U.S. patent application number 14/163298 was filed with the patent office on 2015-07-30 for fracturing methods and systems.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is SCHLUMBERGER TECHNOLOGY CORPORATION. Invention is credited to J. Ernest Brown, Dmitriy Ivanovich Potapenko.
Application Number | 20150211346 14/163298 |
Document ID | / |
Family ID | 53678567 |
Filed Date | 2015-07-30 |
United States Patent
Application |
20150211346 |
Kind Code |
A1 |
Potapenko; Dmitriy Ivanovich ;
et al. |
July 30, 2015 |
FRACTURING METHODS AND SYSTEMS
Abstract
Hybrid gas fracturing methods and systems utilizing an early
stage gas treatment fluid, which may contain a dispersed phase of
fluid loss control agent particles, followed by a proppant stage(s)
to form a fracture system having a branched tip region and a
propped region between the branched tip region and the wellbore.
Also, treatment fluids suitable for use in the methods and systems
are disclosed.
Inventors: |
Potapenko; Dmitriy Ivanovich;
(Sugar Land, TX) ; Brown; J. Ernest; (Sugar Land,
TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
SCHLUMBERGER TECHNOLOGY CORPORATION |
Sugar Land |
TX |
US |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
Sugar Land
TX
|
Family ID: |
53678567 |
Appl. No.: |
14/163298 |
Filed: |
January 24, 2014 |
Current U.S.
Class: |
166/280.2 ;
166/280.1 |
Current CPC
Class: |
E21B 43/267 20130101;
E21B 43/26 20130101 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/267 20060101 E21B043/267 |
Claims
1. A method for treating a subterranean formation traversed by a
wellbore, comprising: injecting a substantially proppant-free early
stage comprising a continuous gas phase into the formation above a
fracturing pressure to form a fracture system comprising a branched
tip region; and injecting a proppant stage comprising a treatment
fluid comprising proppant, wherein the viscosity of the proppant
stage is greater than the early stage, wherein the injecting the
proppant stage behind the early stage forms a propped region of the
fracture system for communication between the wellbore and the
branched tip region.
2. The method of claim 1, wherein the early stage comprises
particles dispersed in the continuous gas phase as a fluid loss
control agent.
3. The method of claim 2, wherein the particles dispersed in the
continuous gas phase comprise fines having a diameter of less than
50 microns and are substantially free of solids having a diameter
greater than 100 microns.
4. The method of claim 2, wherein the particles dispersed in the
continuous gas phase comprise from 0.5 to 10 percent by volume
based on the total volume of the gas stage.
5. The method of claim 1, wherein the early stage comprises liquid
or foam phase particles dispersed as a mist in the gas phase.
6. The method of claim 5, wherein the dispersed liquid or foam
phase particles comprise microdroplets having a diameter of less
than 100 microns.
7. The method of claim 5, wherein the particles dispersed in the
continuous gas phase are aqueous and comprise a foaming agent.
8. The method of claim 5, wherein the mist further comprises fines
having a diameter of less than 50 microns and is substantially free
of solids having a diameter greater than 100 microns.
9. The method of claim 1, wherein the one or more proppant stages
comprise slickwater and a proppant loading from 0.01 to 0.6 g/mL of
carrier fluid (0.1-5 ppa).
10. The method of claim 1, wherein the one or more proppant stages
comprise an aqueous or oil-based carrier fluid, a viscosifier and a
proppant loading of at least 0.6 g/mL of carrier fluid (5 ppa).
11. The method of claim 1, wherein the one or more proppant stages
comprise a high solid content fluid.
12. The method of claim 1, wherein the one or more proppant stages
comprise alternating proppant concentration between successive
proppant stages.
13. The method of claim 1, further comprising injecting one or more
substantially proppant-free stages between successive ones of the
proppant stages.
