed by admixing one of the particulate
materials with the other of the particulate materials.
In one embodiment of the inventive method, a subterranean
formation is stimulated by injecting a treating composition of
the type described hereinabove into the subterranean
formation. The treating composition is injected into the
subterranean formation such that the treating composition
forms a fracture in the subterranean formation and the
21383~G
13
particulate blend is deposited in the fracture to thus provide
a fluid permeable region within the subterranean formation.
A second embodiment of the inventive method pertains to
a gravel packing procedure comprising steps of: (a) placing
a screening device in a wellbore and then (b) injecting a
treating composition of the type described hereinabove into
the wellbore. The treating composition is injected into the
wellbore in step (b) such that the particulate blend contained
in the treated composition is packed around the exterior of
the screening device. The packed particulate blend provides a
fluid-permeable barrier around the screening device which is
operable for preventing the migration of formation
particulates into the screening device.
Another embodiment of the inventive method pertains to a
procedure for producing a formation fluid from a subterranean
formation, said subterranean formation having a portion of a
wellbore extending thereinto. This embodiment of the
inventive method comprises the steps of: (a) placing a
treating composition of the type described hereinabove into
said portion of the wellbore such that the particulate blend
is packed in the wellbore to provide a fluid-permeable barrier
which is operable for preventing the migration of formation
particulates and (b) producing formation fluid through the
packed particulate bed formed in step (a) without further
modifying the packed particulate bed.
Another embodiment of the inventive method pertains to a
procedure for stimulating a subterranean formation. This
213S3~6
14
embodiment of the inventive method comprises the steps of:
(a) applying a first fluid to the formation such that a
fracture is formed therein and (b) injecting a treating
composition of the type described herein above into the
fracture. The treating composition is injected into the
fracture in step (b) such that particulate blend is deposited
in the fracture to thus provide a fluid-permeable region
within the subterranean formation.
In yet another embodiment, the present invention provides
a prepacked screening device. The screening device comprises:
a conduit including a conduit wall and having apertures
extending through the conduit wall; a fluid-permeable screen
positioned exterior to the conduit and spaced apart from the
conduit; and a fluid-permeable particulate bed positioned
between the fluid-permeable screen and the conduit. The
particulate bed comprises a particulate blend formed by
mixing a large particulate material with a small particulate
material. The large particulate material consists essentially
of particles smaller than about 4 mesh but not smaller than
about 40 mesh. The small particulate material consists
essentially of particles smaller than about 16 mesh but not
smaller than about 100 mesh. Substantially all of the
particles of the small particulate material, however, are
smaller than substantially all of the particulates of the
large particulate material. The small particulate material is
present in the particulate bed in an amount in the range of
from about 5~ to about 60~ by weight based on the amount of
213~34~
the large particulate material present in the particulate bed.
The present invention resolves the problems and satisfies
the needs discussed hereinabove which have been encountered in
the use of prior art fracturing, frac-pack, and gravel packing
techniques. The particulate systems utilized in the present
invention provide permeability levels and production rates
substantially superior to those provided by the single-sized
small particulate systems used heretofore. Yet, at the same
time, the particulate systems used in the present invention
provide formation sand and formation fines control levels
which are substantially equivalent to the control levels
provided by single-sized small particulate systems.
Further objects, features, and advantages of the present
invention will be readily apparent to those skilled in the art
upon reference to the accompanying drawing and upon reading
the following description of the preferred embodiments.
BRIEF DESCRIPTION OF THE DRAWING
The drawing provides a partially cutaway elevational view
of a prepacked screening device provided by the present
invention.
DESCRIPTION OF THE PREFERRED EMBODIMENTS
The treating composition used in the methods of the
present invention comprises a mixture including both a carrier
fluid and a particulate blend. The particulate blend is
preferably suspended in the carrier fluid. The particulate
blend comprises a large particulate material and a small
particulate material. The composition can also include a
213~34l~
16
hardenable resin system which will consolidate the particulate
blend to form a hard permeable mass. If a hardenable resin
system is employed in the treating composition, the resin
system can be (a) added to the treating composition at the
well site, (b) included as a precoating on the individual
particles of the particulate blend, or (c) added to the
treating composition using generally any other means commonly
employed in the art.
The particulate materials used in the treating
composition can generally be any of the particulate materials
commonly used in fracturing, frac-pack, gravel packing, and
similar procedures. Examples of such materials are listed
hereinabove. Preferably, both the large particulate material
and the small particulate material used in the treating
composition are sand.
The large particulate material preferably consists
essentially of particles smaller than about 4 mesh but not
smaller than about 40 mesh. More preferably, the large
particulate material is either an 4/8 mesh material, an 8/12
mesh material or a 12/20 mesh material. The large particulate
material most preferably has a particle size distribution of
4/8 mesh or 8/12 mesh.
The small particulate material preferably consists
essentially of particles smaller than about 16 mesh but not
smaller than about 100 mesh. More preferably, the small
particulate material is a 20/40 mesh material, a 40/60 mesh
material, a 50/70 mesh material, a 60/80 mesh material, or an
~ 17 213839~
80/100 mesh material. The small particulate material most
preferably has a particle size distribution of either 20/40
mesh or 40/60 mesh.
