Note: Descriptions are shown in the official language in which they were submitted.
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HYDRAULIC FRACTURE HEIGHT GROWTH CONTROL
Background of the Invention
Fracture height control is a common challenge faced by operators designing
hydraulic
fracture treatments, particularly in low permeability reservoirs. Usually when
a fracture is
initiated in a productive interval, it grows in all directions until it
reaches an interface, for
example with upper and lower formations in the common case of a vertical
fracture in a
horizontal reservoir, and encounters a resistance to its growth. Normally, the
surrounding rock
contacting the productive formation is tougher and less permeable than the
reservoir. If
natural barriers exist above and below the reservoir, the vertical growth of
the fracture will be
restrained and the fracture will propagate within the productive zone. This
provides an
efficient fracture with the entire surface lying inside the reservoir.
However, when the surrounding formation is too weak to withstand the pressure
required to propagate the fracture, the barrier rocks will also crack and the
vertical fracture
growth will continue. This process results in poor fracture efficiency, since
some of the
fracture area lies outside the productive zone. Fracture growth downwards may
also lead to
water breakthrough, if there is a water zone below the reservoir. Water
breakthrough limits oil
production as well as increases the operational costs in order to separate and
dispose of the
water. Fracture growth in the upward direction is undesirable as well, since
there might be a
gas cap and eventually breakthrough into this zone might stimulate gas
production. This could
also result in the reduced ultimate recovery. Even if there is no gas cap or
water zone,
undesired fracture growth is wasteful.
Various methods have been tried to control fracture height growth. Use of low
specific
gravity particles to form an upper barrier by relying on the rising of
individual particles in a
low viscosity fluid to create and place a diverting barrier was described in
U. S. patent No.
4,509,598. Similar treatments may be done with high specific gravity particles
that settle and
form a lower barrier. Typically these barriers are placed prior to the actual
fracturing job by
injecting a cross-linked pad followed by a linear gel laden with a special
diverting particulate
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material that is allowed to rise or settle and bridge thedesired fracture
upper or lower edge; the
fracturing treatment is typically started immediately after placing the
barrier.
US Patent Application Publication No. 2005/0016732 describes a method of
hydraulically fracturing in two principal steps. In the first step, a fracture
in and below the
productive zone of a formation is initiated by introducing a fluid free of a
proppant. In the
second step, proppant-laden slurry that contains a relatively lightweight
density proppant is
introduced into the subterranean formation. Either the fluid density of the
proppant-free fluid
is greater than the fluid density of the proppant-laden slurry or the
viscosity of the proppant-
free fluid is greater than the viscosity of the proppant laden slurry. The
method limits
undesirable fracture height growth in the hydrocarbon-bearing subterranean
formation during
the fracturing.
US Patent 4,478,282 describes a method of hydraulically fracturing an
underground
formation penetrated by a wellbore involving injecting a fracturing fluid pad
into the
formation, then injecting a non-proppant fluid stage that is a transport fluid
and contains a
flow block material, the flow block material being sand and silica flour with
a particle size
distribution of the sand of 10-20, 20-40, and 100 mesh and of the silica flour
of 200 mesh, and
then injecting a proppant laden fluid slurry into the formation. The method
relies on the
assumption that the fracture growing into adjacent shale formations is
narrower than in the
productive formation and so the flow block material will bridge out in the
fracture in the shale.
Consequently, one aspect of that invention is that conditions that promote
fracture height
growth were actually preferred. Fluid viscosities were not considered
important.
There is a need for a method of controlling fracture height growth when
fractures are
growing above the desired interval, when fractures are growing below the
desired interval, and
when fracture height growth must be limited deep in the formation.
Summary of the Invention
A first embodiment of the Invention is a method for creating a fracture, in a
subterranean formation, having a barrier to fluid flow out of the top or
bottom or both the top
and bottom of the fracture; the barrier contains particles.. The method
includes the steps of (a)
injecting a pad fluid having a viscosity that allows settling or rising of
barrier particles toward
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the top. or bottom to form the barrier, (b) injecting a slurry of the barrier
particles in a fluid of a
viscosity higher than the pad fluid (the fluid being capable of transporting
the barrier
particles), and (c) injecting a fluid having a lower viscosity than the fluid
of step (b) through
which the particles may settle or rise to form the barrier. For placement of
at least a barrier at
the base of the fracture, the ratio of the particle density to the densities
of the particle- and/or
proppant-free fluids is in the range of from about 1.0 to about 5.0,
preferably in the range of
from about 2.5 to about 5Ø For placement of at least a barrier at the top of
the fracture, the
ratio of the particle density to the densities of the particle- and/or
proppant-free fluids is in the
range of from about 0.2 to about 1.0, preferably about 0.5 to about 1Ø
Optionally the
particles may be a mixture of particles having a ratio of the particle density
to the fluid density
in the range of from about 0.2 to about 1.0 and particles having a ratio of
the particle density to
the fluid density in the range of from about 1.0 to about 5Ø The method may
also include a
step of injecting, between steps (b) and (c), and/or after step (c), a fluid
capable of transporting
the particles. Optionally, at least a portion of the particles adheres to one
another after
placement. At least a portion of the particles may dissolve after the
treatment. Optionally, at
least a portion of the particles releases acid after the treatment. At least a
portion of the
particles may release a breaker after the treatment. Optionally, one or more
of the fluids
contains fibers. Optionally, one or more of the fluids contains a fluid loss
control additive.