14. The method of claim 1, wherein the one or more proppant stages
comprise carrier fluid, proppant and agglomerant, wherein injection
of the one or more proppant stages forms a substantially uniformly
distributed mixture of the proppant and the agglomerant, and
wherein the proppant and the agglomerant have dissimilar velocities
in the fracture system to transform the substantially uniformly
distributed mixture into areas that are rich in proppant and areas
that are substantially free of proppant.
15. The method of claim 1, wherein the one or more proppant stages
comprise proppant and shapeshifting particles dispersed in a
carrier fluid, and further comprising changing a conformation of
the shapeshifting particles in the fracture system.
16. The method of claim 1, further comprising: continuously
distributing the proppant into the fracture system during the
injection of the one or more proppant stages; aggregating the
proppant distributed into the fracture to form spaced-apart
clusters in the fracture system; anchoring at least some of the
clusters in the fracture system to inhibit aggregation of at least
some of the clusters; reducing pressure in the fracture system to
form interconnected, hydraulically conductive channels between the
clusters in the propped region of the fracture system.
17. The method of claim 1, further comprising: injecting the one or
more proppant stages at a continuous rate with a continuous
proppant concentration; while maintaining the continuous rate and
proppant concentration, successively alternating concentration
modes of an anchorant in the one or more proppant stages between a
plurality of relatively anchorant-rich modes and a plurality of
anchorant-lean modes.
18. The method of claim 1, wherein the early stage is injected as a
pre-pad stage and the method further comprises injecting a foam or
liquid pad stage into the fracture system following the pre-pad
stage prior to the one or more proppant stages.
19. The method of claim 1, further comprising injecting a flush
stage into the fracture system following the one or more proppant
stages.
20. A reservoir fluid production system comprising: a wellbore
penetrating a subterranean formation; and the fracture system
obtained by the method of claim 1 in fluid communication with the
wellbore.
21. The system of claim 20, wherein the branched tip region of the
fracture system is substantially proppant-free.
22. A system to treat a subterranean formation, comprising: a
subterranean formation penetrated by a wellbore; a gas injection
unit to supply a gas treatment fluid stage, substantially free of
proppant and comprising a continuous gas phase, to the formation
above a fracturing pressure to form a fracture system comprising a
branched tip region; and a pump system to supply one or more
proppant stages, comprising a treatment fluid comprising proppant
and having a viscosity greater than the gas treatment fluid stage,
into the fracture system behind the gas treatment fluid stage to
form a propped region of the fracture system to communicate between
the wellbore and the branched tip region.
Description
BACKGROUND
[0001] The statements in this section merely provide background
information related to the present disclosure and may not
constitute prior art.
[0002] Gas fracturing, either with compressed gas alone or with
proppant, has been used to create conductive pathways in a
subterranean formation and increase fluid flow between the
formation and the wellbore. The gas is injected into the wellbore
passing through the subterranean formation at very high rates to
offset high leakoff into the formation being treated. Even without
proppant, the fractures created may have sufficient conductivity
due to their length and dendricity to enable production of
reservoir fluids comparable to fractures in the same formation
conventionally filled with proppant. Accordingly, there is a demand
for further improvements in this area of technology.
SUMMARY
[0003] In some embodiments according to the disclosure herein,
hybrid gas fracturing methods and systems are employed to obtain a
branched gas-fractured tip region and a propped region to
communicate between the wellbore and the branched tip region.
[0004] In some embodiments, a method for treating a subterranean
formation penetrated by a wellbore may comprise injecting an early
stage comprising a continuous gas phase, which may be substantially
proppant-free, into the formation above a fracturing pressure to
form a fracture system comprising a branched tip region; and
injecting one or more proppant stages, comprising a treatment fluid
comprising proppant and having a viscosity greater than the early
stage, into the formation behind the early stage to form a propped
region of the fracture system to communicate between the wellbore
and the branched tip region.
[0005] In some embodiments, a reservoir production system may
comprise a wellbore penetrating a subterranean formation; and the
fracture system obtained by the method described herein in fluid
communication with the wellbore.