The particle site distributions of the small and large
particulate materials should be such that substantially all of
the particles of the small material are smaller than
substantially all of the particles of the large material.
Examples of particularly desirable large and small particulate
combinations include (a) a 4/8 mesh material blended with
either a 16/30 mesh material or a 20/40 mesh material; (b) a
8/12 mesh material blended with either a 30/50 mesh material
or a 40/60 mesh material; (c) a 12/20 mesh material blended
with either a 50/70 mesh material or a 40/60 mesh material;
and (d) a 20/40 mesh material blended with either a 50/70 mesh
material or a 60/80 mesh material.
Particulate blends which are particularly well-suited for
use in the present invention will consist essentially of (a)
a small particulate material of the type just described having
a median particle diameter which is from about four to about
seven times the median diameter of the particulate materials
making up the subterranean zone being treated and (b) a large
particulate material of the type just described having a
median particle diameter which is from about six to about
eleven times the median particle diameter of the small
particulate material. Such particulate blends provide high
permeabilities and excellent sand control properties.
The small particulate material is preferably present in
- 18 2138~4~
the particulate blend in an amount in the range of from about
5~ to about 60~ by weight based on the amount of large
particulate material present in the blend, and more preferably
15 to 40~. Most preferably, the small particulate material is
present in the particulate blend in an amount in the range of
from about 20~ to about 35~ by weight based on the amount of
large particulate material present in the blend.
It is preferred that the bulk volume of small particulate
material used in the particulate blend not substantially
exceed the bulk void volume of the large particulate material.
12/20 mesh resieved Ottawa sand, for example, has a bulk void
volume in the range of from about 34~ to about 36~ of the
total volume of the bulk material. 20/40 mesh resieved Ottawa
sand, on the other hand, has a bulk void volume in the range
of from about 33~ to about 35~ of the total volume of the bulk
material. Significant permeability improvements are realized
when the amount of small particulate material contained in the
particulate blend is low enough to ensure that substantially
all of the small particulate material can be contained within
the bulk void spaces existing between the larger particles.
The carrier fluid used in forming the treating
composition can generally be any type of carrier fluid which
is used in fracturing, frac-pack, gravel packing, or other
similar procedures. Examples include: fresh water; brine;
liquid hydrocarbons (e.g., gasoline, kerosene, diesel, crude
oil, and the like) which are viscous and/or have viscosifiers
or gelling agents incorporated therein; gelled water; and
-- 2138346
19
gelled brine. The carrier fluid is preferably a gelled
aqueous composition formed from water, brine, or a similar
aqueous fluid. The aqueous fluid is preferably a brine
solution produced by the addition of sodium chloride,
potassium chloride, ammonium chloride, calcium chloride, or
the like to fresh water. Most preferably, the aqueous fluid
is a brine solution comprising water and an amount of
potassium chloride or ammonium chloride in the range of from
about 2~ to about 3~ by weight based on the total weight of
the brine solution.
Gelled carrier fluid systems, additives, and
concentrations suitable for use in the present invention are
disclosed, for example, in U.S. Patents 4,199,484, 4,665,988
and 5,128,390. The entire disclosures of these patents are
incorporated herein by reference.
Gelled aqueous carrier fluids utilized in the present
invention can be formed using generally any of the gelling
agents employed heretofore in well treating operations.
Gelling agents preferred for use in the present invention are
polysaccharides having molecular weights in the range of from
about 100,000 to about 4,000,000. Polysaccharides having
molecular weights in the range of from about 600,000 to about
2,400,000 are particularly well-suited for use in the present
invention. Examples of polysaccharide polymers preferred for
use in the treating composition include: substituted carboxy
and hydroxy alkyl cellulose (e.g., hydroxyethyl cellulose and
carboxymethyl hydroxyethyl cellulose); guar gum; guar gum
21383~6
derivatives (e.g., hydroxypropyl guar); and xanthan gum. The
gelling agent most preferably used in the treating composition
is hydroxyethyl cellulose.
The gelled aqueous carrier liquid can also include one or
more gel cross-linking agents. Examples of gel cross-linking
agents preferred for use in the present invention include:
borate salts which will provide borate ions at a pH in the
range of from about 8.5 to about 12; chromium-containing
compounds; lactate; titanium triethanolamine; other titanium-
containing compounds; aluminum acetate; magnesium oxidei and
zirconium salts.
The gelled aqueous carrier fluid will preferably contain
a sufficient amount of polymer or a sufficient amount of
polymer and cross-linker to yield a gelled carrier fluid
viscosity in the range of from about 10 to about 800
centipoise. Assuming that the gelling agent used is
hydroxyethyl cellulose and that a cross-linking agent is not
used, from about 20 to about 100 pounds of gelling agent per
1000 gallons of aqueous fluid will typically be required to
achieve a gelled system viscosity in the range of from about
10 to about 800 centipoise at a shear rate of 511 sec~1.
