U.S. patent application number 13/861021 was filed with the patent office on 2014-01-16 for method of increasing the permeability of a subterranean formation by creating a multiple fracture network.
This patent application is currently assigned to BAKER HUGHES INCORPORATED. The applicant listed for this patent is James B. Crews, Tianping Huang. Invention is credited to James B. Crews, Tianping Huang.
Application Number | 20140014338 13/861021 |
Document ID | / |
Family ID | 49328283 |
Filed Date | 2014-01-16 |
United States Patent
Application |
20140014338 |
Kind Code |
A1 |
Crews; James B. ; et
al. |
January 16, 2014 |
Method of Increasing the Permeability of a Subterranean Formation
by Creating a Multiple Fracture Network
Abstract
The stimulated rock volume (SRV) of a subterranean formation may
be increased by pumping viscous fracturing fluid into the formation
in a first stage to create or enlarge a primary fracture,
decreasing the pumping in order for the fluid to increase in
viscosity within the primary fracture, and then continuing to pump
viscous fluid into the formation in a second stage. The fluid
pumped into the second stage is diverted away from the primary
fracture and a secondary fracture is created. The directional
orientation of the secondary fracture is distinct from the
directional orientation of the primary fracture. The fluid of the
first stage may contain a viscosifying polymer or viscoelastic
surfactant or may be slickwater.
Inventors: |
Crews; James B.; (Willis,
TX) ; Huang; Tianping; (Spring, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Crews; James B.
Huang; Tianping |
Willis
Spring |
TX
TX |
US
US |
|
|
Assignee: |
BAKER HUGHES INCORPORATED
Houston
TX
|
Family ID: |
49328283 |
Appl. No.: |
13/861021 |
Filed: |
April 11, 2013 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61623515 |
Apr 12, 2012 |
|
|
|
Current U.S.
Class: |
166/280.1 ;
166/308.1 |
Current CPC
Class: |
E21B 43/26 20130101;
C09K 2208/26 20130101; C09K 8/685 20130101; C09K 8/885 20130101;
E21B 43/267 20130101; C09K 8/605 20130101; C09K 2208/30
20130101 |
Class at
Publication: |
166/280.1 ;
166/308.1 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/267 20060101 E21B043/267 |
Claims
1. A method for improving the recovery of hydrocarbons from a
subterranean reservoir having a permeability less than 0.1 mD which
comprises: (a) pumping a fluid into the subterranean reservoir at a
pressure sufficient to enlarge or create a primary fracture,
wherein the fluid has a viscosity greater than about 10,000 cP at a
shear rate of 0.01 sec.sup.-1 and further wherein the fluid
contains a viscoelastic surfactant and/or a viscosifying polymer;
(b) stopping the pumping when the viscous fluid is within the
enlarged or created primary fracture; (c) pumping additional fluid
having a viscosity greater than about 10,000 cP at a shear rate of
0.01 sec.sup.-1 into the subterranean reservoir at a pressure
sufficient to create at least one secondary fracture, wherein the
least one secondary fracture is has a directional orientation
distinct from the directional orientation of the primary fracture;
and (d) diverting the flow of the additional fluid of step (c) into
the at least one secondary fracture.
2. The method of claim 1, further comprising: (e) stopping the
pumping of the additional fluid; and further wherein steps (c), (d)
and (e) are continuously repeated for a time sufficient to create a
multiple fracture network consisting of the primary fracture and a
multitude of secondary fractures.
3. The method of claim 1, wherein the viscosity of the viscous
fluid is between from about 10,000 cP to about 2,000,000 cP at a
shear rate of 0.01 sec.sup.-1.
4. The method of claim 3, wherein the viscosity of the viscous
fluid of step (a) and the additional fluid of step (c) is the
same.
5. The method of claim 2, wherein the additional fluid of step (c)
is the same for each repetition of step (c).
6. The method of claim 2, wherein the additional fluid of step (c)
is the same as the viscous fluid of step (a).
7. The method of claim 1, wherein the viscous fluid of step (a)
enlarges a created primary fracture and further wherein a pad fluid
is pumped into the subterranean reservoir prior to step (a) in
order to initiate the primary fracture.
8. The method of claim 1, wherein the viscous fluid of step (a)
and/or the additional fluid of step (c) contains a viscoelastic
surfactant as viscosifying agent.
9. The method of claim 8, wherein the viscous fluid further
contains an internal breaker.
10. The method of claim 8, wherein the viscous fluid further
contains a low shear rate viscosity enhancer.
11. The method of claim 10, wherein the viscosity enhancer is a
wormlike micelle associative agent.
12. The method of claim 1, wherein the viscous fluid of step (a)
and/or the additional fluid of step (c) contains proppants.
13. The method of claim 1, wherein the viscous fluid of step (a)
and/or the additional fluid of step (c) contains a polymeric
viscosifying agent.
14. The method of claim 13, wherein the viscous fluid and/or
additional fluid, in addition to containing a polymeric
viscosifying agent, further contains a crosslinking agent.
15. The method of claim 13, wherein the amount of polymeric
viscosifying agent in the viscous fluid is less than or equal to 6%
by weight.
16. The method of claim 1, wherein the pressure in step (a) and
step (c) is approximately the same.
17. The method of claim 1, wherein the pressure in step (c) is
greater than the pressure in step (a).
18. The method of claim 1, wherein the injection rate of the
additional fluid pumped into the subterranean reservoir in step (c)
is greater than the injection rate of the viscous fluid pumped into
the subterranean reservoir in step (a).
19. A method of fracturing a subterranean formation penetrated by a
wellbore by creating a network of fractures at near-wellbore and
far-wellbore locations wherein the subterranean formation has a
permeability less than 0.1 mD, the method comprising the following
sequential steps: (a) injecting into the subterranean reservoir a
fracturing fluid having a viscosity greater than about 10,000 cp at
a shear rate of 0.01 sec.sup.-1 at a pressure sufficient to enlarge
or create a primary fracture; (b) decreasing the rate of injection
of the fracturing fluid for a time sufficient for the viscosity of
the fracturing fluid to increase within the created or enlarged
fracture; (c) injecting additional fracturing fluid into the
subterranean reservoir to create one or more secondary fractures,
wherein the additional fracturing fluid diverts away from the
primary fracture and into the one or more secondary fractures; (d)
repeating steps (b) and (c) at least twice; and (e) forming a
network of secondary fractures at near-wellbore and far-wellbore
locations from the primary fracture and the secondary
fractures.
20. The method of claim 19, wherein at least one of the following
conditions prevail: (i) the rate of injection of the additional
fracturing fluid of step (c) is different from the rate of
injection of the fracturing fluid of step (a); (ii) the viscosity
of the additional fracturing fluid of step (c) is different from
the viscosity of the fracturing fluid of step (a); or (iii) the
amount of pressure used to inject the additional fracturing fluid
of step (c) is different from the pressure used to inject the
fracturing fluid of step (a).
21. The method of claim 19, wherein the fracturing fluid of step
(a) and/or the additional fracturing fluid of step (c) contains
proppants.
22. The method of claim 21, wherein the particle size of the
proppants in the fracturing fluid of step (a) is less than the
particle size of the proppants in the additional fracturing fluid
of step (c).
23. The method of claim 21, wherein the size of the proppants range
from 12 microns to 4 millimeters.
24. The method of claim 23, wherein the injection of the fracturing
fluid is stopped in step (b) for a time sufficient for the
viscosity of the fracturing fluid to increase within the created or
enlarged fracture.
25. A fracturing operation for recovering hydrocarbons from a
subterranean reservoir penetrated by a wellbore, wherein the
subterranean reservoir has a permeability less than 0.1 mD which
comprises: (a) pumping a fluid into the subterranean reservoir at a
pressure sufficient to enlarge or create a primary fracture in the
reservoir wherein the fluid has a viscosity greater than about
10,000 cP at a shear rate of 0.01 sec.sup.-1; (b) temporarily
stopping the pumping when the viscous fluid is within the primary
fracture; (c) resuming the pumping of the fluid; and (d) diverting
the flow of the fluid pumped in step (c) away from the primary
fracture to create one or more secondary fractures in the
subterranean reservoir.
26. The method of claim 25, further comprising continuously
repeating steps (a), (b), (c) and (d).
27. The method of claim 25, wherein the fracture growth of the
total surface area connected to the wellbore after step (d) is
greater than the total surface area connected to the wellbore after
step (a).
28. The method of claim 25, wherein the viscosity of the fluid
and/or pumping pressure of the fluid in steps (a) and (c) is the
same.
29. The method of claim 25, wherein the viscosity of the fluid
and/or pumping pressure of the fluid in step (a) is greater than
the viscosity of the fluid in step (c).
30. The method of claim 25, wherein the viscosity and/or pressure
of the fluid in each of repeating steps (a) and (c) in the
fracturing operation decreases with each repetition.
31. The method of claim 25, wherein the viscosity and/or pressure
of the fluid in step (a) is less than the viscosity of the fluid in
step (c).