The steps indicated may be followed by a shut in period.
Another embodiment of the Invention is a method for creating a fracture, in a
subterranean formation, having a barrier to fluid flow and/or fracture growth
out of both the
top and bottom of the fracture; the barrier contains particles. The method
includes the steps of
(a) injecting a pad fluid having a viscosity that does not allow settling or
rising of barrier
particles toward the top or bottom during the treatment, (b) injecting the
barrier particles in a
fluid capable of transporting the barrier particles, and (c) injecting a fluid
having a lower
viscosity than the fluid of step (b) through which the particles may settle or
rise to form the
barrier. The fluids of steps (a) and (b) may have the same viscosity, or all
three fluids may
have the same viscosity. The ratio of the particle density to the densities of
the particle- and/or
proppant-free fluids may be in the range of from about 1.0 to about 5.0,
preferably in the range
of from about 2.5 to about 5Ø Optionally, the ratio of the particle density
to the densities of
the particle- and/or proppant-free fluids may be in the range of from about
0.2 to about 1.0,
preferably about 0.5 to about 1Ø The particles may also be a mixture of
particles having a
ratio of the particle density to the fluid density in the range of from about
0.2 to about 1.0 and
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particles-having a ratio of the particle density to the fluid density--in the
range of from about
1.0 to about 5Ø The method may further include a step of injecting, between
steps (b) and
(c), and/or after step (c), a fluid capable of transporting the particles.
Optionally, at least a
portion of the particles adheres to one another after placement. At least a
portion of the
particles may dissolve after the treatment. Optionally, at least a portion of
the particles
releases acid after the treatment. At least a portion of the particles may
release a breaker after
the treatment. Optionally, one or more of the fluids contains fibers.
Optionally, one or more
of the fluids contains a fluid loss control additive. The steps indicated may
be followed by a
shut in period.
Brief Description of the Drawings
Figure 1 shows the results of a process for placing a particle slug at the
bottom of a fracture.
Figure 2 shows the results of a process for placing a particle slug at the top
of a fracture.
Figure 3 shows the results of a process for placing a particle slug at the top
and at the bottom
of a fracture.
Figure 4 shows the results of a process for placing a particle slug that
extends deep into a
fracture at the bottom.
Figure 5 shows the results of a process for placing a particle slug that
extends deep into a
fracture at the top.
Figure 6 shows the results of a process for placing a particle slug that
extends deep into a
fracture both at the bottom and at the top.
Figure 7 shows results calculated with a simulator of a method for placing a
particle slug at
the bottom of a fracture.
Figure 8 shows results calculated with a simulator of a method for placing an
extended
particle slug at the bottom of a fracture.
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Figure 9 shows results calculated with a simulator of a method for placing
extended particle
slugs at the bottom and top of a fracture.
Figure 10 shows results calculated with a simulator of a method for placing an
extended
particle slug at the bottom of a fracture at very low injection rates.
Detailed Description of the Invention
Although the following discussion emphasizes conventional hydraulic
fracturing,
methods of the Invention may be used before or during hydraulic fracturing,
acid fracturing,
slickwater fracturing, and combined fracturing and gravel packing in a single
operation. The
invention will be described in terms of treatment of vertical wells, but is
equally applicable to
wells of any orientation. The invention will be described in terms of vertical
fractures in
horizontal target zones, but is equally applicable to fractures of any
orientation in formations
of any orientation. The invention will be described for hydrocarbon production
wells, but it is
to be understood that the invention may be used for wells for production of
other fluids, such
as water or carbon dioxide, or, for example, for injection or storage wells.
It should also be
understood that throughout this specification, when a concentration or amount
range is
described as being useful, or suitable, or the like, it is intended that any
and every
concentration or amount within the range, including the end points, is to be
considered as
having been stated. Furthermore, each numerical value should be read once as
modified by
the term "about" (unless already expressly so modified) and then read again as
not to be so
modified unless otherwise stated in context. For example, "a range of from 1
to 10" is to be
read as indicating each and every possible number along the continuum between
about 1 and
about 10. In other words, when a certain range is expressed, even if only a
few specific data
points are explicitly identified or referred to within the range, or even when
no data points are
referred to,within the range, it is to be understood that the inventors
appreciate and understand
that any and all data points within the range are to be considered to have
been specified, and
that the inventors have possession of the entire range and all points within
the range.