When a cross-linking agent is used, the amount of organic
gelling agent required to achieve a given gelled system
viscosity can be reduced by approximately one-half. As is
well known in the art, the amount of cross-linking agent
required to achieve a given gel viscosity will (a) vary
depending on the specific gelling and cross-linking agents
21383~6
21
used and (b) be proportional to the amount of gelling agent
used.
When a noncross-linked gelled aqueous carrier fluid is
used, the tendency of the particulate blend to settle out of
the particulate blend/carrier fluid mixture increases as the
amount of visible clear fluid in the particulate blend/carrier
fluid mixture increases (i.e., as the relative amount of
particulate blend in the mixture decreases). Consequently,
the amount of particulate blend used in the mixture is most
preferably an amount which is suitable for pumping downhole
but which also minimizes the amount of visible clear fluid in
the particulate blend/carrier fluid mixture.
Due to the settling phenomenon associated with the use of
a noncross-linked gelled aqueous carrier fluid, the amount of
particulate blend added to a noncross-linked gelled carrier
fluid will preferably be an amount in the range of about 1
pound to about 30 pounds, preferable from about 5 pounds to
about 20 pounds, of particulate blend per gallon of gelled
aqueous carrier fluid.
When a cross-linked gelled aqueous carrier liquid is
used, the amount of particulate blend added to the carrier
liquid will preferably be an amount of at least about 1 pound,
and most preferably from about 5 pounds to about 30 pounds, of
particulate blend per gallon of gelled carrier fluid. In
contrast to noncross-linked carrier fluids, the ability of a
cross-linked carrier fluid to hold the particulate blend in
suspension does not appear to be substantially affected by
21383~6
22
particulate blend concentration.
The treating composition used in the inventive methods
also preferably includes one or more gel breakers. Gel
breaker systems and gel breaker concentrations suitable for
use in the present invention are discussed, for example, in
U.S. Patents 4,199,484, 4,665,988 and 5,128,390. The gel
breakers preferred for use in the treating composition are
materials which, at a time substantially corresponding to the
placement of the treating composition in a desired
subterranean zone, will operate to break the carrier gel and
thereby reduce the viscosity of the carrier liquid. When the
carrier liquid gel is broken, the carrier liquid readily
separates from the particulate blend. Following separation,
the particulate blend provides a permeable mass which
facilitates the flow of formation fluids but prevents the
migration of formation sand and fines into the wellbore.
Examples of gel breakers suitable for use in the present
invention include: enzyme-type gel breakers such as cellulase
and hemicellulase; low molecular weight peroxides and
hydroperoxide compounds (e.g., tert-butyl-hydroperoxide and
alkyl peroxides containing from 2 to about 18 carbon atoms);
perborates; potassium salts; ammonium salts; lithium salts;
inorganic acids (e.g., hydrochloric acid); and organic acids
(e.g., formic acid and acetic acid). When an acid-type gel
breaker is used, the gel breaker can optionally be separately
injected downhole in aqueous solution form following the
injection of the particulate/gelled carrier fluid blend.
2138~4~
23
As indicated above, the treating composition used in the
inventive methods can optionally include a hardenable resin
system. Generally, any epoxy resin system, phenolic/aldehyde
resin system, or other bonding resin system used in the art
for consolidating particulates to form permeable beds or flow
paths can be used in the present invention. When used, the
hardenable resin system will be included in the treating
composition in an effective amount for consolidating the
particulate blend to form a hard permeable mass within the
subterranean zone being treated. Hardenable resin systems,
resin system components, and resin system component
concentrations suitable for use in the present invention are
disclosed, for example, in U.S. Patents 4,199,484, 4,336,842,
4,665,988 and 5,128,390.
The hardenable resin system used in the present invention
will preferably comprise one or more epoxy resins and one or
more hardening agents. Other ingredients typically employed
in such epoxy resin systems include: solvents, coupling
agents, surfactants, and hardening rate controllers.
Examples of epoxy resins preferred for use in the present
invention include: diglycidyl ethers of bisphenol-A;
diglycidyl ethers of bisphenol-F; glycidyl ethers of
aminophenols; glycidyl ethers of methylenedianiline; and epoxy
novolac resins. The epoxy resins used in the present
invention will preferably have epoxide equivalent weights
(EEW) in the range of from about 90 to about 300. The EEW of
an epoxy resin is determined by dividing the molecular weight
-- 213834~
24
of the epoxy resin by the number of epoxide groups contained
in the epoxy resin molecule.
Examples of hardening agents suitable for use in the
resin system include amines, polyamines, amides, and
polyamides. A preferred hardening agent comprises
methylenedianiline which is dissolved in a solvent such as
ethylacetate or is dissolved in a liquid eutectic mixture of
amines diluted with methyl alcohol.
