Note : Les descriptions sont présentées dans la langue officielle dans laquelle elles ont été soumises.
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HYDRAULIC FRACTURING WITH PROPPANT PULSING THROUGH
CLUSTERED ABRASIVE PERFORATIONS
Background
[0001] Hydrocarbons (oil, natural gas, etc.) are obtained from a
subterranean
geological formation by drilling a well that penetrates the hydrocarbon-
bearing
formation. This provides a partial flow path for the hydrocarbon to reach the
surface.
In order for the hydrocarbon to be "produced," that is, travel from the
formation to the
wellbore and ultimately to the surface, there must be a sufficiently unimpeded
flow
path.
[0002] Hydraulic fracturing is a primary tool for improving well
productivity
by placing or extending highly conductive fractures from the wellbore into the
reservoir. During the first stage, hydraulic fracturing fluid is injected
through
wellbore into a subterranean formation at high rates and pressures. The
fracturing
fluid injection rate exceeds the filtration rate into the formation producing
increasing
hydraulic pressure at the sand face. When the pressure exceeds a critical
value, the
formation strata or rock cracks and fractures. The formation fracture is more
permeable than the formation porosity.
[0003] During the next stage, proppant is deposited in the fracture to
prevent it
from closing after injection stops. The resulting propped fracture enables
improved
flow of the recoverable fluid, i.e., oil, gas or water. Many other proppants
may be
used such as sand, gravel, glass beads, walnut shells, ceramic particles,
sintered
bauxites and other materials including bearings of spherical, cylindrical or
irregular
shapes.
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[0004] Hydraulic fracturing fluids are aqueous solutions containing a
thickener,
such as a soluble polysaccharide, to provide sufficient viscosity to transport
the
proppant. Typical thickeners are polymers, such as guar (phytogeneous
polysaccharide), and guar derivatives (hydropropyl guar,
carboxymethylhydropropyl
guar). Other polymers can be used also as thickeners. Water with guar
represents a
linear gel with a viscosity that increases with polymer concentration. Cross-
linking
agents arc used which provide engagement between polymer chains to form
sufficiently strong couplings that increase the gel viscosity and create visco-
elasticity.
Common crosslinking agents for guar include boron-, titanium-, zirconium-, and
aluminum-laden chemical compounds.
[0005] Fibers can be used to enhance the ability of the fracturing
fluids to
transport proppant and to mitigate proppant settling within the hydraulic
fracture. For
operations in which proppant is pumped in slugs or pulses, fibers can also be
used to
mitigate the dispersion of the proppant slugs as they travel throughout the
well
completion and into the fracture.
[0006] Proppant flow back control agents can also be used during the
latter
stages of the hydraulic fracturing treatment to limit the flow back of
proppant placed
into the formation. For instance, the proppant may be coated with a curable
resin
activated under down hole conditions. Different materials, such as bundles of
fibers,
or fibrous or deformable materials, also have been used to retain proppants in
the
fracture. Presumably, fibers form a three-dimensional network in the proppant
pack
that limits its flow back.
[0007] The success of a hydraulic fracturing treatment depends upon
hydraulic
fracture conductivity and fracture length. Fracture conductivity is the
product of
proppant permeability and fracture width; units are typically expressed as
millidarcy-
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feet. Fracture conductivity is affected by a number of known parameters.
Proppant
particle size distribution is one key parameter that influences fracture
permeability.
The concentration of proppant between the fracture faces is another (expressed
in
pounds of proppant per square foot of fracture surface) and influences the
fracture
width. One may consider high-strength proppants, fluids with excellent
proppant
transport characteristics (ability to minimize gravity-driven settling within
the fracture
itself), high-proppant concentrations, or big proppants as means to improve
fracture
conductivity. Weak materials, poor proppant transport, and narrow fractures
all lead
to poor well productivity. Relatively inexpensive materials of little
strength, such as
sand, are used for hydraulic fracturing of formations with small internal
stresses.
Materials of greater cost, such as ceramics, bauxites and others, are used in
formations
with small to moderate closure stresses. Materials of greater cost, such as
ceramics,
bauxites and others, are used in formations with higher closure stresses.
[0008] The proppant pack must create a conduit having a higher
hydraulic
conductivity than the surrounding formation rock. The proppant pack within the
fracture is often modeled as a permeable porous structure, and the flow of
formation
fluids through this layer is generally described using the well-known Darcy's
law (1)
or Forscheimer's equation (2):
[0009] (1) 613/0x=-( u/k);
[0010] (2) 6Pox=-[( u/k)+13pu2],
[0011] where
[0012] P is a fluid pressure in the fracture;
[0013] x is a distance along the fracture from the wellbore;
[0014] itt is a viscosity of the formation fluid;
100151 u is a flow (filtration) speed of the formation fluid;
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[0016] k is a permeability of the proppant pack;
[0017] 13 is a coefficient referred to as beta-factor that
describes non-linear
corrections to the Darcy's filtration law; and
[0018] p is a density of the formation fluid.
[0019] The result of multiplying fracture permeability by fracture
width is
referred to as "hydraulic conductivity". The most important aspect of fracture
design
is optimization of the hydraulic conductivity for a particular formation's
conditions.
[0020] A fracture optimization process will strike a balance among
the
proppant strength, hydraulic fracture conductivity, proppant distribution,
cost of
materials, and the cost of executing a hydraulic fracturing treatment in a
specific
reservoir. The case of large proppant particle sizes illustrates compromises
made
during an optimization process. A significant hydraulic fracture conductivity
increase
is possible using large diameter proppants. However, at a given internal
formation
stress, large diameter proppants crush to a greater extent when subjected to
high
fracture closure stresses, leading to a decrease in the effective hydraulic
conductivity
of the proppant pack. Further, the larger the proppant particles, the more
they are
subjected to bridging and trapping in the fracture near the injection point.
