Note: Descriptions are shown in the official language in which they were submitted.
IB5;26358~US 2 1 88~98
DA'~EOFD~ March 2, 1995
I HEP~ OE~ ~ItAJ'~H5 ~ OR FEE IS BEING
D.. ~ 1 Cv WI~H ~E UNITED ST~TES ~TAL SERVICES
I~IL ~T OFFK E TO ! ~ lL~ SERVICE
UNDER 37 CFR 1.10 ON THE D~TE INDICATED ABOVE AND
~5 ~ Dhta~:v TO THE CO' '-''~U~HER OF PATENTS AND
TW~RK~ ASHU~ON. D~ 211Za~.
~ PATENT
56312 c
CONTRO_ OF PARTIC~LATF FLOWBAC~ IN
~; U ~ '~. K ~ ~ T ~ T ~ S
FT~Tn OF T~R . NVK~ lON
This invention relates to the recovery of
hydrocarbons from subterranean wells. In this
invention, a method, fluid, porous pack and system for
controlling the transport of particulate solids back
from the wellbore is provided. Fibers may be pumped
downhole with proppant to form a porous pack that serves
to inhibit the flow of solid~particulates from the well,
while still allowing the flow of hydrocarbons at
reasonable rates. Other methods allow for selective
formation of voids or channels within the porous pack,
that facilitating well production while filtering
undesirable materials that are not to be admitted into
the wellbore.
RArR~RO~N~ OF T~R lNV~-~ ~ON
- 2 1 88n~8
., .
Transport of particulate solids during the
production of oil or other fluid from a wellbore is a
serious problem in the oil field.
The problem arises because in extracting oil from
undérground it is necessary to facilitate a flowpath for
the oil to allow the oil to reach the wellbore. The oil
is then produced by allowing it to travel up the
wellbore to the surface of the ground.
Transported particulate solids sometimes clog the
wellbore, thereby limiting or completely stopping oil
production. Such solids represent a significant wear
factor in well production equipment, including the pumps
and seals used in the recoveLy and pumping process.
Particles present in the pumped fluid sometimes cause
excess friction and greatly increase wear on sensitive
portions of the fluid handling and production equipment.
Finally, these particulate solids must be separated from
the oil to render the oil commercially useful, adding
even more expense and effort to the processing of oil.
Undesirable paticulate flowback materials that are
transported in fluids flowing to the wellbore are
particularly pronounced in unconsolidated formations.
By ~undesirable', it is meant that the flowback of the
particle is undesirable. In some cases the particles
21 88098
flowed back may be proppant, which is desirable when in
place in the formation (its intended function), but is
not desirable if it flows out of the formation and up
the wellbore. When that occurs, proppant particle
becomes an undesirable contAminAnt because in that
instance it acts to reduce, not increase, the
production of oil from the well in an efficient manner.
In general, unconsolidated formations are those
that are less structured, and therefore, more easily
facilitate the nninhihited flow of fine particles.
Further, particulates sometimes are located in the near
wellbore area for reasons that are not simply based upon
natural flow to such areas. In some cases, the presence
of particulates is attributed to well treatments
performed by the well operator that place particulate
solids into the formation or the near wellbore area.
Examples of such treatments are fracturing and gravel
packlng .
Numerous different methods have been attempted in
an effort to find a solution to the problem of the
undesirable flow of particulates. What has been needed
in the industry is a method, material, or procedure that
will act to limit or eliminate flowback of particulate
materials placed into the formation in a fracturing
21 88098
process. Until the time of this invention, there was no
satisfactory method of reducing or eliminating flowback.
One method employed in the past is a method of
gradually releasing fracturing pressure once the
fracturing operation has been completed so that fracture
closure pressure of the formation rock acting against
the proppant builds gradually. In this way, the method
allows proppant the matrix to stabilize before
fracturing fluid flowback and well production operates
to carry significant quantities of the proppant out of
the fractures and back to the wellbore.
Another method that has been employed in some
instances to assist in reducing flowback of particulates
is the use of so-called "resin-coated proppantn, that
is, particulate proppant materials having an adherent
coating ho~ to the outer surface of the proppant so
that the proppant particles are bonded to each other.
This process further reduces the magnitude of proppant
flowback in some cases. However, there are significant
limitations to the use of resin-coated proppant. For
example, resin coated proppant is significantly more
expensive than other proppant materials, which
significantly limits it application to less economically
2~ viable wells.
2 1 8 8 0 9 8
Fracturing treatments may employ thousands or even
millions of pounds of proppant in a single well or
series of wells. Thus, the use of expensive, resin-
coated proppants is generally limited by economics of
well operation to only certain types of wells, or is
sometimes limited to use in only the final stages of a
fracturing treatment, sometimes known as the ~tailn end
of the fracturing job, or simply the ~tail-in~ of
proppant near the end of the pumping job.
In ll~concolidated formations, it is common to place
a filtration bed of gravel in the near-wellbore area to
present a physical barrier to the transport of
unconsolidated formation fines with the production of
wellbore fluids. Typically, such so-called Rgravel
packing operations" involve the pumping and placement of
a quantity of gravel and/or sand having a mesh size
between lO and 60 U.S. StAn~Ard Sieve Series mesh into
the unconsolidated formation adjacent to the wellbore.
It is sometimes desirable to bind the gravel particles
together to form a porous matrix for passage of
formation fluids while facilitating the filtering out
and retAinm~nt in the well of the bulk of the
unconsolidated sand and/or fines transported to the near
wellbore area by the formation fluids. The gravel
21 8~098
particles may constitute a resin-coated gravel which is
- either pre-cured or can be cured by an overflush of a
chemical b; n~i ng agent once the gravel is in place.
In some instances, various h; n~; ng agents have been
applied to the gravel particles to bind them together,
forming a porous matrix.
Unfortunately, gravel packing is a costly and
elaborate procedure that is to be avoided if possible.
Further, some wellbores are not stable, and thus cannot
be gravel packed. Further, gravel packing does not
completely ~l;m;n~te the production of fines
particulates, and it is preferable to avoid the
production of particulates without employing a gravel
packing operation if possible. Gravel packing will not
work in all instances.
Another recurring problem in pumping wellbore
fluids is the enormous amounts of energy re~uired to
pump fluids cont~ ng large proppant concentrations at
high rates for relatively long periods of time. Large
amounts of energy are needed to overcome the great
frictional forces between the proppant slurry and the
interior of the tubular through which the slurry is
being pumped. Above a certain threshold pressure, the
fluid/proppant mixture cannot be pumped at all, because
2 1 88098
of the great frictional forces present at the
liquid/tubular interface on the interior surface of the
tubular or wellbore. The industry needs a viable
solution to the problem of excess friction during
pumping of proppant. Further, the industry needs a
method or fluid that will inhibit production of
particles, proppant and fines without substantially
adversely effecting oil recovery from the wellbore.
s~n~Y OF '~ vK~1~ON
The present invention provides a method, fluid,
porous pack, and system for treating a subterranean
formation. In one ~mho~im~nt, it provides for formation
of a porous solid pack that inhibits the flow of both
deposited proppant and natural formation particulates
and fines back through the wellbore with the production
of formation fluids. In the practice of this invention,
it is possible to build a porous pack within the
formation that is comprised of fibers and proppant in
intimate mixture.
This porous pack filters out unwanted particles,
proppant and fines, while still allowing production of
oil. In some cases, the porous pack may be selectively
fitted with voids, or finger-shaped projections,
2 1 88098
sometimes called ~hAnne1s~. Such channels are located
wlthin the structure of the porous pack, and serve to
provide a pPrmP~hle barrier that retards flowback of
particles, but still allows production of oil at
sufficiently high rates.
It has been discovered that using fibers to make a
porous pack of fibers and proppant within the formation
also reduces the energy consumption of equipment, and
makes it possible to fracture some wells that
economically could not have justified fracturing without
the added benefit of reduced friction pressure. It has
been found that pumping fibers with proppant provides
significant reductions in the frictional forces that
otherwise limit the pumping of fluids cont~;ning
proppant.
Furthermore, many well treatments that otherwise
were cost prohibitive because of high energy
requirements, or because pumping could not proceed at a
sufficiently high rate to make the procedure
justifiable, are now possible. Using the present
invention, the ability of the fiber mixture to reduce
the friction, thereby allowing faster pumping rates,
facilitates job optimization.
2 1 88098
A well treatment fluid is shown which comprises a
fluid suspension including a simultaneous mixture of a
particulate material and a fibrous material. The
fibrous material may be selected from a group consisting
of natural and synthetic organic fibers, glass fibers,
ceramic fibers, carbon fibers, inorganic fibers and
metal fibers and mixtures of these fibers.
In one aspect of the invention a means for
inhibiting particulate transport in subterranean wells
comprises a porous pack including a particulate material
having a size ranging from about lO to about lO0 U.S.
mesh ln intimate mixture with a fibrous material.
It is therefore an object of this invention to
provide a means and method whereby flowback of
particulate materials either pumped into a wellbore with
a well treatment fluid or present as a result of
unconsolidated formation fines is prevented or inhibited
by the presence of fibers in an intimate mixture with a
particulate material. Further, such flowback may be
prevented by a porous pack, the porous pack formed by
flowing back the well at a relatively high rate, or
perhaps by a chemical means.
~ h~nn~l ~ may be formed in the porous pack to
selectively prohibit production of undesirable
'. 2188o9~ .
particles, while still allowing production of reservoir
fluids, such as oil. This invention may also be used
with resin coated proppants, without any fibers, to form
channels in such proppant materials after they are
deposited in an underground formation This is
especially true.in cases for which the cost of the resin
coated materials is not a significant limiting economic
factor. In some instances, resin coated materials may
be used only as a tail-in at the end of the fracturing
job, because of the relatively high cost of such resin
materials.