[0006] In some embodiments, a system to treat a subterranean
formation may comprise a subterranean formation penetrated by a
wellbore; a gas injection unit to supply a gas treatment fluid
stage comprising a continuous gas phase, which may be substantially
free of proppant, to the formation above a fracturing pressure to
form a fracture system comprising a branched tip region; and a pump
system to supply one or more proppant stages, comprising a
treatment fluid comprising proppant and having a viscosity greater
than the gas treatment fluid stage, into the fracture system behind
the gas treatment fluid stage to form a propped region of the
fracture system to communicate between the wellbore and the
branched tip region.
BRIEF DESCRIPTION OF THE DRAWINGS
[0007] These and other features and advantages will be better
understood by reference to the following detailed description when
considered in conjunction with the accompanying drawings.
[0008] FIG. 1 schematically illustrates a fracture system with a
branched tip region formed by early-stage gas fracturing according
to embodiments.
[0009] FIG. 2 schematically illustrates the fracture system of FIG.
1 following subsequent injection of one or more proppant stages
according to embodiments.
[0010] FIG. 3 schematically illustrates a heterogeneously propped
region of a hybrid fracture as seen generally along the lines 3-3
of FIG. 2 following formation of proppant pillars and fracture
closure according to embodiments.
DETAILED DESCRIPTION
[0011] For the purposes of promoting an understanding of the
principles of the disclosure, reference will now be made to some
illustrative embodiments of the current application. Like reference
numerals used herein refer to like parts in the various drawings.
Reference numerals without suffixed letters refer to the part(s) in
general; reference numerals with suffixed letters refer to a
specific one of the parts.
[0012] As used herein, "embodiments" refers to non-limiting
examples of the application disclosed herein, whether claimed or
not, which may be employed or present alone or in any combination
or permutation with one or more other embodiments. Each embodiment
disclosed herein should be regarded both as an added feature to be
used with one or more other embodiments, as well as an alternative
to be used separately or in lieu of one or more other embodiments.
It should be understood that no limitation of the scope of the
claimed subject matter is thereby intended, any alterations and
further modifications in the illustrated embodiments, and any
further applications of the principles of the application as
illustrated therein as would normally occur to one skilled in the
art to which the disclosure relates are contemplated herein.
[0013] Moreover, the schematic illustrations and descriptions
provided herein are understood to be examples only, and components
and operations may be combined or divided, and added or removed, as
well as re-ordered in whole or part, unless stated explicitly to
the contrary herein. Certain operations illustrated may be
implemented by a computer executing a computer program product on a
computer readable medium, where the computer program product
comprises instructions causing the computer to execute one or more
of the operations, or to issue commands to other devices to execute
one or more of the operations.
[0014] It should be understood that, although a substantial portion
of the following detailed description may be provided in the
context of oilfield fracturing operations, other oilfield
operations such as cementing, gravel packing, etc., or even
non-oilfield well treatment operations, can utilize and benefit as
well from the instant disclosure.
[0015] In some embodiments disclosed herein, a method for treating
a subterranean formation penetrated by a wellbore may comprise
injecting a substantially proppant-free early stage comprising a
continuous gas phase into the formation above a fracturing pressure
to form a fracture system comprising a branched tip region; and
injecting one or more proppant stages, comprising a treatment fluid
comprising proppant and having a viscosity greater than the early
stage, into the formation behind the early stage to form a propped
region of the fracture system to communicate between the wellbore
and the branched tip region.
[0016] According to some embodiments, a hybrid method for treating
a subterranean formation penetrated by a wellbore comprises
injecting a substantially proppant-free early stage comprising a
continuous gas phase, and optionally a mist phase as described
herein, into the formation above a fracturing pressure to form a
fracture system comprising a branched tip region, and injecting one
or more proppant stages, comprising a treatment fluid comprising
proppant and having a viscosity greater than the early stage, into
the formation behind the early stage to form a propped region of
the fracture system to communicate between the wellbore and the
branched tip region. According to some embodiments, the early stage
comprises particles dispersed in the continuous gas phase, as
described above, as a fluid loss control agent, e.g., particles
dispersed in the continuous gas phase comprising fines having a
diameter of less than 50 microns and are substantially free of
solids having a diameter greater than 100 microns.