32. The method of claim 26, wherein the viscosity and/or pressure
of the fluid in each of repeating steps (a) and (c) in the
fracturing operation increases with each repetition.
33. The method of claim 25, wherein the fluid pumped into the
wellbore contains a viscosifying polymer.
34. The method of claim 25, wherein prior to pumping of the pad
fluid, a slickwater fluid having a viscosity less than or equal to
15 cP at a shear rate of 300 sec.sup.-1 is pumped into the
subterranean reservoir.
35. The method of claim 34, wherein the amount of slickwater fluid
is between from 10 to 60 volume percent of the combination of
slickwater fluid, pad fluid and viscous fluid.
Description
[0001] This application claims the benefit of U.S. Patent
Application Ser. No. 61/623,515, filed on Apr. 12, 2012.
FIELD OF THE DISCLOSURE
[0002] A complex network of fractures may be created within a
subterranean formation by pumping fracturing fluid into the
formation in discrete stages. The stimulated rock volume (SRV) of
the formation is increased by developing an extended area for
migration of the fracturing fluid within the formation.
BACKGROUND OF THE DISCLOSURE
[0003] Hydraulic fracturing is widely used to create
high-conductivity communication with a large area of a subterranean
formation, thereby allowing for an increased rate of oil and gas
production. The stimulation process enhances the permeability of
the formation in order that entrapped oil or gas may be
produced.
[0004] During hydraulic fracturing of low permeability formations
(i.e. such as less than 1.0 md), a fracturing fluid is pumped at
high pressures and at high rates into the wellbore penetrating the
subterranean formation. During the process, fractures may be
created and enlarged that increase the amount of fracture surface
area. The efficiency of the process of increasing surface area is
often measured by stimulated rock volume (SRV) of the
formation.
[0005] The fluid used to initiate hydraulic fractures from the
wellbore is often referred to as the "pad". In some instances, the
pad may initially contain a heavy density fine particulate, such as
fine mesh sand, for fluid loss control. In other instances, the pad
may contain larger grain sand in order to abrade perforations or
near-wellbore tortuosity.
[0006] Once the fracture in the reservoir is initiated, subsequent
stages of viscous fluid containing chemical agents, such as
proppants, may be pumped to further create and extend the primary
(i.e. biwing) fracture. The fracture generally continues to grow
during pumping and the proppants remain in the fracture in the form
of a permeable "pack" that serves to "prop" the fracture open. Once
the treatment is completed, the fracture closes onto the proppants.
The fracturing fluid ultimately causes an increase in the leak-off
rate of the fluid through the faces of fractures which improves the
ability of the proppant to pack within the fracture. The proppants
maintain the fracture open, providing a highly conductive pathway
for hydrocarbons and/or other formation fluids to flow into the
wellbore.
[0007] The treatment design of a hydraulic fracturing operation
generally requires the fracturing fluid to reach maximum viscosity
as it enters the fracture. The viscosity of the fluid affects
fracture length and width of the primary fracture and the amount of
secondary fractures formed (i.e. typically creates less complex
fracture network).
[0008] The viscosity of most fracturing fluids may be attributable
to the presence of a viscosifying agent, such as a viscoelastic
surfactant or a viscosifying polymer. An important attribute of any
fracturing fluid is its ability to exhibit reduced viscosity after
injection. Typically, fracturing fluids contain breakers which are
used to reduce viscosity.
[0009] Conventional viscosifying polymers include such
water-soluble polysaccharides, such as galactomannans and cellulose
derivatives. Further enhancement of fracturing fluid viscosity may
be obtained by treating polymeric solutions with cross-linking
agents, typically selected from titanium, aluminum, boron and
zirconium based compounds, or mixtures thereof. Organometallic
compounds are often used as a crosslinking agent in these polymer
gels. After the viscosity of the fluid has been reduced, removal of
the polymer is often difficult, often times resulting in residual
polymer being left on the face of the formation and within the
proppant pack. This causes clogging of the pores of the formation
and proppant pack. Hydrocarbons may therefore be prevented from
flowing freely through and from the formation and proppant
pack.
[0010] The use of non-polymeric treatment fluids, such as those
containing viscoelastic surfactants, has increased in recent years
since such fluids typically exhibit the ability to transport
proppant at lower viscosities than polymer-based treatment fluids.
In addition, the amount of friction between the surfactant-based
treatment fluid and the surfaces contacted by the fluid is often
reduced. Further, since such fluids do not contain polymers, use of
internal breakers typically rearrange the viscous VES-micelles into
non-viscous spherical micelles in brine and the fluid is typically
not obstructed as it passes through the pore throats of the
formation and proppant pack.
[0011] More recently, low viscosity fluids known as slickwater have
been used in the stimulation of low permeability or "tight"
formations, including tight gas shale reservoirs. Such reservoirs
may contain natural fractures or weaker stress planes that may
contribute to a higher number of fractures (i.e. fracture network)
during a hydraulic fracturing treatment.
[0012] Slickwater fluids typically do not contain a viscoelastic
surfactant or viscosifying polymer but do contain a sufficient
amount of a friction reducing agent to minimize tubular friction
pressures. Such fluids, generally, have viscosities only slightly
higher than unadulterated fresh water or brine. Typically, the
presence of the friction reduction agent in slickwater does not
increase the viscosity of the fluid by more than 1 to 2 centipoise
(cP).
[0013] To effectively access hydrocarbons in tight formations,
wells are often drilled horizontally and then subjected to one or
more fracture treatments to stimulate production. Fractures
propagated with low viscosity fluids exhibit smaller fracture
widths than those propagated with higher viscosity fluids. In
addition, low viscosity fluids facilitate reduced fracture height
growth in the reservoir during stimulation. This often results in
the development of greater created fracture area from which
hydrocarbons may flow into. Further, such fluids introduce less
damage into the formation in light of the absence of viscosifying
polymer and/or viscoelastic surfactant in the fluid.
[0014] Slickwater fluids often contain proppants. In light of the
low viscosity of the fluid, the proppant-carrying capacity of the
fluid is low. A lower concentration of proppant requires a higher
volume of fracturing fluid to place a sufficient amount of the
proppant into the induced fractures.
[0015] Slickwater fracturing operations typically proceed by the
continuous injection of slickwater into the wellbore. In some shale
formations, an excessively long primary fracture often results
along the minimum stress orientation. Typically, pumping of
additional fracturing fluid into the wellbore simply extends the
planar fracture. In most instances, primary fractures dominate and
secondary fractures are limited. Fracturing treatments which create
predominately long planar fractures are characterized by a low
surface area, i.e., low SRV. Production of hydrocarbons from the
fracturing network created by such treatments is limited by the low
SRV.
[0016] Slickwater fracturing more commonly in shale formations
create complex fracture networks near the wellbore and are
generally considered to be inefficient in the opening or creation
of complex network of fractures farther away from the wellbore.
Lately, slickwater fracturing operations have been seen to be
successful in producing hydrocarbons from shale. However, the
secondary fractures created by the operation are near to the
wellbore where the surface area is increased. While SRV is
increased in slickwater fracturing, production is high only
initially and then drops rapidly to a lower sustained production
since there is little access to hydrocarbons far field from the
wellbore.
[0017] Like slickwater fracturing, conventional fracturing
operations typically render an undesirably lengthy primary
fracture. While slightly more secondary fractures may be created
farther from the wellbore using viscous fluids versus slickwater,
fluid inefficiency, principally exhibited by a reduced number of
secondary fractures generated near the wellbore, is common in
conventional hydraulic fracturing operations.
[0018] Recently, attention has been directed to alternatives for
increasing the productivity of hydrocarbons far field from the
wellbore as well as near wellbore. Particular attention has been
focused on increasing the productivity of low permeability
formations, including shale. For instance, methods have been
tailored to the stimulation of discrete intervals along the
horizontal wellbore resulting in perforation clusters. While the
SRV of the formation is increased by such methods, production areas
between the clusters are often not affected by the operation. This
decreases the efficiency of the stimulation operation. Methods of
increasing the SRV by increasing the distribution of the area
subjected to fracturing have therefore been sought.
SUMMARY OF THE DISCLOSURE
[0019] The stimulated rock volume (SRV) of a subterranean formation
subjected to a hydraulic fracturing treatment may be increased by
pumping the fracturing fluid into stages to provide a wider
distribution fracturing pattern and an extended area for migration
of the fluid. The method uses a high shear thinning fluid, i.e., a
fluid having high viscosity at low shear rates, which may be
diverted into secondary fractures. The viscosity of the fluid is
typically greater than about 10,000 cP at a shear rate of 0.01
sec.sup.-1.
[0020] The permeability of the subterranean reservoir subjected to
the treatment may be less than or equal to 1.0 mD.
[0021] In an embodiment, a first stage containing a viscous fluid
is pumped into the wellbore to enlarge the fracture. Pumping is
then reduced or curtailed for a period of time for the viscosity of
the injected fluid to increase within the fracture. Pumping is then
resumed after the injected fluid is sufficiently viscous.