Typically, the amount of hardening agent used in the
resin system will be an amount in the range of from about 2 to
about 150 parts by weight per 100 parts by weight of
polyepoxide resin. When the hardening agent employed is an
aromatic amine, the amount of hardening agent used in the
resin system will typically be an amount in the range of from
about 8 to about 50 parts by weight per 100 parts by weight of
polyepoxide resin. When the hardening agent used is
methylenedianiline, the hardening agent will typically be
included in the resin system in an amount in the range of from
about 25 to about 38 parts by weight per 100 parts by weight
of epoxide resin.
The resin system can optionally include a solvent or
solvent system. When used, the solvent or solvent system will
preferably be included in an amount sufficient to ensure that
the viscosity of the resin system does not substantially
exceed about 800 centipoise at 70F. Examples of solvents
suitable for use in the resin system include: polar organic
diluents which are reactive with epoxide and polyepoxide
213~3~
resins; polar organic diluents which are substantially
nonreactive with epoxy resins; commonly used aromatic
solvents; and mixtures thereof. Examples of suitable reactive
polar organic solvents include: butylglycidyl ether;
creosolglycidyl ether; alkylglycidyl ether; phenolglycidyl
ether; and generally any other glycidyl ether which is
miscible with the epoxy resin(s) used. Examples of
substantially nonreactive polar organic solvents suitable for
use in the resin system are described, for example, in U.S.
Patent No. 5,128,390. Preferred nonreactive polar organic
solvents include ethylacetate, butyllactate, ethyllactate,
amylacetate, ethyleneglycoldiacetate, and
propyleneglycoldiacetate.
As indicated above, the hardenable resin system, when
used, will be included in the treating composition in an
effective amount for consolidating the particulate blend to
form a hard permeable mass. Typically, the amount of epoxy
resin system used in the treating composition will be an
amount providing in the range of from about 0.1 to about 20
pounds of epoxy resin per 100 pounds of particulate material.
When the epoxy resin used in the hardenable resin system is a
diglycidyl ether of bisphenel-A (e.g., EPON 828, available
from Shell Chemical Company), the amount of hardenable resin
system used in the treating composition will preferably be an
amount providing in the range of from about 0.5 to about 15
pounds of epoxy resin per 100 pounds of the particulate
material.
21383~6
26
The epoxy resin system can also optionally include one or
more cross-linking agents which promote the cross-linking of
the epoxy resin system. Examples of suitable cross-linking
agents include: methylene dianiline and isomers thereof;
amine adducts of EPON 828; and amine adducts of other glycidol
ether compounds. As will be understood by those skilled in
the art, the use of such cross-linking agents, where possible,
can provide an economically desirable means of reducing the
amount of epoxy resin required for a given application.
One or more coupling agents will preferably be included
in the hardenable resin system in order to facilitate the
coupling of the epoxy resin(s) with the particulate components
of the treating composition. Coupling agents preferred for
use in the resin system are functional silanes (e.g., N-beta-
(aminoethyl)-gamma-aminopropyltrimethoxysilane). The amount
of coupling agent used in the treating composition will
preferably be an amount in the range of from about 0 to about
3 parts by weight per 100 parts by weight of epoxy resin.
As will be understood by those skilled in the art,
hardening rate controllers (i.e., retarders or accelerators)
can be used to extend or shorten the time necessary for curing
the epoxy resin system. Examples of suitable retarders
include low molecular weight organic acid esters (e.g., alkyl
esters of low molecular weight alkyl acids containing from
about 2 to about 3 carbon atoms). Examples of suitable
accelerators include: 2,4,6-trisdimethylaminomethylphenol;
theethylhexonate salt of2,4,6-trisdimethylaminomethylphenol;
- 213~3~6
27
and weak organic acids such as fumeric acid, erythorbic acid,
ascorbic acid, and maleic acid. Any hardening rate controller
used in the hardenable resin composition will typically be
present in an amount in the range of from about O to about 10
parts by weight per 100 parts by weight of the epoxy resin(s)
used in the system.
The hardenable resin system will preferably also include
one or more surfactants which will improve the wettability of
the particulate materials used in the treating composition and
will thereby enable the hardenable resin system to rapidly
coat the particulate materials. Examples of surfactants
suitable for use in the present invention, as well as
desirable concentrations thereof, are disclosed in U.S.
Patents 4,199,484, 4,665,988 and 5,128,390.
In order to further facilitate the coating of the
particulate material, the treating composition can optionally
include an aliphatic alcohol which is only slightly water-
soluble. Examples of preferred aliphatic alcohols include
isoamyl alcohol and isohexyl alcohol. When used, such
alcohols are typically present in the resin system in an
amount in the range of from about 1 to about 2.5 gallons per
1000 gallons of gelled aqueous carrier liquid.
As will be understood by those skilled in the art, the
hardenable resin system can further include various other
components (e.g., foaming agents, oil-water demulsifiers,
etc.) which are commonly used in fracturing, gravel packing,
and frac-pack compositions.
- 21383~G
28
The components of the treating composition can be blended
together using generally any procedure which is commonly used
for preparing fracturing, frac-pack, and gravel packing
compositions. The treating composition is preferably prepared
by first mixing the gelling agent with brine or some other
aqueous fluid to form the gelled aqueous carrier liquid. The
gelled aqueous carrier liquid will typically then be conducted
to a mixing apparatus such as a continuous stream tub mixer.
