Note: Descriptions are shown in the official language in which they were submitted.
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HYDRAULIC FRACTURING METHOD
Background of the Invention
Recovery of hydrocarbons from unconventional reservoirs, for example
tight sandstones and shales, usually requires stimulation, for example
hydraulic
fracturing, to achieve economic production. Water or slickwater (so-called
when
water with a small amount of a friction reducer is used) are often used as
fracturing fluids for stimulation of low permeability unconventional
reservoirs.
Such treatments are designed to stimulate large reservoir volumes and to open
more surface area of hydrocarbon-retaining rock, thus enhancing production.
While slickwater fluids usually provide poor transport for conventional
proppants, due to their very low viscosity, they still have been found
effective
and economic. Using low-viscosity fluids for fracture stimulation in low-
permeability reservoirs sometimes results in the creation of a network of
intersecting fractures and sometimes results in propagation of a single
fracture
plane. Although the low conductivity achieved with these treatments is often
adequate in shale formations, it is believed that an increase in the contact
area
by generation of a complex fracture network is one of the key factors that can
enhance hydrocarbon production in such formations.
Existing treatment techniques have not proven to be sufficiently effective
for formation of fracture networks with high fracture densities. The fracture
network complexity is reflected in the number of interconnected fractures in
the
fracture network system as shown in Figure 1. There is a need for a reliable
fracture treatment technique that generates a greater fracture network
complexity and thus a higher contact area with the reservoir during a single
treatment cycle.
Summary of the Invention
One embodiment of the invention is a method for fracturing a
subterranean formation in which a sequence of fluids is injected into the
formation; the sequence has as a feature a first cycle that involves (a)
injecting
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a pad fluid having a viscosity of less than about 50 mPa-s at a shear rate of
100
s-' under ambient conditions, (b) injecting proppant slurry having a viscosity
of
less than about 50 mPa-s at a shear rate of 100 s-' under ambient conditions,
(c) injecting a thickened fluid (that will act as a diverting agent) having a
viscosity of greater than about 50 mPa-s at a shear rate of 100 s-' under
ambient conditions, and one or more than one subsequent cycles incorporating
repeating steps (b) and (c). Optionally, a pad fluid is injected first.
Typically the
permeability of the formation is less than about 1 mD.
In another embodiment, the thickened diverting fluid has a viscosity of
less than about 20 mPa-s as pumped and then thickens in the reservoir, for
example the reservoir contains carbonate and the thickened fluid is initially
acidic and becomes more viscous as acid is consumed. Self-diverting acids
systems may be used to form such systems that thicken in the reservoir.
In various other embodiments, the thickened fluid further contains a
proppant; the total volume of the fluid injected in steps (b) is at least 75
percent
of the total volume of fluid injected in the treatment; and the fluid injected
in
steps (b) carries at least 90 percent of the total proppant injected in the
treatment; the proppant has a shape selected for example from spheres, rods,
cylinders, plates, sheets, spherocylinders, ellipsoids, toruses, oblongs,
fibers,
arches/cells, meshes, meshes/cells, honeycombs, bubbles, sponge-like or foam
structures, and mixtures of these shapes; the size of the proppant ranges from
about 5 to about 1000 microns.
In yet another embodiment, at least one of the injected fluids comprises
solid degradable materials, for example polylactic acid, polyglycolic acid,
copolymers of polylactic acid and polyglycolic acid, copolymers of glycolic
acid
with other hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing
moieties, copolymers of lactic acid with other hydroxy-, carboxylic acid-, or
hydroxycarboxylic acid-containing moieties, and mixtures of these materials.
The degradable materials are typically used in the form of fibers, plates,
flakes,
beads and combinations thereof.
In further embodiments, the fluid of step (a) or the fluid of step (b) or both
contain a friction reducing agent. The fluid of step or steps (c) may
optionally
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contain less than about 0.024 kg proppant per liter of clean fluid or may
optionally be substantially proppant free.