[0017] In some embodiments, the early stage comprises particles
dispersed in the continuous gas phase as a fluid loss control
agent, e.g., as a mist phase to deposit a fluid loss control agent
on the exposed fracture faces to inhibit fluid loss from the gas
treatment fluid stage for improved fracture efficiency. A "fluid
loss control agent," sometimes referred to herein as a "fluid loss
agent" or "loss agent," refers to a material in the fluid that can
inhibit loss of the fluid through contact with a permeable
structure to a region of lower pressure.
[0018] In some embodiments of the method, treating a subterranean
formation penetrated by a wellbore comprises injecting, above a
fracturing pressure into a fracture in the formation, a gas
treatment fluid stage substantially free of proppant and comprising
a continuous gas phase and a mist phase comprising a liquid or foam
dispersed in the continuous gas phase; depositing particles from
the mist phase onto a surface of the formation to inhibit fluid
loss into a matrix of the formation; and reducing the pressure in
the fracture to form a network of conductive gas-fractured flow
paths in the formation.
[0019] The gas phase in various embodiments may comprise any
material or mixture of materials that is a gas at any or all
downhole or formation temperature(s) and pressure(s) used during
the gas fracturing, including a supercritical fluid. As used
herein, supercritical refers to a fluid above both its critical
temperature and its critical pressure, whereas subcritical refers
to a fluid which is below its critical temperature, or below its
critical pressure, or both. Gases, including supercritical fluids,
may have a viscosity at the fracturing conditions equal to or less
than about 100 .mu.Pa-s. Representative gases for the continuous
gas phase include nitrogen, air, carbon dioxide, methane, ethane,
and the like.
[0020] In some embodiments, the continuous gas phase comprises a
supercritical fluid, e.g., a supercritical fluid having a viscosity
in the range of 10 to 100 .mu.Pa-s. In some embodiments, the use of
a supercritical fluid as the gas phase inhibits gas leakoff since
supercritical fluids generally have a higher viscosity than their
non-supercritical counterpart gases and hence a lower permeation
rate into the formation matrix.
[0021] In some embodiments, the gas phase is a subcritical fluid,
and in some further embodiments the use of a subcritical gas phase,
e.g., with a generally lower viscosity less than about 10 .mu.Pa-s
and thus having a tendency for a higher leakoff rate which might
make them otherwise impractical for use in gas fracturing, is
facilitated by the presence of the leakoff inhibition obtained by
the presence of the mist phase.
[0022] The mist phase in various embodiments may be any particles
(including fluid or foam droplets) that are suspended or otherwise
dispersed as a discontinuous phase in the continuous gas phase in a
disjointed manner, e.g., colloidal particles in an aerosol or
larger particles in a gas suspension. The term "dispersion" means a
mixture of one substance dispersed in another substance, and may
include colloidal or non-colloidal systems. In this respect, the
mist phase can also be referred to, collectively, as "particle" or
"particulate" which terms may be used interchangeably. As used
herein, the term "particle" should be construed broadly. For
example, in some embodiments, the particles of the current
application are fine solids, defined for the purposes herein as
having a particle size less than 10 microns, e.g., 1 to 10 .mu.m,
or ultrafine solids or colloids, defined for the purposes herein as
fine particles having a particle size less than 1 micron, e.g., 1
to 1000 nm; however, in some other embodiments, the particle(s) can
be liquid, foam, emulsified droplets, fine or ultrafine solids
coated by or suspended in liquid or foam, etc. The particles
comprising the mist phase may have a particle size distribution
that is either monodisperse or polydisperse, e.g., bimodal,
trimodal, tetramodal, or the like. Liquid and/or foam particles
whether containing solids or not, are almost always spherical or
nearly spherical, but may be irregular; whereas solid particles may
be spherical or irregular, e.g., with varying degrees of sphericity
and roundness, according to the API RP-60 sphericity and roundness
index. For example, the particle(s) used as fluid loss agents in
the mist phase may have an aspect ratio of more than 2, 3, 4, 5 or
6. Examples of such non-spherical particles include, but are not
limited to, fibers, flocs, flakes, discs, rods, grains, stars, etc.