We describe here a method for placing a barrier at the bottom or the top of a
hydraulic
fracture to control the undesired growth of the fracture height (explained
here in terms of a
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vertical fracture in a horizontal zone). Note that the barrier is a barrier to
fluid flow and a
barrier to fracture growth. The method is based essentially on the two
following phenomena:
the gravitational settling (or rising) of particles in a fluid, and the
penetration of a finger of a
low-viscosity fluid into a high-viscosity fluid in a slot, for example a
fracture, according to the
Saffman-Taylor instability mechanism. Note that the displacement of one fluid
by another in a
narrow vertical slot (for example a fracture in a subterranean formation)
gives rise to the
development of the Saffman-Taylor instability only in the case in which the
displacing fluid is
less viscous than the displaced fluid, thereby providing a thin finger of
lower-viscosity fluid
which penetrates into the higher-viscosity fluid and cuts the latter into two
portions, which are
then displaced to the top and the bottom of the slot. If the displacing fluid
has the same or
higher viscosity than the displaced fluid, the flow is stable.
The process of the barrier placement consists of three necessary stages: (i)
the injection
of a first relatively low-viscosity particle-free fluid, (ii) then the
injection of a thickened
barrier-particle-laden fluid, and then (iii) injection of a second relatively
low-viscosity
particle-free fluid. By "particle-free" we mean not containing sufficient
particles to contribute
significantly to formation of a barrier; we do not mean that the fluid may not
contain any
particles of any type; for example, a pad fluid may contain fluid loss
particles that are not
major contributors, for example greater than 20%, to the barrier. The fluids
injected before
and after the particle-laden slug provide a relatively low-viscosity medium,
in which the slug
sediments rapidly to the fracture bottom (or rises rapidly to the fracture
top). Below, when we
describe the first low-viscosity fluid as having a "low-viscosity", we mean
that the fluid has a
viscosity sufficiently low that the particles will rise or fall through it to
the location required in
the time allowed by the pumping schedule and any optional shut in.
Additionally, the low-
viscosity fluid injected after the slug cuts the highly-viscous particle-laden
fluid into two
unequal parts according to the Saffman-Taylor instability mechanism,
displacing the lower,
larger, part of the slug to the fracture bottom, thereby enhancing the
sedimentation of a lumped
barrier. The lower portion is larger because of gravitational settling of
individual proppant
particles towards the bottom of the fracture. Below, when we describe the
second low-
viscosity fluid as having a "low viscosity", we mean that it fingers through
the thickened
particle-laden fluid under the pumping conditions, and when we describe the
particle-laden
fluid as "thickened" or "highly-viscous", we mean that the second low-
viscosity fluid will
finger through it under the pumping conditions. Low-viscosity fluids have been
used in the
past to provide particle settling or rising in fracturing, but not to cut a
particle-laden fracturing
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fluid into portions for the purpose of forming fluid flow and fracture growth
barriers. When a
"stretched" barrier is required (a barrier extending farther out into the
fracture from the
wellbore in which the fracture is being created than would occur without the
auxiliary stage),
then an auxiliary stage is introduced between the injection of the slug and
the injection of the
second low-viscosity fluid. The auxiliary stage is the injection of a highly-
viscous particle-
free fluid. This fluid bulldozes the particle-laden slug along the fracture
(at the top, the
bottom, or both) thereby providing an extended barrier, which bridges along a
greater portion
of the fracture. Below, when we describe the auxiliary stage fluid as being
"highly-viscous"
we mean that it is sufficiently viscous to be able to push the barrier
particles farther into the
fracture.
This method and fluid system for barrier placement assisted by gravitational
settling or
rising and by an unstable fluid-fluid displacement in a hydraulic fracture
makes it possible to
control the fracture height growth and to prevent the fracture from
propagating into the
undesired zones located either above or below the target formation. For
example the method
and fluids allow the operator to keep a fracture in an oil-bearing formation
and avoid water- or
gas-bearing regions. The process of placing an extended barrier at the top or
bottom of a
fracture includes four stages of injecting different fluids into the
subterranean formation. The
stages are as follows: (i) the injection of a pad of a low-viscosity particle-
free fluid into a well
in order to open and propagate the hydraulic fracture in the subterranean
formation, (ii) then
the injection of a more viscous particle-laden fluid, (iii) then the injection
of a low-viscosity
particle-free fluid, and then (iv) the injection of a highly-viscous particle-
free fluid. The
particle-free pad injected in the first stage provides a low-viscosity medium,
in which the slug
sediments rapidly to the fracture bottom or rises rapidly to the fracture top.
In such cases the
pad fluid must have a lower viscosity than that of the fluid used to place the
barrier particles.
(Whenever we say one fluid has a lower (or higher) viscosity than another, we
mean at all
shear rates.) The pad fluid must have a sufficiently low viscosity to allow
the barrier to settle
(or rise), but at the same time it must have a sufficiently high viscosity to
open and propagate a
fracture, so there must be a balance. In cases in which the formation is high
permeability, then
the pad fluid will commonly have a fairly high viscosity and in such cases the
stage or stages
after the barrier injection stage must be long enough, or there must be a shut
in period, to allow
the time necessary for the barrier to rise or fall in a viscous environment.