In yet further embodiments, one or more than one cycle is followed by
injection of a fluid having a viscosity of greater than about 50 mPa-s at a
shear
rate of 100 s-' under ambient conditions and containing a coarse proppant; the
one or more steps of injection of a fluid having a viscosity of greater than
about
50 mPa-s at a shear rate of 100 s-1 under ambient conditions containing a
coarse proppant may optionally be followed by injection of a fluid containing
a
proppant flowback control agent.
In another embodiment, the method includes a final step of injecting a
flush fluid; at least one of the fluids is viscosified with a degradable
viscosifying
agent. In other embodiments, at least one step (b) after the first step (b) is
preceded by a step (a), or each step (b) is preceded by a step (a).
The total volume of the fluid injected in steps (c) preferably makes up
less than 10 percent of the total volume of fluid injected in the treatment.
In
each cycle the ratio of the volume of fluid in stage C to the volume of fluid
in
stage B is preferably less than about 1/10.
Brief Description of the Drawings
Figure 1 illustrates fracture system complexity, increasing from A to B to C.
Figure 2 is a schematic of the manifold system.
Figure 3 shows the pressure in the manifold system vs. time.
Detailed Description of the Invention
The invention will be described in terms of the treatment of vertical wells,
but is equally applicable to wells 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
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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 have developed a method of increasing fracture system complexity to
enhance hydrocarbon production from unconventional low-permeability
reservoirs. In the method, a sequence of stages is pumped into the reservoir;
a
low viscosity fluid treatment is complemented by at least one stage of pumping
of a relatively low volume of a fluid, viscosified by a degradable
viscosifying
agent that is used as a diverting agent. Pumping of the viscous fluid
diverting
agent leads to a net pressure increase and to plugging of some of the
microfractures in the initial fracture system created, which induces formation
of
supplementary microfractures connected to the initial fracture network and
increases the contact area with the formation rock. The injection of viscous
slugs of diverting agent is generally repeated. Such a use of slugs of a
viscous
fluid enables stimulation of larger reservoir volumes in remote regions of a
reservoir. After the treatment, the viscosified fluid degrades naturally or is
destroyed with a breaker, opening up production from the temporarily-plugged
fractures. Note that the present invention relates to a method of treatment
redirection within an already stimulated zone which results in creation of a
larger
contact area with the reservoir because of a fracture complexity increase
within
that zone.
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When multiple productive zones are fracture stimulated it is often
necessary to treat multiple zones in multiple stages. This creates a need for
a
diverting technique which enables treatment redirection from zone to zone.
Such diversion, optionally with new perforations shot after each treatment, is
done, for example, with bridge plugs, ball sealers, solid gel plugs, or plugs
of
degradable fibers, powder, flakes, granules, pellets, and chunks, optionally
with
slowly water-soluble coatings. The other situation in which diversion is
required
is treatment redirection within a stimulating zone. In this case an additional
formation rock volume is stimulated using the same entry point in the
formation
without treatment redirection to another zone along the wellbore.
Interestingly,
techniques have been developed using slugs of viscous fluids or fine sand for
control of leak-off and for fracture complexity decrease, not increase, in
naturally fractured reservoirs. Creation of a single fracture plane in the
near-
wellbore zone instead of multiple interconnected fracture channels has in the
past been sought deliberately to provide a significant tortuosity decrease and
minimize the risk of premature screen-out.
Slickwater treatments have been shown to provide production
comparable to that from conventional gel treatments, but for significantly
lower
cost. One of the most important features of slickwater jobs is low gel damage,
due to the low polymer content of the fluid. However, the low fluid viscosity
strongly affects its proppant transport properties, and placement of proppant
deep into a fracture is a challenge. Utilization of lightweight and ultra
lightweight
proppants has been one solution. Another solution is pumping a combination of
slickwater and gel in stages with varying quantities of proppants; such
treatments are often referred as hybrid fracs or hybrid water fracs. Although
the
objective of hybrid fracs is better proppant placement with a fluid of higher
viscosity than that of slickwater, other benefits have been noted including
creation of wider fractures and thus avoidance of proppant bridging. It has
also
been noted that hybrid fracs can generate longer effective frac lengths, but
the
effective conductivities in the hybrid fracs were not consistently higher than
those in water fracs.