All such variations should be considered within the scope of the
current application.
[0023] As used herein, "substantially free of proppant" refers to a
gas treatment fluid stage to which proppant or other solid
particles having a particle size of 100 microns or more is not
present, or if present, is present in amounts of less than 0.5
volume percent, or has not been deliberately added in amounts of
more than 0.5 volume percent, by total volume of the gas treatment
fluid stage, or if a mist phase is present, comprises less than 10
volume percent by volume of the mist phase.
[0024] In some embodiments herein, fluid loss control to inhibit
loss of the gas phase is effected by plugging at least a portion of
micropores in the formation matrix with a fluid loss control agent
such as fine solids, which results in a decrease in permeability
and thus a reduction of the gas penetration rate into the
formation. In some embodiments, at least a portion of the
micropores may be alternatively or additionally filled with a fluid
such as liquid, foam, or the like which has a higher viscosity
relative to the gas phase, which also contributes to a decreased
fluid penetration rate.
[0025] According to some embodiments, liquid, foam and/or solid
fluid loss agents may be delivered in a form of a mist or vapor,
and deposited on the fracture face, followed by penetration into
the pore spaces. In some embodiments, a foam, which generally has a
much higher viscosity than its liquid phase per se, may be used to
fill micropores to enhance loss control. In some embodiments, an
energized liquid may be used to fill micropores, and may thereafter
form a foam in situ upon expansion from the fracturing pressure to
the formation pressure. Such fluid loss agents in various
embodiments may also comprise several components, such as, for
example, clay stabilizing agent(s), surfactant(s), foaming
agent(s), corrosion inhibitor(s), gelling agent(s), delayed
crosslinking agent(s), pH agent(s), breaker(s), etc., including
combinations thereof.
[0026] According to some embodiments, the mist phase particles
comprise a size of less than 100 microns, e.g., less than 50
microns, less than 20 microns, less than 10 microns or less than 1
micron. According to some embodiments, the particles comprise
monophasic liquid, emulsion, foam, solids or a combination thereof.
According to some embodiments, the mist phase is aqueous, such as,
for example, comprised of water, brine, acid solutions, alkali
solutions, or the like. According to some embodiments, the mist
phase comprises a hydrophobic phase such as a hydrocarbon, e.g., a
subcritical hydrocarbon liquid. As used herein, subcritical refers
to a material which is below its critical temperature, or below its
critical pressure, or both. In some embodiments, the mist phase
comprises a mixture of water based liquids and organic liquids,
including emulsions. As used herein, "emulsion" generally means any
system with one liquid phase dispersed in another immiscible liquid
phase, and may apply to oil-in-water and water-in-oil emulsions,
including oil-in-water-in-oil and water-in-oil-in-water emulsions.
Invert or reverse emulsions refer to any water-in-oil emulsion in
which oil is the continuous or external phase and water is the
dispersed or internal phase.
[0027] According to some embodiments, the mist phase comprises a
hydrolyzable compound. According to some embodiments, the mist
phase comprises a degradable oil. In embodiments, the degradable
oil is any degradable oleaginous fluid such as, for example, an
oleophilic ester, ether, amide, amine, alcohol, glycoside, or
combination thereof, and may have a solubility in water of less
than 10 wt %, or less than 5 wt %, or less than 1 wt % at
25.degree. C. In embodiments, the degradable oil may be selected
from the group consisting of oleophilic monocarboxylic acid esters
comprising from 3 to 40 carbon atoms, oleophilic polycarboxylic
acid esters comprising from 4 to 40 carbon atoms, oleophilic ethers
comprising from 3 to 40 carbon atoms, oleophilic alcohols
comprising from 3 to 40 carbon atoms, and combinations thereof. In
some embodiments, the degradable oil is non-toxicological.