It is yet another object of this invention to
provide a means to control the flowback of particulate
materlal in subterranean fluid production without the
use of complicated and expensive resin formulations. In
most cases, it is believed that use of a porous pack
without resin coated proppants is less expensive.
nF.~RTpTToN OF T~l2 p~ FF ~R~;!n EMBODIMENTS
In the treatment of subterranean formations, it is
common to place particulate materials as a filter medium
in the near wellbore area, or sometimes in fractures
ext~n~;~g outward from the wellbore. In fracturing
2 1 ~8098
operations, proppant is carried into fractures created
when hydraulic pressure is applied to these subterranean
rock formations in amounts such that fractures are
developed in the formation. Proppant suspended in a
viscosified fracturing fluid is then carried out and
away from the wellbore within the fractures (as the
fractures are created) and extended with continued
pumping. Ideally, upon release of pumping pressure, the
proppant materials remain in the fractures, holding the
separated rock faces in an open position forming a
~hAn~e1 for flow of formation fluids back to the
wellbore.
Proppant flowback is the transport of proppant sand
back into the wellbore with the production of formation
fluids following fracturing. This undesirable result
causes several undesirable problems: (l) undue wear on
production equipment, (2) the need for separation of
solids from the produced fluids and (3) occasionally
also decreases the efficiency of the fracturing
operation since the proppant does not remain within the
fracture and may limit the size of the created flow
channel.
Currently, the primary means for addressing the
proppant flowback problem is to employ resin-coated
21 ~8098
-
proppants, resin consolidation of the proppant or forced
- closure techniques. The cost of resin-coated proppant
is high, and is therefore used only as a tail-in in the
last five to twenty percent of the proppant sand
placement. Resin-coated proppant is not always
effective since there is some difficulty in placing it
uniformly within the fractures and, additionally, the
resin coating can have a deleterious effect on fracture
conductivity. Resin coated proppant also undesirably
interacts chemically with common fracturing fluid
crosslinking systems such as guar or hydroxypropyl guar
with organo-metallics or borate. This interaction
results in altered crosslinking and break times for the
fluids thereby affecting placement. Additionally, these
chemicals can dissolve the coating on the resin-coated
proppant making their use ineffective.
The difficulties of using resin-coated proppants
are overcome in many instances by the present invention.
Incorporating an amount of fibrous material in intimate
mixture with conventional proppants solves many
problems. The fibers act to bridge across constrictions
and orifices in the proppant pack, and they serve to
stabilize the proppant pack ~ith no or m;nimA1 effect on
proppant conductivity. While this invention is not to
12
2 1 88098
.
be limited by theory of operation, it appears that the
fibers are dispersed within the sand and, at the onset
of sand production from the fracture, the fibers become
concentrated into a mat or other three-~;m~n~ional
framework that holds the sand in place thereby limiting
further proppant flowback with the fluid production.
As used in this specification, the term ~intimate
mixture n will be understood to mean a substantially
uniform dispersion of components in a mixture.
Similarly, the term H simultaneous mixture" will be
understood to mean that the mixture components are
blended in the initial steps of the process, i.e., prior
to pumping.
Fiber length, thickness, density and concentration
are important variables in the success of preventing
proppant flowback. In accordance with the invention,
the fiber length ranges upwardly from about 2
millimeters, fiber diameter ranges of from about 3 to
about 200 microns. There appears to be no upper limit
on the length of the fibers employed from the standpoint
of stabilization. However, practical limitations of
handling, mixing, and pumping equipment currently limit
the practical use length of the fibers to about lO0
millimeters. Fibrillated fibers can also be used and
~ ~ ~8098
.
the diameters of the fibrils can be significantly
smaller than the aforementioned fiber diameters. The
fiber level used in the proppant pack can range from
0.01% to 50~ by weight of the proppant sand. More
- 5 preferably, the fiber concentration ranges from 0.1% to
5.0~ by weight of proppant.
The modulus or stiffness of the fiber appears to be
important in detprm;n;ng perforr-nce. Nodulus is a
measure of the resistance to deformation of a material
and is a material property rather than a sample
phPnnmPn~. Stiffness is a sample specific number which
depends on both the material and its ~;mDncions. As a
general rule, fibers with a modulus of about 70 GN/sq. m
or greater are preferred. This includes materials like
E-glass, S-glass, AR-glass, boron, aramids, and
graphitized carbon fibers. Organic polymers other than
the aramides usually have relatively lower modulus
values. In order for organic polymers, such as nylon,
to be useful in this application larger diameter fibers
are required to provide equivalent performance to that
of E-glass and stiffer materials.
In the materials listed above, E-glass is a
commercially available grade of glass fibers optimized
for electrical applications, S-glass is used for
14
2 ~ 88098
-
strength applications and AR-glass has improved alkali
resistance. These terms are.com.mon in the glass fiber
industry and compositions of these types of glass are
universally understood.
A wide range of ~;m~ncions are useful. Length and
diameter have been discussed above. An aspect ratio
(ratio of length to diameter) in excess of 300 is
preferred. The fiber can have a variety of shapes
ranging from simple round or oval cross-sectional a~eas
to more complex trilobe, figure eight, star shaped,
rectangular cross-sectional areas or the like.
Most commonly, straight fibers are used. Curved,
crimped, spiral-~h~r~ and other three ~;m~ncional fiber
geometries are useful. Likewise, the fibers may be
hooked on one or both ends. They may be of a composite
structure, for example a glass fiber ccated with resin
to increase fiber-fiber adhesion.
The materials from which the fibers are formed is
not a key variable provided that the fibers do not
chemically interact with components of the well
treatment fluids and are stable in the subterranean
envi~ ..e~lt. Thus, the fibers may be of glass, ceramic,
carbon, natural or synthetic polymers or metal
filaments. Mixtures of these fibers may also be
2 1 88098
advantageously employed. Glass, carbon and synthetic
polymers are preferred for their low cost and relative
chemical stability. The density of the fibers used is
preferably greater than one g/cm3 to avoid separation by
flotation in the fluid/particulate slurry. Preferably,
the fiber density is in the range of 1 to 4 grams per
cc, closely mimicking the density of the particulate
materials employed.
Glass fibers are particularly preferred due to
their relatively low cost, easy availability and high
stiffness. R~cAll~e of the fact that placement fluids
and subterranean formation fluids tend to have an
alkaline pH, it is most preferred to use an alkaline
resistant glass (hereinafter AR-glass) having a high
zirconium content. The use of more common, commercially
available silica glasses is possible within the scope of
this invention but, the solubility of these glasses in
an alk~l;ne medium, particularly at elevated
temperatures, may affect the long term stability of the
fiber/proppant mixture over its lifetime in the
w~l1hore.
Carbon fibers are preferred for use under harsh
conditions. That is, under conditions in which the
21 8~3098
lifetime of glass fibers in the formation is limited.
This may include wells with bottom hole temperatures
above about 300 degrees F., steam injection wells, wells
in formations in which the connate water is not silica
saturated (such as limestone formations), wells which
might be expected to be treated with acid, particularly
hydrofluoric acid some time after the proppant/fiber
mixture is put in place, and wells which involve high or
low pH or corrosive enviLo~ s.
Preferable, the carbon fibers should be at least
partially graphitized, preferably more than about 90%
graphitized, and more preferable more than 95%
graphitized. The fibers may be comprised from pitch,
polyacrylonitrile fibers or from novolac fibers by
processes known to those familiar with the art.
Examples of commercially available carbon fibers which
are useful in this process include, but are not limited
¦~ to, Donacarbo-S or Donacarbo-S S-335 from Donac Co.,
l~ Ltd., T-125T carbon fibers from Kreha Corp. of America,
Dialead ~arbon Fibers from Mitsubishi Kasei Corp. and
Panex carbon fibers from Zoltek Corporation.
21 88098
A number of different proppants can be used in this
- invention. Sized sand and synthetic inorganic proppants
are the most c~mmon. Examples include 40/60 sized sand,
20/40 sized sand, 16~20 sized sand, 12/20 sized sand,
8/12 sized sand and similarly sized ceramic proppants
such as "CARBOLITETM~ proppants.
The proppant can be resin coated sand or ceramic
proppant. Resin coated sand is used in some cases as a
substitute for more expensive ceramic proppants because
both are cl~;m~ to be more crush resistant than sand.
The addition of fibers would aid in the control of
proppant flowback or serve t~e other purposes described
herein.
The combination of resin coated sand and fibers
would provide a stronger pack than either system alone.
This may be useful in itself. In addition, the fibers
could allow use of more highly precured resin coated
proppants thereby m; ni m; zing the deleterious interaction
of curable resin coated proppant with typical fracturing
fluid c~mronents.
18
2 1 8809~
The preferred job execution practice is to mix the
fibrous material throughout the entire batch of proppant
to be pumped during the job. This may be accomplished
by adding the fiber to the proppant before it is mlxed
with the fluid, A~;ng the fiber to the fluid before it
is mixed with the proppant or by A~ing a slurry of
fibers at some other stage, preferably before the slurry
is pumped downhole.
In certain cases, it may be preferred to pump the
slurry of proppant and fiber only during a portion of
the job, for example as the last 10-25% of the proppant
into the fracture as a "tail-in~ to control flow back in
the most economical m~nner or for other reasons. The
slug could also be pumped at other stages, for example
to provide an absorbed scale inhibitor to be pumped to
the front of the fracture.