Suitable viscosities,
stage volumes, optional shut in periods, and pumping rates may be calculated
by those skilled
in fracturing, for example by using one of the many numerical simulators
available. A
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conventional fracturing treatment may begin right after the end of stage (iv),
or optionally the -
well may be shut in to allow additional time for the barrier particles to rise
or fall to form the
barrier(s). The treatment is designed so that the barrier particles form a
barrier by the end of
the injection of the last stage before initiation of a conventional fracture
treatment, or, if shut
in is necessary (because of the need for time for settling (rising) or for any
other operational
reasons), by the end of the shut in period. The barrier is considered to have
been formed when
flow out of the top or bottom or both the top and bottom of the fracture has
been inhibited such
that fracture growth past the barrier does not occur.
When the operator desires to place a barrier both at the top and the bottom of
the
fracture, a different sequence of fluids may be used; in this case the first
stage may be a
highly-viscous fluid. When the highly-viscous fluid is injected during the
first stage, then the
finger of the low-viscosity fluid injected during the third stage cuts the
slug into two almost
equal parts and displaces the lower and the upper parts downwards and upwards,
thereby
providing the placement of two barriers, one at the top and one at the bottom
of the fracture.
The particles constituting the slug, injected in the second stage, when
deposited at the
fracture bottom or top, bridge at the fracture edge, reduce the pressure
applied to the
surrounding rock at the fracture edge to below the critical value required for
the fracture to
propagate into the surrounding rock, and thus stop the fracture growth in the
vertical direction.
This particulate material may consist of small rigid or deformable particles
of any shape with
the density higher or lower than that of any of the injected fluids. (Note
that all the fluids ,will
typically be water-based and the densities of the fluids will all typically be
about the same and
about that of water; in this context, when we speak of the density of the
fluid, we mean the
density of a carrier fluid, not that of a slurry.) The particles may or may
not adhere to one
another and/or the surrounding rock after placement, may or may not dissolve
in the fluid, and
may or may not release acid to etch the surrounding formation. This will be
discussed further
below; these actions may be instigated by the action of a physical trigger
(which may for
example be closure stress, a temperature increase, a pH change, contact with
water, etc.). The
low-viscosity particle-free fluid injected at the third stage penetrates into
the slug according to
the Saffman-Taylor instability mechanism, cuts the slug into two unequal
parts, and in the case
of heavy barrier particles displaces the lower bigger part of the slug towards
the fracture
bottom thereby enhancing the sedimentation of the slug.
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The following guidelines are followed for a successful barrier placement:
= the flow rate should be the minimum possible, for example as low as about
3.2 m3/min,
although this may favor screening out;
= the density of the particles constituting the barrier should be high (for a
barrier at the
bottom of the fracture) relative to that of the fluid, for example up to about
3600 kg/m3,
although this may favor screening out;
= the particle diameter should be approximately that of conventional proppant
or smaller
to minimize the risk of a screenout;
= the barrier particle concentration in the slug may be as high as practical,
for example
up to about 1000 kg/m3, to promote efficiency and to promote fast barrier
particle
settling (rising); the upper limit is governed by equipment limitations and
prevention of
a screenout (depending upon the other job design parameters);
= the viscosity of the low-viscosity fluid should be as low as possible
without promoting
a screenout;
= all parameters (for example fluid density and viscosity, barrier particle
size and
density, stage length (time)) should be selected to optimize barrier placement
while
minimizing the likelihood of near-wellbore screenout; such decisions may
conveniently be made by modeling with a simulator;
= the barrier placement job consists of three or four stages (exemplary
amounts of fluids
and particles are given in the examples following this section) in the
following order
(optionally, additional stages may be added, or stages may be divided into sub-
stages,
for example as shown in the examples); a specific design is determined, for
example,
from a series of numerical simulations with a fracture simulator:
o a pad of a clean low-viscosity fluid used to create an initial fracture and
to
provide a low-viscosity medium inside the fracture, in which the barrier
particles will settle or rise rapidly; when it is desired to place, two
barriers (one
at the bottom and one at the top of the fracture), the pad fluid should, on
the
contrary, be higher-viscosity; when it is necessary for the pad to have higher
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viscosity (to initiate and propagate a- fracture) than would be desirable for
the
barrier placement, the pad may contain a breaker, for example a fast-acting
breaker; the suitable balance between a viscosity sufficiently high to
initiate
and propagate a fracture and sufficiently low to allow barrier particle
settling(rising) may be determined by numerical simulation; the volume of the
pad should be sufficient to create a fracture of desired length;
o a portion of slurry of a diverting particulate material mixed with, for
example, a
cross-linked gel to transport the particles through the perforations and to
place
the slug inside the fracture; the particle concentration is high, for example
up to
about 8 PPA in oilfield units (about 0.96 kg/L); barrier placement will
generally
lead to increased fracture width and decreased likelihood of screenout in the
subsequent fracturing treatment; the volume should be sufficient to create a
barrier of the desired length along the fracture;
o an optional portion of a clean highly-viscous fluid, for example a cross-
linked
gel, to stretch the slug along the fracture, so that it will settle (or rise)
and form
a barrier bridging along the entire lower (or upper) edge of the fracture;
when a
lumped barrier (most of the barrier material near the wellbore) is acceptable,
this stage may be omitted; the volume needed is the volume sufficient to push
the barrier to the desired location, or to stretch the barrier over a desired
distance along the bottom of fracture;
o a portion of a low-viscosity fluid (for example the same as the pad fluid)
to
penetrate into the more viscous particle-laden fluid according to the Saffman-
Taylor instability mechanism and to displace at least the larger lower part of
the
slug towards the fracture bottom, or, if the particles are less dense than the
fluid, to displace at least the larger portion towards the top; if the pad
fluid is
highly-viscous, then the slug is cut into two almost equal parts displaced
upwards and downwards, which results in the placement of two barriers, on the
top and the bottom of the fracture, respectively; the volume of clean lower-
viscosity fluid is determined by the time needed for the barrier to settle
(rise).