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Slickwater fracs with no proppant or with coarse proppant only, or with
alternation of these two, have been tried. However, the usual slickwater
treatment includes the following stages: a) slickwater pad; b) slickwater
stage
with fine proppant (for example approximately 100-mesh sand (grains of from
about 0.105 to about 0.21 mm) or about 30/70 sand (about 0.21 to about 0.595
mm)) in concentrations gradually increasing from about 0.1 to about 2 ppa
(pounds proppant added) (about 0.012 to about 0.240 kg of sand added per liter
of clean fluid); c) linear gel (with a typical viscosity of from about 10 to
about 100
mPa-s at a shear rate of 100 s-) with coarse proppant (for example
approximately 20/40 sand (about 0.42 to about 0.841 mm) or about 20/40 resin
coated sand) in concentrations increasing to up to about 5 ppa (about 0.6 kg
of
sand added per liter of clean fluid) to prop open the near wellbore region of
the
fracture; and d) flush. Typically, the pad stage is from about 500 to about
3000
bbl (about 80 to about 480 m), the slickwater stage is from about 500 to about
25,000 bbl (about 80 to about 4000 m), the gel stage is from about 500 to
about 25,000 bbl (about 80 to about 4000 m3) and the flush is approximately
the
volume of the wellbore from the wellhead to the perforations, sometimes plus
up
to about 50 bbl (about 8 m).
The hybrid treatments attempt to achieve the benefits of both
conventional gel and slickwater treatments. Typically hybrid fracs include
pumping of: a) slickwater pad; b) an optional slickwater stage with fine
proppant
(for example less than about 0.5 ppa (about 0.06 kg/I of clean fluid)); c)
cross-
linked gel with a viscosity of about 100 to about 1000 mPa-s at a shear rate
of
100 s-1 with coarse proppant, for example about 20/40 (about 0.4 to about
0.841 mm), (at a concentration for example of up to about 5 ppa (about 0.6 kg
of sand added per liter of clean fluid)); optionally repeating stages b) and
c); and
flush. Volumes are typically about the same as for the conventional slickwater
treatments described above. In a modification of the hybrid frac called a
reverse hybrid frac the sequence of fluid injection is changed, so a high
viscosity polymer (linear or cross-linked) is used to create a fracture, while
the
proppant, transported with a low viscosity fluid, is pumped behind the viscous
pad. The viscosity contrast results in the formation of fingers of low
viscosity
proppant laden fluid in the higher viscosity fluid and proppant settling is
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hindered by the layers (fingers) of the more viscous fluid. Again, as in the
classical hybrid fracs, the objective of the design is to deliver proppant
deeper
into the fracture to ensure longer propped length and higher fracture
conductivity. In any slickwater pumping schedule, when the fluid is switched
from slickwater to viscous proppant slurry, the fluid may be changed from
slickwater to viscous fluid for a period before proppant is added; for example
in
another version of a hybrid frac, slickwater is pumped first to generate
length;
this is then followed by a crosslinked gel pad, and then by coarse sand in a
crosslinked gel.
The key distinction of the method of the present invention from the hybrid
fracs is in the volumes of viscosified fluids pumped in the slickwater stages.
Since proppant placement is not the real objective of the method of the
invention, viscous fluid is only a small fraction of the total job volume.
Furthermore, proppant concentration in the viscosified fluid is similar to
that in
slickwater stages.
Unconventional gas reservoirs are characterized by extremely low
formation permeabilities (for example less than about 0.1 mD down to about
100 nD in shales), and stimulation treatments often require large treatment
volumes (for example over about 15,000 m3 (1 Mgal)) and high pumping rates
(as examples, at least about 6.4 m3/min (40 bpm), typically about 10 m3/min
(60
bpm), and sometimes up to about 20 m3/min (120 bpm)) to open long fractures
and generate complex fracture networks, which can provide unrestricted gas
flow towards a wellbore. The fractures typically are propped with sands of
various sizes transported by slickwater fluids, which are usually water with
small
amounts of polymeric friction reducers, having viscosities up to about 50 mPa-
s
at a shear rate of 100 s-1. Fluids having higher viscosities, for example
above
about 15 cP would typically be called water frac fluids. Lightweight
proppants,
for example having specific gravities of from about 2.2 to about 2.8, and
ultra
lightweight proppants for example having specific gravities of from about 1.0
to
about 2.0 may be used for water fracs. Slickwater fluids contain significantly
lower polymer concentrations than linear or cross-linked gels, so they do much
less damage to the proppant pack.
