U.S. patent application number 14/226512 was filed with the patent office on 2014-10-09 for method of increasing fracture network complexity and conductivity.
The applicant listed for this patent is Baker Hughes Incorporated. Invention is credited to James B. Crews, Chunlou Li.
Application Number | 20140299318 14/226512 |
Document ID | / |
Family ID | 50686195 |
Filed Date | 2014-10-09 |
United States Patent
Application |
20140299318 |
Kind Code |
A1 |
Crews; James B. ; et
al. |
October 9, 2014 |
METHOD OF INCREASING FRACTURE NETWORK COMPLEXITY AND
CONDUCTIVITY
Abstract
A complex fracture network within a hydrocarbon-bearing
subterranean formation is created by first pumping a first fluid
into the formation to create or enlarge a primary fracture and then
pumping a second fluid into the formation wherein the second fluid
contains a viscous material and the first fluid. By diverting the
flow of the second flow, a secondary fracture is created having a
directional orientation distinct from the directional orientation
of the primary fracture.
Inventors: |
Crews; James B.; (Willis,
TX) ; Li; Chunlou; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Baker Hughes Incorporated |
Houston |
TX |
US |
|
|
Family ID: |
50686195 |
Appl. No.: |
14/226512 |
Filed: |
March 26, 2014 |
Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
|
|
61809187 |
Apr 5, 2013 |
|
|
|
Current U.S.
Class: |
166/280.2 ;
166/308.5 |
Current CPC
Class: |
C09K 8/80 20130101; C09K
8/62 20130101; E21B 43/267 20130101 |
Class at
Publication: |
166/280.2 ;
166/308.5 |
International
Class: |
E21B 43/267 20060101
E21B043/267 |
Claims
1. A method of fracturing a hydrocarbon-bearing subterranean
formation penetrated by a wellbore which comprises, in a first
stage: (a) pumping a first fluid into the formation at a pressure
sufficient to create or enlarge a primary fracture; (b) pumping a
second fluid into the formation, wherein the second fluid comprises
the first fluid and a viscous material; (c) creating or enlarging
at least one secondary fracture having a directional orientation
distinct from the directional orientation of the primary fracture
by diverting the flow of the second fluid; and (d) forming a
complex fracture network by creating multiple fractures in the
formation originating from the at least one secondary fracture.
2. The method of claim 1, wherein the viscous material is selected
from the group consisting of viscoelastic surfactants, linear
polymers, crosslinked polymers, surfactants, gelled hydrocarbons,
and emulsion fluids and mixtures thereof.
3. The method of claim 2, wherein the viscous material is a gelled
fluid of a viscoelastic surfactant, a linear polymer or a
crosslinked polymer or a mixture thereof.
4. The method of claim 2, wherein the viscous material is selected
from the group consisting of galactomannan gums, guars, derivatized
guars, cellulose and cellulose derivatives, starch, starch
derivatives, xanthan, derivatized xanthan and mixtures thereof.
5. The method of claim 2, wherein the viscous material is selected
from the group consisting of crosslinked guars and crosslinked
cellulosic derivatives and mixtures thereof.
6. The method of claim 1, wherein the viscous material is an
emulsified fluid or a gelled oil.
7. The method of claim 1, wherein the first fluid or second fluid
or both first fluid and second fluid further comprises a
proppant.
8. The method of claim 7, wherein the proppant forms a partial
monolayer within the created or enlarged fracture.
9. The method of claim 1, wherein the viscous material and the
first fluid are present on the fly.
10. The method of claim 7, wherein during the first stage, at least
one of the following factors varies: (a) the size of the proppant
within the first fluid or second fluid; (b) the apparent specific
gravity of the proppant within the first fluid and second fluid; or
(c) the shape of the proppant within the first fluid and second
fluid.
11. The method of claim 7, wherein the apparent specific gravity of
the proppant in the first fluid and/or the second fluid is less
than or equal to 2.0.
12. The method of claim 11, wherein the apparent specific gravity
of the proppant in the first fluid and/or the second fluid is less
than or equal to 1.2.
13. The method of claim 1, wherein the viscous material further
comprises an internal additive selected from the group consisting
of biocides, tracers, proppants, nanocoating agents, surfactants,
scale inhibitors, asphaltene inhibitors, hydrogen sulfide
scavengers, nanoparticles, polymer breakers, VES breakers,
microemulsions, fines migration control additives, fracture imaging
materials, piezoelectric particles, metal particles, metal
complexes, metal salts, fines control agents, solid acids, solid
high pH buffers, salts, chelants, oxidizers, plant and fish oils,
mineral oils, shape memory polymers, fibers, glass spheres,
encapsulations, and combinations thereof.
14. The method of claim 1, wherein the viscosity ratio, Vr,
representing the viscosity of the viscous material at 0.01
sec.sup.-1 and 80.degree. F. to the viscosity of the first fluid at
0.01 sec.sup.-1 and 80.degree. F. is 100 or greater.
15. The method of claim 14, wherein the viscosity ratio, Vr, is
10,000 or greater.
16. The method of claim 15, wherein the viscosity ratio, Vr, is
100,000 or greater.
17. The method of claim 1, wherein the viscous material has an
average particle size from about 500 nm to about 50 cm.
18. The method of claim 1, wherein the permeability of the
hydrocarbon-bearing subterranean formation is less than or equal to
0.1 mD.