Any oilfield fluid may be used for the lower-viscosity and higher-viscosity
fluids of the
methods of the Invention. The viscosity suitable for a specific job is
determined by
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simulation, for example by comparing and contrasting a series-of simulations.
The fluids may
be oil-based or water-based and may be foamed or energized. Most commonly, the
fluids are
polymer viscosified water based fluids or viscoelastic surfactant (or other
non-polymeric
viscosifier) viscosified water-based fluids. If made with polymers, a
convenient method is to
use the same polymer concentration in each fluid but to crosslink the higher-
viscosity fluid.
The crosslinking may optionally be delayed; the fluids may optionally contain
breakers. The
fluids may contain any of the additives normally found in oilfield fluids,
such as, but not
limited to, iron control agents, clay control agents, stabilizers,
demulsifiers, buffers, etc.
Any particles used in the oilfield as a proppant, lost circulation, or fluid
loss control
additive may be used as the barrier particles. Mixtures of particles may be
used. Particularly
suitable are those normally used as proppants, for example, sand, ceramics,
plant matter,
polymer beads, glass, hollow glass microspheres. Other particularly suitable
materials are
those normally used as fluid loss control agents such as calcium carbonate
flakes and polyester
flakes, for example polyglycolic acid or polylactic acid flakes. The choice of
particle material
(density, shape, size) is based primarily on the settling (rising) rate,
fracture width, fluid
viscosities, and screenout potential. The nature of the particles, and their
amount and
concentration, are preferably selected so that the barrier formed has a
permeability between
about 0.0 and about 1.0 Darcy.
At least a portion of the barrier particles may optionally be selected, or
treated, so that
they adhere to one another after they are placed. For example, there are many
resin coated
proppants available that have this property. At least a portion of the barrier
particles may
optionally be slowly soluble (or hydrolysable) in the fracture fluid or the
formation fluid or
produced so that they survive long enough to prevent fracture height growth
but then dissolve
(or hydrolyze) so that they no longer inhibit flow into (or out of) the
fracture. For example,
the barrier should be gone within a week or a month. Optionally, only a
portion of the barrier
is subsequently removed, by the same mechanism(s) and over the same time
scale. This
increases the barrier permeability and so increases the fracture conductivity.
Partial or
complete removal of the barrier may be initiated by any of a number of
triggers, including, by
example, closure stress, temperature, pressure, pH change, contact with
reservoir fluid, water
or another substance, etc. At least a portion of the barrier particles may
optionally be an acid-
precursor, such as polylactic acid or polyglycolic acid that releases an acid
that may etch
carbonate formations. The acid may, for example, differentially etch the
fracture faces so that
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they leave a- flow path when the fracture closes, or it may etch cavities into
the surrounding
formation; either increases the fracture conductivity. The barrier particles
may optionally
contain an acid in a protective coating that, for example, under pressure,
increased
temperature, or in the presence of water, releases the acid, for the same
purposes. At least a
portion of the barrier particles may optionally be or include a breaker for
the viscosifier used
in the fracture fluid used in the subsequent fracturing treatment; this
breaker may be released
after the fracturing treatment to help break the fracturing fluid, thereby
decreasing its viscosity
and providing a more efficient fracture cleanup. The breaker may optionally
also be a breaker
for the viscosifier(s) used in the fluid(s) used to place the barrier. The
barrier particles may be
rigid or deformable and may be of any shape.
The method of the Invention may be applied in many different ways. A barrier
may be
placed at the bottom of a fracture by the sequential injection of a lower-
viscosity particle-free
pad, then a higher-viscosity particle-laden thickened fluid, and then a lower-
viscosity particle-
free fluid, into the subterranean formation. The conventional fracturing
treatment may begin
immediately after the end of the final stage of the barrier placement stage
sequence.