In certain cases, it may be desired to pump small
slugs of the slurry of proppant and fiber in between
slugs of slurry of proppant or to pump small slugs of a
slurry of fiber between slugs of proppant slurry. This
could conceivably be used to control flow dynamics down
the fracture, for example by providing more plugflow-
19
~l 88û98
like behavior. Pumping of small slugs of slurry offiber as the tail-in is one example of this general
procedure.
The slurry of a mixture of proppant and fibers is
useful for various reasons in the entire range of
reservoir applications from fracturing to sand control.
This especially includes the newer technologies of frac-
and-sand-pack and high p~r~-~hility stimulation. In
these applications formation p~rmeAhilities are
typically higher than those for classical fracturing,
ext~n~; ng into the 10 md to 2~ darcy range. As a result,
the fractures are shorter (e.g. 10-200 ft) and wider
(e.g. 1/2-2 ;nches) than classical fractures. Control
of flowback of proppant on these types of jobs can
reduce or eliminate the need for costly hardware such as
gravel pack screens in the hole and simplify job design.
The selection of fiber can be based on chemical as
well as physical reasons. For example, in gravel
packing and related applications where it is anticipated
that the resulting pack-in-place will be treated with
acid mixtures cont~;n;ng hydrofluoric acid, carbon
fibers will he preferred over glass fibers when long
2 1 88098
life of the fibers is desired. Further, such treatments
can provide ~hAnn~ls in the porous pack that serve to
facilitate the filtering action of the proppant pack, as
further described below.
The opposite may also be desired. Use of carbon
fibers through the first 90% or so of the job followed
by glass fibers in the tail-in would result in a pack
which could be treated with solutions of hydrofluoric
acid to dissolve the glass, allow flowback of a small
portion of the sand at the face of the fracture and
improve well productivity. Pumping alternate slugs of
proppant/fiber slurries contA;n-ng the different fibers
could be followed by treatment with acid to produce
fracture with high permeability zones (where the glass
fibers were) but with stable proppant/fiber pack zones
(where the carbon fibers were) to keep the fracture
open. Further, in some cases acid treatment can provide
channels, or voids, in the porous pack. These voids are
regions wherein the proppant is removed from the porous
pack. The treatment of the porous pack may sometimes
result in formation of one or more Ufingern shaped
projections to traverse the porous pack.
21
21 88098
Beyond the advantages of avoiding proppant
flowback, additional advantages have been noted in the
use of fibrous materials in the well treatment fluid.
First, the presence of fibers advantageously has been
found to reduce the friction encountered by the fluid in
the tubular, thereby saving energy and making it
possible to pump jobs that otherwise would not be
economical. This is described in greater detail below.
The presence of fibers in the fluid also slows the
settling rate of the solid materials in the fluid
thereby permitting the use of lesser amounts of
polymeric gelling material in the placement fluid. This
feature offers the advantages of less cost, greater
retA; n~ permeAh;1;ty, a need for lower concentrations
of breaker and avoidance of chemical interaction with
the treatment fluid cn~ronPnts.
The fluid loss properties of the fibers are also
available when fibers are incorporated into a proppant
carrying fracturing fluid. In areas of high fluid loss,
the fibers and sand will concentrate into a mat thereby
limiting additional fluid loss in these areas.
Fibers also offer an opportunity to place well
treatment chemicals in a dispersed form within the
proppant pack. Thus, porous or hollow or dissolvable
21 88098
;
fibers can be filled or formed with various materials
such as polymer breakers, scale inhibitors, and/or
paraffin and asphaltene inhibitors which can be slowly
released within the pack.
The materials from which the fibers are formed is
not a key variable, provided that any chemical
interaction between the fibers and the comro~nts of the
well treatment fluids do not dramatically decrease the
ability of the fibers to perform the desired function.
In some cases, the desired function may actually require
chemical interaction with well treatment fluids.
The exact mech~nip~ of the greatly reduced friction
that may be achieved while pumping fibers and proppant
in connection with the practice of this invention is not
1~ readily det~rm;n~hle. Nevertheless, without limiting
this invention in any way, it is believed that proppant,
during pumping in a fluid wihtin a tubular, generally
tends to align along the center of a tubular, and that
fact tends to provide a destabilized fluid flow, causing
greater frictional forces. When pumped with sufficient
amounts of fiber, however, the proppant/fiber mixture
exhibits reduced friction, apparently because the
mixture stabilizes the proppant across a larger cross-
sectional area of the tubing, rather than merely along
2 1 88098
the center of the tubing. This results in formation of
a lubricating thin water layer at the pipe wall surface,
facilitating decreased friction pressure.
Fibers may be used to design complex flow
channels in the proppant pack. For example, a
fracturing job may be engineered such that voids or
channels (sometimes called ~fingers~) of proppant flow
out of the proppant pack after the pack is formed
downhole, resulting in the creation of open channels
which allow well fluids to flow into the wellbore
without substantial restriction. Of course, the
proppant pack still provides an effective barrier to
particles, proppant or fines that otherwise would flood
into the wellbore.
These fingers may range in length from about one
inch to several feet, or maybe even lor.ger. They may be
created in a number of ways. For example, the well can
be flowed back at a rate sufficient to create channels
without loss of the majority of the proppant pack. A
glass fiber proppant pack, which utilizes glass fibers,
may be treated with mud acid (an aqueous solution of
hydrochloric acid and hydrofluoric acid) under matrix
conditions to dissolve the glass fibers within the
porous pack in finger-like patterns. This may be
24
2 1 88098
accomplished at treating pressures less than that
required to fracture the formation. When the well is
allowed to flow, the proppant will be produced back from
those finger-like areas which no longer contain any
fibers.
This type of process, or others, results in the
selective creation of a customized pack-in-place wherein
the pack contains a series of concentrations of
fiber/proppant mixtures. For example, the majority of
the fracture could be packed with a proppant pack
cont~; n; ng, for example, 1.5% fibers as a total
fiber/proppant mixture by weight. During the final
tail-in at the end of the fracturing job (such as during
the last 1-15% of the total proppant placed in the well)
the amount of fibers could be decreased such that some
lower level of fiber concentration, e.g. 1% fibers could
be utilized.
In general, pack stability to flow decreases with
decreasing fiber concentration. In other words, the
more fiber, the stronger the pack in general. Using
this invention, the zone closest to the wellbore could
develop open fingers while the rest of the pack r~m~i n~
stable. In another example, the majority of the pack
could consist of a carbon fiber proppant pack and the
2 1 88098
tail-in could consist of a glass fiber proppant pack.
In that instance, treatment ~with mud acid or other
hydrofluoric acid cont~; n; ng solution or solvent would
dissolve some of the glass fibers and produce fingers in
that area which will not extend into the areas
cont~; n; ng carbon fibers (because carbon is not believed
to be soluble in hydrofluoric acid).
In a similar m~nner~ ~h~nn~l s can be created in
porous packs of resin coated proppant and fiber, or
under certain conditions even without fibers. Acid
treatment can L~l-~Ve the resin coating on resin coated
proppant after it is in place in the formation. In that
instance it is possible to decrease the flow resistance
of that portion of the pack, allowing it to destabilize
and proceed out of the pack, thereby allowing fingers to
form. In the presence of fibers, acid treatment may be
provided shortly after fracturing. With resin coated
proppants, the acid treatment could occur only after the
resin coated proppant has been allowed to cure properly.
The use of acid resistant fibers, such as carbon,
also allows formations to be treated with acids after
thé fiber/proppant pack is in place. In that instance,
the acid treatments most likely could dissolve the glass
fibers in a matter of minutes to hours.
26
21 83098
The use of fibers may reduce costs in comparison
to, for example, using resin coated proppants because
the use of fibers does not require extended cure .imes
as usually is necessary in applications using resin
coated proppant. Further, fibers can be advantageously
used where multizone formations with low bottom hole
temperatures require a long shut in time between
fracturing each formation to allow resin coated proppant
to cure. The long cure times associated with such
formations may be substantially avoided by using fibers,
so that no shut in time is required, and several zones
may be fractured in a single day. In this case, the
cost saving will vary dep~n~i~g upon the number of zones
to be fractured, and the required shut in times. In some
cases, this will result in the ability to fracture a
well in one day, rather than over a period of about one
week. This is a substantial reduction, and it reduces
cost and reduces shut in time for the well, which is
costly in terms of lost production.
Using resin coated proppant could be accomplished
by shutting in the well to cure, followed by a pumping
of viscosified of fluid having a mobility ratio at
downhole conditions of at least 50/l greater than the
following fluid that would be injected at less than
2t 88098
-
fracturing rates. This fluid could be gelled brines,
but could also be a gelled oil. Following the
viscosified fluid, a solution of regular mud acid
contA i n; ng a mutual sol~ent such as U66 brand mud acid
(U66 is believed to be a registered trademark) or butyl
acetate could be applied in a strength of about 10%.
This fluid might be allowed to flow into the
viscosifying fluid to react with and remove the
viscosified consolidation resin within the channel or
finger. The shut in time would be based on the type of
resin used for consolidation It is anticipated that
some resin systems would be more favorable than others
for this application. The well would then be produced
at a rate that would produce the now unconsolidated
proppant out of the created ch~nn~l s. This cleanout
process could be assisted in some cases in low pressure
wells by injecting nitrogen or carbon dioxide and
rapidly pumping the well back to create the conductivity
enhancing channels or fingers.