[0022] In one embodiment, a first stage consists of injecting into
the wellbore a fluid containing a viscoelastic surfactant, a
viscosifying polymer or both viscoelastic surfactant and
viscosifying polymer at a pressure sufficient to enlarge or create
a primary fracture. Pumping may then be reduced or stopped when the
viscous fluid is within the enlarged or created primary fracture.
The second stage of the operation consists of injecting into the
wellbore a second fluid at a pressure sufficient to create at least
one secondary fracture wherein the directional orientation of the
secondary fracture is distinct from the directional orientation of
the primary fracture. The total surface area of the fractured area
is increased which provides an increase to the SRV. The flow of the
second fluid is diverted into the secondary fracture due to
resistance of the first fluid to flow or movement due to exhibiting
very high viscosity at low shear rate. The diversion of the primary
flow process is contrary to the continued high rate flow of viscous
fluids in planar fractures. The fluid of the first stage and the
fluid of the second stage may be the same or different.
[0023] In another embodiment, a multiple fracture network
consisting of a primary fracture and a multitude of secondary
fractures may be created by injecting into the wellbore in a first
stage a fluid containing a viscoelastic surfactant, a viscosifying
polymer or both viscoelastic surfactant and viscosifying polymer at
a pressure sufficient to enlarge or create a primary fracture.
Pumping of the fluid of the first stage may then be decreased or
curtailed when the viscous fluid is within the enlarged or created
primary fracture. The second stage of the operation consists of
injecting into the wellbore a second fluid at a pressure sufficient
to create at least one secondary fracture off the primary fracture.
The directional orientation of the secondary fracture is distinct
from the directional orientation of the primary fracture. A
multitude of fractures may be created by pumping one or more
additional stages into the wellbore. Each stage may be interrupted
for a time sufficient for the fluid of the preceding stage to flow
into the created or enlarged secondary fracture. A complex network
of secondary fractures may therefore be created off the primary
fracture and the SRV dramatically increased. The fluids of the
first stage, the second stage and the additional stages may or may
not be the same fluid.
[0024] The combination of the low shear high viscosity
shear-thinning fluid and the multi-stage process wherein pumping of
fracturing fluid is reduced or curtailed between stages provides
for controlled placement of the fluid into the primary fracture. As
such, the flow of the fluid of the first stage may be controlled
such that it doesn't advance too far from the wellbore and yet does
not remain within the immediate vicinity of the near wellbore.
[0025] In addition to varying the rate of pumping of the fluids of
the stages, the network of fractures may be created and placement
of the fluid may be controlled by varying the amount of pressure
during injection of the fluid stages into the wellbore, varying the
rate of injection of the fracturing fluid between the stages or
varying the viscosity of the fracturing fluid between the stages.
Any combination may further be used. Thus, for instance, a
fracturing operation may proceed wherein one or more stages differ
by (i) the amount of pressure during injection of the fluid into
the wellbore; (ii) the rate of injection of pumping the stage fluid
into the wellbore; (iii) the viscosity of the fluid introduced into
the wellbore; or (iv) a combination of (i), (ii) and (iii).
Further, any of these combinations may be used in conjunction with
the procedure wherein reduced or curtailed pumping of the viscous
fluid occurs between the pumping of viscous stages.
[0026] An illustrative embodiment of the disclosure may consist of
developing a network of fractures at near-wellbore and far-wellbore
locations within a subterranean formation by first injecting into
the reservoir a fracturing fluid having a viscosity greater than
about 10,000 cp at a shear rate of 0.01 sec.sup.-1 at a pressure
sufficient to enlarge or create a primary fracture. The rate of
injection may then be decreased for a sufficient time in order to
increase the viscosity of the fluid within the created or enlarged
fracture, particularly the portion of the fluid further from the
wellbore that has less shear (e.g. flow) rate as fracture length
increases. Additional fracturing fluid may then be injected into
the reservoir at a rate different than the rate of the preceding
stage to create one or more secondary fractures. The additional
fracturing fluid diverts away from the primary fracture and into
the created secondary fracture due to the viscosity property of the
first fluid to resist flow to the force applied. These steps may
then be repeated wherein each repetitive stage has a rate of
injection of fluid distinct from the rate of injection of a
previous stage to form a network of secondary fractures at
near-wellbore and far-wellbore locations from the primary fracture
and the secondary fractures.
[0027] In another illustrative embodiment, a network of fractures
at near-wellbore and far-wellbore locations may be created within a
subterranean formation by first injecting into the reservoir a
fracturing fluid having a viscosity greater than about 10,000 cp at
a shear rate of 0.01 sec.sup.-1 at a pressure sufficient to enlarge
or create a primary fracture. The pressure may then be decreased
for a sufficient time in order to increase the viscosity of the
fluid within the created or enlarged fracture. Additional
fracturing fluid may then be injected into the reservoir to create
one or more secondary fractures at a higher or lower pressure than
the pressure used in the injection of the preceding stage. The
additional fracturing fluid diverts away from the primary fracture
and into the created secondary fracture. These steps may then be
repeated wherein the pressure of injection of each stage may be
distinct from the pressure of another stage to form a network of
secondary fractures at near-wellbore and far-wellbore locations
from the primary fracture and the secondary fractures.
[0028] In another illustrative embodiment, a network of fractures
at near-wellbore and far-wellbore locations may be created within a
subterranean formation by first injecting into the reservoir a
fracturing fluid having a viscosity greater than about 10,000 cp at
a shear rate of 0.01 sec.sup.-1 at a pressure sufficient to enlarge
or create a primary fracture. The rate of injection may then be
decreased for a sufficient time in order to increase the viscosity
of the fluid within the created or enlarged fracture. Additional
fracturing fluid having a viscosity greater or less than the
viscosity of the fluid of the preceding stage may then be injected
into the reservoir to create one or more secondary fractures. The
additional fracturing fluid diverts away from the primary fracture
and into the created secondary fracture. These steps may then be
repeated wherein the viscosity of each of the additional stages is
distinct from the viscosity of the fluid of another stage to form a
network of secondary fractures at near-wellbore and far-wellbore
locations from the primary fracture and the secondary
fractures.
[0029] In another embodiment, a network of fractures at
near-wellbore and far-wellbore locations may be created within a
subterranean formation by first pumping into the reservoir
slickwater fluid having a viscosity greater than about 15 cP at a
shear rate of 300 sec.sup.-1 at a pressure sufficient to enlarge or
create a primary fracture. A viscous fluid having a viscosity
greater than about 10,000 cP at a shear rate of 0.01 sec.sup.-1 may
then be pumped behind the slickwater fluid and the primary fracture
extended. Pumping of the viscous fluid may be decreased or stopped
for a period of time for the viscosity of the fracturing fluid to
increase within the primary fracture. Slickwater having a viscosity
greater than about 15 cP at a shear rate of 300 sec.sup.-1 may then
be pumped into the reservoir to divert the viscous fluid away from
the primary fracture and to create one or more secondary fractures.
A viscous fluid having a viscosity greater than about 10,000 cP at
a shear rate of 0.01 sec.sup.-1 may then be pumped behind the
slickwater fluid to extend the secondary fracture(s). The flow of
the fluid pumped behind the slickwater fluid is then diverted away
from the primary fracture into the secondary fracture(s). This
process may be repeated in order to create a wider distribution of
secondary fractures.
[0030] In any of the methodologies, the amount of viscosifying
agent in the viscous fluid may be less than or equal to 6% by
weight.
[0031] Further, in any of the methodologies, the viscous fluid of
any of the stages may contain a low shear rate viscosity enhancer,
such as a wormlike micelle associative agent.
BRIEF DESCRIPTION OF THE DRAWINGS
[0032] In order to more fully understand the drawings referred to
in the detailed description of the present disclosure, a brief
description of each drawing is presented, in which:
[0033] FIG. 1A illustrates the fracturing network created by the
prior art method wherein slickwater fracturing fluid is
continuously injected into the wellbore.
[0034] FIG. 1B illustrates the fracturing network created by the
prior art method wherein a viscous fluid is continuously injected
into the wellbore.
[0035] FIG. 1C illustrates a complex network of multiple secondary
fractures created from near wellbore to far-field by use of the
method described herein.
[0036] FIG. 2 illustrates the increase in production and the
improvement in stimulated reservoir volume (SRV) by use of the
method described herein.
[0037] FIG. 3 illustrates the 2 sec.sup.-1 fluid viscosity after
being left static for about 30 minutes.
[0038] FIG. 4 profiles viscosity vs. shear rates and illustrates
the high viscosity at low shear rates exhibited by the fluids used
in the method described herein.
[0039] FIG. 5 illustrates the reduction in pressure required for
cleanup of a fracturing fluid used in the method described
herein.
[0040] FIG. 6 illustrates higher sustainable hydrocarbon production
rates attained by use of the method described herein when the
fracturing fluid contains proppants.