[0028] For purposes herein, a material having solubility in water
of less than 10 wt %, or less than 5 wt %, or less than 1 wt % at
25.degree. C. is said to be oleophilic. In some embodiments, the
degradable oil may comprise two or more moieties attached via a
functional group, e.g., a carboxylic acid, an alcohol, an amine, an
amide, a glycoside, an ether, in which the chain length of one of
the moieties is from 1 to 40, or from 6 to 30, or from 8 to 15
carbon atoms, with the remaining carbon atoms, or hydrogen atom(s)
in the case of an alcohol or an amine, forming the other moiety or
moieties. In some embodiments, the degradable oil undergoes
hydrolysis upon contact with an aqueous solution having a pH from
about 9 to 14 and/or a pH from about 0 to 5. In some embodiments,
the degradable oil has a hydrophilic-lipophilic balance of less
than 16, or less than 14, or less than 12, or less than 10, as
determined according to Griffin's method on a scale from 0 to 20 as
is readily understood by one having minimal skill in the art.
[0029] In embodiments, the degradable oil is converted from a
relatively water insoluble oil into its water soluble components
upon exposure to temperature, biological agents, acids, bases,
and/or the like present at, or provided to the intended location of
the fluid for a particular use, e.g., upon or after fracture
closure or otherwise after the degradable oil has been used as a
fluid loss agent during the gas fracturing operation. In some
embodiments, the degradable oil undergoes hydrolysis at a pH from
about 0 to 14, or at a pH of greater than or equal to about 9,
e.g., from about 9 to 14 or higher, and/or at a pH of less than or
equal to about 4, e.g., from about 4 to about 0 or less.
[0030] In some embodiments, the degradable oil comprises a
monocarboxylic acid ester having ecologically acceptable components
from the class of so-called non-polluting oils. Examples include
esters of "lower" carboxylic acids having from 1 to 10 carbons.
Suitable lower monocarboxylic acids include the reaction products
of monofunctional alcohols, polyfunctional alcohols, and the like.
Suitable alcohols include di- to tetra-hydric alcohols, lower
alcohols of this type, including having 2 to 6 carbon atoms.
Examples of such poly-hydric alcohols include aliphatic glycols
and/or propanediols such as ethylene glycol, 1,2-propanediol and/or
1,3-propanediol. Suitable alcohols can be of natural and/or
synthetic origin. Straight-chain and/or branched alcohols may be
used herein.
[0031] In some embodiments, the ester oils may be the reaction
product of long-chain acids having from 11 to 40 carbon atoms,
which may include unsaturated and/or polyunsaturated acids. The
carboxylic acid radicals present can be of vegetable and/or animal
origin. Vegetable starting materials include, for example, palm
oil, peanut oil, castor oil and/or rapeseed oil. The carboxylic
acids of animal origin include tallow, fish oils, rendering oils,
and the like. Other suitable degradable oils include anchovy oil,
castor oil, palm oil, virgin coconut oil, salmon oil, sunflower
oil, soy bean oil, cod liver oil, oil, C.sub.10-28 fatty acid
C.sub.1-10 alkyl esters (e.g., fatty acid methyl esters), and the
like.
[0032] In some embodiments, the ester-containing degradable oil may
be contacted with dilute alkali to produce a salt and an alcohol.
The formation of alcohol reduces the surface tension and alters
wettability. In the case of an emulsion with water as a continuous
phase and the ester based oil as the dispersed phase, the
hydrolysis of the oil will reduce the surface tension of the
continuous water phase and enhance wettability, which may likewise
enhance the flowback and cleanup in some embodiments.
[0033] In some embodiments, the degradable oleaginous oil may
include an ester, which, when contacted with an acid will hydrolyze
to produce an acid and an alcohol, which may reduce the surface
tension and enhance the wettability of the formation.