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Various diversion techniques are used to increase the effective
stimulated volume (ESV) of a reservoir. The methods rely on temporary
plugging of some zones (for example already-stimulated zones) in order to
stimulate others with the same treatment. Most of the existing diversion
methods target welibores and perforations to stimulate different formation
zones. These methods include various casing-conveyed zonal isolation tools,
such as bridge plugs, sand plugs, ball sealers, induced stress diversion and
others. Diversion within a fracture is less common in the art of hydraulic
fracturing. One method provides near-wellbore fracture diversion on demand.
The method uses a mixture of proppant and degradable fiber and a placement
strategy to plug a fracture face temporarily in the near wellbore region to
enable
treatment diversion to a different wellbore zone.
The present invention discloses a method of fracture network complexity
increase and reservoir contact area enhancement by means of viscosified
fluids. The viscosified fluids may be selected from fluids such as, but not
limited to, viscoelastic surfactants, borate and/or metal cross-linked
polysaccharides, for example guar gums, cellulose derivatives, xanthans,
scleroglucans, etc. The fluids may further include crosslink delay agents to
control the fluid viscosity, breakers, including encapsulated breakers, to
ensure
slug degradation after the treatment, degradable fibers and other additives.
Such fluids and their components are known to those skilled in the art. The
method is preferably applied to formations having a permeability less than
about
1 mD, and more preferably to formations having a permeability less than about
mD, and most preferably to shale formations with permeabilities less than
1000 nD. The method may be used in a refracturing treatment.
As in a common slickwater treatment, a typical treatment of the invention
starts with a pad, stage A, in which a pure slickwater fluid is pumped. The
pad
stage creates the fracture system and ensures that the width is sufficient for
proppant passage. The pad stage is followed by a large-volume stage B,
pumping of a proppant-laden slickwater, which delivers the proppant into the
opened main fracture and additional fracture networks. Fluid B makes up at
least 75 percent of the total fluid volume of the treatment. The fluids of
stages A
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and B have viscosities of less than about 50 mPa-s at a shear rate of 100 s-1
under ambient conditions, preferably from about 1 to about 10 mPa-s at a shear
rate of 100 s-'. Fluids A and B may be the same or different. The proppants
for
slickwater treatments are known to those skilled in the art; non-limiting
examples include sands and other rocks and minerals, including muscovite
mica, ceramics, polymeric materials, biomaterials and mixtures of these
materials. Special attention should be paid to the choice of proppant
material,
as slickwaters have quite poor transport properties due to their very low
viscosities. A diversion stage C follows the far-field placement of proppant
in
stage B and involves pumping of a viscosified fluid, which may optionally
further
contain proppant and/or fiber material(s). The fluid of stage C has a
viscosity,
after viscosifying, greater than about 50 mPa-s, preferably from about 100 to
about 1000 mPa-s, at a shear rate of 100 s-1 under ambient conditions.
Optionally, the fluid of stage C may be pumped as a low viscosity fluid and
the
viscosity of the fluid is increased in the reservoir; in that case, the
initial viscosity
is greater than about 20 mPa-s at a shear rate 100 s-1 (with a preferred range
of
from about 20 to about 100 mPa-s at a shear rate of 100 s-) and the final
viscosity is greater than about 50 mPa-s, preferably from about 100 to about
1000 mPa-s, at a shear rate of 100 s-' under ambient conditions. The volume
of stage C is generally smaller than the volumes of the other stages of the
treatment. The ratio of the volumes of fluid in stage C to fluid in stage B is
less
than about 1/10, preferably from about 1/100 to about 1/10. The upper limit of
the total volume of fluid in stage C of each treatment cycle (before treatment
redirection to another wellbore interval) is about 64 m3 (400 bbl); as little
as
about 10 m3 of fluid may be used. Fluid C optionally contains a fiber, for
example a degradable fiber, and/or a proppant. The preferred proppant size is
from about 0.05 mm to about 1 mm (preferably from about 0.2 to about 0.4 mm;
the preferred proppant concentration is from about 0.012 to about 0.6 kg added
per liter of clean fluid (most preferably from about 0.024 to about 0.24 kg
per
liter of clean fluid).