In some applications, the fibrous material need not
be fibers, but could be platelet type materials which
increase the cohesion of the proppant in place. Such
platelet materials may increase the cohesion of the
proppant and m;n;mize the amount of proppant flowback
2 1 88098
when the well is produced. The platelets could be used
in the full procedure of the fracturing job, or as a
tail-in. In one application, the platelet materials
could be mixed with gravel at the same vertical level,
wherein the gravel is used in sand control. The
platelets in that instance would p~ve~L the gravel
placed outside the wellbore from flowing back with the
produced fluids, el;m;n~ting the need for a screen in
the wellbore. Platelets may be comprised of a wide
variety of materials, including discs or shavings of
metal, polymers, ceramics, glass, or other naturally
occurring materials. Preferable, the approximate size
of platelets would be larger than 0.6 mm in the longest
~im~n~iOn.
The fluids to be used in as a transport medium for
the fluid suspension are not believed to be a critical
factor in the practice of the invention. In general,
commonly used fluids may be utilized, such as water
based fluids and oil based fluids (foamed or not
foamed). The preferred fluid will vary dep~n~in~ upon
the particular requirements of each well.
The following examples will illustrate several
formulations incorporating fibers. It will be
understood that the presentation of these examples is
2 1 88098
;
solely for the purpose of illustrating the invention and
should not be considered in any way a limitation on the
scope or applicability of the concept of the present
invention.
21 880~
PATENT
C-56312
EXANPIE 1 (CONTR0~):
The leakoff rate of a borate _~osslinked guar
fracturing fluid was determined in the.following manner:
A ~racturing ~luid wa- prepared from ~ynthetic seawater
conta~n1n~ 30 lb/1000 g~l o~ a poly~er ~lurry, 1.0
gal/1000 gal surfact~nt, 0.5 gal/1000 g~l bactericide and
0.25 gal/looo gal antifo~ming agent. A~oximately 2000
~1 of thi~ fluid wa~ croJ~linked with a ~orate
cro~ n~i~7 agent, ~ el into a l~rge baroid cell and
heat-d to 20~ F for 30 r~n~ s~ng 1000 p~i pre~ure,
a fluid 1 ~a~n~ tc~t wa~ per~ormed with a one inch
cand~tone cor having _ low permeability (O.5
n~ arcy). Re~ults are pre~ented in Table A.
EXAMPLES 2--5:
In a m~nner simllar to exa~ple 1, the beha~ior o~
fiber/fracturing fluid m~ - LULe~ were determined. All
test~ were performed identical to exa~ple 1 but included
2.0g of gla~ fiber~ tl/2" long and 16 microns in
dl~meter) th~t were added to the ~luid prior to
~ . Other mo~f~c~tion~ to example ~ were:
EXAMPTF 2 contain~ 30 lb/1000 gal of a polymer ~lurry.
2 1 88098
PATE~T
C-56312
EXAMPLE 3 contAins 25 lb/1000 gAl of a poly~er ~lurry
EXANPIE 4 W~6 prepared u~ing 2% RCl tap water, 30 lb/lOoO
gal polymer ~lurry, 1 0 g~l/1000 gal surfact~nt, O 5
gal/lOoO gal bactericide and 0 25 gal/looo gal
antifoamlng agQnt No cro~ n~ W~ A~ to the
~y~tem
EXANPLE 5 i~ ~dentical to EYa~ple 3 but a F-~A~tone core
ha~ing A per~e~bility of 100 ~ cy Wa6 used
The data are prea~t-~ in T~ble A The6e d~t~
demonstr~t- that t~ fiber~ drA~Atically decre~e the
le~koff rat~ rracturing cond~tion~
TA8LE A T~FF VQT~5 AS A F~NCTION OF TIM~
EX 1 EX 2 EX 3 EX 4 EX 5
1 min 0 4 ml 0 3 ml 0 6 ml 0 8 ml6 6 ml
4 ~in 1 2 ~1 0 6 ml 0 9 ml 1 0 ml7 6 ~1
9 min 2 1 ml 0 6 ~1 1 1 ml 1 7 ml8 2 ~1
16 ~ 2 9 ml 0 6 ~1 1 1 ml 2 2 ml8 8 ml
25 ~n 3 6 ~1 0 6 ~1 1 4 ml 2 7 ml9 4 ~1
36 min 4 4 ml 0 6 ml 1 5 ml 3 1 ml 0 1
2 l 8~0q8
PATENT
C-56312
EXAXPIE 6: (~N ~KUL)
Ihe le~koff rate o~ a part~ te o~rrying fluid was
measured. The ~luid contained t~p water and 80 lb/1000
gal. of hy~ko~y~Lhylcellulose. The p~rticulate was ~
~zed c~lcium c~rbonate ~1-500 microns) which was added
at ~ rtration o~ O.S lb~/gallon of fluid.
A~ tely 250 mls oS t~is f~uid was blended and added
to a l~rge b~roid fluid 108e cell preheated to 17~ F.
A~ter 15 ~inutee, 500 p8i of niL~y~- pre~sure was
applied to force the Sluid a~n-t a one inch sandstone-
core h~ing a perme~bility of 250 n~ rcy.
RQeU1t~ ~re preeentQd in T~ble B.
~S: 7-10
The teets were repeated using gla~s f~bers ~lone and
in combin~tion with thc c~lcium r~hon~te particulate
material. The p~rticle loa~r~ re~ained constant at 0.5
l'b~ of ~luid. The fiber~ were ~dded to the fluid
~t the ti~e of the calcium r~rhon~te addition. The fiber
wa~ q~ ~B ~ function o~ weight percent of the initi~l
c~l r~l~l r~rhor~-te ~ teri~l.
EXAMPIE 6: 100% Calcium r~rhon~te; OS Fiber
33
2 1 8~09~
PATENT
C-56312
EXAMPLE 7: 99S Calcium r~hQn~te; 1% Fi~er
EXAMPl~ 8: g5% Calciu~ r~-honAte; 5% Fiber
EXAMPIE ~: 90S Calciu~ r~-~Qnate; 10% Fiber
EXAMPL~ 10: o% Calcium r~-~Q~ate; 100% Fiber
TABLE 8 T~ FF V~T~U~-~ AS A ~uN~ ON OF TIME
TIME EX. 6 EX. 7 EX. 8 EX. 9 EX. 10
O o O o O o
1 min.110 87 76 171 3~ 2
4 ~n- 117 90 79 174 ~1
9 min.118 93 81 17S 31-1~2
16 min. 119 94 83 176 37
25 min. 118 94 83 176 37
36 mln. 118 94 83 176 38
Example 10 (fiber~ alone) ~howed no migration t nto the
core. P~rt~ ate sy~te~ (Example 6) always ~how ~ome
migration into the core.
The data de~on6trate Du~Lior leakoff ~.,L~ol by the
fiber~. An a~dit t o~Al _avantage of fiber~ is no
part~late ~igration into y.a~el p~ck or formation,
therefore, le8~ damage.
The following eYample~ illu6trate the abiltty o~
f-ibrill_ted fiber6 to 6t~bilize proppant pack6:
34
2 1 38098 PATENT
C-5631~
EXAMPLE 11: (~UN'l'~): 200gram~ 20/40 mesh sand in 105
ml aqueou~ guar ~olution wa~ ~ourLd into a 25 mm di~meter
glas~ column fitted with a bottom valve. Permea~ility o~
the pack wa~ 380 d~rciefi. The sand r~adily flowed
through the 1/8 inch di~meter ~alve when it was opened.
EXA~PLE 12: In a ct~lar ~anner, the Exa~ple ll wa~
repeated but 2g polyacrylonitrile fibrillated fiber wa~
~Y~ with thc ~a~e ~lurry before it wa~ ~u~cd into the
colu~n. The pack perme~h~l~ty wa~ 120 darcies. The pack
did not flow out when the valve wa~ . It wa~ al~o
~table when the val~e wa~ co~plctely rsmoved leaving a
1/4 inch dia~eter hole ~ectly under the ~and pack.
Thi8 illustrate~ the ability o~ fibrillated fiber~
to consolidate a ~and pack.
EXAMPIE 13: Fibers Stabilize Sand Pack: A 30 lb/1000
g~llon ~ ~rl~nk~ guar ~olution was m~de. The
composition Or this fluid was the ~ame a~ in Example 1.
Fifty ml of t~is fluid were ~ixed with 0.8 grams o~ 12mm
long, 16 micron diameter glaa~ fibers. They were nixed
with a ~a~llton ~e~ stirrer at low ~peed for 15
2 1 8~098
PATENT
C-56312
seCon~C. 100 gramc of 20/40 ~L~ nt sand were added to
the ~ixture and mixed by hand in ~ cloPed 4 oz. j~r by
gentle ~h~k;~. The resulting ~ixture~was poured into a
~ertical glags column 12 mm in di~meter with ~ "T"
section at the botto~. The left end of the "TH had ~
6creen installed and the right end did not. First, water
wa~ flowed down th~ colu~ and out the left side Or the
~T" to cle~n the guar fro~ the sand/fiber ~nd ~ake a
p~ck. The per~e~bility of the pack wa~ then me~sured.
It was 278 darcies.
Next, the wat ~ flowed left to right across the "T".
Thi~ w~shed the ~and an~ fiber from the ~T~ section. The
6and/fiber pack in the column section remained stable.
The water ~irection wa then changed to flow down
the column and out the right side of the "Tn. This
created a ~ -~ re drop across the B nd/fiber pack, and
no screen ~.~v~.Led the s~nd fro~ mo~ing with the flow.