19. A method of fracturing a hydrocarbon-bearing subterranean
formation penetrated by a wellbore which comprises, in a first
stage: (A) pumping a first fluid of low viscosity into the
formation at a pressure sufficient to create or enlarge a primary
fracture; and (B) forming a complex fracture network comprising (a)
at least one secondary fracture having a directional orientation
distinct from the directional orientation of the primary fracture;
and (b) a multiple of fractures originating from the at least one
secondary fracture and having a directional orientation distinct
from the direction orientation of the at least one secondary
fracture wherein the complex fracture network is formed by pumping
a second fluid into the formation, wherein the second fluid
comprises (i) the first fluid of low viscosity and (ii) a plurality
of discrete bodies having a viscosity greater than the viscosity of
the first fluid.
20. The method of claim 19, wherein the first fluid and the
plurality of discrete bodies are present on the fly.
21. The method of claim 19, wherein the pumping of the first fluid
and the second fluid reduces or minimizes conductivity-limited
choke points within the complex fracture network.
22. A method of hydraulically fracturing a hydrocarbon-bearing
subterranean formation penetrated by a wellbore which comprises, in
a first stage: (a) pumping a first fluid of low viscosity into the
formation at a pressure sufficient to create or enlarge a primary
fracture; (b) pumping a second fluid into the formation, wherein
the second fluid is prepared by adding to the first fluid a
plurality of discrete bodies having a viscosity greater than the
viscosity of the first fluid; (a) creating or enlarging at least
one secondary fracture having a directional orientation distinct
from the directional orientation of the primary fracture by
diverting the flow of the second fluid; and (b) forming a complex
fracture network through the addition of a diverting fluid into the
formation and creating multiple fractures in the formation
originating from the at least one secondary fracture wherein the
diverting fluid is prepared by adding to the first fluid a
plurality of discrete bodies having a viscosity greater than the
viscosity of the first fluid and wherein the multiple fractures are
created by the action of the plurality of discrete bodies of
viscous material in the diverting fluid.
23. The method of claim 22, wherein the second fluid and the
diverting fluid are the same.
24. The method of claim 22, wherein the pumping of the first fluid,
the second fluid and the diverting fluid reduces or minimizes
conductivity-limited choke points within the complex fracture
network.
25. The method of claim 22, wherein the permeability of the
subterranean formation is less than or equal to 0.1 mD.
26. A method of fracturing a hydrocarbon-bearing subterranean
formation penetrated by a well to create a complex fracture
network, the method comprising pumping into the formation, in a
first stage a, first fluid and at least one second fluid, wherein
the at least one second fluid is comprised of a viscous material
and the first fluid, wherein: (a) a primary fracture is created or
enlarged by pumping into the formation the first fluid; (b) at
least one secondary fracture perpendicular and/or orthogonal to the
primary fracture is created by diverting the flow of the at least
one second fluid; and (c) a complex fracture network comprising a
series of fractures is created by continuously diverting the flow
of the at least one second fluid through the formation and further
wherein either: (i) the surface area ratio (Sr), defined by Scf/Spf
wherein Scf is the surface area of the complex fracture network and
Spf is the surface area over the primary fracture, is greater when
the first fluid and second fluid are pumped into the formation
versus when only the first fluid is pumped into the formation; or
(ii) the conductivity ratio (Cr) defined by Ccf/Cpf, wherein Ccf is
the conductivity of the complex fracture network and Cpf is the
conductivity of the planar fracture divided by 1000 is greater when
the first fluid and the at least one second fluid are pumped into
the formation versus when only the first fluid is pumped into the
formation.
27. The method of claim 25, wherein the first fluid is a brine.
28. The method of claim 25, wherein the first fluid contains a
friction reducing agent.
29. The method of claim 25, wherein the conductivity within the
complex fracture network ranges from nano-darcies at the tip of the
fractures to milli-darcies to the primary fracture.
30. The method of claim 25, wherein the rate of pumping of the
first fluid and/or the second fluid is varied during the
fracturing.
31. The method of 25, wherein the subterranean formation is
shale.
32. A method of generating diversion during the fracturing of a
subterranean formation penetrated by a wellbore comprising: (a)
introducing into the wellbore, at a rate and pressure sufficient to
fracture the subterranean formation, a brine fracturing fluid
comprising: (i) a lower viscosity fluid stream; and (ii) a
plurality of discrete bodies of a higher viscosity material; and
(b) diverting the lower viscosity fluid stream by action of the
discrete bodies of the higher viscosity material.
33. The method of claim 30, wherein the discrete bodies generate
viscosity in the lower viscosity fluid stream in narrow fractures
and under high fracture wall shear.
Description
[0001] This application claims the benefit of U.S. patent
application 61/809,187, filed on Apr. 5, 2013, herein incorporated
by reference.
FIELD OF THE DISCLOSURE
[0002] Fracture network complexity within a subterranean formation
may be created by pumping a low viscosity fluid into the formation
followed by a low viscosity fluid containing independent small
masses of viscous material. Stimulated rock volume (SRV) of the
formation is increased with the complex fracture network created in
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 ultra-low permeability
formations (i.e. such as less than 0.1 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 is often
measured by stimulated rock volume (SRV) of the formation.
[0005] Once the fracture is initiated, subsequent stages of viscous
fluid containing chemical agents, such as proppants, may be pumped
into the created 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, for the purpose of providing a highly
conductive pathway for hydrocarbons and/or other formation fluids
to flow into the wellbore.
[0006] Typically, the treatment design of a hydraulic fracturing
operation requires the fracturing fluid to reach maximum viscosity
as it enters the fracture. The viscosity of the fluid affects
fracture length and width. 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. After the
viscosity of the fluid has been reduced, complete 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.
[0007] 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 degrade viscous VES-micelles into non-viscous
spherical-micelles and the clean breaking fluid is typically not
obstructed as it passes through the pore throats of the formation
and proppant pack.
[0008] 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. 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). Slickwater fluids may be pumped down
the wellbore as fast as 100 bbl/min. to fracture the low
permeability formation. Without using slickwater the top speed of
pumping is around 60 bbl/min.