[0041] FIG. 7A illustrates the increased SRV in near wellbore
regions and far-field regions within the wellbore which results
from the method described herein in contrast to FIG. 7B.
[0042] FIG. 8 illustrates the reduction in fracturing areas which
are outside of intervals subjected to fracturing by use of the
method described herein.
DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS
[0043] Illustrative embodiments of the disclosure are described
below as they might be employed in the operation and treatment of
oilfield applications. In the interest of clarity, not all features
of an actual implementation are described in this specification. It
will of course be appreciated that in the development of any such
actual embodiment, numerous implementation-specific decisions must
be made to achieve the developers' specific goals, which will vary
from one implementation to another. Moreover, it will be
appreciated that such a development effort might be complex and
time-consuming, but may nevertheless be a routine undertaking for
those of ordinary skill in the art having the benefit of this
disclosure. Further aspects and advantages of the various
embodiments of the disclosure will become apparent from
consideration of the following description.
[0044] The production of hydrocarbons from a subterranean formation
is enhanced by the methods described herein. In addition to
increasing the effectiveness of the fracturing operation, the
methods described herein reduce intervention costs for remediation.
In particular, the methods described herein may minimize the need
for the removal of unwanted deposits by reducing accumulation and
deposition of residual polymer within the wellbore and formation.
Further, the methods described herein provide for a more efficient
use of on-the-fly equipment and materials. In particular, the
methods described herein provide a more efficient use of (i)
hydraulic horsepower to place fluid into the created fractures;
(ii) fracturing fluid by minimizing the volume of fracturing fluid
introduced into the wellbore; and (iii) proppant by reducing the
amount of proppant introduced into the reservoir while providing an
increase in proppant placement within the formation.
[0045] The methods described herein may be used in the fracturing
of formations penetrated by horizontal as well as vertical
wellbores.
[0046] The methods described herein provide for the creation of a
multiple network of fractures such that oil and/or gas may be
produced through the interconnected fractures. The first stage may
consist of injecting into the wellbore a pad fluid at a pressure
sufficient to either propagate or enlarge a primary fracture.
Fracture conductivity may be improved by the incorporation of a
small amount of proppant in the pad fluid. Typically, the amount of
proppant in the pad fluid is between from about 0.12 to about 24,
preferably between from about 0.6 to about 9.0, weight percent
based on the total weight percent of the pad fluid.
[0047] The fluid of the first or pad stage may be water or brine
and may contain a viscosifying agent such as a viscosifying polymer
and/or viscoelastic surfactant.
[0048] Alternatively, the fluid of the pad stage or the first stage
may contain slickwater. The viscosity of the fluid of the first
stage is typically greater than about 10,000 cP at a shear rate of
0.01 sec.sup.-1. The slickwater fluid typically contains a friction
reduction agent. Suitable friction reduction agents include
polyacrylamides, polyacrylates, as well as any of the viscoelastic
surfactants described herein. Typically, the amount of friction
reduction agent in the slickwater fluid is between from about 0.5
gpt to 2 gpt.
[0049] Following the injection of the pad fluid, a viscous fluid
may then be introduced into the wellbore. The viscous fluid
typically has a viscosity greater than about 10,000 cP at a shear
rate of 0.01 sec.sup.-1. The rate of pumping of the viscous fluid
is then reduced or stopped for a sufficient time to allow the
viscous fluid to increase viscosity within the fracture. This is to
curtail additional growth of the primary fracture. Thus, for
instance, if the primary fracture is desired to be limited to 500
feet, the volume of viscous fluid introduced into the wellbore may
be selected to provide the desired length of the primary fracture.
Reduction or suspension of the pumping causes the viscous fluid to
gel within the fracture, particularly near the tips of the fracture
where the fluid flow rate may be the slowest. In some cases, since
the fluid in the fracture is highly viscous at low shear rate or is
static (zero shear rate), increased pressure may be required in
order to move the entire section of fluid from the wellbore to the
fracture tip.
[0050] Additional fluid may then be injected into the wellbore as a
second fracturing stage. When pumping is resumed to the levels used
in the first fracturing stage, the additional fluid encounters a
"viscosity wall" or "viscosity wedge" of fluid within the primary
fracture. The force applied by the additional fluid will pressure
divert fluid flow away from the fracture tip and thus promote a
change in fracture orientation, thereby creating at least one
secondary fracture. The flow of this additional fluid is diverted
into the secondary fracture. The secondary fracture thus has a
directional orientation distinct from the directional orientation
of the primary fracture. Thus, at some point along the primary
fracture the resistance to flow of the viscosity wall induces the
second stage fluid to be diverted to a new area of the reservoir
such that the increase in SRV occurs.
[0051] Multiple fracturing stages may then follow. Such additional
stages will be referred to herein as the "successive stage" and the
"penultimate stage" to refer to the latter and next to latter
stages, respectively. For example, where three stages are employed
and when reference is made to the third and second stages, the
third stage may be referred to as the "successive stage" and the
second stage as the "penultimate stage." Where four stages are
employed and when referring to the fourth and third stages, the
fourth stage may be referred to as the "successive stage" and the
third stage may be referred to as the "penultimate stage," etc. The
successive stage may be pumped into the wellbore following a period
of time for the fluid of the penultimate stage to be diverted into
the created fracture which results from the penultimate stage. The
fracture created from the pumping of any penultimate stage shall be
referred to as a "secondary fracture".
[0052] Where a fracturing operation proceeds in multiple stages,
the pumping of fluid of a successive stage creates a secondary
fracture off of the fracture created by the penultimate stage. In
between each stage, pumping is stopped for a period sufficient for
fluid to divert into the secondary fracture. Each of the secondary
fractures created in the formation has a directional orientation
distinct from the directional orientation of the fracture from
which it extends. In other words, the fracture created from a
successive stage has a directional orientation distinct from that
of the fracture created from a penultimate stage.
[0053] Between any penultimate stage and successive stage, pumping
may be stopped and a pad fluid containing a proppant may be pumped
into the reservoir to assist in the creation or enlargement of
secondary fractures.
[0054] The methods described herein can be used to create a
multiple of fractures originating from the original primary
fracture wherein each successive stage creates a fracture having an
orientation distinct from the directional orientation of the
fracture created by the penultimate fracture.
[0055] The term "secondary successive fracture" as used herein
therefore refers to the fracture created in a successive fracturing
stage which has an orientation distinct from the directional
orientation of the fracture created in the penultimate stage. The
term "secondary penultimate fracture" as used herein refers to the
fracture created during a penultimate fracturing stage. Thus, where
three stages are employed and when referring to the fractures
created in the third and second stages, the fracture created from
the third stage may be referred to as the "secondary successive
fracture" and the fracture created by the second stage prior to the
successive stage as the "secondary penultimate fracture". Where
four stages are employed and when referring to the fourth and third
stages, the fracture created by the fourth stage may be referred to
as the "secondary successive fracture" and the fracture created by
the third stage may be referred to as the "secondary penultimate
fracture," etc. A successive stage may be pumped into the wellbore
following a period of time for the fluid of the penultimate stage
to be diverted into the secondary penultimate fracture.
[0056] The fracturing pattern generated by the method of the
disclosure may be illustrated in FIG. 1C which demonstrates that
excessive primary fracture length may be reduced and well spacing
tightened and optimized to maximize recovery and costs. This is in
contrast to FIG. 1B which represents the fracture pattern generated
by the fracturing operation of the prior art wherein an identical
fracturing fluid is used but wherein the rate of pumping between
fracturing stages is not reduced or curtailed.
[0057] In an embodiment of the disclosure, a network of fractures
are created at near-wellbore and far-wellbore by varying the rate
of injection of the fluid and/or the viscosity of the fluid and/or
the pressure during injection of the fluid for various stages. The
rate of injection of the fluid pumped into the formation for each
successive stage may be the same or different.
[0058] A reduction in injection rate may, for instance, be used to
allow the shear thinning fluid to build sufficient low shear rate
viscosity for adequate pressure diversion for the changing fracture
orientation created by the secondary fractures. In addition,
reduction in injection rate may contribute to the opening and
connecting of secondary fractures.
[0059] Stages of fracturing may be separated by periods wherein
pumping is reduced or stopped dramatically. In a first stage, fluid
is pumped into the wellbore which enters into a primary fracture.
The fluid of the second stage is diverted away from the primary
fracture and creates or enlarges a secondary fracture. After
pumping the first stage and prior to pumping the second stage,
pumping may be reduced by at least 80%. In an embodiment, pumping
between stages is shut down completely during this period. The
duration of the reduced pumping is sufficient to allow the fluid in
a first stage to be subjected to very low shear rates in the
reservoir, particularly the fluid near the tip of the fracture
which does not move as fast as the fluid at the wellbore during a
treatment. This substantially increases the apparent viscosity of
the fluid within the primary fracture. Upon resuming pumping, the
fluid introduced in the second stage encounters a viscous wall
within the fractured area created or enlarged by the first stage.