The pres~ure drop W~6 increa~ed (by increasing the flow
rate) until the ~and/fiber pack f~iled and flowed out of
the ~ertical ~ection Or the column. The pre~sure drop
acro~ the ~and/fiber pack required to do th$s was in
e~ of 275 kP~ ~ 40 pBi) . Al~ost none of the sand in
;2 ~ 8~09&
PATENT
C-56312
the g nd/~iber pack flowed out of the vertical section of
the colu~n until the ~and pack ~failed.~
EXA~PLE 14: A 30 lb/1000 uncrOf~l tnlre~ guar ~olution
was mixed with the ~.~ant ~an~ (50 ~1 solution with 100
gra~ sand) following the s~me ~.o.~ ~e as in Exa~ple 13
but w~ u~ the ~iber. Ihi~ Lu~e wa~ put into the
column and the guar was cleaned out of the ~ nd pack in
the ~me ranner a~ in Ex~ple 13. The per~eability of
the ~and pack was 2~0 darcics. The c nd pack f~iled
under an un~-a~ably low pre~sure.
These ex~mples (13 ~nd 14) ~llustr~te that mixing
ribers w~th the ~o~y~.L ~and caused the formation of a
~table pack in the colu~n. The fibers held the sand in
place against a such higher force (pre~sure) than t~e
~and without fibera. Al~o, the fibers had a negligible
effect on the permeability o~ the sand pack.
EXAMPI~ 15: Nylon Fibers: Firty ml Or a 30 lb/1000
~n gu~r ~olution were m~Yed with 0.2 gr~mC o~ 20mm
long, 64 micron di~meter, nylon polyamide ~iber6. The
ng W~ done in a ~imil~r manner to that o~ Ex~mple
21 8~09~
PATENT
C-56312
13. Thi~ ~ixture w~s yOu~l into the column and tested
as described in Ex~mple 13. The per~eability of the
sand/fiber pack w_~ 200 d~rcie~. The ~ nd/fiber pack
failed at a ~ wn pre~ure across the pack of 265 XP~.
EXAMPIE 16: S_nd pack Stah~ ation With ~igh Viscosity
Fluid~: 1 gram o~ 32mm long, 16 micron diameter glass
fiber wa~ ed with a ~olution o~ corn ~yrup and water
haYing a ~i-co~ity o~ 600 c~ntipoi~e. The ~ixing wa~
done in a ~a~lton BQ_ch ~tirrer _t low ~peed ~or 10
~con~. 100 gr~m 0~ 20/40 yL~ L s~nd was then ~iYed
with the fibcr and colution. The mixture wa~ ~Ou~ed into
the column descri~ed in Ex~mple 13. In thi~ cace, the
600 centipoise corn ~yrup ~olution w~s ~lowed through the
column. The cand/fiber pack perme~bility wa5 3S2
darcie~- The ~ eD~U~e drop acros~ the ~and/fiber pack
wa~ increased with the flow direction out of the right
side of the ~T" (no screen). The ~ ure drop ~cross
the ~and pack wa~ raised to 400 kPa without p~ck failure.
T~i~ example illustrate~ t~at the ~i~er~ c~u~e the
~nd pack to be st~ble even with hi~h ~isco~ity ~luids
flowing through them. Xigh vi~co~ity ~luids ~lowing
38
2 1 8~09~
PATENT
C-S6312
through the ~and would occur if ~ gu r gel was flowed
b~ck through the ~racture during clean-up.
EXAMPIE 17: scttling: A 30 lb/1000 g~ll n~ guar/borate
cros~linked gel wa~ ~ade. The co~position was that of
the guar solution in kxample 13. 12 ~m, 16 nicron
di~meter gla~ ~ibcr~ (0.8 weight % of sand) ~nd 20/40
~L u~ nt ~and were added to a gu~ntity of the gel such
that thc sand concentration was 10 lb/gallon of gel. The
~and and ~iber werc added to the guar solution prior ~he
gel cross~t n~r solution. The fiber wa~ added to the
~olution, and ~i~pereed w~th a Hamilton ~e~ch ~ixer.
Thi~ w~s added to the ~and in a clo~ed ~ar and gently
~t ~ed by ~h~t ~g. The compo~ition Or the cro~linker
~olution was 0.3 gra~ boric acid, 0.6 grams ~odium
.~d~o~ide, 1.2 grams codiu~ glucon~te, 0.~ ~1 trieth nol
amine, and 0.6 gr~ms ~odiu~ thio~ulfate for 500 ml of
guar ~olution. The re~ulting ~ixture was placed in a
heated clo~ed column ~nd further ~ixed ~y in~erting the
2~ colunn once per ~nute. The mixture wa~ heating to 66
dc~ L__ Cel~u~ ~nd thc column wa~ oriented in the
vertical. The m~LuL~ ran to the bottom of the column.
The settling of the sand and ~iber in the guar gel were
0 9 ~
PAT~
C-~6312
ob~erved a~ ~ function of time at 66 degrees Ce~sius
Pe~ ettling w~ c~lcul~ted ~ follows
~ settling - 100 X (tot~l height-~nd h~ght)/~xlmu~
liquid h - ~ ~ht.
Tot~l height i~ the h~ht o~ ~and plu~ gel liguid
Sand h~ ~t i8 t_~ h~~ ~ht 0~ the top o~ the ~ nd
l~yer ~Axi~U~ ~ height i~ determined with
~and ~nd w~ter in the ~me~ ~mount~
After 315 ~nute~ the ~ettling for the sand and
~ib~r W~8 17% There w~ no t-n~-n~y o~ the sand and
riber~ to ph~se eep~r~te during the ~ettling
EXANPLE ~8 The ~xperinent of Ex~mple 17 was repe~ted
with 1 3% o~ the gl~ fiber ha~ on the ~and we~ght
In this c~e, ~fter 260 ~inute6 the settling wa6 14%
EXANPIE 19 T~e ~and ~lone in the fluid o~ Ex~mple 17
~ettled 60% in 300 minuteC By comp~rison with Example~
17 ~nd 18, thi8 ex~mple ~how6 th~t the gla~s ~iber~
reduce the ~ettling r~te of the s~nd in the gel
~? I 8~0~8
PATEN~
C-56312
EXANPLE 20: Interaction with Borate Gel: Six liters of
a 30 ~ OOo gallon ~.~LC~ n~ guar ~olution were
mixed with 47.6 gra~ oi 12 mm long, 16 micron diameter
glass fihers. Th- fiher level wac har~~ on 8 lb/gallon
6~nd lo~ n~. No s~nd was added to the fiber/601ution
~ixture. The fiber/so~ution mlxture was allowed to sit
a~lo~imatcly one halr hour ~fter ~ixing. Two fifty ~1
6ample~ wer- r-~ov-d. Thc fibe~ were filtered rrom one
Or the fifty ~1 ~pl-s. Thc Fann35 viccosity Or each
sample was ~ea~ured at 70 degrees F. The sample ~i~
ribcrs had ~iscocities Or 51 and 30 cp. ~t 170 ~nd S10
sec~l r~te re~pectively. The filtered s~mple had
- ~iccosities Or 42 ~n~ 24 cp respectively. The
visco~itie~ Or the ~iltered ~ample were well within
6pect~0~t~0ns for this gu~r solution. The ~olution with
fibers had a slightly h~ r ~i~cosity.
Next bor~te cro~Cl~n~r solution (composition in
Ex~mple 17) W~6 added to both solutions. The time to
g~ n~ wa~ nsa~ured for both by ~h~ng lip~ method~. The
filtered ~olution had a ~hang lip~ time Or 4 minutes, 44
-e.-Qn~. The ~ Q le with ~iber had ~ ~hang lip~ ti~e of
41
2 ~ 8~9~
PATENT
C-56312
4 ~inutes 27 -~oon~ . Both these cross1inking times are
within specification~ for the~e guar gelc.
This ~x~mple illufitrates t_at the preferred glass
fiber~ do not afrect t_e ~isco~ity and the "hang lip" gel
tines of the borate croc-l~ n~ guar gel. This
illu~trates th~t the glas6 fibers ~o not affect the guar
gel chemi~try or ~isco~ity ~ ~n~ ficantly.
EXAMPI~ 21: Interaction With Zirconate Gel: The s~me
mixing ~o~ o as in Example 20 was followed with a 50
lb/1000 gallon L~dk~ 1 gu~r solution. The 12 ~m
glass ribers wcre added to, then riltered out o~ one
aliquot o~ the solution. Thi~ aliquot and another
aliquot t~at had not been expoQed to the fibers were
CrOB~l ~ n~ with a 4.5 lb/1000 gallon zirconium solution.
The solution was 4~% zirconium crosslinker, 24S high
te~pet~Lule stab~l~ 7er ~ and 36% w~ter. Crossl~ n~ ~g hang
lip time~ were 9:19 ~inutes for the s~mple not ~x~_-ed to
the fiber~, and 10:13 minute~ for the ~mple ~YpOFr~ to
the ~iberG. Again, the ~ibers do not affect the
cro~l ~nlr~ gel che~iE~try.
2 1 8~09~3
PATENT
C-56312
EXANPIF 22: ron~ti~ity. ron~ti~ity ~esting was done
with 20/40 mesh ~ G~ant. The fluid was a 30 lb/lOOo
gallon uncros~linked guar ~olution. Th~ co~pos~tion was
17ml of 2% ~Cl water, 0.12 ~1 guar ~lurry, 0.02ml
S fluoroo~rh~n ~urfact~nt, ~nd 0.005ml defoamer. The fluid
was mixed with 63 gr~m~ o~ 20/40 ~ ~nt. The test was
done in ~ n~ti~ity cell at 25~ F and 5000 psi clo~ure
DL~ . The ~ tivity after 23 hours of ~lowback was
157 d~rcie~.