[0009] 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, two wings of the
fracture extend away from the wellbore in opposing directions
according to the natural stresses within the formation. 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.
[0010] 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.
[0011] Like slickwater fracturing, conventional fracturing
operations typically render an undesirably lengthy primary
fracture. While a greater number of 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.
[0012] 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. 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.
[0013] It should be understood that the above-described discussion
is provided for illustrative purposes only and is not intended to
limit the scope or subject matter of the appended claims or those
of any related patent application or patent. Thus, none of the
appended claims or claims of any related application or patent
should be limited by the above discussion or construed to address,
include or exclude each or any of the above-cited features or
disadvantages merely because of the mention thereof herein.
[0014] Accordingly, there exists a need for improved compositions,
systems, apparatus and methods useful for increasing the
productivity of hydrocarbons far field from the wellbore as well as
near wellbore especially in low permeability formations equipped
with having one or more of the attributes or capabilities described
or shown in, or as may be apparent from, the other portions of this
patent.
SUMMARY OF THE DISCLOSURE
[0015] In an embodiment of the disclosure, a method of fracturing a
hydrocarbon-bearing subterranean formation is provided in which the
first stage comprises:
[0016] (a) pumping a first fluid into the formation at a pressure
sufficient to create or enlarge a primary fracture;
[0017] (b) pumping a second fluid into the formation, wherein the
second fluid comprises the first fluid and a viscous material;
[0018] (c) creating or enlarging at least one secondary fracture
having a directional orientation distinct from the directional
orientation of the primary fracture by diverting the flow of the
second fluid; and
[0019] (d) forming a complex fracture network by creating multiple
fractures in the formation originating from the at least one
secondary fracture.
[0020] In another embodiment, a method of fracturing a
hydrocarbon-bearing subterranean formation is provided in which the
first stage comprises:
[0021] (A) pumping a first fluid of low viscosity into the
formation at a pressure sufficient to create or enlarge a primary
fracture; and
[0022] (B) forming a complex fracture network comprising [0023] (a)
at least one secondary fracture having a directional orientation
distinct from the directional orientation of the primary fracture;
and [0024] (b) a multiple of fractures originating from the at
least one secondary fracture and having a directional orientation
distinct from the direction orientation of the at least one
secondary fracture wherein the complex fracture network is formed
by pumping a second fluid into the formation, wherein the second
fluid comprises (i) the first fluid of low viscosity and (ii) a
plurality of discrete bodies having a viscosity greater than the
viscosity of the first fluid.
[0025] In another embodiment of the disclosure, a method of
hydraulically fracturing a hydrocarbon-bearing subterranean
formation is provided in which a first stage comprises:
[0026] (a) pumping a first fluid of low viscosity into the
formation at a pressure sufficient to create or enlarge a primary
fracture;
[0027] (b) pumping a second fluid into the formation, wherein the
second fluid is prepared by adding to the first fluid a plurality
of discrete bodies having a viscosity greater than the viscosity of
the first fluid;
[0028] (c) creating or enlarging at least one secondary fracture
having a directional orientation distinct from the directional
orientation of the primary fracture by diverting the flow of the
second fluid; and
[0029] (d) forming a complex fracture network through the addition
of a diverting fluid into the formation and creating multiple
fractures in the formation originating from the at least one
secondary fracture wherein the diverting fluid is prepared by
adding to the first fluid a plurality of discrete bodies having a
viscosity greater than the viscosity of the first fluid and wherein
the multiple fractures are created by the action of the plurality
of discrete bodies of viscous material in the diverting fluid.
[0030] In still another embodiment of the disclosure, a method of
fracturing a hydrocarbon-bearing subterranean formation is provided
in order to create a complex fracture network, wherein in a first
stage, a first fluid and a second fluid are pumped into the
formation, wherein the at least one second fluid is comprised of a
viscous material and the first fluid, wherein:
[0031] (a) a primary fracture is created or enlarged by pumping
into the formation the first fluid;
[0032] (b) at least one secondary fracture perpendicular and/or
orthogonal to the primary fracture is created by diverting the flow
of the at least one second fluid; and
[0033] (c) a complex fracture network comprising a series of
fractures is created by continuously diverting the flow of the at
least one second fluid through the formation and further wherein
either: [0034] (i) the surface area ratio (Sr), defined by Scf/Spf
wherein Scf is the surface area of the complex fracture network and
Spf is the surface area over the primary fracture, is greater when
the first fluid and second fluid are pumped into the formation
versus when only the first fluid is pumped into the formation; or
[0035] (ii) the conductivity ratio (Cr) defined by Ccf/Cpf, wherein
Ccf is the conductivity of the complex fracture network and Cpf is
the conductivity of the planar fracture divided by 1000 is greater
when the first fluid and the at least one second fluid are pumped
into the formation versus when only the first fluid is pumped into
the formation.
[0036] Accordingly, the present disclosure includes features and
advantages which are believed to enable it to advance methods of
fracturing. Characteristics and advantages of the present
disclosure described above and additional features and benefits
will be readily apparent to those skilled in the art upon
consideration of the following detailed description of various
embodiments and referring to the accompanying drawings.
BRIEF DESCRIPTION OF THE DRAWINGS
[0037] The following figures are part of the present specification,
included to demonstrate certain aspects of various embodiments of
this disclosure and referenced in the detailed description
herein:
[0038] FIGS. 1a, 1b, 1c and 1d are schematic illustrations of how
discrete bodies of higher viscosity material described herein may
vary;
[0039] FIGS. 2a, 2b and 2c are schematic illustrations of discrete
bodies of higher viscosity material having different materials
contained therein;
[0040] FIGS. 3a and 3b are schematic illustrations of how discrete
bodies of higher viscosity material as described herein may be
sized and formulated to generate viscosity under wall shear
conditions in narrow fractures; and
[0041] FIG. 4 is a schematic illustration of possible choke points
in within a complex fracture network.