100211 Patent US 6,776,235, "Hydraulic Fracturing Method",
discloses a method and means for optimizing fracture
conductivity. The well productivity is increased by sequentially injecting
into the
wellbore alternate stages of fracturing fluids having a contrast in their
ability to
transport propping agents to improve proppant placement, or having a contrast
in the
amount of transported propping agents. The propped fractures obtained
following this
process have a pattern characterized by a series of bundles of proppant spread
along
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the fracture. In another words, the bundles form "pillars" that keep the
fracture opens
along its length but provide a lot of channels for the formation fluids to
circulate.
[0022] Hydro-abrasive methods for surface treatment and cutting are
often
used for cutting perforation holes or slots in casing and formation instead of
using
explosive cumulative charges or milling cutters.
[0023] Devices for cutting slots in a formation with a hydro-abrasive
jet may
include a perforator hung on tubing inside of a well with a hydro-abrasive jet
generator located on ground surface. The perforator may include two opposite
side
oriented nozzles directed to wall of the well. A hydro-abrasive slurry may be
prepared in a hydro-abrasive jet generator and pumped through tubing and down
hole
to perforator. Other abrasive perforating devices are known in the art.
Summary of the Disclosure
[0024] This summary is provided to introduce a selection of concepts
that are
further described below in the detailed description. This summary is not
intended to
identify key or essential features of the claimed subject matter, nor is this
summary
intended to be used as an aid in limiting the scope of the claimed subject
matter.
[0025] For purposes of this disclosure, the terms perforation and
station are
interchangeable and the term perforation will be used. On the other hand, a
cluster
may include one or more perforations. If the cluster includes a plurality of
perforations, the perforations are grouped relatively close together and
typically, are
formed simultaneously using an abrasive jet perforations tool with a plurality
of
nozzles. A plurality of clusters would refer to individual clusters (i.e., one
or more
perforations) separated by an unperforated interval.
[0026] In one aspect, a method for perforating and fracturing of a
subterranean
formation with a wellbore lined with casing extending through at least part of
the
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formation'. The disclosed method may include forming at least one cluster of
perforation(s) through the casing and into the formation with hydro-abrasive
jets. The
disclosed method may further include injecting a proppant-free fracturing
fluid into
the wellbore through the cluster. The disclosed method may also include
combining
the proppant-free fracturing fluid with a proppant to form a first proppant-
laden slurry
and alternatingly and repeatedly injecting the first proppant-laden slurry
followed by
injecting the proppant-free fracturing fluid into the wellbore and through the
cluster of
perforations. The method may also include repeating the combining of the
proppant-
free fracturing fluid with the proppant to provide additional (i.e., second,
third, fourth,
etc.) proppant-laden slurries of varying proppant concentrations, altematingly
and
repeatedly injecting each additional proppant-laden slurry followed by
injecting the
proppant-free fracturing fluid into the wellbore and through the cluster of
perforations. The method may also include forming additional cluster(s)
through the
casing and into the formation with hydro-abrasive jets, wherein the additional
cluster(s) are spaced apart from the other cluster(s) by a non-perforated
interval. The
disclosed method may also include treating all clusters simultaneously with
the
proppant-free fracturing fluid followed by the proppant-laden slurries as
discussed
above.
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[0026a] According to one aspect of the present invention, there is
provided a method
for perforating and fracturing of a subterranean formation with a wellbore
lined with casing
extending through at least part of the formation, the method comprising:
forming a first cluster
and a second cluster of a plurality of clusters having at least one
perforation through the
casing and into the formation with hydro-abrasive jets by locating an abrasive-
jet perforating
tool within a zone of interest and pumping an abrasive laden fluid through
jetting ports of the
abrasive-jet perforating tool, wherein the plurality of clusters are separated
by nonperforated
intervals, wherein each nonperforated interval is located downhole from the
first cluster and
uphole from the second cluster, wherein the jetting ports on a sand jetting
sub of the abrasive-
jet perforating tool have a variable configuration, and wherein the forming of
the first cluster
is performed through coiled tubing fluidly connected to the abrasive-jet
perforating tool;
before fracturing, moving the abrasive-jet perforating tool away from the at
least one
perforation; and pulsing a proppant-free fracturing fluid and a first proppant-
laden slurry into
the wellbore through the first cluster and the second cluster simultaneously,
thereby
generating fractures and creating proppant-free channels inside the fractures.
[0026b] According to another aspect of the present invention, there is
provided a
method for perforating and fracturing of a subterranean formation with a
wellbore lined with
casing extending through at least part of the formation, the method
comprising: (a) forming a
first cluster and a second cluster of a plurality of clusters through the
casing and into the
formation with hydro-abrasive jets by locating an abrasive-jet perforating
tool within a zone
of interest and pumping an abrasive laden fluid through jetting ports of the
abrasive-jet
perforating tool, wherein the first and the second clusters are separated by a
non-perforated
interval; wherein the nonperforated interval is located downhole from the
first cluster and
uphole from the second cluster, wherein the jetting ports on a sand jetting
sub of the abrasive-
jet perforating tool have a variable configuration, and wherein at least one
of the first cluster
and the second cluster is formed by the forming being performed through coiled
tubing fluidly
connected to the abrasive-jet perforating tool; (b) before fracturing, moving
the abrasive-jet
perforating tool away from the at least one perforation; (c) injecting a
proppant-free fracturing
fluid into the wellbore through the first and second clusters of perforations
simultaneously;
(d) injecting a first proppant-laden slurry through the first and second
clusters simultaneously;
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and (e) repeating parts (c) and (d) in an alternating fashion, thereby
generating fractures and
creating proppant-free channels inside the fractures.