The te~t WaB repeated with the same guantities of
fluid and ~ nt. In addition, 0.5 qr~R (0.8%) o~ 12
mm long, 16 ~icron di~eter ql~Rs fiber~ were ~ixed with
the propp~nt ~nd ~ . Th~ CQ~ ~ti~ity ~fter 24 hour~
o~ ~1fwLack ~as 153 darcies.
Thi~ ex~pl~ illustr~te~ that the fibers have a
negligible effect on ~L~ant pack permeability.
EXAMP~E 23: Slot Flow. The fiber/6and p~ck
st~ility wa~ ts~ted in ~ ~lot geometry. 5 liter6 o~ 30
lb/1000 g~llon ~ sltn~A guAr ~olution were m~de (34
ml gu~r ~lurry, 5 ~1 surract~nt, ~nd 1.25 ml defo~mer and
5000 nl of tap water). ThiB wa~ mixed by recircul~ting
the ~luid through ~ holding t~nk and centrifuge pump for
43
2 1 8~3~8
PATENT
C-56312
15 ~inutes. 5000 gr~ms of 20/40 ~ nd was then added ~nd
allowed to disper~e for ~.oximately 1 ~inute. ~0 g ~ms
of 12 ~ long, 16 micron di~meter gla~s fiber were added
to the mixture. The re~ultiNg ~lurry was pumped into the
slot.
The slot i8 ~ x~ately 5-1/2 feet long, 1/4~ wide
and 6" hig~. The ~urface- are ~mooth, with the ~ront
~urfaoe being clear to ~llow ob~ervation. A screen w~
pl~r-~ over the ~xlt port ~o th~t the ~and could not flow
out of the ~lot. The 81urry was pumped into the ~lot
fron the other en~. In thi~ g~ometry, a pack of ~and and
fiber~ built up agatn t the ~creen, while the fluid was
~llowed to flow through the ~crsen to ~ hnl~n~ tank. A
6" long sand/fiber pack W~6 built up again t the screen.
The gu~r fluid wa~ then W~h~ from the p~ck wit~
water. The acreen wa~ removed from the end o~ the slot,
le~ing the pack with ~n open 1/4~ x 6~ ~ace. W~ter was
flowed through the p~ck to te~t it~ DL~-yLh. The w~ter
flow was incre~sed until ~ 6 pci ~ -~ure drop w~s
~ LQd by the p~ck. At this point the p~ck beg~n to
fail ~nd ~nd flowed out of the ~lot.
44
0 9 8
PAT~NT
C-S6312
EXAMPLE 24 Slot Flow, Rough wall~, Glass fi~ers The
same ~lurry a~ in Example 23 wa~ again tested in the 510
geo~etry In thi~ exa~ple, the w~ of the slot were
ro~ghPn~d Thi~ was done by ~d~ering ~ layer of 20~40
~and to the wall~ of the ~lot with rubber cement In
thi~ geo~etry, ~ 22~ ~ny fiber p~ck w~ obt~in~ and the
~L ~ yUh o~ t~e p~ck e~ e~ 15 p~i drawdown (upper
l~mit on pump)
EXAMP~ 25 Slot Wlth Gas Flow A si~il~r ~lurry as
used in EY~mple 23 w~ uJed in thi~ ex~mple In thi~
eY~mple we u-ed ~ 10 ~b/1000 g~llon gu~r ~olut~on Thi~
~lurry wAc pu~ped into the elot with rough wall~ and the
s~reen a- de~cribed in ~Ya~ple 24 The guar solution wa~
wa~hed from the ~~nd/~iber pack with water Then the
pack WA~ dried with ais ~lowing through ~t for 3-1/2
hours The ~creen was removed and the te~t for p~ck
L ~ ~y Lh was performed The p~ck length was lB n . ~he
~ir Slow rate was increased to 13 p~i drawdown acrosc the
pack The pack did not fail
The pack was then ~urther dried at low _ir ~low rate
for an a~tttn~Al two hours The test was repeated The
2 1 8~098
PATENT
C-~6312
sand/fiber pack did not fail with flow up to an 11 psi
drawdown ~cro~s the pack.
This examplc illu-trate~ that the sand/~iber paok is
re~i~tant to ga~ flow~ ~8 well as w~ter ~low~.
S
EXAN~IE 26: Slot Flow With 1/2 n ar~ide fibers:
~EVLARTM poly~r~mide ~berc were tested in th- clot
geometry wit~ rough walls. The fluid was a 20 lb/1000
gallon uncro~sl tn~ gu~r ~olution similar to Exa~ple 23.
The ar~m$de ~ibers were 12 ~m long ~nd 12 ~icrons in
diameter. The slurry ~ixture was 4 llters of ~luid, 4 kg
o~ 20/40 ~.~.L 8~n~, _nd 12 gr_ms o~"KE~AR' riber (0.3
wt. % of sand)-
The sand/~iber ~lurry was pum2ed into the rough
w~lled ~lot with the screen at one end a~ was de6cribed
~n Ex~ple~ 23 and 24. The re~ulting ~and pack was 14.5~
long. The fluid was wa~hed rrom the sand fiber p~ck w~th
wAter. The ~ _~. was removed and the water wa6 agzin
~lowed th~v~yL the pack. The pack beg~n to fail at 3 ps~
~ wn.
EXA~}IE 27: Slot Flow, 1~ Nylon Fiber~: We te~ted 1
long nylon fi~er~ in the rough walled ~lot. The fiber~
46
2 1 ~9~
PATENT
~-~6312
were 64 mlcron6 in diameter. The ~lurry was 5 liters of
30 lb/1000 gallon uncro~ClinkD~ guar ~olution, 5 Rg of
20/40 ~L~ant ~and, ~nd ~5 yramfi of nylon fiber. The
~and/fiber p ck length wac 6~. The pack began to fail at
le6~ than 1 p~i d.~w~wn.
Example~ 23-27 illustrate that ~iber~ 6tabilize a
~,u~nt p~ck in a ~racturing geometry even with 6~00th
wall~ an~ no clocur~ ~tr~
EXANPIE 28: ~lot Flow: The fib ~ ~and pack DLL~yLh was
te6tod. A 30 lb/1000 g~ uncro~ n~ gu~r solution
with the same composltion as RY~mrle 23 e~c~L that 2S
RCl water wa8 u~ed. 20/40 ~ant was added to the
fluid at 12 poundc per gallon. 12 ~m long, 16 micron
diameter glass fiber~ were al80 A~D~ at lS o~ the
~o~ant lovel.
The clurry wa~ loAded into a 5-1/4 n by 5-1/4~ by
1/4~ ~lot. The walls of the slot were lined wlth
Springwall ~_ndstone. A clo~ure Dl ~er- o~ 250pri was
~pplied. The cell wa~ heated to 21~ ~. The fluid wa~
washed from thQ gel with a 1% RCl ~olution flowing at a
slow rate (50ml/mln). The brine was then w s~ed ~rom the
2 ? 8809~
PATENT
C-56312
cell with a saturated niL.G~e.. gas flow. The cell was
then heAted to 22~ F. The test wa~ no performed with the
nitrogen flow at incr~ar~n~ drawdown across the pack.
The pack w~ ~tablc at 20 p~$/ft. with a closure stress
ranging from 100 to 200 psi.
EXANPLE 29: Slot Flow, NO FIBER~: The ~ame experi~ent as
in Example 28 wac performed with ~yant without fibers.
At 250 p8i clo~urc .LL~r, 1/4~ ~lot, 22~ F, the y~y~ant
lo pack fa$1ed at le~ than 0.2 psi/ft.
~ -~ e~mple~ demonstrate the ab~lity of fiber~ to
6tabilize a ~.~yant pack under representative downhole
conditions.
EXANPI~ 30: Yard Test: The glass fibers were tested in
a yard te~t. The 12 mm long, 16 micron diameter glass
fiber~ were A~A~ at a 1% level to the s~nd in a
simulated ~racture ~ob. The fiber~ were ~P~ by hand
into a fracturing fluid blcnder with the 20/40 proppant.
T~i~ ~ixture wa~ combined with the 30 lb/1000 g~llon
cro~ racturing fluid in the blender. It then
flowed tl~ouyh a triplex pump, a tree savex, a vaxiable
48
2 1 ~09~
PATE~T
C-56312
choke with 1000 p~i drawdown, and 300 y~rds of 3 inch
pipe.
The pumping ~chedule was:
1 ppg ~ ~ant at 6bbl-/~in.
1.5 ppg ~L~fV-~L at 6 bblc/~in.
2 ppg ~ nt at 6 bbl-/~in.
3 ppg ~ .ant ~t 8 bbl~/~in.
4 ppg ~ nt at 8 b~ n.
1o S~mple~ of the ~ixture wcre taken at the exit of the
pipe. The glas~ fiber- were well ~ixed with the propp~nt
~nd fluid, ~l~h~h ~omc ~lber br~ ge was apparent.