DETAILED DESCRIPTION OF EMBODIMENTS
[0042] Characteristics and advantages of the present disclosure and
additional features and benefits will be readily apparent to those
skilled in the art upon consideration of the following detailed
description of exemplary embodiments of the present disclosure and
referring to the accompanying figures. It should be understood that
the description herein and appended drawings, being of example
embodiments, are not intended to limit the claims of this patent or
any patent or patent application claiming priority hereto. On the
contrary, the intention is to cover all modifications, equivalents
and alternatives falling within the spirit and scope of the claims.
Many changes may be made to the particular embodiments and details
disclosed herein without departing from such spirit and scope.
[0043] In showing and describing embodiments in the appended
figures, common or similar elements may be referenced with like or
identical reference numerals or are apparent from the figures
and/or the description herein. The figures are not necessarily to
scale and certain features and certain views of the figures may be
shown exaggerated in scale or in schematic in the interest of
clarity and conciseness.
[0044] As used herein and throughout various portions (and
headings) of this patent application, the terms "disclosure",
"present disclosure" and variations thereof are not intended to
mean every possible embodiment encompassed by this disclosure or
any particular claim(s). Thus, the subject matter of each such
reference should not be considered as necessary for, or part of,
every embodiment hereof or of any particular claim(s) merely
because of such reference.
[0045] Certain terms are used herein and in the appended claims to
refer to particular elements and materials. As one skilled in the
art will appreciate, different persons may refer to an element and
material by different names. This document does not intend to
distinguish between elements or materials that differ in name.
Also, the terms "including" and "comprising" are used herein and in
the appended claims in an open-ended fashion, and thus should be
interpreted to mean "including, but not limited to . . . ."
Further, reference herein and in the appended claims to elements
and components and aspects in a singular tense does not necessarily
limit the present disclosure or appended claims to only one such
component, materials or aspect, but should be interpreted generally
to mean one or more, as may be suitable and desirable in each
particular instance.
[0046] 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 low permeability or "tight" formations, such as shale,
tight sandstone and coal bed methane wells.
[0047] 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.
[0048] The disclosed method may consist of one or more stages. In
one embodiment, a network of fractures may be created at
near-wellbore and far-wellbore locations in a first stage.
[0049] The first stage comprises the pumping of a low viscosity
fluid into the formation at a pressure which is sufficient to
create or enlarge a primary fracture. This low viscosity fluid may
be referred to as the "first fluid" of the first stage of the
fracturing operation. The volume of first fluid pumped into the
formation is selected in order to provide the desired length of the
primary fracture. Thus, for instance, if the primary fracture is
desired to be limited to 500 feet, the volume of low viscosity
fluid pumped into the wellbore may be selected to provide the
desired length of a 500 foot primary fracture.
[0050] The low viscosity fluid may be slickwater or a brine.
[0051] The low viscosity fluid may contain a friction reduction
agent. Suitable friction reduction agents include polyacrylamides,
polyacrylates, as well as any of the viscoelastic surfactants
described herein. When present, the amount of friction reduction
agent in the first fluid is typically between from about 0.5
gallons per thousand (gpt) to 2 gpt.
[0052] After the primary fracture is created (or a primary fracture
within the reservoir is enlarged), one or more secondary fractures
are created within the formation. The secondary fracture typically
extends from the primary fracture and has a directional orientation
which is distinct from the directional orientation of the primary
fracture.
[0053] The secondary fracture(s) are created by pumping into the
formation a second fluid. The second fluid comprises the first
fluid along with a viscous material. The viscosity of the second
fluid is substantially the same as the viscosity of the first
fluid. As such, the presence of the viscous material in the fluid
does not substantially affect the viscosity of the second fluid.
Thus, during fracturing, at the surface and within the wellbore the
second fluid exhibits fluid properties like the low viscosity
(first) fluid.
[0054] Typically, a low loading of the viscous material is used in
the second fluid in order that the viscosity of the second fluid
and first fluid may be substantially the same. The low loading of
the viscous material also minimizes residue and conductivity
damage. Representative concentrations of the viscous material in
the relatively low viscosity (first) fluid may range from about 0.1
vol % to about 20 vol %; alternatively range from about 0.2% vol %
to about 5 vol %; alternatively range from about 0.25 vol % to
about 2 vol %. Use of a viscous material in the low viscous fluid
provides the second fluid with the initial properties of the low
viscosity first fluid and higher viscosity properties once it is in
select sections of the primary and secondary fractures.
[0055] In one non-limiting embodiment, the viscous material
consists of discontinuous masses or discrete bodies. Such discrete
bodies may be prepared by the use of an extruder or die having a
sizing cutter adapted to divide the viscous material into discrete
bodies of a predetermined size such as that set forth in the U.S.
patent application entitled "Method to Generate Diversion and
Distribution For Unconventional Fracturing in Shale" by inventor
James B. Crews, filed on an even date of the present application,
and assigned U.S. patent application Ser. No. 14/225,526 filed on
Mar. 26, 2014 and which is incorporated herein by reference.
[0056] The size of the viscous material will typically vary
depending on the width characteristic of the hydraulic fractures
created within lower permeability reservoirs. For instance, the
viscous material may have an average particle size from about 500
nm to about 50 cm, in one non-limiting embodiment 500 nm to about
30 mm, alternatively from about 1 .mu.m to about 4 mm, and in
another non-limiting embodiment about 10 .mu.m to about 1 mm.