A particularly suitable method of pumping a low viscosity fluid Stage C
and then having the viscosity of the fluid increase in a carbonate-containing
reservoir, for example a carbonate-containing shale, is the use of an acidic
fluid
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that undergoes an increase in viscosity when the pH is raised, for example by
contact with the reservoir rock. Many such systems are known for use in
acidizing and acid fracturing; they are commonly called self-diverting acids
and
when based on viscoelastic surfactants they are called viscoelastic diverting
acids. In the present invention, they are used to divert slickwater. Examples
are those based on viscoelastic surfactants, for example certain betaines.
Suitable viscosifiers and systems are described in U. S. Patent Nos.
6,399,546;
6,667,280; 6,903,054; 7,119,050; 7,148,184; 7,380,602; and 7,666,821. In
addition to diversion, the use of such self-diverting acids in the present
invention
can further enhance the complexity of fracture networks by introducing
heterogeneity by etching the formation and reducing the fracture initiation
pressure, and also by selective dissolution of scales, that have usually
accumulated in the natural fractures/fissures/fabric of a reservoir.
Stage C may also contain fibers, preferably having a diameter of from
about 1 to about 100 microns (more preferably from about 10 to about 30
microns) and a length of from about 1 to about 50 mm (preferably from about 3
to about 35 mm) at a concentration of from about 0 to about 60 g per liter of
clean fluid, (preferably about 1.2 to about 16 g per liter of clean fluid).
Substantially proppant free fluid is defined here as a fluid having a
loading of proppant less than about 0.024 kg per liter of clean fluid. The
viscous
fluid is intended and therefore designed to divert, not to carry proppant or
fiber.
Stage C fluids are substantially proppant free.
Pumping of the viscosified fluid increases the net pressure in the fracture,
which temporarily decreases fluid flow in a portion of the primary fracture
and
induces the formation of side fractures along the primary fracture. This
temporary pressure increase can also reversibly increase the fracture width,
decreasing the probability of proppant bridging in the fracture. As the
viscosified fluid has a density close to that of the slickwater itself, the
fluid slugs
can be transported into a fracture network system without any of the problems
associated with slug settling (see Example 1).
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II
Fluids A and B are preferably selected from fresh water, brine, seawater,
solutions of polymers, solutions of viscoelastic surfactants, gelled oils,
viscosified diesel fuels, emulsions and mixtures of such fluids. Fluid C is
preferably chosen from solutions of polymers, gels, cross-linked gels,
solutions
of viscoelastic surfactants, gelled oils, viscosified diesel fuels, and
emulsions.
These viscosifiers are preferably degradable. Preferred polymers include guar
gum, gum arabic, gum karaya, tamarind gum, locust bean gum, cellulose,
xanthan, scleroglucan, polyacrylamide, polyacrylate, combinations of these
materials, and modified, substituted or derivatized versions of these
polymers.
The polymers in the fluids may be crosslinked, for example by compounds of
boron, aluminum, titanium, zirconium, chromium, iron, copper, zinc, antimony,
organic or inorganic polyions and combination of these materials. The fluids
may optionally contain crosslink delay agents or gel or polymer breakers, for
example encapsulated gel breakers, internal delayed gel breakers, temperature-
activated gel breakers and combination of these. The proppant in fluid B, and
optionally in fluid C, preferably is selected from sands, ceramics, glasses,
rocks
and minerals such as mica, organic and inorganic polymers, metals and alloys,
composite materials and mixtures of these materials. These proppants
preferably have shapes selected from spheres, rods, cylinders, plates, sheets,
spherocylinders, ellipsoids, toruses, oblongs, fibers, meshes, arches/cells,
meshes/cells, honeycombs, bubbles, sponge-like or foam structures, and
mixtures of these shapes. "Arches/cells" and "meshes/cells" are special three-
dimensional organizations of materials, for example reticulated foamed
polyurethane. Such materials have a three-dimensional bubble structure
consisting, for example, of dodecahedrons, each face of which is a pentagon.