The stress placed on the reservoir by second stage fluid meeting
the viscosity wall causes the fluid of the second stage to be
diverted away from the primary fracture. Secondary fracture(s) are
thereby propagated and the SRV increases. Repeated stages may
follow wherein a penultimate stage is separated from the successive
stage by a period of reduced pumping.
[0060] The viscosity wall of the near-static fluid from the
penultimate stage enhances placement of fluid of a successive stage
into a secondary fracture. The fracture growth of the total surface
area connected to the wellbore after the fluid of the second stage
is pumped is greater than the total surface area connected to the
wellbore after the primary fracture is created or enlarged.
Likewise, the fracture growth of the total surface area connected
to the wellbore after the fluid of a successive stage is pumped is
greater than the total surface area connected to the wellbore after
a successive fracture is created or enlarged.
[0061] In another embodiment, the rate of injection of the fluid
between the first stage and the second stage or any penultimate
stage and successive stage may be varied. The change in the rate of
injection of the second fluid causes pressure diversion such that
the flow of the second fluid is diverted away from the primary
fracture. Likewise, the change in the rate of injection of fluid of
a successive stage causes pressure diversion such that the flow of
the fluid of the successive stage is diverted away from the
secondary penultimate fracture.
[0062] In another embodiment, the injection pressure of the fluid
of first stage and the injection pressure of the fluid of the
second stage or any penultimate stage and successive stage may be
varied. Increase of the injection pressure of the second stage
induces additional pressure diversion to force open a secondary
fracture. Thus, the change in the injection pressure of the second
fluid causes diversion such that the flow of the second fluid is
diverted away from the primary fracture. Likewise, the change in
injection pressure of the fluid of a successive stage causes
diversion such that the flow of the fluid of the successive stage
is diverted away from the secondary penultimate fracture.
[0063] In an embodiment of the disclosure, the fluid volume of the
fracturing stages may be set by an operator and the total volume of
the fluid may be broken into two or more stages. Each stage may be
separated by a period of reduced or suspended pumping for a
sufficient duration to allow the staged fluid in the reservoir to
flow into a created or enlarged fracture at very low shear
rates.
[0064] In another embodiment, the treatment operation may use a
constant viscosity of fluid for each stage or the viscosity may be
tapered from high viscosity in a first stage to low viscosity in a
second stage or low viscosity in a first stage to high viscosity in
a second stage. Alternatively, the viscosity may be tapered from a
low viscosity in a penultimate stage to high viscosity in a
successive stage or the viscosity may be tapered from high
viscosity in a penultimate stage to low viscosity in a successive
stage. Varying the viscosity improves the amount of proppant the
fluid may suspend. Proppant may therefore be placed deeper within
the reservoir. This, in turn, increases the net fracture
conductivity per treatment. This is in contrast to those prior art
treatment, such as water fracturing operations, which are unable to
carry high loadings of proppant and thus are ineffective at
placement of proppant into far-field regions of the reservoir.
[0065] The apparent fluid viscosity of the fluid therefore
increases. The fluid of each of the stages exhibits high viscosity
at low shear rates, such as below 1 sec.sup.-1. The fluid of each
of the stages may typically be between from about 1000 cP to about
2,000,000 cP at a shear rate of 0.01 sec.sup.-1.
[0066] A complex network of multiple secondary fractures may be
created from near wellbore to far-field regions by the methods
described herein. The length of the primary fracture is curtailed
and the depth of the network is increased in the near wellbore as
well as the far-field areas. In addition, the total amount of
opened and connected fractures to the wellbore is increased as well
as the depth distribution of the opened and connected fractures.
This provides for increased initial production near the wellbore
and sustained production of fluids near the wellbore and far field
from the wellbore, as illustrated in FIG. 2. FIG. 2 further
illustrates the increase in production resulting from the increased
surface area near wellbore and far field compared to a conventional
fracturing operation. The increase in surface area improves SRV and
provides a higher initial and sustained hydrocarbon production over
time.
[0067] As described, the multiple network of fractures may be
created by varying the rate of pumping of the fluids of the stages,
the rate of injection of the fracturing fluid between the stages or
varying the viscosity of the fracturing fluid between the stages or
any combination. In other words, a fracturing operation may proceed
wherein one or more stages differ by (i) the amount of pressure
during injection of the fluid into the wellbore; (ii) the rate of
injection of pumping the stage fluid into the wellbore; (iii) the
viscosity of the fluid introduced into the wellbore; or (iv) a
combination of (i), (ii) and (iii). Further, any of these
combinations may be used in conjunction with the procedure wherein
reduced or curtailed pumping of the viscous fluid occurs between
the pumping of viscous stages in order to obtain a network of
fractures at near-wellbore and far-wellbore locations.
[0068] In an embodiment, a network of fractures may be created at
near-wellbore and far-wellbore locations by varying the pressure
during injection of the fluid for various stages. For instance, the
pressure used in injecting the fluid in the stage wherein the
primary fracture is enlarged or created may be greater than or less
than the pressure when injecting the fluid in the additional stage.
The fluid is preferably allowed to divert into the enlarged or
created primary fracture.
[0069] Thus, the viscosity of the fluid of successive stages may be
the same or different. For instance, the viscosity of the fluid
and/or pumping pressure of the fluid in the initial step causing
the creation or enlargement of the primary fracture may be the same
as a subsequent stage. Alternatively, the viscosity of the fluid
and/or pumping pressure of the fluid in the initial step may be
greater than the viscosity and/or pumping pressure of the fluid in
a successive stage. The viscosity of the fluid and/or pumping
pressure of the fluid in the initial step may be less than the
viscosity and/or pumping pressure of the fluid in a successive
stage. For instance, the viscosity and/or pressure of the fluid in
each successive stage may decrease with each additional stage.
[0070] The loading of the viscosifying agent in the fluid in each
of the stages may also be the same or may be different. While
typically the amount of viscosifying agent in the viscous fluid may
be less than or equal to 6% by weight, the amount may vary from one
stage to another.
[0071] The first fracturing fluid, additional fluids and any of the
penultimate fluids or successive fluids referred to herein, may
also contain other conventional additives common to the well
service industry such as surfactants, biocides, gelling agents,
cross-linking agents, foaming agents, demulsifiers, buffers, clay
stabilizers, fines migration control agents, VES-micelle associate
agents, chelants, internal VES-micelle breakers, or mixtures
thereof. In the practice of the disclosure, the fracturing fluid
may be any carrier fluid suitable for transporting a mixture of
proppant into a formation fracture in a subterranean well. Such
fluids include, but are not limited to, carrier fluids comprising
salt water, fresh water, liquid hydrocarbons, and/or nitrogen or
other gases.
[0072] The viscosity of the viscous fluid of any or all of the
stages of the method described herein may be the same or different.
For instance, the viscosity of the fluid of the pad fluid and the
second stage may be the same. The constituency of the fluid of each
of the stages may be the same or different. Thus, for example, in a
method having nine different stages, three of the nine stages may
be of the same fluid while the remaining six stages may all be
different fluids.
[0073] The amount of viscosifying agent in the viscous fluid of any
of the described stages may be less than or equal to 6% by
weight.
[0074] The methods described herein may be used in the treatment of
conventional rock formations such as carbonate formations (like
limestone, chalk and dolomite), sandstone or siliceous substrate
minerals, such as quartz, clay, shale, silt, chert, zeolite, or a
combination thereof. The methods have particular applicability in
the treatment of unconventional hydrocarbon reservoir formations,
such as shale, tight sandstone and coal bed methane wells.
[0075] The methods described herein are especially effective with
those subterranean reservoirs having a permeability less than or
equal to 1.0 mD and most especially those subterranean reservoirs
having a permeability less than or equal to 0.1 mD.
[0076] The viscosifying polymer may be a hydratable polymer like,
for example, one or more polysaccharides capable of forming linear
or crosslinked gels. These include galactomannan gums, guars,
derivatized guars, cellulose and cellulose derivatives, starch,
starch derivatives, xanthan, derivatized xanthan and mixtures
thereof.
[0077] Specific examples include, but are not limited to, guar gum,
guar gum derivative, locust bean gum, welan gum, karaya gum,
xanthan gum, scleroglucan, diutan, cellulose and cellulose
derivatives, etc. More typical polymers or gelling agents include
guar gum, hydroxypropyl guar (HPG), carboxymethyl hydroxypropyl
guar (CMHPG), hydroxyethyl cellulose (HEC), carboxymethyl
hydroxyethyl cellulose (CMHEC), carboxymethyl cellulose (CMC),
dialkyl carboxymethyl cellulose, etc. Other examples of polymers
include, but are not limited to, phosphomannans, scleroglucans and
dextrans.
[0078] The fluid containing the viscosifying polymer may further
include a crosslinking agent. Typically, a low loading of the
polymer is used in order to minimize polymer residue and
conductivity damage. Where the fluid uses a viscosifying polymer,
the loading of the polymer or crosslinked polymer is low, typically
between from about 0.1 to about 6% by weight.