[0034] In some embodiments, the degradable oil is
non-toxicological, meaning it does not degrade into toxic
substances, or substances which have an acute toxicity such that
they would be considered hazardous or toxic in the intended
environment. In some embodiments, the degradable oil comprises less
than about 1 wt % aromatic content, or less than about 0.5 wt %, or
less than 0.1 wt % aromatic content.
[0035] In some embodiments, the degradable oil comprises a linear
alpha olefin, which may be of natural or synthetic origin.
[0036] In some embodiments, the degradable oil may comprise various
substituted and/or fully esterified triglycerides.
[0037] In some embodiments, the degradable oil may comprise
C.sub.2-C.sub.12 alkoxylates, e.g., ethoxylates, propoxylates,
and/or the like, including alkoxylated alcohols, acids, polyethers,
amines, amides, glycosides, and/or the like.
[0038] Suitable degradable oils include FlexiSOLV.RTM. dibutyl
ester (DBE) (INVISTA, Koch Industries, USA), which are high boiling
oxygenated solvents that are miscible with organic solvents, low
odor and flammability, comprising refined dimethyl esters of
adipic, glutaric and succinic acids. The DBE esters undergo
reactions expected of the ester group such as hydrolysis and
transesterification. At low and high pH the DBE esters are
hydrolyzed to the corresponding acids, their salts and alcohol. The
dibutyl ester components of dimethyl succinate, dimethyl glutarate
and dimethyl adipate are readily biodegradable.
[0039] Suitable examples further include AMSOIL.RTM. biodegradable
oil (AMSOIL INC., USA) which is designed to biodegrade when
subjected to sunlight, water and microbial activity. The
biodegradable oil is a blend of oleic vegetable oils and customized
synthetic esters. AMSOIL.RTM. oil exhibits high biodegradability
and low aquatic toxicity, along with superior oxidative stability,
and low temperature performance. It contains anti-oxidants that
ensure long oil life and foam inhibitors that promote problem-free
operation. It is hydrolytically stable and ideal for use where
water contamination is a problem.
[0040] Other suitable degradable oils include those disclosed in
U.S. Pat. Nos. 4,374,737; 4,614,604; 4,802,998; 5,232,910;
5,252,554; 5,254,531; 5,318,954; 5,318,956; 5,348,938; 5,403,822;
5,441,927; 5,461,028; 5,663,122; 5,755,892; 5,846,601; RE 36,066;
5,869,434; 6,022,833; 6,122,860; 6,165,946; 6,289,989; 6,350,788;
6,716,799; 6,806,235; 6,828,279; 7,041,738; 7,666,820; 7,741,248;
and 8,236,735; all of which are hereby incorporated by
reference.
[0041] According to some embodiments, the mist phase comprises a
material selected from the group consisting of esters, polyamines,
polyethers and combinations thereof. According to some embodiments,
the method further comprises degrading the mist particles deposited
on the formation surface to facilitate conductivity.
[0042] According to some embodiments, the mist phase comprises a
foaming agent and/or may be a foam. The term "foam" refers to a
stable mixture of gas(es) and liquid(s) that form a two-phase
system. Foam is generally described by its foam quality, i.e. the
ratio of gas volume to the foam volume (fluid phase of the
treatment fluid), i.e., the ratio of the gas volume to the sum of
the gas plus liquid volumes). If the foam quality is between 52%
and 95%, the fluid is usually called foam. Below 52%, the foam may
be referred to as an "energized fluid." Above 95%, foam is
generally changed to mist, i.e., dispersed liquid or foam droplets
in a continuous gas phase. In the present patent application, the
term "foam" also encompasses two-phase energized liquids and refers
to any stable mixture of gas and liquid, regardless of the foam
quality.