The pentagons are formed by edges between which there is a membrane or
window. At least one membrane is always missing, thus forming an open pore
structure. Viscosifiers and proppants and methods of preparing these fluids
are
all known in the art.
The proppant in fluids B, and optionally C, preferably is in a size range of
from about 5 to about 1000 microns, most preferably from about 50 to about
840 microns. These proppants may optionally be coated or may have an
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organophilic treatment. Fluid B preferably carries at least about 90 weight
percent of the proppant in stages B and C.
The fluids of stages B and C may optionally also contain degradable
materials, for example fibers, plates, flakes, beads and combinations of these
materials. The degradable materials are chosen, for example, from polylactic
acid, polyglycolic acid, copolymers of polylactic acid and polyglycolic acid,
copolymers of glycolic acid with other hydroxy-, carboxylic acid-, or
hydroxycarboxylic acid-containing moieties, copolymers of lactic acid with
other
hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing moieties, and
mixtures of these materials.
Any of the fluids, in particular the fluids used in stages C, may be foamed
or energized.
The fracture systems formed with water fracs in heterogeneous
reservoirs are often believed to have complex and branched structures with
many intersecting natural fractures, with changes in fracture direction (see
Figure 1C). However, the viscosified fluids and methods used in the present
invention plug the existing fractures at a considerable distance from the
wellbore; this depends on fluid viscosity which in turn may be controlled by a
delay agent. By varying the delay time, an operator can control the distance
from the wellbore at which the plugging occurs. The plug formed drastically
increases the pressure and induces creation of new fractures connected to the
same fracture network, growing in other directions, stimulating previously non-
treated zones (see Example 2).
Stages A (optionally) and B are repeated after each diversion (stage C)
to create new fracture(s) and fracture networks. Each pumping of at least a
stage B and a stage C (in either order) is called a cycle; each cycle contains
at
least stages B and C; the entire treatment starts with a stage A. The cycles,
for
example ABC-ABC (preferred), ABC-BC, ABC-BC-BC, ACB-CB-CB, ABC-BAC
-BC, or ABC-BC-ABC-BC, etc., are repeated as many times as necessary to
develop the fracture network desired. The ratio of the volumes, in any cycle,
of
fluid in stage C to fluid in stage B is less than about 1/10, preferably from
about
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1/100 to about 1/10. The upper limit of the total volume of fluid in stage C
of
each treatment cycle (before treatment redirection to another wellbore
interval)
is about 64 m3 (400 bbl); as little as about 10 m3 of fluid may be used. Any
cycle may optionally include a stage A and optionally may be followed by a
stage D, in which a gel with coarse (for example from about 0.4 to about 1 mm
(preferably from about 0.42 to about 0.84 mm)) proppant is pumped to prop the
primary fracture and to ensure that it has a high conductivity. Any stage D is
optionally followed with a stage E, pumping of a proppant flowback control
agent, e.g. resin-coated proppant or any other proppant control agent known
from the art, such as fibers, and finally with an optional flush, stage F.
Water,
brine, or a fluid that is the same as or similar to the fluid of any stage A
may be
used for the flush; the flush is usually about the volume of the wellbore from
the
wellhead to the top or bottom of the perforated interval being treated
(increased
or decreased by from about 3 to about 100 bbl (about 18 to about 65 m) . The
fluid of any stage D has a viscosity of about 1 to about 1000 mPa=s at a shear
rate of 100 s-'; the fluid of any stage E has a viscosity of about 1 to about
50
mPa-s at a shear rate of 100 s-'.
The fluid of each stage A, stage B, stage C, stage D, or stage E need not
be identical to the fluid of any other stage A, stage B, stage C, stage D, or
stage
E. After the end of the treatment and fracture closure, the fluid plugs
created by
stage(s) C for diversion degrade naturally or are destroyed with oxidative or
other types of breakers, which reduce the fluid viscosity. This opens the
originally fractured regions of the reservoir and provides hydrocarbon or
other
fluid transport to the wellbore, enhancing production.