[0079] Any crosslinking agent suitable for crosslinking the
hydratable polymer may be employed. Examples of suitable
crosslinking agents include metal ions such as aluminum, antimony,
zirconium and titanium-containing compounds, including
organotitanates. Examples of suitable crosslinkers may also be
found in U.S. Pat. No. 5,201,370; U.S. Pat. No. 5,514,309, U.S.
Pat. No. 5,247,995, U.S. Pat. No. 5,562,160, and U.S. Pat. No.
6,110,875, incorporated herein by reference. Further examples of
crosslinking agents are borate-based crosslinkers such as
organo-borates, mono-borates, poly-borates, mineral borates,
etc.
[0080] In an embodiment, the viscosifying agent may be
non-polymeric such as a viscoelastic surfactant. The viscoelastic
surfactant suitable for use as the viscosifying agent may be
micellular, such as worm-like micelles, nano-size particle
associated worm-like micelles, micron-size particle associated
worm-like micelles, surfactant aggregations or vesicles, lamellar
micelles, etc. Such micelles include those set forth in U.S. Pat.
Nos. 6,491,099; 6,435,277; 6,410, 489; 7,115,546; 7,343,972;
7,550,413; 7,723,272; 8,114,820; and 8,278,252.
[0081] Suitable viscoelastic surfactants include cationic,
amphoteric and anionic surfactants. Suitable cationic surfactants
include those having only a single cationic group which may be of
any charge state (e.g., the cationic group may have a single
positive charge or two positive charges). The cationic group
preferably is a quaternary ammonium moiety (such as a linear
quaternary amine, a benzyl quaternary amine or a quaternary
ammonium halide), a quaternary sulfonium moiety or a quaternary
phosphonium moiety or mixtures thereof. Preferably the quaternary
group is quaternary ammonium halide or quaternary amine, most
preferably, the cationic group is quaternary ammonium chloride or a
quaternary ammonium bromide.
[0082] The amphoteric surfactant preferably contains a single
cationic group. The cationic group of the amphoteric surfactant is
preferably the same as those listed in the paragraph above. The
amphoteric surfactant may be one or more of glycinates,
amphoacetates, propionates, betaines and mixtures thereof.
Preferably, the amphoteric surfactant is a glycinate or a betaine
and, most preferably, the amphoteric surfactant is a linear
glycinate or a linear betaine. Amine oxide type surfactants are
also most preferable, such as those disclosed in U.S. Pat. No.
7,723,272.
[0083] The cationic or amphoteric surfactant has a hydrophobic tail
(which may be saturated or unsaturated). Preferably the tail has a
carbon chain length from about C12-C18. Preferably, the hydrophobic
tail is obtained from a natural oil from plants, such as one or
more of coconut oil, rapeseed oil and palm oil. Exemplary of
preferred surfactants include N,N,N trimethyl-1-octadecammonium
chloride: N,N,N trimethyl-1-hexadecammonium chloride; and N,N,N
trimethyl-1-soyaammonium chloride, and mixtures thereof.
[0084] Exemplary of anionic surfactants are sulfonates,
phosphonates, ethoxysulfates and mixtures thereof. Preferably the
anionic surfactant is a sulfonate. Most preferably the anionic
surfactant is a sulfonate such as sodium xylene sulfonate and
sodium naphthalene sulfonate.
[0085] In one embodiment, a mixture of surfactants are utilized to
produce a mixture of (1) a first surfactant that is one or more
cationic and/or amphoteric surfactants set forth above and (2) at
least one anionic surfactant set forth above.
[0086] The relative amounts of the viscosifying agent in the stages
referenced herein may be determined based upon the desired
viscosity of the fluid. In particular, in operation, the viscosity
of the fluid may first be determined. Further, the volume of the
fluid which is required may be determined at this time. The
requisite amount of viscosifying agent to obtain the predetermined
viscosity may then be combined with the requisite amount of water
to produce the fluid.
[0087] Preferably where a mixture of surfactants are used, such as
those disclosed in U.S. Pat. No. 6,875,728 or 6,410,489 (herein
incorporated by reference), the amount of the cationic/amphoteric
surfactant and the amount of anionic surfactant which are used is
preferably sufficient to neutralize, or at least essentially
neutralize, the charge density of the surfactants. Accordingly, if
the cationic surfactant is N,N,N, trimethyl-1-octadecammonium
chloride and the anionic surfactant is sodium xylene sulfonate,
then the surfactants may be combined in a ratio from about 1:4 to
about 4:1 by volume to obtain a clear viscoelastic gel which is
capable of transporting a proppant. Typically of such viscoelastic
surfactants are AquaClear, a product of Baker Hughes
Incorporated.
[0088] Any breaker known in the hydraulic fracturing art may also
be included in the fluid. The breaker is selected such that it is
capable of degrading, enhancing the degradation of or reducing the
viscosity of the viscosifying agent in one or more of the stages.
Preferred breakers are delayed internal breakers such as peroxides,
enzymes, and esters or mixtures thereof. Such delayed internal
breakers include encapsulated breakers.
[0089] Any amount or concentration of breaker suitable for
degrading or reducing the viscosity of the viscosifying agent or
filter cake or other solids may be used. Often, the concentration
of breaker used is that amount sufficient to cause complete
degradation of the filter cake which is formed at the fracture face
of the formation.
[0090] Typically, such breakers are included in their respective
fluid in a concentration of between about 0.1 lb/1000 gals. and
about 10 lb/100 gals.
[0091] Suitable breakers may include oils, such as mineral oil. Oil
breakers have particular applicability in the breaking of
surfactant-gelled fluids. At other times, the breaker may be an
enzyme or oxidative breaker and may include enzyme precursors as
well as enzymatically catalyzed oxidizers.
[0092] Examples of suitable types of oxidizing breakers include,
but are not limited to, ammonium persulfate, sodium persulfate,
ammonium peroxydisulfate, encapsulated ammonium persulfate,
potassium persulfate, encapsulated potassium persulfate, inorganic
peroxides, sodium bromate, sodium perchlorate, encapsulated
inorganic peroxides, organic peroxides, encapsulated organic
peroxides, sodium perborate, magnesium perborate, calcium
perborate, encapsulated sodium perborate. Specific examples of
suitable oxidizing materials include, but are not limited to,
breakers available from Baker Hughes Incorporated as GBW5 (ammonium
persulfate), GBW7 (sodium perborate), GBW23 (magnesium peroxide),
GBW24 (calcium peroxide), GBW36 (encapsulated potassium
persulfate), HIGH PERM CRB (encapsulated potassium persulfate),
HIGH PERM CRB LT (encapsulated persulfate), ULTRA PERM CRB
(encapsulated potassium persulfate), SUPER ULTRA PERM CRB
(encapsulated potassium persulfate), and TRIGINOX (organic
peroxide).
[0093] Further, any enzyme suitable for degrading or otherwise
reducing the viscosity of a filter cake and/or gel residue may be
employed. Such enzymes include those described in U.S. Pat. No.
5,165,477; U.S. Pat. No. 5,201,370; U.S. Pat. No. 5,247,995; and/or
U.S. Pat. No. 5,562,160; and/or U.S. Pat. No. 6,110,875. Suitable
enzymes include hydrolases, lyases, transferases and
oxidoreductases.
[0094] The presence of breakers in the fluid dramatically decreases
the low shear rate viscosity of the fluid. As illustrated in FIG.
4, as shear rate decreases, the viscosity of the fluid increases.
Thus, as the fluid in the fracture starts to slow down at very low
shear rate, the viscosity of the fluid increases.
[0095] Preferred fluids of the disclosure preferably include
viscoelastic surfactants since such surfactants typically minimize
damage to the formation. In addition, since the methods described
herein extend complex fractures farther away from the wellbore, the
use of such viscosifying agents enables easier treatment fluid
cleanup once a fracturing job is complete. For instance, reservoir
fluid flow decreases with increasing distance from the wellbore,
and the amount of reservoir cleanup energy also decreases from the
wellbore. Thus a clean breaking, easy to cleanup viscoelastic
surfactant treatment fluid is most preferred for this art. The
clean-up of the treatment fluids in far-field and near-wellbore
complex fracture networks can be improved by the use of
viscoelastic surfactant fluids with internal breakers. This is
illustrated in FIG. 5 wherein low reservoir pressure is seen to
displace internally broken viscoelastic fluids. In particular, by
degrading the low shear rate viscosity by internal breakers, the
amount of pressure required for fluid cleanup can be significantly
reduced, such as far-field complex fracture networks with low
reservoir cleanup energy. FIG. 5 demonstrates the Berea core
cleanup test data. Such VES-micelles internal breakers include
those set forth in U.S. Pat. Nos. 7,343,266; 7,595,284; 7,615,517;
7,645,724; 7,696,134; 7,696,135; 7,728,044 and 7,967,068. In one
non-limiting embodiment, the internal breaker works by
rearrangement of the worm-like (i.e. long) micelle structure rather
than surfactant molecule decomposition or alteration, although the
alteration method of reducing VES-micelle viscosity may also be
used.