Examples of continuous tub mixers used in the art are
disclosed, for example, in U.S. Patents 4,490,047, 4,802,141,
and 4,919,540. The entire disclosures of U.S. Patents
4,490,047, 4,802,141, and 4,919,540 are incorporated herein by
reference. In the tub mixer, the other components of the
inventive composition will preferably be continuously added to
and mixed with the gelled aqueous carrier fluid. As the
components are mixed, the resulting mixture is continuously
drawn from the mixer. The continuous mixture is injected into
the well such that the mixture is directed to a desired
subterranean zone.
If the treating composition includes (a) a particulate
blend which has not been precoated with a resin composition
and (b) a hardenable resin system, the treating composition
undergoes additional blending as it flows down the well tubing
toward the subterranean zone such that: (1) the particulate
blend is thoroughly mixed with the gelled aqueous carrier
liquid; (2) the components of the hardenable resin system are
thoroughly mixed; and (3) the particulate blend is thoroughly
213~34~
29
coated with the hardenable resin system.
When a cross-linked gelled aqueous carrier fluid is used,
the gel cross-linking agent is preferably added to the
composition after (a) the gelling agent is mixed with the
aqueous liquid to form a noncross-linked aqueous gel and (b)
the particulate blend is mixed with the noncross-linked
carrier. This delayed addition of the gel cross-linking agent
can be accomplished at the well site by injecting the gel
cross-linking agent at a point downstream of the mixing tub.
In one embodiment of the present invention, a treating
composition of the type described hereinabove is used to
fracture a subterranean formation. The inventive fracturing
method can be conducted in generally the same manner as a
conventional hydraulic fracturing procedure. The treating
composition is pumped into the formation under a pressure
sufficient to enlarge natural fractures in the formation
and/or open up new fractures in the formation. As the
treating composition is pumped into the formation, the
proppant blend contained in the treating composition rem~in.~
in the fractures which are formed and/or enlarged during the
fracturing operation. The deposited proppant blend operates
to (a) prevent the formation fractures from closing, (b)
provide a high permeability flow path to the wellbore and (c)
prevent the migration of formation sand and fines through the
formation fractures.
If the treating composition used in the inventive
fracturing method includes a bonding resin system, the resin
21~34~
system is allowed to harden after the proppant blend is placed
in the formation fractures. During the resin hardening
process, a sufficient amount of fluid pressure is preferably
maintained on the resin-coated particulate blend to ensure
that substantially all of the coated proppant material remains
in the formation fractures. The hardened resin composition
operates to consolidate the proppant materials in the
formation fractures to thereby provide high permeability flow
paths within the formation which resist particulate migration.
In an alternative embodiment of the inventive fracturing
method, the above-described treating composition is used in a
fracturing procedure of the type described in U.S. Patent No.
4,336,842. As indicated above, this fracturing procedure
comprises the steps of: fracturing a formation by pumping a
viscous liquid of the type described in U.S. Patent No.
4,336,842 into the formation at a pressure and rate sufficient
to fracture the formation; continuing to pump the viscous
fracturing fluid into the formation until a desired fracture
geometry is obtained; pumping a treating composition of the
type described hereinabove into the resulting fracture(s) such
that the particulate blend deposits in and fills the
fracture(s); and, assuming that the treating composition
includes some type of bonding resin system, allowing the resin
composition to harden.
In yet another embodiment of the inventive fracturing
method, the above-described treating composition is used in a
fracturing procedure of the type described in U.S. Patent No.
21333g~
31
5,131,472, issued to Dees et al. The entire disclosure of
U.S. Patent No. 5,131,472 is incorporated herein by reference.
In this embodiment of the inventive method, one or more
fractures are formed in a formation by suddenly applying a
fluid pressure to the formation (preferably by means of a
compressible fluid or a compressible/non-compressible fluid
combination) which exceeds the formation fracturing pressure.
Then, before the fluid pressure being applied to the formation
declines to a point such that the formation fracture(s) is/are
allowed to close, a treating composition of the type described
hereinabove is pumped into the formation fracture(s). In
pumping the treating composition into the formation fractures,
the treating composition will preferably have been mixed with
a gas. The amount of treating composition contained in the
treating composition/gas mixture will preferably be an amount
in the range of from about 5 to about 95 volume ~, based on
the total volume of the treating composition/gas mixture at
surface pumping pressure conditions.
In one form of the inventive Dees et al. type method, a
formation having a casing extending thereinto is fractured by
perforating the casing at a time when the portion of the
casing being perforated is filled with a high-pressure fluid.
A treating composition/gas mixture is then pumped into the
well immediately after the operation of the perforating
apparatus. Examples of perforating devices suitable for use
in this method include wireline-conveyed perforating guns,
perforating guns activated by drop bars, pressure activated
213~3~6
perforating guns, and other such devices.