[0026c] According to another aspect of the present invention, there is
provided a
method for perforating and fracturing of a subterranean formation with a
wellbore lined with
casing extending through at least part of the formation, the method
comprising: forming a
plurality of clusters of perforations with abrasive-jets, by locating an
abrasive-jet perforating
tool within a zone of interest and pumping an abrasive laden fluid through
jetting ports of the
abrasive-jet perforating tool, with non-perforated intervals disposed between
each cluster;
wherein the plurality of clusters comprises from 2 to about 100 clusters
including at least a
first cluster and a second cluster which are separated by a first
nonperforated interval, wherein
the first nonperforated interval is located downhole from the first cluster
and uphole from the
second cluster, wherein the jetting ports on a sand jetting sub of the
abrasive-jet perforating
tool have a variable configuration, and wherein the forming of the plurality
of clusters is
performed through coiled tubing fluidly connected to the abrasive-jet
perforating tool; before
fracturing, moving the abrasive-jet perforating tool away from the plurality
of clusters of
perforations; pulsing a proppant-free fracturing fluid and a first proppant-
laden slurry into the
wellbore through the first cluster and the second cluster simultaneously,
thereby generating
fractures; and pulsing one or more additional proppant-laden slurries having
concentrations of
proppant that vary with respect to the first proppant-laden slurry followed by
injecting the
proppant-free fracturing fluid into the wellbore and through the plurality of
clusters, thereby
creating proppant-free channels inside the fractures.
Brief Description of the Drawings
[0027] FIG. 1 illustrates a plurality of discreet perforation clusters
separated by non-
perforated intervals that may be formed by abrasive-jet perforating.
[0028] FIG. 2 illustrates an annular fracturing and abrasive-jet
perforating tool.
[0029] FIG. 3 graphically illustrates a fracturing pumping schedule in
accordance with
this disclosure.
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[0030] FIG. 4 is a photograph of a cavern or perforation made by an
abrasive-
jet technique.
[0031] FIG. 5 is a flow diagram illustrating a perforation and pumping
schedule in accordance with this disclosure.
Detailed Description
[0032] This disclosure is directed to the combination of improved
abrasive-jet
perforation techniques which enables the creation of discreet clusters of
perforations
separated by nonperforated intervals followed by improved hydraulic fracturing
techniques which include proppant pulsing. Anywhere from one to 100 or more
clusters may be treated together and each cluster may include from one to 20
or more
perforations. Each cluster may be up to 5 m or more in length and the
nonperforated
intervals may range from about 10 cm to about 5 m or more in length. The
abrasive-
jet perforating may optionally be performed through coiled tubing and the
subsequent
fracturing techniques may optionally be performed through an annulus created
by the
coiled tubing and the casing. Of course, other techniques may be employed as
will be
apparent to those skilled in the art.
[0033] Abrasive-jet perforation may have advantages over cumulative
perforation in the respect that abrasive-jet perforating can allow for a
selective
approach to perforating cluster location and a nonperforated interval between
perforation clusters. Abrasive-jet perforation may also allow for
significantly reduced
amount of perforations inside the casing, but may still provide risk-free
proppant
admittance due to the large surface area of the caverns created inside the
cement and
the formation by abrasive-jet perforation techniques. Further, such caverns
may
connect the wellbore with the fracture.
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[0034] In an embodiment, an abrasive perforating scheme may include
clusters
of perforations of up to 5 meters long and also may include non-perforated
intervals
between the clusters that can from about 10 cm to 5 m or more in length. The
number
of clusters for the fracturing treatment can vary from 1 to 100, or any
suitable number,
depending upon such factors as formation thickness, wellbore deviation and
fracture
design parameters. The number perforations in each cluster may vary from 1 to
20 or
more, or any suitable number, depending upon such factors as formation
characteristics and fracturing treatment design specifics. In one instance,
each cluster
may include from 1 to 6 perforations or caverns created in azimuthally
different
directions by fluid jet flow through nozzles of the perforator. An
illustration of such a
perforation scheme is shown in FIG 1 and an illustration of an abrasive-jet
perforating
device is shown in FIG. 2
[0035] FIG. 1 shows a sectional view of a wellbore 10 that is been
lined with
casing 11 with the annular space disposed between the casing and the formation
12
being filled with cement 13. FIG. 1 illustrates a plurality of perforation
clusters 14
that, in the embodiment illustrated in FIG. 1, each include from one to four
perforations 15 that form caverns that extend through the cement 13 and into
the
formation 12. The clusters 14 may be separated from one another by
nonperforated
intervals 16. While each cluster 14 may be treated separately using the
improved
hydraulic fracturing techniques disclosed below, each cluster 14 may also be
treated
simultaneously using the disclosed hydraulic fracturing techniques.
[0036] An abrasive-jet perforating tool 19 for forming the clusters 14
shown in
FIG. 1 is illustrated in FIG. 2. The tool 19 includes a collar
locator/centralizer 20, a
connector 22, and a sand jetting sub 23. The collar locator/centralizer 20 is
connected
beneath connector 22, which may be used to attach the tool 19 to coiled tubing
(not
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81779057
shown) or another tool string (not shown). The collar locator 20 is used to
determine
when the tool 19 is within a particular zone of interest in the well based on
collars 24
located in the well casing 11 (FIG. I). Although the embodiment of FIG. 2
includes a
collar locator/centralizer 20, this device may be one of a various number of
down hole
devices used to determine the location of a down hole assembly within a
weIlbore 10.
The disconnect tool (not shown) may releasably connect the tool 19 to the
bottom end
of a coiled tubing, tool string, drill pipe, wire line, etc. A reverse check
valve with a
bull nose 25 is disposed at a distal end of the tool 19.