The examples below illustrate the transportability of a viscosified fluid in a
slickwater fluid having a similar density (Example 1); plugging of a manifold
system (which simulates a complex fracture network) with a slug of viscosified
fluid (Example 2); and degradation of the plug over time in the presence of an
oxidative breaker (Example 3). The examples are presented for the purpose of
illustrating the preferred embodiments of the invention and do not constitute
any
limitations to the scope of the invention.
Example 1:
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A fluid slug prepared from a borate cross-linked guar gel, having a guar
concentration of 6 g/L (50 lb/1000 gal) was placed in a Plexiglas settling
slot
with dimensions 1000 x 300 x 4 mm, above a slug of similar-density slickwater
containing 0.05 weight percent of a polyacrylamide friction reducer. No slug
diffusion during the experimental time of 4 hours at room temperature was
observed. The viscous slug remained consolidated and floated on the
slickwater slug without settling.
Example 2:
The behavior of a viscous slug being transported in a long horizontal pipe
was studied. A laminar fluid flow regime was tested. These data can be used
to evaluate slug transport inside a fracture. In order to investigate slug
transport
dependencies, a special set-up was constructed. It consisted of a clear
plastic
water pipe (35 m in length and 18 mm ID), systems for injection of the viscous
slug and of a base fluid, a water pump, and two photo sensors (one at the
beginning and one at the end of the pipe) to determine the length of the
viscous
slug, and a data acquisition system. A special loop was used for injection of
slugs of the viscous fluid. A viscous slug of a desired composition was loaded
into the slug injection loop before the experiment and was isolated from the
main line by valves. Base fluid was pumped through the pipe for several
minutes until the base fluid flow stabilized. Once flow stabilization was
attained,
the flow was directed into the slug sample injection loop and a viscous slug
was
pumped into the system.
Viscous fluid slugs were prepared from a borate cross-linked guar gel
having a guar concentration of 6 g/L (50 lb/1000 gal) and dyed with
phenolphthalein for visualization; a base fluid, slickwater, containing 0.05
wt %
of a polyacrylamide friction reducer was used. The slickwater and viscous
fluid
slugs were pumped and slug stretching during transport inside the tube was
studied. The flow rate of the slickwater was 8.1 L/min, which corresponds to a
linear velocity of 43.6 cm/sec. The experiment showed that the average viscous
fluid slug velocities were 42 cm/sec. The difference between the base fluid
and
the viscous slug velocities was caused by a fingering effect in which the
denser
and more viscous fluid was transported with a lower rate relative to the base
CA 02799555 2012-11-14
WO 2011/145966 PCT/RU2010/000248
fluid velocity. The initial slug lengths injected were 215 20 cm. The final
slug
lengths at the end of the tube were 250 24 cm. No significant slug stretching
during transportation inside the tube was observed when the flow was laminar.
This experiments shows that it is possible to transport slugs of viscous
fluids
inside a fracture; the slugs were not significantly dispersed under conditions
that
mimic the flow conditions inside a fracture.
Example 3:
A manifold [3] as shown in Figure 2 was built using Swagelok tubes with
outer diameters varying from 6.35 mm (0.25 in) down to 1.59 mm (1/16 in).
Figure 3 shows the test results in which the pressure inside the tube was
plotted
against time. The same slickwater as used in Examples 1 and 2 was pumped
through the manifold with a Knauer pump [1] at 0.5 I/min flow rate with
pressures generally not exceeding 138 kPa (20 psi). Slugs of the crosslinked
gel used in Examples 1 and 2 were then placed in the slurry tank [2] and the
pressure was followed during pumping; the pressure increased up to 1007 kPa
(146 psi), at which pressure the pressure relief rapture disk [4] broke. The
manifold system emulates a complex fracture network during the diversion
stage, and the rupture disk break mimics fracturing of a non-stimulated zone
of
the reservoir due to the net pressure increase.