[0057] During pumping, the viscous material effectively retains its
size and shape within the second fluid and appears as discrete tiny
masses with near zero shear rate viscosity in the low viscosity
fluid. The tiny high viscosity material in the second fluid, in one
non-limiting embodiment, is thus highly elastic and deformable and
resists fluid-shear-induced fragmentation during pumping. Depending
on the size of the viscous material, the second fluid may behave
like the first fluid as it flows into and through the initial
portion of the primary fracture. Once the second fluid is within a
section of the primary fracture which has a width similar to or
smaller than the viscous material, such as the primary fracture
width 500' from the wellbore, the second fluid will change its flow
properties (i.e. during viscous material interaction with the
fracture walls) and be diverted from the primary fracture.
Initiation and extension of one or more secondary fractures can
then occur off of the primary fracture, preferably initially
far-field. Changes to any of the size, shape, viscosity, or other
parameters of the viscous material as well as a change in the
pumping rate of the second fluid may allow flow of the second fluid
into secondary fractures. Then, like within the primary fracture,
when the high viscosity masses encounter fracture widths similar to
or less than the size of the viscous material, due to the
parameters of the viscous material and interaction with the
fracture walls the flow properties of the second fluid will change
and flow may be diverted from one or more of the secondary
fractures.
[0058] Pumping of the second fluid into the formation may be
suspended for a sufficient time to allow the fluid to be diverted
away from the primary fracture.
[0059] By controlling the viscosity and shear sensitivity of the
viscous material, frictional interaction of the viscous material
with the walls of narrow fractures may cause the second fluid to
transition from a low viscosity fluid flow (brine or slickwater) to
a combination of low viscosity fluid flow (brine or slickwater) and
discrete viscous material having fracture wall interaction
properties flow (i.e. dual-fluid; brine fluid having little
interaction with fracture walls and discrete viscous fluid masses
with viscous interaction with fracture walls). Once the second
fluid interacts with narrow hydraulic fractures the flow induces
performance properties and processes such as a) path of least
resistance flow deviation; b) lodging of viscous material in the
fracture that reduces but does not totally eliminate treatment
fluid flow; (c) total fluid diversion; (d) in situ wall-shear
induced fluid viscosity generation (i.e. less elastic and more
deformable discrete viscous masses that shear thins in viscosity
into a somewhat flowable, discrete fluid mass in the narrow
fracture and thereby becoming flattened, like a pancake, and take
up greater area in the narrow fracture); and (e) distribution of
delayed released treatment additives can be engineered (once
viscous masses internally break in viscosity). Most of these
processes (i.e., partial diversion, path of least resistance flow
alteration, complete flow diversion, etc.) will induce increased
hydraulic fluid pressure (i.e. within the fracture where
interactions are occurring). The increase in fluid pressure in the
fracture may: a) reduce flow of the second fluid in the fracture;
b) increase fracture width (build-up of fluid pressure in fracture
does not divert fluid instantly but may open fracture wider), c)
alter fracture extension (as fracture width builds fracture length
can grow), and d) eventually the build-up of pressure in the
fracture will overcome the anisotropy rock stress to initiate and
propagate new fracture(s). Fracture network complexity therefore
results.
[0060] Successive generated fractures may be created as an inherent
characteristic of use of the second fluid as diverting fluid. Such
additional fractures may then be created which originate from the
secondary fracture(s). For instance, a tertiary fracture may be
created by pumping the second fluid at a pressure which is
sufficient for the fluid to be diverted away from the secondary
fracture. A quaternary fracture may be created by pumping the
second fluid at a pressure which is sufficient for the fluid to be
diverted away from the tertiary fracture, and so on. Changes to the
size, shape, viscosity and the like of the discrete tiny masses,
and the type of interaction they exhibit with the walls of the
fracture, play an important function in ability to induce diversion
of the second fluid and the number of diversions within successive
fractures. The tertiary, quaternary, quintary fractures and so on
all originate from the creation of the secondary fractures. Each of
the fractures originating from secondary fractures typically has a
directional orientation distinct from the direction orientation of
the fracture from which it extends. Thus, a tertiary fracture
originating from a secondary fracture typically has a directional
orientation distinct from the direction orientation of the
secondary fracture; the quaternary fracture stemming from the
tertiary fracture (originating from the secondary fracture)
typically has a directional orientation distinct from the tertiary
fracture; the quintary fracture stemming from the quaternary
fracture (originating from the secondary fracture) has a
directional orientation distinct from the quaternary fracture and
so on.
[0061] Such additional fractures will be referred to herein as the
"successive fracture" and the "penultimate fracture" to refer to
the latter and next to latter fractures, respectively, wherein the
fracture created from a successive stage has a directional
orientation distinct from that of the fracture created from a
penultimate stage. For example, where a tertiary fracture is
created which extends from a secondary fracture, the tertiary
fracture may be referred to as the "successive fracture" and the
second fracture (extending from the primary fracture) as the
"penultimate fracture." Where a quaternary fracture is created, the
quaternary fracture stage may be referred to as the "successive
fracture" and the tertiary fracture may be referred to as the
"penultimate fracture," etc. Where a fracturing operation consists
of the creation of multiple fractures, the fracture created from
the pumping of a second fluid shall be referred to as a "secondary
fracture".
[0062] In some cases, the second fluid and the diverting fluid used
in the creation or enlargement of successive and penultimate
fractures may be the same. The fluids may differ by varying the
factors which are described herein. However, for simplicity, the
fluid pumped into the formation to create such successive fractures
and penultimate fractures shall only be referred to as the "second
fluid" since the fluid will be comprised of the low viscosity
(first) fluid and the viscous material. Certain characteristics of
the viscous material may be optimized in order to create the
multiple fractures defining the complex fracture network. In other
words, the first stage of the disclosed method designed to render
the complex fracture network may be monitored and tailored such
that the fluid creating the fracture(s) is targeted to maximize the
amount of fluid used in order to render the desired fracture.