In another form of the inventive Dees et al. type method,
a well having previously formed casing perforations is treated
by: (a) positioning a tubing string in the well casing, said
tubing string including means for releasing a fluid pressure
in the tubing string; (b) filling the tubing string with high
pressure fluid; (c) suddenly releasing the high pressure fluid
into the portion of the casing which includes the previously
formed perforations such that the high pressure fluid flows
through the perforations and thereby fractures the formation;
and (d) pumping a treating composition/gas mixture into the
formation fractures.
The sudden application of a high pressure fluid to a
subterranean formation in accordance with the Dees et al. type
methods is believed to cause the opening of fractures in
multiple formation planes. Additionally, the fact that the
high pressure fluid is present at each casing perforation
helps to ensure that the high pressure fluid will enter and
fracture substantially all of the perforations. Further, the
injection of the treating composition/gas mixture at a time
before the formation fractures have had a chance to close
desirably increases the size of the formation fractures.
In another embodiment of the present invention, a
treating composition of the type described hereinabove is used
for gravel packing a wellbore. The inventive gravel packing
method is conducted in substantially the same manner as
conventional gravel packing procedures which use standard
- 21383~
33
gravel packing materials. In the inventive gravel packing
method, a screening device is positioned in an open hole or
inside a well casing. If placed in an open hole, the portion
of the wellbore which is to be packed will preferably be
underreamed prior to placing the liner therein. After placing
the liner in the wellbore, the treating composition is
preferably pumped down a tubing string positioned inside the
screening device, out the distal end of the screening device,
and into the annulus existing between the screening device and
the bore wall or well casing. As a result, the particulate
blend deposits in and is packed in the annulus. The treating
composition carrier fluid, on the other hand, separates from
the particulate blend, flows through the fluid openings in the
screening device, and flows out of the well via the annulus
existing between the treating composition tubing string and
the interior wall of the liner.
If the treating composition includes a hardenable resin
composition, the hardenable resin composition is allowed to
harden after the particulate blend has been packed around the
screening device. Upon hardening, the resin system
consolidates the particulate blend to form a hard permeable
mass around the screening device. The inventive gravel
packing method provides a gravel pack which is highly
permeable and which operates to prevent the migration of
formation sand and fines into the screening device.
In an alternative embodiment of the inventive gravel
packing method, a treating composition of the type described
21383~
34
hereinabove is used to pack an open or cased portion of a
wellbore. In this embodiment, a screening device is not used.
Rather, the treating composition is preferable pumped into the
wellbore such that (a) the particulate blend portion of the
treating composition fills the portion of the wellbore which
is to be packed and (b) the carrier fluid portion of the
treating composition separates from the particulate blend and
flows into the formation and/or out of the well via, e.g., a
casing or tubing annulus. If the treating composition
includes a hardenable resin composition, the hardenable resin
composition is allowed to harden. After the resin composition
hardens, a bore hole can optionally be drilled into the gravel
pack in order to further facilitate fluid recovery.
Regardless of whether a hardenable resin composition is used
and/or a bore hole is drilled into the gravel pack, however,
once the gravel pack is in place, fluid recovery is obtained
directly through the gravel pack without placing additional
devices and/or compositions (e.g., casings, cement, etc.)
therein.
In yet another embodiment of the present invention, a
treating composition of the type described hereinabove is used
in the performance of an otherwise conventional frac-pack
procedure. The inventive frac-pack procedure preferably
embodies the features of both the inventive fracturing and the
inventive gravel packing procedures discussed hereinabove. In
the inventive frac-pack procedure, a subterranean formation is
preferably initially fractured using a treating composition of
213&346
the type described hereinabove. The particulate blend
component of the treating composition deposits in fractures
which are opened and/or enlarged during the fracturing step.
After a desired amount of fracturing is achieved, additional
particulate blend is tightly packed in the wellbore. The
additional particulate blend is preferably packed in the
wellbore using a gravel packing procedure of the type
described hereinabove. Most preferably, the additional
particulate blend is held tightly on the wellbore by (a)
packing the additional particulate blend around a gravel
packing screen and/or (b) consolidating the particulate blend
by means of a resin composition.
In most vertical wells, gravel packing provides a
relatively inexpensive and effective means of controlling
particulate migration. In horizontal wells, however, the
length of the production interval involved will commonly be
much larger than the length of a typical vertical production
interval. Therefore, the cost of gravel packing a horizontal
well will generally be much greater than the cost of gravel
packing a typical vertical well. Additionally, due to several
factors inherent in nonvertical completions, it is typically
difficult to form a gravel pack in a nonvertical well such
that the gravel pack surrounds the packing liner in a
desirably uniform manner.
These problems have been addressed somewhat by the use of
prepacked screening devices (see, e.g., U.S. Patent No.
4,969,523, the entire disclosure of which is incorporated
21383~
36
herein by reference).
In addition to the inventive well treating methods
discussed hereinabove, the present invention provides a
prepacked screening device which addresses the problems just
mentioned and provides fluid flow and particulate migration
control properties substantially superior to those provided by
the prepacked screening devices heretofore used in the art.