Optionally, there may be a shut-in period before commencement of the
conventional
treatment; the fracture may optionally be allowed to close during this shut-in
period. The
apparent viscosity of the lower-viscosity fluids should be significantly lower
than that of the
higher-viscosity fluid at any shear rate. (The lower-viscosity fluids may be
the same or
different in composition and in rheology.) When the ratio of the particle
density to the fluid
density ranges from between about 1.0 and about 5.0 (preferably between about
2.5 and about
5.0 to promote settling), this sequential injection of fluids results in the
placement of a
"lumped" barrier (most of the barrier material is near the wellbore) at the
bottom of the
fracture as shown in Figure 1, where the wellbore is shown at [1], the
fracture is shown at [2],
and the barrier is shown at [3]. When the ratio of the particle density to the
fluid density
ranges from between about 0.2 and about 1.0 (preferably between about 0.5 and
about 1.0 to
promote rising), this sequential injection of fluids results in the placement
of a "lumped"
barrier (most of the barrier material is near the wellbore) at the top of the
fracture as shown in
Figure 2, where the wellbore is shown at [1], the fracture is shown at [2],
and the barrier is
shown at [3]. (The wellbore, fracture and barrier(s) are indicated by the same
numbers in each
of Figures 1-6.) When the viscosities of the lower-viscosity fluid in the pad
and the higher
viscosity fluid used to inject the barrier particles are the same (including
approximately the
same), then the method provides the placement of two barriers (two almost
equal portions of
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13
the initial. particle slug)-one on the top and one on the bottom of the
fracture, respectively (as
shown in Figure 3). In this case, the key mechanism providing the two slugs on
the top and
the bottom is the Saffman-Taylor instability, which results in cutting the
slug into two portions
by the finger of lower-viscosity fluid. These two portions are then displaced
towards the top
and the bottom of the fracture. The placement of these barriers is enhanced by
the
phenomenon of the fluid/fluid displacement; gravitational settling alone would
not be
sufficient. The relative sizes of the top and bottom barriers may be adjusted
by adjusting the
relative densities of the particles and the fluid, and the relative
viscosities of the different
fluids.
Barriers may also be placed at both the top and the bottom of the fracture at
the same
time by the sequential injection of a lower-viscosity particle-free pad, then
a higher-viscosity
particle-laden thickened fluid, and then a lower-viscosity particle-free
fluid, where the
particulate material includes a mixture of (a) particles having a ratio of the
particle density to
the fluid density ranging between about 1.0 and about 5.0 and (b) particles
having a ratio of
the particle density to the fluid density ranging from about 0.2 and about
1Ø This results in
the placement of two lumped particle slugs, one at the top and one at the
bottom of the
fracture, respectively, as shown in Figure 3.
In order to extend the barrier farther out into the fracture away from the
wellbore, to
any of the sequences just described an additional stage of a highly-viscous
fluid may be added
between the stage of barrier particle injection and the subsequent stage of
lower-viscosity
fluid. The fluid in this additional stage is a particle-free material, for
example a cross-linked
gel. At any shear rate the viscosity of the fluid used in this stage is lower
than, equal to, or
slightly higher than that of the fluid used to inject the particles, but it is
highly viscous and is
more viscous than the subsequent stage of lower-viscosity fluid. This method
results in the
placement of a stretched particle slug at the bottom of the fracture (Figure
4), a stretched
particle slug at the top of the fracture (Figure 5) or stretched particle
slugs at the top and
bottom of the fracture (Figure 6).
The barrier placement method of the Invention may be applied during a
conventional
fracturing treatment if the operator determines that undesirable fracture
growth is occurring.
The conventional treatment is stopped, with or without fracture closure and/or
shut in, the
barrier is placed with the various stages as detailed above, the fracture is
optionally allowed to
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close and/or is- optionally shut in, and then the fracture treatment is
resumed, optionally with
modifications to the original pumping schedule. In such instances it is
advantageous to use the
same fluids and proppants used in the fracturing treatment for the barrier
placement treatment;
concentrations of components (such as viscosifiers, proppant (barrier
particles), crosslinkers,
and breakers) may differ in some or all the barrier placement stages from
those in any of the
fracturing treatment stages and still use chemicals and equipment on hand.
Fibers may be added to any of the fluids used in the barrier placement method
of the
Invention. Fibers in the pad and in the lower-viscosity fluid injected after
the barrier particle
slug may inhibit settling (or rising) and may not be desirable unless they are
needed for some
other purpose, for example the breaker or an acid precursor is in the form of
fibers. Fibers (or
other proppant retention means) in the barrier particle slug may be used to
hold the barrier in
place during the subsequent fracture treatment, and to adjust the relative
rates of barrier
particle settling (rising) and barrier particle transport. Fluid loss control
additives may be
added to any of the stages used for barrier placement; they would be most
advantageous in the
pad when a large wide fracture is desired.