100371 Once the tool 19 has been located within the new zone of
interest and
the sand jetting sub 23 is positioned at the proper location, an abrasive
laden fluid
may be pumped at a high pressure through the jetting ports 27 on the exterior
of the
sand jetting sub 23. For example, 20/40 Ottowa sand may be pumped through the
sand jetting sub 23 to create perforations 15 through the casing 11 at the
desired
locations as shown in FIG. 1. Using 20/40 Ottowa sand pumped through the sand
jetting sub 23 may perforate the casing 11 and cement 13 at the zone of
interest in as
little as twenty minutes. The tool 19 may also be used to perforate tubing as
would be
appreciated by one of ordinary skill in the art having the benefit of this
disclosure.
The configuration of the jetting ports 27 of the sand jetting sub 23 may be
varied to
change the number and locations of perforations created by the sand jetting
sub 23.
The configuration of the individual jetting ports 27 may also be changed to
modify the
cutting power of the sand jetting sub 23.
[00381 After the easing 11 (or tubing) has been perforated as shown
in FIG. 1,
the tool 19 may be withdrawn from the wellbore 10 or, if the tool 19 is
disposed at an
end of a coiled tubing (not shown), the tool may be moved away from the
perforations
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15 to provide a sufficient annular flow path to allow stimulation of the
perforations
15.
[0039] Fracturing fluid is pumped down the casing 11 at a high
pressure in an
attempt to generate fractures through the perforations 15 in the zones of
interest.
[0040] In a hydraulic fracturing method for a subterranean formation,
a first
stage referred to as the "pad stage" involves injecting a fracturing fluid
into a wellbore
at a sufficiently high flow rate that it creates a hydraulic fracture in the
formation.
The pad stage is pumped until the fracture is of sufficient dimensions to
accommodate
the subsequent slurries pumped in the proppant stages. The volume of the pad
can be
designed by those knowledgeable in the art of fracture design.
100411 Water-based fracturing fluids are common with natural or
synthetic
water-soluble polymers added to increase fluid viscosity and are used
throughout the
pad and subsequent propped stages. These polymers include, but are not limited
to,
guar gums; high-molecular-weight polysaccharides composed of mannose and
galactose sugars; or guar derivatives, such as hydropropyl guar, carboxymethyl
guar,
and carboxymethylhydropropyl guar. Cross-linking agents based on boron,
titanium,
zirconium or aluminum complexes are typically used to increase the polymer's
effective molecular weight making it better suited for use in high-temperature
wells.
[0042] To a small extent, cellulose derivatives, such as
hydroxyethylcellulose
or hydroxypropylcellulose and carboxymethylhydroxyethylcellulose, are used
with or
without cross-linkers. Two biopolymers--xanthan and scleroglucan--prove
excellent
proppant-suspension ability, but are more expensive than guar derivatives and
so are
used less frequently. Polyacrylamidc and polyacrylatc polymers and copolymers
are
used typically for high-temperature applications or as friction reducers at
low
concentrations for all temperatures ranges.
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[0043] Polymer-free, water-base fracturing fluids can be obtained
using
viscoelastic surfactants. Usually, these fluids are prepared by mixing in
appropriate
amounts of suitable surfactants, such as anionic, cationic, nonionic and
Zwiterionic.
The viscosity of viscoelastic surfactant fluids are attributed to the three-
dimensional
structure formed by the fluid's components. When the surfactant concentration
in a
viscoelastic fluid significantly exceeds a critical concentration, and in most
cases in
the presence of an electrolyte, surfactant molecules aggregate into species,
such as
worm-like or rod-like micelles, which can interact to form a network
exhibiting
viscous and elastic behavior.
[0044] After the "pad stage", several stages, referred to as "propping
stages",
are injected into formation. A propping stage involves the periodical
introduction into
the fracturing fluid in the form of solid particles or granules to form a
suspension.
The propped stage is divided into two periodically repeated sub-stages, the
"carrier
sub-stage" involves injection of the fracturing fluid without proppant; and
the
"propping sub-stage" involves addition of proppant into the fracturing fluid.
As a
result of the periodic slugging of slurry containing granular propping
materials, the
proppant doesn't completely fill the fracture. Rather, spaced proppant
clusters form as
posts with channels between them through with formation fluids pass. The
volumes
of propping and carrier sub-stages as pumped may be different. That is the
volume of
the carrier sub-stages may be larger or smaller than the volume of the
propping sub-
stages. Furthermore the volumes of these sub-stages may change over time. That
is,
a propping sub-stages pumped early in the treatment may be of a smaller volume
than
a propping sub-stage pumped latter in the treatment. The relative volume of
the sub-
stages is selected by the engineer based on how much of the surface area of
the
fracture he desires to be supported by the clusters of proppant, and how much
of the
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fracture area is open channels through which formation fluids are free to
flow. As
non limiting example, the volume of carrier sub-stage or propping sub-stage
can be
zero.
[0045] A sample pumping schedule for a propped stage is shown in Table
1
below. Table 1:
Stage Pump Fluid Prop Prop Slurry Pump Dirty Clean Cycles
Rate volume Conc, mass volume time pulse pulse
m3/min m3 kgPA kg m3 min sec sec
PAD 3.18 79.5 0 0 79.5 25 0 1500 0
1 PPA 3.18 3.9 120 228 3.9 1.2 12.4 12.4 2
2 PPA 3.18 7.4 240 854 7.6 2.4 12 12.0 6
3 PPA 3.18 6.1 359 1033 6.4 2.0 12 12.0 -- 5
4 PPA 3.18 10.7 479 2401 11.4 3.6 12 12.0 9
PPA 3.18 11.8 589 3233 12.7 4.0 12 12.0 10
6 PPA 3.18 11.6 719 3766 12.7 4.0 12 12.0 10
7 PPA 3.18 18.3 839 6829 20.4 6.4 12 12.0 -- 16
TAIL- 3.18 0.8 839 711 1.1 0.3 20 0 0
IN
FLUSH 3.18 6.2 0 0 6.2 1.9 0 116.5 0
Another pumping schedule is illustrated graphically in FIG. 3. In Table 1 and
FIG. 3,
"dirty pulse' refers to "propping sub-stage" and "clean pulse" refers to
"carrier sub-
stage". Referring to FIG. 3, the first stage, known as the pad stage is shown
at 31. A
plurality of proppant stages are shown at 32-37 wherein, each proppant stage
32, 33,
34, 35, 36 represents the injection of a proppant-laden fracturing fluid
having
increasing concentrations of proppant. Within each stage, 32, 33, 34, 35, 36,
pulses of
"clean" fracturing fluid is followed by pulses of "dirty" or proppant-laden
fracturing
fluid (or slurry). The At for each pulse may vary widely from the example of
12
seconds given in Table 1. For example, the clean and dirty pulse times may
range
from about 5 seconds to a minute or longer, also pulse times in the range of
from
about 5 seconds to about 30 seconds may be preferred. The final tail-in stage
is
shown at 37 and has zero volume of clean pulse.