[0096] In an embodiment, for greater than about 225.degree. F.
applications the fracturing fluids of the disclosure contain a
viscoelastic surfactant in combination with temperature stabilizers
as set forth in U.S. Patent Publication No. 2009/0272534, herein
incorporated by reference. Suitable stabilizers include alkaline
earth metals selected from magnesium, calcium, strontium, barium
and mixtures thereof, and alkali metals selected from lithium,
sodium, potassium and mixtures thereof. Preferred temperature
stabilizers include MgO, TiO.sub.2, Al.sub.2O.sub.3 and mixtures
thereof. Nanoparticles of such stabilizers are especially
preferred.
[0097] Any of the stages described herein may further include a low
shear rate viscosity enhancer. Suitable viscosity enhancers
include, but are not limited to, pyroelectric particles,
piezoelectric particles, and mixtures thereof. In one non-limiting
embodiment, specific viscosity enhancers may include, but are not
necessarily limited to, ZnO, berlinite (AlPO.sub.4), lithium
tantalate (LiTaO.sub.3), gallium orthophosphate (GaPO.sub.4),
BaTiO.sub.3, SrTiO.sub.3, PbZrTiO.sub.3, KNbO.sub.3, LiNbO.sub.3,
LiTaO.sub.3, BiFeO.sub.3, sodium tungstate,
Ba.sub.2NaNb.sub.5O.sub.5, Pb.sub.2KNb.sub.5O.sub.15, potassium
sodium tartrate, tourmaline, topaz and mixtures thereof.
[0098] The viscosity enhancer particles may be very small so they
do not readily settle out of the fluid. This permits their removal
from the formation to be easy and complete causing little or no
damage to the formation.
[0099] Some or all of the stages may further contain proppant.
Typically, the amount of proppant in a stage is greater than the
amount of proppant in the pad fluid. The addition of proppant to
the fracturing fluid in combination with the stop-start cycle
described herein provides an increase in the amount of secondary
fractures (Fs) that are propped (Fsp). The increase in the ratio of
Fsp/Fs provides greater net fracture conductivity for the secondary
fractures formed. FIG. 6 illustrates that greater Fs conductivity
provides an improvement in higher sustainable hydrocarbon
production rates.
[0100] In some treatment operations, it may be desirable to taper
the loading of proppant to the viscosity of the fluid. In other
treatment operations, it may be desirable to use proppant only with
stages using a viscous fluid. In another embodiment, each fluid
stage between stop-start may be designated like a typical frac
treatment, i.e., a pad followed by increasing proppant loadings
with small amount of displacements by slickwater fracturing
operation. In this scenario, it may be desirable to not completely
displace the fluid to the fractures but only have the slickwater
displace 10 to 30% by volume of the fracture. Still further, it may
be desirable to utilize smaller proppant size in the initial stages
and follow with larger proppant sizes for the latter stages.
[0101] Examples of proppants include, but are not limited to,
ceramics, silica, quartz sand grains, glass and ceramic beads,
walnut shell fragments, aluminum pellets or needles, nylon pellets,
resin-coated sand, synthetic organic particles, glass microspheres,
sintered bauxite, mixtures thereof and the like.
[0102] In a preferred embodiment, the proppant is a relatively
lightweight or substantially neutrally buoyant particulate material
or a mixture thereof. Such proppants may be chipped, ground,
crushed, or otherwise processed. By "relatively lightweight" it is
meant that the proppant has an apparent specific gravity (ASG) that
is substantially less than a conventional proppant employed in
hydraulic fracturing operations, e.g., sand or having an ASG
similar to these materials. Especially preferred are those
proppants having an ASG less than or equal to 3.25. Even more
preferred are ultra lightweight proppants having an ASG less than
or equal to 2.25, more preferably less than or equal to 2.0, even
more preferably less than or equal to 1.75, most preferably less
than or equal to 1.25 and often less than or equal to 1.05.
[0103] The proppant may further be a resin coated ceramic proppant
or a synthetic organic particle such as nylon pellets, ceramics.
Suitable proppants further include those set forth in U.S. Patent
Publication No. 2007/0209795 and U.S. Patent Publication No.
2007/0209794, herein incorporated by reference. The proppant may
further be a plastic or a plastic composite such as a thermoplastic
or thermoplastic composite or a resin or an aggregate containing a
binder.
[0104] By "substantially neutrally buoyant", it is meant that the
proppant has an ASG close to the ASG of an ungelled or weakly
gelled carrier fluid (e.g., ungelled or weakly gelled completion
brine, other aqueous-based fluid, or other suitable fluid) to allow
pumping and satisfactory placement of the proppant using the
selected carrier fluid. For example, urethane resin-coated ground
walnut hulls having an ASG of from about 1.25 to about 1.35 may be
employed as a substantially neutrally buoyant proppant particulate
in completion brine having an ASG of about 1.2. As used herein, a
"weakly gelled" carrier fluid is a carrier fluid having minimum
sufficient polymer, viscosifier or friction reducer to achieve
friction reduction when pumped down hole (e.g., when pumped down
tubing, work string, casing, coiled tubing, drill pipe, etc.),
and/or may be characterized as having a polymer or viscosifier
concentration of from greater than about 0 pounds of polymer per
thousand gallons of base fluid to about 10 pounds of polymer per
thousand gallons of base fluid, and/or as having a viscosity of
from about 1 to about 10 centipoises. An ungelled carrier fluid may
be characterized as containing about 0 pounds per thousand gallons
of polymer per thousand gallons of base fluid. (If the ungelled
carrier fluid is slickwater with a friction reducer, which is
typically a polyacrylamide, there is technically 1 to as much as 8
pounds per thousand of polymer, but such minute concentrations of
polyacrylamide do not impart sufficient viscosity (typically <3
cP) to be of benefit).
[0105] Other suitable relatively lightweight proppants are those
particulates disclosed in U.S. Pat. Nos. 6,364,018, 6,330,916 and
6,059,034, all of which are herein incorporated by reference. These
may be exemplified by ground or crushed shells of nuts (pecan,
almond, ivory nut, brazil nut, macadamia nut, etc); ground or
crushed seed shells (including fruit pits) of seeds of fruits such
as plum, peach, cherry, apricot, etc.; ground or crushed seed
shells of other plants such as maize (e.g. corn cobs or corn
kernels), etc.; processed wood materials such as those derived from
woods such as oak, hickory, walnut, poplar, mahogany, etc.
including such woods that have been processed by grinding,
chipping, or other form of particalization. Preferred are ground or
crushed walnut shell materials coated with a resin to substantially
protect and water proof the shell. Such materials may have an ASG
of from about 1.25 to about 1.35.
[0106] Further, the relatively lightweight particulate for use in
the disclosure may be a selectively configured porous particulate,
as set forth, illustrated and defined in U.S. Pat. No. 7,426,961,
herein incorporated by reference.
[0107] The particle size of the proppants in the fluid of each of
the stages may be the same or different. For instance, the particle
size of the proppants in the stage wherein the primary fracture is
created or enlarged may be less than the particle size of the
proppants in subsequent stages. Further, the particle size of the
proppants in each successive stage may increase as the number of
stages increases. Typically, the size of the proppants range from
12 microns to 4 millimeters.
[0108] An advantage of the methods disclosed herein is that less
fracturing intervals are required during a treatment operation in
order to obtain the same amount of hydrocarbons as those produced
in conventional operations which use a greater number of fracturing
intervals. For example, where the treatment operation consists of
decreasing the rate of injection after the fluid of a first stage
is introduced into the wellbore and then continuing with the same
rate of injection of additional fluid into the formation after
pumping has been reduced or stopped and diverting the additional
fracturing fluid away from the primary fracture to create a
secondary fracture, the amount of hydrocarbons recovered is greater
than the amount of hydrocarbons recovered from a primary fracture
and secondary fractures which had been created in a fracturing
operation performing an equivalent number of stages but wherein
each stage is introduced into the formation at the same rate of
injection. This may be observed in a treatment operation producing
multiple fractures by the methods defined herein wherein the number
of stages of the inventive method are the same number of stages as
the conventional method.
[0109] Since the amount of hydrocarbons produced is greater under
such conditions, fewer stages in a fracturing operation are
required in order to produce an equivalent amount of hydrocarbons.
Since the number of intervals may be increased across the wellbore,
the methods described herein provide the ability to effectively
fracture longer frac interval lengths. The phenomena is
attributable to the multiple fracture network providing a wider
distribution pattern which is created by a reduced fluid volume. In
other words, assuming that the treatment operation used successive
fracturing stages wherein the rate of injection remained the same
for each fracturing stage, a greater number of fracturing intervals
may be required to obtain a given volume than in the method
described herein wherein the rate of injection of a successive
fracturing stage is greater or less than the rate of injection of a
penultimate fracturing stage. The reduction in the number of
hydraulic fracturing treatments across a given horizontal wellbore
by use of the methods described herein is illustrated in FIG. 7A
and comparative FIG. 7B. The reduction may be attributable to
improved distribution of fluid in the zones.