[0063] As an example, during the first stage, the viscous material
within the second fluid may be varied, depending on the desired
fracture length, width and level of conductivity, by 1) viscosity;
2) low shear rate elasticity; 3) size; 4) shape; 5) combination of
sizes and/or shapes; 6) concentration to first fluid; 7)
composition and density of the first fluid; and 8) inclusion of
treatment materials within the viscous material (such as proppant,
cleanup agent, clay control agent, breaker, tracer, and the
like).
[0064] Thus, during the first stage where the complex fracture
network is created, more than one viscous material may vary in
viscosity, composition, density, content, size, shape,
concentration in the brine, and the like, for providing more
versatility or wider range of fracture interaction. In one
non-limiting example, larger size, higher concentration and more
viscous material may be used to produce a second fluid for
improving treatment fluid diversion from the primary fracture,
where a second viscous material could produce a second fluid better
suited for fluid diversion within narrow secondary fractures, and a
third viscous material could be used to produce a second fluid
better suited (i.e. smaller in size, less elastic and more
deformable, and contain smaller proppant) for creating a successive
fracture(s).
[0065] Control of conditions to create the complex fracture network
such as varying the size of the viscous material, the shape of the
viscous material and/or the concentration of the viscous material
within the second fluid may be effectuated by use of an extruder or
dye on the fly. Such extruders and dies include those known in the
art including those described in the patent application entitled
"Method to Generate Diversion and Distribution For Unconventional
Fracturing in Shale" by James B. Crews, filed on an even date of
the present application. Thus, the method disclosed herein may
provide for a more efficient use of on-the-fly equipment and
materials.
[0066] The multiple fractures created by diversion of the second
fluid through the formation form a complex fracture network
exhibiting an increase in SRV.
[0067] Further in a non-limiting embodiment, the surface area ratio
(Sr), defined by Scf/Spf wherein Scf is the surface area of the
complex fracture network and Spf is the surface area over the
primary fracture, has been noted to be greater when the first fluid
and second fluid are pumped into the formation versus when only the
first fluid is pumped into the formation.
[0068] The viscous material comprising the second fluid may be a
hydratable polymer such as, 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.
[0069] 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, polyacrylamides,
polyvinylacetates, copolymers, terpolymers, phosphomannans,
scleroglucans and dextrans.
[0070] The fluid containing the viscosifying polymer may further
include a crosslinking agent.
[0071] 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.
Organic crosslinkers known to the art may also be utilized.
[0072] In an embodiment, the viscosifying agent is 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, 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; and 7,115,546.
[0073] 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.
[0074] 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, amine oxides, and mixtures
thereof. Preferably, the amphoteric surfactant is a glycinate,
amine oxide or a betaine and, most preferably, the amphoteric
surfactant is a linear glycinate, alkylaminopropyl amine oxide, or
a linear betaine.
[0075] 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, soybean oil, rapeseed oil and palm oil.
Exemplary of 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.
[0076] 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.
[0077] 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.
[0078] A mixture of any of the aforementioned viscous materials may
also be used.
[0079] While the viscosity of the second fluid and first fluid may
be substantially the same, the viscous material is at least 1,000
times more viscous than the first fluid, and typically is more than
100,000 times more viscous than the first fluid at 0.01 sec.sup.-1
shear rate at 80.degree. F. (27.degree. C.). The ratio in viscosity
(measured at 0.01 sec.sup.-1 and 80.degree. F. ((27.degree. C.)),
Vr, of the viscous material to the first fluid may be designed to
achieve the fracturing and production purposes of the methods
described herein. In one non-limiting embodiment, for example, Vr
is 100 or greater, in one non-limiting embodiment 1000 or greater,
alternatively is 10,000 or greater, and in a different non-limiting
embodiment is 100,000 or greater.
[0080] The integrity of the viscous material to retain its size and
shape during shear when being pumped downhole may be dependent on
the viscosity, size, shape, density and other properties of the
viscous material. While the viscous material may be of larger sizes
fluid diversion in fairly wide fracture widths; small sizes are
preferred within very narrow fracture widths.
[0081] Shown in FIGS. 1a, 1b, 1c and 1d are schematic illustrations
of the discrete bodies of viscous material which may vary one to
the other. FIG. 1a shows that discrete bodies may have different
average particle sizes. FIG. 1b schematically illustrates that
discrete bodies may have different viscosities, where the heavier
the shading, the greater the viscosity. FIG. 1c schematically
illustrates how discrete bodies may be of different shapes, for
instance a spherical shape shown at the top; to bent round rods or
pins shapes, second; to straighter round rods or pins shapes,
third; and long-aspect rectangles (for instance, a "french
fry"-like shape), or discs of varying thickness (for instance,
flattened spheres or egg-shapes) shapes, fourth. In some cases,
some shapes may work better than others at holding their shape in
different applications, or may function better than others for
certain purposes, e.g. distributing proppants or enclosed
additives. FIG. 1d schematically illustrates how different shapes
may contain various other materials. It will be appreciated that
these various characteristics may be combined with each other so
that discrete bodies may be customized for a particular
application.
[0082] The first fluid or second fluid may also contain other
conventional additives common to the well service industry such as
surfactants, biocides, gelling agents, crosslinking agents, curable
resins, hardening agents, solvents, foaming agents, demulsifiers,
buffers, clay stabilizers, acids, or mixtures thereof. Other
additives may include, but are not necessarily limited to,
piezoelectric particles, metal particles, metal complexes, metal
salts, fines control agents, solid acids, solid high pH buffers,
salts, chelants, oxidizers, plant and fish oils, mineral oils,
shape memory polymers, fibers, glass spheres, encapsulations and
combinations thereof.