The -~A~ple ~e~on~tr~te~ that fiber/~and ~lurrie~
can be pu~ped wlth ~G~v~ o~Al pumping eguip~ent and
th~t the fiber~ are ~t~ble ~uyh to survive thi~
treatment
EXAMPIE 31 Pe~ Lion pA~t~ The ~bility of riber~
to keep sand in a re~ervoir over a 1/4~ perforation was
tested A ~odel perfor~tion 1/4~ in diameter and 3~ long
with a 75 cubic inch re~-rvoir at the outlet wa~ used for
th~ te6t~ The reservoir wa~ eguipped with a 20 me~h
~creen at the oth ~ side from the perforation Slurry
~o 11~ then flow into the reservoir tLL~yL the
perfor~tion ~nd out thl~yh the ~creen ~ 5 ~ of ~ 20
2 i 8~09~
PAT~
C-56312
lbm/1000 gal/h~o~Lhyl cellulo~e tREC) solu~ion was
prepared (135 g Ng4Cl (3 wt%), 28 3 m~ HEC olution and
dry caustic to rai~e the p~ to 8) Thic w~s ~ixed by
recirculating th- fluid Lhl~uyL a holding tank and
~e L.ifuge pump The fluid wa~ L~aLed for ca 30 min
13 5 g ArA~ide ~tapl-, V2~ long, wac ~lxed in and
2,696 5 g 20/40 ~and were adaed to the ~Yture (~ l~n/gal
~ant, 0 5 wt% ~iber b~ed on the ~L~ nt) The
resulting 81urry wac pu~ped into the reser~oir LL~vuyL
the 1/4" perforat~on A pack Or ~and and ~iber~ ~uilt up
againct the ccr en, whlle the ~ wa~ allowed to flow
through the ~ e~ into the h~ n~ tank.
After p~r~ n~ the perfor~ation, the line~, the
holding tank ana the pu~p were cleaned and f~lled with
water. The flow ~rection wa~ .~v~ed and water wa~
pu~pcd from the ~creen side tL~uyL the packed
perforation. No ~ nt W~B ~ 1 through the 1/4~
hole even by increasing the flow rate till a pre~6ure
drop across the pack of 15 p~i was re~h~ and kept for
sevcral ~inutefi. The water flow wa~ turned off and on
se~eral time~. That did not pro~uce s~nd either.
2 1 8~098
PATENT
C-56312
EXAMPIE 32: The ~ame perforaetion was pA~ with 20/40
~and and 12 mm long, 16 micron diameter gl~s~ fiber using
~a 30 lbm/looo gallon uncro~-ltn~ guar solution. 4.5 L
fluid were prep~red (90 g RCl (2 wtS), 4.5 ~L surractant,
1.125 ~ defoamer, 30.6 m~ guar ~lurry) ~nd hydrated for
30 ~in. 27 g gl~s fiber w re ~ nd ~fter one minute
2,700 g 20/40 ~,~.L (5 lhm~gal~ 1 wt% fiber based on
~ant). The p~ck~ n~ and w~ter flow were done as in
EY~P1e 3 1 .
T~e p~cked perfor~tion w~ kept for 10 daya. Wi~hin
t~i~ time w~ter W~8 flown through it c~. 5 times, each
time turnlng the pump on _nd off ~ever~l timea. The pack
wa~ ~table ~nd pr~An~ - ~ one tea~poon ~ o~ant at ~he
mo~t.
EXAMPLE 33: The ~me ~etup a~ in Exa~ple 31 except for
a 1/2~ peYrv~Lion. Thi~ time pol~o~ylene fiber~ (1/2"
long, 4 ~ r) ~nd 30 l~m/1000 gal HEC were used.
Fluid: 4.5 ~. 135 g N~4Cl, 42.5 ~L HEC ~olution, caustic
to rai~e the p~ to 8.
~ nt: 2,696.5 g 20/40 ~and (5 lbm/gal)
Fiber: 27 g poly~lv~ylene, 1/2~ long, 4 denier (1 wt%
- based on ~L~p~.L)
21 88098
.,
Packing and flowing water through the above worked
well, and no sand production was encountered even over
1/2~ hole.
Examples 31 through 33 illustrate that different
types of fibers may be used to hold sand in place in the
formation beyond the perforation tunnels. This is
applicable to gravel packing, where gravel is placed
outside of the perforations to stabilize subterranean
formation sands.
EXAMPLE 34: Stabilization of Different Types of
Proppant: Column experiments were performed using the
fluid c~mro~ition (30 lbilO00 gallon guar solution), and
procedure as in Example 13. 50 ml aliquots of fluid
were mixed with 100 grams each of various proppants and
1 gram (or 1.6 grams) each of 12 mm long, 16b micron
diameter glass fibers. The proppants were 20/40
"CARBOLITETM , 20/40 ~ACFRAC SB ULTRATM curable resin
coated sand, and 20/40 ~ISOPACTM light weight gravel.
The ~CARBOLITE n proppant has approximately the same
density as sand, but is more spherical. The "SB ULTRA"
has a~o~Lmately the same density and sphericity as
sand,.but has a polymer coating. The n ISOPAC"
2 1 88098
lightweight gravel is much less dense than sand, is more
spherical, and has a polymer coating.
The results of the column tests are shown in Table
S C -
.
TABLE C. Strengths of Various Glass Fiber/Proppant
- Packs
Fiber Level CARBOLITE SB ULTRA ISOPAC
St. % sand
1% >2 5 kPa >250 kPa 55 kPa
l.6% >2 0 kPa >250 kPa
Examples 13 and 34 illustrate that the coating and
sphericity of the proppant do not affect the ability of
the fiber to strengthen the pack. Low density proppants
("ISOPAC") may require greater amounts of fiber for pack
strength.
EXAMPLE 35: The procedure of Example 31 was repeated
except that the pack was made in such a way that the
half of the perforation model closest to the perforation
hole was filled with an identical sandtfiber mixture
- while the back half of the perforation was filed with
sand. The pack was tested in the same way. No sand was
produced.
53
2 1 88098 -
Packing and flowing water through the above worked
well, and no sand production was encountered even over
1~2~ hole.
Examples 31 through 33 illustrate that different
types of fibers may be used to hold sand in place in the
formation beyond the perforation tunnels. This is
applicable to gravel packing, where gravel is placed
outside of the perforations to stabilize subterranean
formation sands.
EXAMPLE 34: Stabilization of Different Types of
Proppant: Column experiments were performed using the
fluid composition (30 lb/1000 gallon guar solution), and
procedure as in Example 13. 50 ml aliquots of fluid
were mixed with 100 grams each of various proppants and
1 gram tor 1.6 grams) each of 12 mm long, 16b micron
diameter glass fibers. The proppants were 20/40
"CARBOLITETM , 20/40 ~ACFRAC SB ULTRATM curable resin
coated sand, and 20/40 "ISOPACTM light weight gravel.
The "CARBOLITE~ proppant has approximately the same
density as sand, but is more spherical. The n SB ULTRA"
has a w~oximately the same density and sphericity as
sand, but has a polymer coating. The n ISOPAC"
2 1 8 8098
''
lightweight gravel is much less dense than sand, is more
spherical, and has a polymer coating.
The results of the column tests are shown in Table
C. -
TABLE C. Strengths of Various Glass Fiber/ProppantPacks
Fiber Level CARBOLITE SB ULTRA ISOPAC
St. % sand
1% >225 kPa ~250 kPa 55 kPa
l.6% >250 kPa >250 kPa
Examples 13 and 34 illustrate that the coating and
sphericity of the pro~p~nt do not affect the ability of
the fiber to strengthen the pack. Low density proppants
("ISOPAC") may require greater amounts of fiber for pack
strength.
EXAMPLE 35: The procedure of Example 31 was repeated
except that the pack was made in such a way that the
half of the perforation model closest to the perforation
hole was filled with an identical sand/fiber mixture
while the back half of the perforation was filed with
sand. The pack was tested in the same way. No sand was
produced.
21 88098
':
Example 35 demonstrates that the proppant/fiber slurry
may be used as a tail-in during the final stages of the
procedure, or may be pumped in stages between slugs of
proppant slurry.
S ' ..
EXAMPLE 36: Proppanttfiber pack strength tests were
performed in a rectangular cell with inside ~;m~ncions
of 12.7 cm long, 3.8 cm wide, and 2.5 cm thick. The
cell was open at both ends. A perforation type geometry
was set up in the cell by creating a restriction 0.63 cm..
on all inside dimensions. T~e cell was set up with a
screen at the outlet. A slurry contAin;ng 500 ml of 30
lb/1000 gallon guar solution in water (composition in
Example 1), 500 grams or 20/40 sand, and water
(composition in Example 1), 500 grams of 20/40 sand, and
1.25 grams of 7 micron by 0.63 cm carbon fiber was
pumped into the cell and formed a pack against the exit
screen. The guar was washed from the pack and then the
screen was removed from the exit port. A closure stress
of 500 psi was applied to the face of the pack. Water
was flowed from the inlet to outlet through the length
of the pack. The proppant and carbon fiber pack
resisted the flow of water up to 35 kPa ~about 5 psi)
56
- 2 1 88098
before the pack filed and flowed through the
restriction.'
EXAMPLE 37: The same test as above was performe by 5
grams of AR grade glass fibers (20 micron diameter, 1.27
cm long) were added to the sand and carbon fiber slurry.
The resulting pack held a drawdown of 135 kPa (about 18
psi) without failing.
10 EXAMPLE 38: The same test as above was performed with a
slurry of 500 ml 30 lb/1000 gallon guar solution, 500
grams 20/40 sand, and 5 grams AR grade glass fibers (20
micron diameter, 1.27 cm long). The pack failed at a
drawdown of 36 kPa (5 psi).
EXAMPLE 39: The same test as above was performed with a
slurry of S00 ml 30 lb/1000 gallon guar solution, and 50
grams 20/40 sand without fiber added. The pack failed
;mme~;ately with the onset of water flow, and no
measurable pressure drop was.maintained across the pack.
EXAMPLES 36 - 39 show that carbon fibers can be used to
stabilize the pack and that mixtures of fiber can result
in stronger packs than a single fiber type.
57
2 1 88098
- EXAMPLE 40: Proppant fiber pack strength tests were
performed in a disk shaped cell. The diameter of the
disk is 15.2 cm, and the thickness is 1.2+/-0.05 cm.
the cell has inlet and output openings 10.2 cm across.