[0110] The method has particular applicability with the treatment
of shale oil and/or gas reservoirs. In previous methods, shale
reservoirs were fractured using short intervals and thus an
increased number of fracturing treatments. Such fracturing
treatments have become closer together. The method described herein
may provide for a decrease in interval per a given length. For
instance, the methods described herein may provide 8 intervals (and
fracturing treatments) per 3,000 ft. of horizontal wellbore
compared to 30 intervals (and fracturing treatments) per 3,000 ft.
This reduction is possible without compromising the net surface
area increase and SRV provided by the methods described herein and
without extending the hydrocarbon drainage area of the reservoir.
Further, reducing the number of intervals required for a treatment
operation provides a cost savings to the operator since the number
of interval isolation tools is decreased.
[0111] The methodology described herein may increase the net
surface area far-field and near wellbore. Most conventional viscous
fluid shale fracs induce mostly long planar fractures with few
secondary fractures (FIG. 1A). Alternately, most slickwater fracs
(i.e. fluids with <15 cps at 100 sec.sup.-1) typically induce
near wellbore complex fracture network and SRV, and in some cases
with long primary fractures with very few secondary fractures (FIG.
1B). However, the methodology described herein by controlling pump
rate and fluid viscosity can induce more secondary fractures
further away from the wellbore (far-field) and near wellbore by low
shear rate fluid viscosity pressure diversion (FIG. 1C). The bottom
line in FIG. 2 represents typical production data for conventional
fracturing (i.e. using single pump rate with a viscous frac fluid),
complex fractures that develop primarily near the wellbore typical
of slickwater fracs (middle line), and near wellbore and far-field
complex fracture network SRV achievable by adjusting or hesitating
pumping rate with a viscous fluid (top line). In practicing this
method, the viscous fracturing fluid may be high shear thinning
with greater than 10,000 cP viscosity at 0.01 sec.sup.-1 shear.
FIG. 3 shows the 2 sec.sup.-1 shear rate viscosity at 150.degree.
F. of a 13.0 brine fluid having 4 volume % viscoelastic surfactant,
6 pounds per thousand gallons (pptg) of viscosity enhancer and 2
gallons per thousand gallons (gptg) breaker after setting static
for 30 minutes. FIG. 4 shows how unbroken shear thin fluid can have
much higher apparent viscosity at low shear rates, and how the use
of internal breaker is preferred to reduce low shear rate fluid
viscosity after the treatment, particularly the low shear rate
fluid viscosity. FIG. 5 shows how unbroken viscoelastic surfactant
fluid can take a significant amount of pressure to flow from 6 in.
Berea core buts much less pressure is needed with use of internal
breaker.
[0112] The methodology described herein may further be used in a
slickwater-viscous fluid fracturing operation. Unlike the
fracturing pattern generated by conventional slickwater fracturing
(illustrated in FIG. 1B), the slickwater fracturing operation
defined herein provides a optimized primary fracture length and
multiple secondary fractures (illustrated in FIG. 1C).
[0113] For instance, in one embodiment, prior to pumping of the pad
fluid, a slickwater fluid may be pumped into the reservoir. The
slickwater fluid typically has a viscosity less than or equal to 15
cP at a shear rate of 300 sec.sup.-1. This may be followed by the
pad fluid and then the (first) treatment using the viscous fluid.
In such embodiments, the amount of slickwater fluid introduced into
the wellbore is typically between from about 10 to about 60 volume
percent of the combination of slickwater fluid, pad fluid and
viscous fluid.
[0114] Thus, in an embodiment, hydrocarbons may be recovered from a
fracturing operation by first pumping slickwater fluid into the
reservoir for a time and at a pressure sufficient to create a
primary fracture in the reservoir. A viscous fluid containing an
aforementioned viscosifying agent may then be pumped behind the
slickwater fluid in order to extend the created primary fracture.
The viscous fluid typically has a viscosity greater than about
10,000 cP at a shear rate of 0.01 sec.sup.-1. In an embodiment, the
pumping of the viscous fluid may be suspended for a sufficient time
to allow the viscous fluid to be diverted within the primary
fracture. Additional slickwater fluid may then be pumped into the
reservoir for a time and at a pressure sufficient to divert the
viscous fluid away from the primary fracture and to create one or
more secondary fractures in the subterranean reservoir. The pumping
of the additional slickwater fluid is usually at a higher injection
rate than the injection rate of the viscous fluid. The process
creates a multiple fracture network near the wellbore than when the
fracturing is limited to slickwater treatment. In addition, the
process provides for the creation of a more complex network of
secondary fractures near the wellbore (FIG. 1B).
[0115] The viscosifying agent used in the method is preferably a
viscoelastic surfactant. An internal breaker is also preferable to
induce a clean breaking fluid that does not leave apparent residual
mass that impairs fracture conductivity, such as polymer residue.
Since the fluid is laden with a viscosifying agent with internal
breaker, the water load recovery after the staged treatment is
high. This results in an improved SRV and enhances gas connectivity
to the wellbore from a higher percentage of the hydraulically
induced fractures.
[0116] In an embodiment, additional viscous fluid is then pumped
behind the slickwater fluid in order to extend the secondary
fracture. Pumping may then be suspended in order to divert the flow
of slickwater away from the primary fracture into the one or more
secondary fractures. This process may be continuously repeated to
create a network of far-field and near wellbore secondary fractures
from the primary fracture (FIG. 1C). Typically, the volume percent
of slickwater fluid pumped in penultimate stage to viscous fluid
pumped in a successive stage is between from about 10:90 to about
50:50.
[0117] In another embodiment, hydrocarbons may be recovered from a
fracturing operation by a series of slickwater fracturing stages
wherein slickwater fluid is first pumped into the reservoir for a
time and at a pressure sufficient to create a primary fracture in
the reservoir. Pumping may then be suspended for the fluid to
divert into the created fracture. Additional slickwater fluid may
then be pumped into the reservoir for a time and at a pressure
sufficient to extend fluid and to create one or more secondary
fractures in the reservoir. Pumping may then be suspended in order
to divert the flow of slickwater away from the primary fracture
into the one or more secondary fractures. This process may be
continuously repeated to create a network of secondary fractures
from the primary fracture. Increased water recovery from the
slickwater fracturing stages allows for greater gas connectivity to
the reservoir.
[0118] The viscosity of the slickwater fluid in a slickwater stage
may be the same or different from the viscosity of the slickwater
fluid in another slickwater stage. Likewise, the viscosity of the
viscous fluid may be different or the same from one viscous fluid
stage versus another viscous fluid stage. Further, the rate of
injection of the pumping of the fluids and the pumping pressure of
the stages may be the same or different from one slickwater stage
to the next or from one viscous fluid stage to another viscous
fluid stage.
[0119] Any combinations of the methods disclosed herein may be used
in a fracturing operation. For instance, a diversion process as
described herein may be used in combination with a slickwater
fracturing operation. Specifically, a viscous fluid containing a
viscosifying agent may be alternated with a slickwater fracturing
fluid. In such an instance, for example, the first stage may be a
viscous fluid containing a viscoelastic surfactant followed by a
slickwater fracturing stage wherein the total volume of viscous
fluid stage to slickwater fracturing stage may be 50:50 or 75:25
volume percent.
[0120] As another example, a series of viscous fluid stages may be
injected into the wellbore with a suspension of pumping between
each stage and the last stage of the operation may be a slickwater
fracturing stage. In this scenario, the viscosity of the viscous
fluid of each of the stages may be the same or different. Likewise,
the viscous fluid may exhibit greater viscosity in the first few
stages and less viscous in the latter stages. Conversely, a series
of fluid stages may be injected into the wellbore wherein the first
fluid is a slickwater fracturing fluid and the last stage is a
viscous fluid. Similarly, alternating stages between a viscous
fluid and a slickwater fracturing fluid may be injected and
repeated for two or more cycles. In this scenario, the viscosity of
the viscous fluid may be the same for each fluid stage or the
viscosity may be tapered.
[0121] The methods described herein may further limit the
fracturing of zones in formations such as shale formations which
are known to exhibit non-uniform interval coverage. Microseismic
mapping and well temperature logging often show poor frac fluid
distribution across each interval and re-fracturing of nearby
intervals. By directing the placement of fluid within the fractured
zones, out of intervals fracturing areas may be reduced. This is
shown in FIG. 8.
[0122] The foregoing disclosure and description of the disclosure
is illustrative and explanatory thereof and it can be readily
appreciated by those skilled in the art that various changes in the
size, shape, and materials, as well as in the details of
illustrative methodologies described herein may be made without
departing from the spirit of the disclosure.
* * * * *