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[0046] Some concepts in support of such an abrasive perforation scheme
to
promote channel creation inside fracture after treatment with proppant pulsing
technique include the following: (1) The near-wellbore area is the most
critical zone
for proppant admittance (high tangential stresses). The disclosed technique
may
allow for reliable proppant admittance and reduction of risk for proppant
bridging.
This can be achieved even with a lower number of holes inside the casing than
the
number of holes that would be needed with a cumulative perforation technique.
The
reduced number of holes inside casing would be achieved by the geometry of the
abrasive cavern ¨ which has larger contact area with the fracture relative to
the
contact area generated from a channel developed with the cumulative
perforation
technique. An abrasive cavern is created without excessive temperatures or
pressures
and without damaging the surface around it. (2) Due to better proppant
admittance, it
is possible to decrease total number of perforation holes without increasing
risk of
proppant bridging (one perforation hole per cluster in some cases) to increase
diverting pressure resulting in enhancement of injection profile (all clusters
admit
slurry). Better division of a proppant pulse into smaller structures is
achieved by
clusters at the wellbore, before slurry enters the fracture. (3) Decreasing
number of
perforations within a given perforation interval can be beneficial in
completions
where several fractures are to be initiated during fracturing fluid injection.
An
example is initiation of several transverse fractures in a horizontal wellbore
where one
fracture is to be initiated through each perforation cluster. The more
perforations are
created within a cluster, the less predictable the number of initiated
fractures is. If the
number of perforations within a cluster is not enough for adequate proppant
admittance (e.g. cumulative perforations), then no fracture may be created at
a given
cluster. If the number of perforations is too large, then more than one
fracture can be
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created within one cluster. Accurate estimation of number of fractures created
is
necessary for proper design of fracturing job. For example number of created
fractures can affect choice of duration for "propping sub-stage" and "carrier
sub-
stage". Hence, using of abrasive perforations with small number of holes
within a
cluster can result in more reliable design of the fracturing treatment. (4)
Clusters can
be tailored in their separation one from another to ensure optimal channel
creation.
Clusters sizes, distances between clusters, hole density, variations of hole
density
inside specific cluster, hole sizes, variations of hole sizes inside of
specific cluster can
be readily customized to fit changes of geomechanical properties of formation
if
abrasive perforation is used. One of characteristics of a perforation gun is
shot
density. Inverse value to shot density is shot spacing or distance between
shots. If
conventional perforation guns are used than cluster height and distance
between
clusters should be multiple to shot spacing. Abrasive perforation does not
have such
limitations. Hole size and perforation channel geometry in cumulative
perforation
depends on thickness of casing, charge type and rock properties. For
cumulative
perforation, parameters such as hole size and channel geometry are limited by
gun and
charge specifications. In case of abrasive perforation, slurry rate and
duration of
cutting can be chosen during treatment to customize hole size and cavern
geometry
[0047] Reinforcing and/or consolidating material may be introduced
into the
fracture fluid during the propped stage to increase the strength of the propp
ant clusters
formed and prevent their collapse during fracture closure. Typically the
reinforcement material is added to the propping sub-stage, but this may not
necessarily be always the case. The concentrations of both propping and the
reinforcing materials can vary in time throughout the propping stage, and from
sub-
stage to sub-stage. That is, the concentration of reinforcing material may be
different
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at two subsequent sub-stages. It may also be suitable in some applications of
the
present method to introduce the reinforcing material in a continuous fashion
throughout the propped stage, both during the carrier and propping sub-stages.
In
other words, introduction of the reinforcing material isn't limited only to
the propping
sub-stage. Particularly, different implementations may be preferable when the
reinforcing material's concentration doesn't vary during the entire propped
stage;
monotonically increases during the propped stage; or monotonically decreases
during
the propped stage.
[0048] Curable or partially curable, resin-coated proppant may be used
as
reinforcing and consolidating material to form proppant clusters. The
selection
process of the appropriate resin-coated proppant for a particular bottom hole
static
temperature (BHST), and the particular fracturing fluid are well known to
experienced
workers. In addition, organic and/or inorganic fibers can reinforce the
proppant
cluster. These materials can be used in combination with resin-coated
proppants or
separately. These fibers could be modified to have an adhesive coating alone;
or an
adhesive coating coated by a layer of non-adhesive substance dissolvable in
the
fracturing fluid as it passes through the fracture. Fibers made of adhesive
material
may be used as reinforcing material, coated by a non-adhesive substance that
dissolves in the fracturing fluid as it passes through the fracture at the
subterranean
temperatures. Metallic particles are another preference for reinforcing
material and
may be produced using aluminum, steel containing special additives that reduce
corrosion, and other metals and alloys. The metallic particles may be shaped
to
resemble a sphere and measure 0.1-4 mm. Preferably, metallic particles are
used of
an elongated shape with a length longer than 0.5 mm and a diameter of 10 to
200
microns. Additionally, plates of organic or inorganic substances, ceramics,
metals or
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metal-based alloys may be used as reinforcing material. These plates may be
disk or
rectangle-shaped and of a length and width such that for all materials the
ratio
between biggest and smallest dimensions is greater than 5 to 1.