When the method of the Invention is applied to a vertical fracture (long axis
vertical or
having a significant vertical component); for example created from a
horizontal well, gravity-
driven placement of a barrier particle slug results in barrier particle
placement at the tip(s) of
the fracture, preventing fracture length growth and promoting fracture width
growth and
keeping the fracture in the formation. The method of the Invention may be
applied to fractures
in deviated wells. The method of the Invention may be applied in any situation
in which a
fracture of any orientation has a vertical component and the operator wishes
to limit fracture
growth upwards or downwards or wishes to create a wide fracture.
The method of the Invention may be used before or during acid fracturing
treatments,
or fracture treatments with other formation-dissolving fluids. The fluids used
in the barrier
placement process may or may not contain an acid or formation-dissolving
fluid. The method
of the Invention may be used before or during a slickwater treatment, provided
that the
equipment available can create and pump fluids having high particle
concentrations and can
formulate higher-viscosity fluids. If only slickwater fluids and pump rates
can be used, it is
still possible to create barriers by the method of the Invention if the
pumping times of the
barrier particle stage and subsequent stages are long enough to allow
sufficient particles to be
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placed and to allow sufficient particle settling (rising). The method of the
Invention may- be
used before frac-pack treatments (fracturing and gravel packing in a. single
treatment) without
deleteriously affecting the frac-pack; normally this would be unnecessary, but
it may be done,
for example, if the operator plans a fracture treatment and then part way
through the treatment
changes it to a frac-pack.
The present invention can be further understood from the following examples.
Example 1:
This example demonstrates how the method of the Invention performs under
typical
field conditions. Table 1 shows the pumping schedule and Figure 1 demonstrates
the particle
concentration distribution after the end of stage 4, calculated (as in all the
examples) using a
pseudo 3D fracturing simulator (fracture design, prediction, evaluation and
treatment-
monitoring program) commercially available under the trade designation
FracCADETM from
Schlumberger Technology Corporation, Sugar Land, Texas, U. S. A. The density
of the
barrier particles (called sand in this and the other examples) was equal to
3600 kg/m3 and the
particle mean diameter was 0.589 mm (20/40 mesh sand). The "highly-viscous"
fluid
parameters were as follows: the power-law exponent was n=0.59 and the
consistency was
K=0.383 Pas"; the density was that of water, and the apparent viscosity was
g=28.1 cP at a
shear rate equal to 170 s 1. (The fluid modeled contains 3.6 kg/m3 bromate-
crosslinked guar.)
The "low-viscosity" fluid modeled contains 3.6 kg/m3 uncrosslinked guar and
was assumed to
have the same density and rheology as water. These were the high and low
viscosity fluids
used in each of the examples.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump
rate, Volume, Conc., Mass, Volume, Time,
m3/ m3 kg/m3 kg m3 min
min
1 6.36 Low- 80 - 0 0 80 12.6
visc
2 6.36 High- 10 Sand 958.61 9586 12.7 2.0
visc
3 6.36 Low- 30 - 0 0 30 4.7
visc
4 6.36 High- 100 - 0 0 100 15.7
visc
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Table 1: Treatment schedule for Example 1
The first stage was a clean pad. The second stage contained the barrier plug;
the third
and fourth stages were clean fluid. In this and all the examples, there was no
shut-in time; the
calculation shows the position of the barrier at the start of the subsequent
fracture treatment.
Figure 7 shows the calculated results. A barrier was placed in approximately
the near-
wellbore half of the fracture, primarily in the near-wellbore third of the
fracture and almost all
at the bottom. Not shown is that when a similar treatment was modeled except
that all four
stages used the high-viscosity fluid, the proppant was distributed throughout
the fracture with
the highest concentration centered (between the top and the bottom) about two
thirds of the
way to the tip. The barrier particle distribution was in the shape of a
horizontal "U" with the
open end toward to wellbore; the viscous fluid following the barrier particle
slug pushed the
slug into the fracture but there was no low-viscosity fluid through which the
particles could
settle. Also not shown is that when a similar treatment was modeled except
that the first stage
was the low-viscosity fluid and the last three stages were the high viscosity
fluid, a significant
portion of the slug formed a barrier at the bottom of the fracture, and most
likely, would bridge
the lower fracture edge, but there was an upper wing of the deformed slug that
had not settled
and thus could mix with the conventional proppant in the treatment to follow.
Also not shown
is that when the third stage was lower-viscosity fluid and the other three
stages were higher-
viscosity fluid, the performance was almost as good as the base case, although
the barrier had
a slightly lower particle concentration and was a little closer to the
wellbore. Thus, for a
barrier at the bottom, a lower-viscosity first stage was preferable, and
additionally a lower-
viscosity stage after barrier slug injection (to displace at least a larger
part of the slug towards
the bottom of the fracture according to the Saffman-Taylor instability
mechanism and to
promote barrier particle settling as shown in Figure 7 for the design of Table
1) was more
preferable. This lower-viscosity stage after the barrier slug injection is
kept small to minimize
the possibility of a screenout.