A prepacked screening device 2 provided by the present
invention is depicted in the drawing. Device 2 comprises: a
pipe or other conduit 4 having perforations 6 extending
through the wall thereof around the entire circumference of
conduit 4; an inner screen 12 wrapped around the exterior of
conduit 4 such that screen 12 covers perforations 6; an outer
screen 14 surrounding and spaced apart from inner screen 12;
and a gravel pack 16 which fills the void space formed between
inner screen 12 and outer screen 14. Device 2 will also
preferably include conventional threaded connections 8 and 10
provided on the ends of pipe 4 for connecting apparatus 2 in
a tubing string in substantially the same manner that a
conventional packed or unpacked screening device is assembled
in a tubing string.
Although other suitable screening systems (e.g.,
perforated tubes) can be used, inner screen 12 and outer
screen 14 are preferably permeable wrapped wire screens.
If desired, inner screen 12 can be radially spaced
slightly apart from the exterior surface of conduit 4 to
thereby provide fluid collection and distribution spaces
21383~6
between screen 12 and conduit 4. The provision of such
spacing between inner screen 12 and conduit 4 can be
accomplished, for example, by positioning conventional spacer
bars 18 between conduit 4 and inner screen 12. Spacer bars 20
can also be positioned between outer screen 14 and gravel pack
16.
The gravel pack 16 employed in inventive device 2 is
comprised of a large particulate/small particulate blend of
the type described hereinabove. The particulate sizes and
concentrations used for forming gravel pack 16 are preferably
the same as those used for forming the particulate blend
employed in the above-described well treating composition.
Gravel pack 16 can be either an unconsolidated
particulate bed or a consolidated particulate bed. Gravel
pack 16 is most preferably a particulate blend which has been
consolidated using a hardenable resin composition of the type
described hereinabove. Although device 2 always preferably
includes an inner screening means 12, inner screen 12 can be
excluded from device 2 when a consolidated gravel pack 16 is
used.
In using inventive device 2, device 2 is preferably
connected in a tubing string and then delivered downhole such
that device 2 is positioned adjacent a producing formation.
Gravel pack 16 provided in device 2 operates to prevent the
migration of formation sand and fines into pipe 4. Additional
particulate migration control can optionally be obtained by
installing a gravel pack around the exterior of device 2.
2l3s3~e
38
This additional gravel pack is preferably formed around device
2 using an inventive gravel packing procedure as described
hereinabove.
The following examples are provided in order to further
illustrate the present invention.
EXAMPLE I
Six packed-bed systems consisting of 12/20 mesh resieved
Ottawa frac sand and/or 50/70 mesh resieved Ottawa frac sand
were prepared for testing. The composition of each of these
packed beds is provided in Table 1.
In preparing each of packed beds 1-6, the 12/20 and/or
50/70 mesh material used in forming the bed was first blended
with 37.5 milliliters of a gelled aqueous carrier fluid. The
gelled aqueous carrier fluid was formed by blending
hydroxyethyl cellulose with an aqueous 2~ potassium chloride
brine solution. The hydroxyethyl cellulose was added to the
brine solution in an amount of 40 pounds per 1000 gallons of
brine solution.
In each case, the particulate material(s) and the gelled
aqueous carrier fluid were blended in a beaker at moderate
speed using a stirring guard and an associated stirring blade.
Approximately one milliliter of a gel breaker (hemicellulase)
was also blended with each composition.
The gelled slurry compositions thus formed were placed in
separate teflon chambers. Each teflon chamber had a 100 mesh
screen positioned in the bottom thereof. After placing the
slurry compositions in the teflon chambers, each composition
213834G
39
was lightly tamped with a lucite rod to ensure that the
mixture was properly packed and did not include air pockets or
void spaces. Each of the packed chambers was then maintained
overnight at a temperature of 100 F. Throughout the packing
and heating process, a vacuum was applied to the bottom of
each teflon chamber.
Each of the packed beds was then flushed with one liter
of a filtered aqueous 2~ potassium chloride solution. After
flushing, the initial permeability of each bed was determined.
The initial permeabilities determined for each of test beds 1-
6 are provided in Table 2.
To determine whether the gel breaker used was successful
in breaking down the gelled carrier liquids employed in
forming packed beds 1-6, two additional packed beds were
prepared and tested. The first additional packed bed
consisted of 100~ 50/70 mesh resieved Ottawa frac sand and was
prepared using only water as the carrier fluid. The second
additional packed bed consisted of 100~ 12/20 mesh resieved
Ottawa frac sand and was prepared using only water as the
carrier fluid. The initial permeabilities of the additional
packed beds were essentially the same as the initial
permeabilities of the corresponding test beds (i.e., test beds
1 and 6) which contained 100~ 50/70 mesh sand and 100~ 12/20
mesh sand. Thus, the gel breaker was apparently successful in
completely breaking down the gelled carrier used in forming
the test beds.