[0083] In an embodiment, illustrated in FIG. 2a, discrete bodies 10
may include spherical encapsulant 12 containing a treatment agent.
FIG. 2b illustrates discrete body 14 containing a dispersed or
soluble treatment agent 16. The treatment agent may include, but
not be limited to, biocides, tracers, proppants, self-assembling
nanocoating agents for modifying fracture face properties,
surfactants, scale inhibitors, asphaltene inhibitors, hydrogen
sulfide scavengers, polymer breakers, VES breakers, microemulsions
to improve treatment fluid cleanup, other treatment fluid cleanup
agents, fines migration control additives, fines migration control
nanoparticles, fracture imaging materials (diagnostic agents that
interact with signals and sensors), delayed release additives and
combinations thereof. For instance, one type of nanocoating agent
may be surface-modifying agents to introduce hydrophobicity and/or
oleophobicity to the fracture surfaces. In a preferred though
non-limiting embodiment, the second fluid may contain an internal
viscosity breaker to enable the viscous material to break at
targeted locations within the formation under downhole conditions.
In an embodiment, spherical encapsulant 12 as well as treatment
agent 16 may be blended into the viscous material in the device
reservoir prior to being extruded through a conduit into discrete
bodies 10.
[0084] The second fluid may further contain proppant. FIG. 2c
illustrates discrete body 18 containing dispersed proppant
particles 20.
[0085] The viscous materials disclosed herein are effective in
promoting distribution of proppants in complex fracture networks.
Particularly by wedging or elongating and/or flattening within the
complex fractures to lodge the proppant particles in place, such as
small unconventional proppants designed to create transitional
nanodarcy to microdarcy to millidarcy conductivity in the narrow
secondary, tertiary, quaternary, and the like complex fractures
that typically remain unpropped due to the size and use of only
conventional proppants like 20/40 and 30/70 mesh sand and ceramic
proppants.
[0086] In an embodiment, the proppant having an apparent specific
gravity (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.
[0087] 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. 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. Further, lightweight particulate
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.
[0088] The proppants for use in the second fluid most preferably
have an ASG between from about 0.9 to about 1.8, and most
preferably from about 1.0 to about 1.2. The smaller size will
depend on the complex fracture widths for the particular lithology
that is hydraulically fracture treated. In some cases, such
proppants will be less than 1 mm but larger than 10 microns in
size.
[0089] Conventional proppants, such as sand, quartz, ceramics,
silica, glass and bauxite, may be used and are more typically used
for wider complex fractures and planar fracture to provide
millidarcy to macrodarcy fracture conductivities.
[0090] Conductivity of the primary fracture may be enhanced by
pumping into the formation a second stage. The viscosity of the
second stage fluid(s) is generally greater than the viscosity of
first fluid or second fluid. Typically, the viscosity of the second
stage fluid(s) is greater than 10 cps at 80.degree. F. at 100
sec.sup.-1. In some circumstances, the fluid of the second stage
may be the same as the first fluid of the first stage.
[0091] The second stage fluid(s) may contain any of the
viscosifying polymers or viscoelastic surfactants referenced in the
paragraphs above. Thus, the second stage fluid(s) may contain of
the aforementioned linear polymers, crosslinked polymers,
viscoelastic surfactants, as well as combinations thereof.
[0092] Further, the second stage fluid(s) may contain a proppant.
Suitable proppant may include any of the proppants referenced in
the paragraphs above include conventional heavier proppants such as
sand, bauxite, glass, etc. as well as lightweight proppants having
an ASG less than 2.45.
[0093] In some embodiments, selection of proppant is designed in
order to form a partial monolayer of proppant within created or
enlarged fracture(s).
[0094] Fracture conductivity may be enhanced with any created or
enlarged fracture(s) by varying the size of the proppant within the
first fluid or second fluid; the apparent specific gravity of the
proppant within the first fluid or second fluid; or the shape of
the proppant within the first fluid or second fluid.
[0095] Depending on the formation being treated, all or part of the
second stage fluid may be pumped into the formation prior to
pumping of the first fluid, prior or after pumping of the first
fluid but prior to pumping of the second fluid of the first
stage.
[0096] The method of the disclosure further helps in the creation
of a transition of propped fracture conductivity from the fracture
tip to the wellbore, starting with nanodarcy permeabilities at the
fracture tips, to microdarcy permeabilities in the complex,
secondary fractures to millidarcy to darcy permeabilities near the
primary fracture, then to darcy to macrodarcy permeabilities within
the primary propped fracture. Such transitional fracture
conductivity and the control of conductivity within the complex
fracture network may be attributable to the presence of the viscous
material in the pumped fluid coupled with proppant placement and
distribution within the fractures.
[0097] In non-limiting embodiment, the conductivity ratio (Cr)
defined by Ccf/Cpf, wherein Ccf is the conductivity of the complex
fracture network and Cpf is the conductivity of the planar fracture
divided by 1000, has been noted to be is greater when the first
fluid and the at least one second fluid are pumped into the
formation versus when only the first fluid is pumped into the
formation.
[0098] Referring to FIG. 3a viscous material 20 within second fluid
18 is shown entering fracture 22. As the width of the fracture 22
narrows viscous material 20 interacts with the fracture walls.
Viscous material 20 is illustrated as masses of discrete bodies.