Example 2:
The next example illustrates the placement of a barrier stretched along the
bottom edge
of the fracture. In order to provide an elongated barrier, an auxiliary stage
was introduced
between pumping the barrier particle slug (Stage 2) and injecting the low-
viscosity fluid
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(Stage 4 in this example). At this point (Stage 3) a small portion of clean
cross-linked gel was
introduced. The extended job design is presented in Table 2.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump
rate, Volume, Conc., Mass, Volume, Time,
m3/ min m3 kg/m3 kg m3 min
1 6.36 Low- 80 - 0 0 80 12.6
visc
2 6.36 High- 10 Sand 958.61 9586 12.7 2.0
visc
3 6.36 High- 20 - 0 0 20 3.1
visc
4 6.36 Low- 30 - 0 0 30 4.7
visc
6.36 High- 100 - 0 0 100 15.7
visc
Table 2: Treatment schedule for Example 2
The particle concentration distribution calculated for this job design is
shown in Figure
8. It can be seen that the small stage of clean viscous fluid pushed a portion
of the barrier slug
farther into the fracture. This job design was optimized for this effect by
running a series of
numerical simulations (not shown) in which the amounts of fluids injected in
the different
stages were varied.
Example 3:
The next example illustrates the effect of the rheology of the fluid injected
before the
slug on the final pattern inside the fracture. In this case, the pad fluid
used was a highly-
viscous cross-linked gel. As a result, two barriers were placed, one at the
bottom and one at
the top of the fracture; The lower-viscosity fluid fingered into the higher-
viscosity fluid
according to the Saffman-Taylor instability and cut the barrier particle slug
into uneven parts;
the larger portion was displaced and then settled towards the bottom and the
smaller portion
was pushed towards the top. The particles used in this simulation had a mean
diameter equal
to 0.661 mm and a density of 2540 kg/m3. The results calculated for the
particle concentration
distribution are summarized in Figure 9, and the pumping schedule is presented
in Table 3.
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Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump
rate, Volume Conc., Mass, Volume, Time,
m3/ min m3 kg/m3 kg m3 min
1 6.36 High- 80 - 0 0 80 12.6
visc
2 6.36 High- 5 Sand 958.61 4793 6.3 1
visc
3 6.36 High- 10 Sand 958.61 9586 12.7 2.0
visc
4 6.36 High- 20 - 0 0 20 3.1
visc
6.36 Low- 30 - 0 0 30 4.7
visc
6 6.36 High- 140 - 0 0 140 22
visc
Table 3: Treatment schedule for Example 3
Example 4:
An investigation into the effect of the flow rate on the process of barrier
placement
showed that the lower the flow rate, the easier it was to place the barrier
accurately. In this
example, the flow rate was set to 3.2 m3/min, which is near the lowest pumping
flow rate
possible for most operators' equipment. (Lower flow rates are better and are
permissible if the
operator's equipment allows.) The pumping schedule and the resulting particle
concentration
distributions are shown in Table 4 and Figure 10.
Stage Pump Fluid Fluid Particles Particle Particle Slurry Pump
rate, Volume, Conc., Mass, Volume, Time,
m3/ min m3 kg/m3 kg m3 min
1 3.2 Low- 80 - 0 0 80 25
visc
2 3.2 High- 10 Sand 958.61 9586 12.7 4
visc
3 3.2 High- 20 - 0 0 20 6.3
visc
4 3.2 Low- 30 - 0 0 30 9.4
visc
5 3.2 High- 100 - 0 0 100 31.3
visc
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Table 4: Treatment schedule for Example 4
The concentration pattern shown in Figure 10 corresponds to a quite successful
placement of a barrier stretched along the fracture, bridging a substantial
portion of the lower
fracture edge. Again, this pumping schedule was selected from a number of
schedules tried.
For example, not shown was a similar simulation in which the fifth stage was
30 instead of
100 m3; more of the barrier material ended up at the top of the fracture and
nearer the wellbore
on the bottom. Also not shown is that when a treatment following the schedule
of Table 4, but
with the higher-viscosity fluid used in all stages, was modeled, the barrier
was not placed in
the bottom, but rather in the middle (vertically) of the fracture, and the
fracture height was
much greater, especially near the wellbore. Modeling with any of a number of
simulators
available may be used by one skilled in the art to select a suitable job
design for the nature of
the strata to be treated and the desired end result and for the available
equipment, fluids, and
barrier materials. Conventional fracture treatments are designed so that the
velocity of
longitudinal proppant transport away from the wellbore is much greater than
the velocity of
proppant settling (or rising). Barrier placement treatment designs are
intended to make these
rates approximately comparable, and preferably to make settling (rising) take
less time than
longitudinal transport.