Formation sand migration tests were then conducted
-- 21383~6
through each of test beds 1-6 using an Oklahoma No. 1 sand
sample having a particle size distribution consisting of 50.1~
by weight of 0.0085-0.0059 inch particles, 29.8~ by weight of
0.0059-0.0049 inch particles, 17.7~ by weight of 0.0049-0.0041
inch particles, and 2.4~ by weight of 0.0041-0.0035 inch
particles. The Oklahoma No. 1 sand sample was blended with an
aqueous 2~ potassium chloride solution to form a sand testing
slurry consisting of one gram of sand per 100 milliliters of
the 2~ KCl solution.
In conducting the sand migration tests, 500 milliliters
of sand slurry were pumped through each of the test beds. In
each case, near the end of the sand slurry flow period, the
fluid pressure just upstream of the packed bed was determined.
The effluent flowing through each of the packed beds during
the sand migration tests was also collected in order to
determine the extent to which sand particles had migrated
through the packed bed.
Following the sand migration tests, the permeability of
each of test beds 1-6 was again determined using an aqueous 2~
potassium chloride solution. As part of the post-permeability
test, 4 liters of the potassium chloride solution were pumped
through each of the packed beds. The effluent produced from
each of the packed beds as a result of the post-permeability
test was also collected and examined for the presence of
formation sand. The post-permeabilities determined for each
of the six test beds are recorded in Table 2. Table 2 also
provides the percentage reduction in permeability of each of
213834G
41
the test beds produced as a result of the formation sand
migration test.
The test results provided in Tables 2 and 3 indicate that
the permeabilities and flow conductivities of the test beds
containing more than 60~ by weight of 12/20 mesh sand
substantially exceeded the flow conductivities and
permeabilities of the test beds in which the concentration of
12/20 mesh sand was 60~ or less. As also indicated in Table
3, the pumping pressures required during the migration flow
tests for pumping the dilute sand slurry through the test beds
were substantially lower for those test beds containing more
than 60~ by weight 12/20 mesh sand. Further, the percentage
reductions in permeability resulting from the sand migration
flow tests for the large particulate/small particulate blend
beds are comparable to the percentage permeability reductions
observed for the 100~ 50/70 mesh test bed.
The test beds consisting of 12/20 mesh and 50/70 mesh
sand blends, and particularly test bed 3, also exhibited sand
control properties which were equivalent to the sand control
properties exhibited by the 100~ 50/70 mesh sand bed. No sand
was detected in the effluents collected from any of test beds
1-6.
21383~6
42
TABLE 1
COMPOSITIONS OF PACKED BEDS TESTED
50/70 Mesh Sand 12/20 Mesh Sand
Bed No. (Grams) (Grams)
100 0
2 40 60
3 30 70
4 20 80
go
6 0 100
TABLE 2
TEST BED P~M~RILITIES
Initial Post Reduction
n
Permeability Permeability
Bed No.(Darcies) (Darcies)Due to Flow
Test (~)
1 78 61 22
2 98 68 29
3 140 95 31
4 174 125 29
277 159 42
6 425 292 31
TABLE 3
PUMPING PRESSURE REOUIRED AT END OF FLOW TEST
Pumping Pressure
Bed No. Required (psi)
1 1.67
2 0.71
3 0.38
4 0.51
0.52
6 0.55
EXAMPLE II
Six consolidated particulate beds (i.e., beds 7-12)
consisting of mixtures of 12/20 mesh resieved Ottawa frac sand
2138~46
43
and 50/70 mesh resieved Ottawa frac sand were prepared. The
concentrations of 12/20 mesh sand in consolidated beds 7, 8,
9, 10, 11, and 12 were, respectively, 10~ by weight, 30~ by
weight, 50~ by weight, 70~ by weight, 80~ by weight, and 90
by weight.
In preparing each of the consolidated test beds, 100
grams of the particulate blend in question was blended with a
gelled aqueous carrier fluid and an EPON 828 epoxy resin
system in a beaker using a stirring guard and blade apparatus.
The gelled aqueous carrier fluid consisted of 200 milliliters
of an aqueous 2% potassium chloride brine solution and 0.6
milliliters of a surfactant (i.e., a mixture of coco-betaine
and ethexylated nonyl phenol). 2.1 milliliters of the epoxy
resin system was used for preparing each of consolidated
samples 7-12.
After curing, a micrograph analysis was performed for
each of consolidated beds 7-12. The micrographs indicated
that the large particulate material (i.e., the 12/20 mesh
sand) contained in each of beds 7-12 was evenly distributed.
At low-weight ratios of large sand to small sand, the small
sand appeared dominant. In the bed samples containing 70
weight ~ or less of the large sand material, the small sand
material appeared to encapsulate or surround the large
particles. At higher large sand concentrations, the large
sand particles were much more likely to be situated in contact
with each other.
Thus, the present invention is well adapted to carry out
2138~q~
44
the objects and attain the ends and advantages mentioned above
as well as those inherent therein. While presently preferred
embodiments have been described for purposes of this
disclosure, numerous changes and modifications will be
apparent to those skilled in the art. Such changes and
modifications are encompassed within the spirit of this
invention as defined by the appended claims.