[0049] Both the
carrier and propping sub-stages may include introduction of an
agent into the fracturing fluid to increase the proppant transport capability.
In other
words, reducing the settling rate of proppant in the fracture fluid. The agent
may be a
material with elongated particles whose length much exceeds their diameter.
This
material affects the rheological properties and suppresses convection in the
fluid,
which results in a decrease of the proppant settling rate in the fracture
fluid. Materials
that may be used include fibers that are organic, inorganic, glass, ceramic,
nylon,
carbon and metallic. The proppant transport agents may be capable of
decomposing
in the water-based fracturing fluid or in the down hole fluid, such as fibers
made on
the basis of polylactic acid, polyglycolic acid, polyvinyl alcohol, and
others. The
fibers may be coated by or made of a material that becomes adhesive at
subterranean
formation temperatures. They may be made of adhesive material coated by a non-
adhesive substance that dissolves in the fracturing fluid as its passes
through the
fracture. The fibers used can be longer than 0.5 mm with a diameter of 10-200
microns, in accordance with the main condition that the ratio between biggest
and
smallest dimensions is greater than 5 to 1. The weight concentration of the
fibrous
material in the fracturing fluid is from 0.1 to 10%. The proppant should be
chosen
with consideration to increasing the proppant clusters strength. In an
embodiment, the
fibers may be made of polylactic acid, polyglycolic acid or copolymers
comprising
lactic acid and/or glycolic acid. In another embodiment, the fibers are added
at a
concentration of 0.5 to 20 kg per m3 of fracturing fluid.
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[0050] A proppant cluster should maintain a reasonable residual
thickness at
the full fracture closure stress. This method provides an increase in fluid
inflow
through open channels formed between the proppant clusters. In this situation,
a
permeability value of the proppant, as such, isn't decisive for increasing the
well's
productivity using this method. Thus, a proppant cluster may be created
successfully
using sand whose particles are too weak for use in standard hydraulic
fracturing in the
present formation. Sand costs substantially less than ceramic proppant.
Additionally,
destruction of sand particles during application of the fracture closure load
might
improve strength behavior of the same cluster consisting of proppant granules.
This
can occur because the cracking/destruction of proppant particles decreases the
cluster
porosity thereby increasing the proppant compactness degree. Sand pumped into
the
fracture to create proppant clusters doesn't need good granulometric
properties, that is,
the narrow diameter distribution of particles. For example, it is possible to
use 50
tons of sand, wherein 10 to 15 tons have a diameter of particles from 0.002 to
0.1 mm,
15 to 30 tons have a diameter of particles from 0.2 to 0.6 mm, and 10 to 15
tons have
a diameter of particles from 0.005 to 0.05 mm. It should be noted that about
100 tons
of a proppant more expensive than sand would be necessary to obtain a similar
value
of hydraulic conductivity in the created fracture implementing the prior
(conventional) method of hydraulic fracturing.
[0051] It may be preferable to use sand with an adhesive coating alone,
or an
adhesive coating coated by a layer of non-adhesive substance dissolvable in
the
fracturing fluid as it passes through the fracture. A non-adhesive substance
guarantees that particles of the adhesive proppant won't form agglomerates
prior to
entering the fracture, and allows for control of a time moment (a place) in
the fracture
when (where) a proppant particle gains its adhesive properties. The adhesive
coating
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is cured at the formation temperature, and sand particles conglutinate between
each
other. Bonding particles within the clusters reduces the proppant cluster
erosion rate
as formation fluids flow past the cluster, and minimizes proppant cluster
destruction
by erosion.
[0052] In some cases, the propping stage may be followed by a proppant
stage,
referred to as the ''tail-in stage" in FIG. 3, which involves a continuous
introduction of
an amount of proppant. If employed, the tail-in stage of the fracturing
treatment
resembles a conventional fracturing treatment, where a continuous bed of
proppant is
placed in the fracture relatively near to the wellbore. The tail-in stage may
involve
introduction of both an agent that increases the fluid's proppant transport
capability
and or an agent that acts as a reinforcing material. The tail-in stage is
distinguished
from the second stage by the continuous placement of a well-sorted proppant,
that is,
a proppant with an essentially uniform size of particles. The proppant
strength is
sufficient to prevent its cracking (crumbling) when subjected to stresses that
occur at
fracture closure. The role of the proppant at this stage is to prevent
fracture closure
and, therefore, to provide good fracture conductivity in proximity to the
wellbore.
[0053] The disclosed hydraulic fracturing methods introduce one or
more
agents into the treatment fluid to promote the formation of proppant clusters
in the
fracture during pumping, while continuously pumping propping agents. When the
agent reacts it causes the local formation of a proppant cluster. Typically
the agent is
selected or designed such that its action or function is delayed until it is
placed within
the fracture. Delaying chemical and or physical reaction is a process commonly
used
in hydraulic fracturing as well as many other industrial processes. One
process that
can be used is the simple temperature activation of the agent as the
fracturing fluid
heats up as it enters the higher temperature formation deep in the earth. For
example,
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ammonium persulfate homolysis is relatively slow at surface temperatures of 20
C,
but relatively rapid at formation temperatures of 100 C. A second process is a
slow
dissolution of a reactive agent, or of a binder. For example, the dissolution
ratio of
polyvinyl alcohol in water is dependent on its molecular weight. Encapsulation
of a
reactive species is a common process employed in hydraulic fracturing. The
reactive
material or agent is protected for a time from the fracturing fluid by a
relatively non-
reactive capsule. The encapsulated material subsequently releases the reactive
agent,
either slowly or quickly by many different methods. The encapsulation can be
designed to release its contents by dissolution, mechanical erosion, crushing
swelling
and rupturing, or simply by slow diffusion.