FIG. 3b illustrates examples of specific type of discrete bodies
20a that may more easily deform in the narrow fracture region of
fracture 22. The deformation of bodies 20a are by interaction with
the walls of fracture 22, where the shear force relatively thins
the viscosity of bodies 20a. The more they shear thin and deform
the more fluid-like bodies 20a become. Depending on their initial
viscosity and fracture wall-induced shear thinning properties,
bodies 20a become discrete viscous fluid bodies 26 that occupy
greater fracture surface area within the narrow region of fracture
22, as represented by viscous deformed masses 26. Viscous deformed
masses 26 represent the adaptive properties of high viscosity
bodies 20a, where they can be transformed or modified in situ into
discrete viscous fracturing fluid masses.
[0099] The ability to transform viscous material 20a into viscous
fluid masses 26 promotes unique hydraulic pressure with the first
fluid within the fracture 22, generating a combined second fluid
hydraulic pressure medium to slow and eventually prevent further
fracture growth and the restrictive flow pressure will initiate a
new fracture and create fluid diversion. Additionally, viscous
fluid masses 26 can occupy greater fracture surface area the deeper
masses 26 penetrate. When the masses of the discrete bodies 20a
contain proppant and create greater fracture surface area masses 26
they will thus create channel-type conductivity, as illustrated in
FIG. 3b.
[0100] As further schematically illustrated in FIG. 5b, viscous gel
bodies 20a generate viscosity only in very narrow fractures. Narrow
fractures may be defined as less than 1 mm wide, and may range from
about 1 .mu.m (micrometer) up to 1 mm. The typical range where
viscous gel bodies 20a generate viscosity and form high fracture
surface area fluid masses 26 will be from 0.5 mm to 0.02 mm, in one
non-limiting example. For relatively wider fracture widths,
discrete bodies 26 will retain their shapes as shown in the left
side of FIG. 3b. However, for very narrow fracture widths, as at
the bottom of fracture 22 in FIG. 3a, and the right side of FIG.
3b, discrete bodies 20a may form wall-shear deformed discrete fluid
masses 26 and generate viscosity in second fluid 18 as well as
provide the diverting function. Thus, where bodies 20a are wedged
in the tip of fracture 22, they will shear thin and optimize to the
local fluid pressure conditions for limiting fracture growth and
preferentially induce a new fracture off of fracture 22.
[0101] Conductivity limited "choke points" may also be reduced by
the viscous material and proppant retained at restrictive flow
locations in the complex fracture network during the treatment. The
method thus provides greater versatility in treatment design,
control and results than methods practiced previously.
[0102] FIG. 4 is a schematic illustration of possible choke points
in a complex fracture network having a wellbore 30 from which
extends a primary, propped fracture 32, and a plurality of more
complex, unpropped fractures 34. The extent of SRV is illustrated.
The value X.sub.pf is the half-length of primary fracture 32, which
is a bilength of the total fracture since a biwing (not shown)
extends from wellbore 30 on the opposite side. The value d.sub.r is
the distance between unpropped fractures 34 and L.sub.sf is the
length of the secondary fractures extending from primary fracture
32. Potential conductivity choke points 36 are the locations in the
fracture network having insufficient fracture conductivity. Such
choke points restrict the rate of flow of hydrocarbons. The
incidence and/or extent of conductivity choke points 36 may be
reduced by viscous material 20 which may contain proppant and which
are retained at such restrictive flow locations in the complex
fracture network. The ability to pinpoint placement of proppant by
selectively sized viscous material within the second fluid that
become wedged at such locations will prevent or greatly reduce the
lack of propped fracture conductivity at these locations.
[0103] Numerous advantages have been noted by used of the disclosed
method to create a complex fracture network. Such advantages may be
attributable to the fact that (i) the viscosity of the second fluid
of the first stage is more adept than the conventional fluids such
as slickwater and viscous crosslinked polymer systems for creating
complex fracture networks; (ii) the second fluid containing the
viscous material exhibits brine-like viscosity from the surface to
the fractures; (iii) the ability to target deeper and more narrower
fracture regions before the viscous material interacts with the
fracture walls; (iv) the promotion by the second fluid of increased
hydraulic pressure during flow only within narrow width fractures;
(v) the promotion by the second fluid of pressure-initiated
fractures; yl) the ability of the second fluid with the defined
viscous material to create deeper fluid diversion and fracture
complexity; and (vi) the ability to target and engineer placement
treatment additives deeper within the complex fractures.
[0104] Embodiments of the present disclosure thus offer advantages
over the prior art and are well adapted to carry out one or more of
the objects of this disclosure. However, the present disclosure
does not require each of the components and acts described above
and are in no way limited to the above-described embodiments or
methods of operation. Any one or more of the above components,
features and processes may be employed in any suitable
configuration without inclusion of other such components, features
and processes. Moreover, the present disclosure includes additional
features, capabilities, functions, methods, uses and applications
that have not been specifically addressed herein but are, or will
become, apparent from the description herein, the appended drawings
and claims.
[0105] The methods that may be described above or claimed herein
and any other methods which may fall within the scope of the
appended claims can be performed in any desired suitable order and
are not necessarily limited to any sequence described herein or as
may be listed in the appended claims. Further, the methods of the
present disclosure do not necessarily require use of the particular
embodiments shown and described herein, but are equally applicable
with any other suitable structure, form and configuration of
components.
[0106] While exemplary embodiments of the disclosure have been
shown and described, many variations, modifications and/or changes
of the system, apparatus and methods of the present disclosure,
such as in the components, details of construction and operation,
arrangement of parts and/or methods of use, are possible,
contemplated by the patent applicant(s), within the scope of the
appended claims, and may be made and used by one of ordinary skill
in the art without departing from the spirit or teachings of the
disclosure and scope of appended claims. Thus, all matter herein
set forth or shown in the accompanying drawings should be
interpreted as illustrative, and the scope of the disclosure and
the appended claims should not be limited to the embodiments
described and shown herein.
* * * * *