A screen was placed across the outlet. A slurry
cont~; n;ng 1000 ml of S0 lb/ 1000 gallon guar solution,
1000 grams of proppant, 15 grams of AR glass fibers (20
micron diameter, 12.7 mm long) was pumped into the cell
and formed a pack against the screen. In each test the
proppant size was varied. The guar was w-~he~ from the
pack, and then the screen was L~..ov~d. Closure stress of
1000 psi was applied to the faces of the disk. The
excess pack was cleaned from the cell, so that the pack
was perpendicular to the flow direction from inlet and
outlet. This resulted in a pack length from inlet to
outlet of 11.4 cm. Water was then flowed through the
pack until it failed and proppant flowed out of the
cell. This coincided with a relaxation of the closure
20 stress.
PROPPANT PACK STRENGTH
20/40 60 kPa (8.5 psi)
12/20 21 kPa (3 psi)
16/30 21 kPa (3 psi)
58
- 2 1 88098
The same procedure was followed as in example 40
except that no fiber was added to the 20/40 sand pack.
The pack failed at the onset of water follow and no
pressure drawdown was maintA;ne~.
The results show that the fibers will strengthen
different proppant sizes.
EXAMPLE 41: 500 ml of a 50 pound per 1000 gallon borate
crosslinked guar gel were prepared. The gel contained 3
grams guar, 10 grams potassium chloride 0.5 ml
surfactant, 0.25 ml bactericide, 0.125 ml antifoam
agent, 0.5 ml stabilizer (iron control), 0.6 grams
oxygen scavenger, 0.6 grams boric acid, 1.5 grams sodium
hydroxide, and 3 grams sodium gluconate. 500 grams of
20/40 US mesh brady sand and 7.5 grams AR grade glass
fiber (20 microns diameter, 12.7 mm length) were mixed
into the gel.
The resulting slurry was poured into a metal tube
22.1 mm inside diameter, and 127 mm in length. The ends
of the tube were capped, and it was then heated to 150~C
for 24 hours. These conditions were sufficient to
"break~ the gel. The tube was cooled, opened and a
2 t 88098
washer with 12.7 mm hole was fitted into one end of the
tube. The tube was connected to a water source such
that the washer was at the outlet end of the tube.
Effectively the slurry mixture was held from sliding out
of the tube by the washer, but water could flow through
the slurry sand pack.
The water flow was initiated at a low flow rate to
wash the broken gel from the sand pack. No sand flowed
out the tube with the water. The water flow rate was
then increased. No sand flowed until the flow rate
reAche~ 7.6 L/min. which correcron~ to 381 kPa
drawdown across the pack. At this point the sand pack
failed and ran out of the tubing through the washer.
EXAMPLE 42: The same experiment as abG~e was run with
the crosslinked gel and sand, but without the AR glass
fibers. The sand pack flowed out of the tube through
the washer at very low flow rate during the cle~ning of
the broken gel from the pack.
EXAMPLE 43: ~
This example shows that the use of fibers may
reduce treating pressures. During a fracturing
2~ ~8~98
treatment in southern Texas, concentration of 20/40
ceramic proppant was ramped up from 0 to 2 to 4 to 6 to
8 pounds proppant added (ppa) per gallon of fluid.
Shortly after initiation of the 8 ppa stage the treating
pressure increased from 5800 psi to more than 7500 psi.
Then, 1.5% fiber was added to the slurry. The treating
pressure rapidly decreased back to 5800 psi. After some
time, fiber addition was stopped. Treating pressure
;mme~;ately began to increase. When the pressure
reached 6500 psi, addition of fibers was resumed, this
time at 1% by weight of propp~nt. Treating pressures
again declined to 5500 psi. This example demonstrates
the use of fibers to reduce treating pressure during a
fracturing treatment.
EXAMPLE 44:
Fibers may be used to provide rapid well
turnaround, reducing treating costs. Typical wells in
the shale formations in Indiana contain several
productive zones. Creation of one large fracture to
cover all zones in a given well is not a viable
solution.
Previous practice had involved fracturing each zone
using resin coated proppant. At the end of each
61
21 88098
treatment, the well is shut in for 12 to 20 hours to
allow the resin coated proppant to cure. The well then
is allowed to flow for 30 minutes and the next zone then
is fractured. In this manner it requires one week on
location to fracture four zones in a well.
With the use of fibers at 1.5% by weight of
proppant during the last stage of each treatment, the
zone fractured may be turned around within ten minutes
and then the next zone is fractured. That second zone
then is produced for about 30 minutes and then the next
(third) zone may be fractured, and so on. In this way,
four zones in a single well were fractured in less than
8 hours on location. This results in a sa~ings of 3-4
days of rig time on location that otherwise would be
required while waiting for resin coated proppants to
cure, followed by subsequent drilling GUt of the cured
proppant in the well bore. In most cases, it requires
several days on location for a power swivel and bit to
drill out cured resin coated proppant. This can reduce
costs by several thousand dollars per well. This
example illustrates the use of fibers to allow rapid
well turnaround, thereby reducing treating costs of
multizone wells.
62
2~ 8~098
EXAMPLE 45:
Creation of fingers or chAnnels in a porous pack
may dramatically increase productivity of a well as
compared to stAn~Ard fracturing processes. A plexiglass
cell was construct2d contA;n;ng a 9~ X 3.875~ X 1.5~
ca~ity. The cell was fitted with a slurry of 501b/1000
gallon guar solution cont~;n;ng 16/20 sand and 1.5%
glass fiber by weight of sand by pumping the slurry
through the metal tube through the cell and against the
screen on the opposite end. Water then was pumped
through the proppant/fiber pack in the same direction to
remove residual guar. Air was then pumped through the
cell in the same direction to displace most of the
water. An aqueous glycerol solution ha~ing a viscosity
of 300 cP then was pumped through the screen into the
pack and out the open tube. flow rate is was increased
up to 50 ml/minute without failure of the pack. This is
approximately equivalent to a flow rate of about half a
barrel per day of high visco$ity fluid per perforation
in a well. As the flow rate is increased, a finger or
chAnnel begins to form in the pack. At a rate of 380
ml./minute the ~hAnnel is about 1/2~ in diameter
ext~nA;~g the length of the cell. Flow rate can be
increased to greater than 1550 ml/min without further
2 1 8~98
changes in the pack. This example illustrates the very
high flow rate that can be handled by this channel.
This is one way to dramatically increase the
productivity of a well compared to standard fracturing
S practices.
EXAMPLE 46:
After a collve~tional fracturing treatment using a
15% resin coated proppant tail-in based upon total
volume of proppant pumped, the well is shut in for a
sufficient time for the resin coated proppant to cure.
A pad of viscosified fluid is then pumped downhole at
less than fracturing rated pressure. The viscosified
fluid may be gelled brine or gelled oil. The viscosity
of this fluid is at least 50 times greater than that of
the next fluid. The next fluid is conventional mud acid
cont~i n; ng a mutual solvent such as butyl acetate. This
fluid will finger into the previous fluid in the resin
coated proppant pack, dissolving the coating and
allowing the proppant to be produced back from these
fingers once the well is turned around. This reduces
well productivity as in the Example immediately
preceding this Example.
64
2~88098 l -
EXAMPLE 47:
This example is basically the same as in the
Example 46 except that the resin coated proppant tail-in
if further stabilized by the addition of 1.5% fibers by
weight of resin coated proppant. In this case no shut
in time is ne~ and the acid can be pumped ;m~;ately
following the viscous fracturing fluid. Or, if desired,
the acid treatment may follow the procedure described in
Example 46 above. In either case, high productivity
10 ch~nn~l S are created in the pack.
EXANPLE 48:
The use of fibers can allow for optimization of
flowback rates to m~X;m;ze polymer removal from the
fracture and thereby increase the productivity of a
well. In Southern Texas, for example, fractures using
resin coated proppant must be flowed back at relatively
slow rates, typically less than 250 barrels of water per
day. Otherwise, catastrophic failure of the resin
coated proppant pack may occur. At this slow rate, only
a very limited amount of fracturing fluid and associated
polymer residues can be recovered before gas breaks
through and begins to be produced from the formation.
Once gas production begins, the water return rate
2 1 ~09~3'
decreases and polymer r~m~;nin~ in the fracture can be
baked on the proppant surfaces, clogging flow ch~nnels
and reducing well productivity. In one well in South
Texas, for example, flowback from a resin coated
proppant job was monitored. Gas broke through after
about 22 hours. At that stage, less than 10% of the
fracturing fluid volume had been recovered and less than
10% of the polymer pumped during the job had been
returned to the surface. Less than 15% of the total
polymer pumped had been returned to the surface after 50
hours of total flowback time.
In contrast, a well was.fractured using fibers to
control proppant flowback in this same formation. The
water return rate was increased to over 2000 bbl of
water per day without failure of the pack. Gas broke
through after only 8 hours, but by that time more than
15% of the polymer pumped already had been recovered.
After 50 hours, 25% of the polymer pumped during the
fracture treatment had been returned to the surface.
That is nearly twice the clean up efficiency of resin
coated proppant fracturing treatments.
In neighboring formations, polymer return rates in
excess of fifty percent have been recovered after 50
hours of flowback time.
2 1 88~98
This Example illustrates that use of fibers can
allow optimization of the flowback rates to maximize
polymer removal from the fracture and thereby increase
the productivity of the well.
The invention has been described in the more
limited aspects of preferred embodiments hereof,
including numerous examples. Other embodiments have been
suggested and still others may occur to those skilled in
the art upon a re~; ng and underst~n~; ng of the this
specification. It is intended that all such embodiments
be included within the scope of this invention.