100541 The first stage of the fracturing treatment, the "pad stage"
(FIG. 3) is
pumped as usual. Unlike the previous embodiment where proppants were pumped
discontinuously, the proppant (propping agents) are pumped continuously. The
concentration of the proppant may increase, stay constant, or decrease during
the
propped stage. Normally proppant concentrations start low, and are ramped up
to
higher concentrations near the end of the treatment. The key to this
embodiment is
that an agent causes the nucleation or formation of proppant clusters is
discontinuously or periodically introduced into the fracturing fluid during
the propped
stage. The agent is designed to work in only a small region or zone within the
fracture. Propping materials within this zone are influenced in such a way
that they
form cluster, bridge out and become immobile. In addition proppants that are
pumped
subsequent to the cluster formation may accumulate on the cluster and make it
grow
in size.
[0055] One way to generate clusters of proppant is to locally reduce
the ability
of the fluid to transport solid phase particles. In this case, the agent could
be a high
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concentration of oxidative "breakers", such as ammonium persulfate, that--when
reacting with the fracturing fluid at different places in the fracture--lead
to drastic and
significant decreases in the fracturing fluid's local viscosity. When fluid
viscosity
drops below a critical value, the fracturing fluid is unable to transfer the
proppant
particles and the particles stop, settle, and form proppant clusters. The
addition of
fibers greatly enhances proppant cluster formation. Encapsulated breakers with
a long
release time can be used at the beginning of the propped stage, and
encapsulated
breakers with short release times can be used at the end of the propped stage.
[0056] Reinforcing materials such as fibers can greatly increase the
tendency of
proppants to locally jam between the fracture walls and form a cluster.
Therefore, in
this embodiment fibers and or other reinforcing materials as discussed above
may be
added to the fracturing fluid during the propped stage either continuously
into or
discontinuously (at the same time as the breaker).
[0057] Requirements for proppant properties used in the first
embodiment
apply in the second one as well. It's possible to use a proppant without a
narrow
diameter distribution of particles, that is, a poorly-sorted proppant with a
relatively
small strength value per particle. For instance, there may be sand particles
with
coatings similar to that described in the first embodiment of the method. The
above-
mentioned third stage may also take place.
[0058] Chemical species that competitively bind the crosslinking
agents could
be another type of agent used to locally reduce fluid viscosity. The local
release of
chel ants, (that react with zirconate crosslinkers), sorbitol or
polyvinylalcohol (that
react with borate crosslinkers) or other species that deactivate the cross
linker can
cause the polymer gel to de-crosslink and significantly reduce the fracturing
fluid
viscosity. Since many crosslinking reactions are pH dependent, the localized
release
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of an acid or base can also reduce fluid viscosity. For example, one may
manipulate
the fracturing fluid pH through the introduction of an encapsulated acid
and/or
particles of substances, for instance polylactic acid or polyglycolic acid in
which
release or generation of the acid occurs at a controlled rate. Changing the
fracturing
fluid pH reduces the cross linker affinity to form stable bonds with the
polymer and
the fluid viscosity decreases for certain specific polymer cross linker
combinations.
[0059] For said purposes, an encapsulated absorbent or competitive
chelating
agent of the polymer chain cross-linker may be used also, which allows for
controlled
release. Cross-linked gel chemicals, such as sodium gluconate or sorbitol, may
be
used for a borate. For metal crosslinkers, such as titanates or zirconates,
chemicals
including but not limited to EDTA, NTA, phosphates, polyvinyl acetates may be
used.
Selection of the specific chemical to attack the cross linker in question are
well known
to skilled workers. Such absorbents may be, for instance, phosphates or
polyvinyl
acetates.
[0060] The agent that provides proppant cluster formation by
decreasing the
fracturing fluid's local viscosity may also represent chemical substances that
react
with the fracturing fluid to provide a significant amount of local heat
extraction,
resulting in heating the fracturing fluid and thereby decreasing its local
viscosity.
Examples of such substances include explosives or encapsulated reactive metals
such
as sodium, that release the substance in various places in the fracture to
provide
proppant cluster formation throughout the length of the fracture.
[0061] Proppant clusters and channels between the clusters may be
formed by
reducing proppant mobility in the fracture. This method includes the pad and
propping stages described above, but differs in that the agents that produce
cluster
formations decrease mobility of proppant particles.
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[0062] Specifically, the additives may be fiber bundles that slowly
expand and
shed individual fibers due to mechanical agitation. The increased excluded
volume of
the bundle and the localized increase in fiber concentration can initiate jams
and
create of proppant clusters.
[0063] The additives may be also cut wires made of an alloy possessing
"shape
memory" properties. For example Copper-Aluminum-Nickel (CuAlNi) shape memory
alloys fimetion over the temperature range of many oil and gas-bearing
formations.
These materials may be bent to shape small balls (springs) and retain their
shape at
surface temperature. When heated to reservoir temperature, the material with
"shape
memory" undergoes phase transition accompanied by recovery of its original
memorized straight-line shape. Phase transition temperature variation is
possible by
varying the alloy composition. It may be preferable to introduce a material
whose
phase transition temperature varies from portion to portion. At the beginning
of the
propped stage, for instance, it may be reasonable to introduce materials with
the
highest phase transition temperature, for example, slightly less than the
formation
temperature; and at the end of the second stage in may be reasonable to
introduce a
material having the lowest phase transition temperature, for example, slightly
more
than the surface fluid temperature. Balls of the material with "shape memory"
are
usually similar in size to proppant particles.
100641 When the metal balls are subjected to an elevated temperature
in the
fracture, they recover their original shape, that is, they straighten. As
noted above,
local increase of their contents effectively promotes formation of proppant
clusters in
the fracture. The ability to vary the shape recovery temperature gradually by
varying
the alloy composition allows formation of wires and thereby immovable clusters
of
proppant distributed uniformly throughout the length of the fracture.
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[0065] The use of super-absorbing material to form local jams in the
flowing
fracturing fluid may also be employed. Super-absorbents such as cross-linked
polyacrylamide polyacrylate copolymers can adsorb an amount of water 100 to
300
times their weight in water. A wide variety of super-absorbents are available.
Selection of a particular one may be determined by such factors as formation
temperature, salt content of the water used to prepare the fracturing fluid,
and others.
[0066] A super-absorbent may be used that is protected by a shell or
emulsion
that is dissolved or dispersed at its passes through the fracture or upon
elevation of the
fracturing fluid temperature, or a combination of these conditions. By varying
shell
thickness, it is possible to control the time span between introduction of a
portion of
the super-absorbent into the fracturing fluid and its release from the shell.
When the
shell dissolves or is dispersed, an absorbing particle begins its growth by
absorbing
water from its surroundings. Increasing the mass and size of particles
decelerates
their movement through the fracture and ultimately results in local jams,
capture of
proppant particles, and formation of proppant clusters.
[0067] Additives may also be used to decrease proppant mobility in the
fracture may be granules, fibers, or plates whose surface becomes "adhesive"
at
formation temperatures. Additional coating of particles with adhesive surfaces
with a
layer of a non-adhesive substance dissolvable in the fracturing fluid may be
preferable; by varying the substance thickness, the time span can be varied
whose
lapse gives rise to formation of proppant clusters due to their surface
adhesive
properties. Another technique for controlling time span employs coatings that
gain
adhesive properties at different temperatures. It may be preferable to
introduce
particles with a maximum thickness of protective coating (thus with a maximum
temperature of demonstrating "adhesive" properties) at the beginning of the
second
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stage. And be preferable to introduce respectively particles with a minimum
thickness of a protective coating (thus with a minimum temperature of
demonstrating
"adhesive" properties) at the end of the second stage. When such particles
enter the
fracture, they collide (bump) and conglutinate forming agglomerates of
proppant
particles. When the agglomerates size become comparable with the
characteristic
width of the fracture, they wedge between the fracture faces causing local
proppant
jams and formation of proppant clusters.
[0068] Using reinforcing materials with the fracturing fluid may also
be
employed, thus increasing the strength of the formed proppant clusters; and
introducing agents that increase the fluid's proppant transport ability by
decreasing the
proppant settling rate through the fracturing fluid. All these requirements
for
proppant selection, particularly for use of a proppant that is relatively
moderately
strong, a (possibly) wide distribution of particle sizes, the proppant coated
preliminarily with a binder layer curable under formation conditions, remain
applicable.
[0069] The formation of proppant clusters and channels between them by
sequentially pumping two fluids with contrasting viscosities into the wellbore
may be
employed. This method involves a pad stage as discussed above, and the
propping
stage involves continuous introduction of proppant into a given fluid. Similar
to the
previous embodiments, the propping stage may involve introducing reinforcing
materials into the fracturing fluid, these materials increasing the strength
of the
formed proppant clusters; and introducing an agent that increases the fluid's
proppant
transport ability by decreasing the proppants settling rate. All requirements
for
proppant selection, particularly the use of a proppant with a relatively
moderate
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strength, a wide size distribution of particles, and preliminarily coated with
a binder
layer curable under formation conditions, are still applicable.
[0070] Then the injection of proppant-containing fracturing fluid
together with
other materials is terminated, and a fluid of very low viscosity is injected
into the
created fracture. Owing to the difference between their viscosities, injection
of the
lower-viscosity fluid after injection of the more viscous fluid results in
penetrating the
lower-viscosity fluid into the more viscous fluid in the form of "intrusions".
This
forms channels in the proppant that fills the fracture dividing the proppant
into
discrete clusters.
[0071] As discussed above, a fourth "tail-in" stage may involve a
continuous
introduction of a proppant with essentially uniform particle size, a
reinforcing
material, and/or a material with elongated particles that increase the
proppant
transport ability of the fracturing fluid into the fluid.
[0072] All methods for hydraulic fracturing described above and with
different
mechanisms to form proppant clusters provide very high hydraulic fracture
conductivity. This occurs through the formation of strong proppant clusters
well
spaced throughout the fracture's length and height. The clusters are stable
enough to
prevent the fracture from closing; and the inter-cluster channels have a
sufficiently
large cross-section for formation fluids to flow.
Industrial Applicability
[0073] FIG. 5 is a flow diagram illustrating another disclosed
combination of
abrasive jet perforating and improved hydraulic fracturing techniques. Part 41
signifies the placement of the disclosed perforating tool 19 into the wellborc
10. The
tool 19 is located within the zone of interest in part 42. An initial
perforation cluster
14 is created within abrasive jet at part 43. In part 44, the tool 19 is
relocated to a new
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zone of interest. In part 45, a new cluster 14 is perforated. In part 46,
fracturing fluid
without proppant is pumped down the casing 11. This is referred to above as
the pad
stage, which is also illustrated FIG. 3. Then, in part 47, proppant-laden
slurry is
pumped down the casing 11 and parts 46 and 47 are repeated sequentially for a
given
proppant concentration in part 48 as illustrated in FIG. 3. Then, another
proppant-
laden slurry is pumped down the casing 11 in part 49 followed by pumping clean
fracturing fluid in part 50. Parts 49-50 may then be repeated in part 51 and
the pattern
set forth in FIG. 3 may be followed.
[0074] Although only a few example embodiments have been described
in
detail above, though skilled in the art will readily appreciate that many
modifications
are possible in the example embodiments without materially departing from the
scope of this disclosure. Features shown in individual embodiments referred to
above may be used together in combinations other than those which have been
shown
and described specifically. Accordingly, all such modifications are intended
to be
included within the scope of this disclosure as defined in the following
claims.
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