[0043] According to some embodiments, the mist phase comprises fine
solids less than 10 microns, or ultrafine solids less than 1
micron, or 30 nm to 1 micron. According to some embodiments, the
fine solids are fluid loss control agents such as .gamma.-alumina,
colloidal silica, CaCO3, SiO2, bentonite etc.; and may comprise
particulates with different shapes such as glass fibers, flocs,
flakes, films; and any combination thereof or the like. Colloidal
silica, for example, may function as an ultrafine solid loss
control agent, depending on the size of the micropores in the
formation, as well as a gellant and/or thickener in any associated
liquid or foam phase. As representative leakoff control agents,
there may be mentioned latex dispersions, water soluble polymers,
submicron particulates, particulates with an aspect ratio higher
than 1, or higher than 6, combinations thereof and the like, such
as, for example, crosslinked polyvinyl alcohol microgel. The fluid
loss agent can be, for example, a latex dispersion of
polyvinylidene chloride, polyvinyl acetate,
polystyrene-co-butadiene; a water soluble polymer such as
hydroxyethylcellulose (HEC), guar, copolymers of polyacrylamide and
their derivatives; particulate fluid loss control agents in the
size range of 30 nm to 1 micron, such as .gamma.-alumina, colloidal
silica, CaCO.sub.3, SiO.sub.2, bentonite etc.; particulates with
different shapes such as glass fibers, flakes, films; and any
combination thereof or the like. Fluid loss agents can if desired
also include or be used in combination with
acrylamido-methyl-propane sulfonate polymer (AMPS).
[0044] In embodiments, the leak-off control agent comprises a fine
or ultrafine solid that may removable by degradation, dissolution,
melting, or the like. In some embodiments, the fluid loss agent may
be a reactive solid, e.g., a hydrolysable material such as
polyglycolic acid (PGA), polylactic acid (PLA), PGA-PLA copolymers,
or the like; or it can include a soluble or solubilizable material
such as a wax, an oil-soluble resin, or another material soluble in
hydrocarbons, or calcium carbonate or another material soluble at
low pH; and so on. In embodiments, the leak-off control agent
comprises a reactive solid selected from ground quartz, oil soluble
resin, degradable rock salt, clay, zeolite or the like. In other
embodiments, the leak-off control agent comprises one or more of
magnesium hydroxide, magnesium carbonate, magnesium calcium
carbonate, calcium carbonate, aluminum hydroxide, calcium oxalate,
calcium phosphate, aluminum metaphosphate, sodium zinc potassium
polyphosphate glass, and sodium calcium magnesium polyphosphate
glass, or the like.
[0045] According to some embodiments, the mist phase comprises from
0.5 to 10 percent by volume, or less than 5 percent by volume of
the gas treatment fluid stage, based on the total volume of the gas
treatment fluid stage, as determined at the bottom hole pressure
and temperature where it enters the fracture.
[0046] According to some embodiments, the gas treatment fluid stage
is injected as a pad or pre-pad stage and the method further
comprises: injecting one or more proppant stages into the fracture
following the gas treatment fluid stage prior to fracture
closure.
[0047] According to some embodiments of the hybrid method, the one
or more proppant stages comprise slickwater and a proppant loading
from 0.01 to 0.6 g/mL of carrier fluid (0.1-5 ppa).
[0048] According to some embodiments of the hybrid method, the one
or more proppant stages comprise an aqueous or oil-based carrier
fluid, a viscosifier and a proppant loading of at least 0.6 g/mL of
carrier fluid (5 ppa).
[0049] According to some embodiments of the hybrid method, the one
or more proppant stages comprise a high solid content fluid, e.g.,
a slurry wherein a sum of all the particulates in the fracturing
slurry is greater than about 16 pounds per gallon of the carrier
fluid, or is greater than about 23 pounds per gallon of the carrier
fluid, or is greater than 30 pounds per gallon of the carrier
fluid, as disclosed in U.S. Pat. No. 7,784,541, herewith
incorporated by reference in its entirety.
[0050] According to some embodiments of the hybrid method, the one
or more proppant stages comprise alternating proppant concentration
between successive proppant stages and/or alternating stages of
proppant-containing hydraulic fracturing fluids contrasting in
their proppant-settling rates to form proppant clusters which
become pillars that prevent the fracture from completely closing,
as described in U.S. Pat. No. 6,776,235, herewith incorporated by
reference in its entirety.
[0051] According to some embodiments of the hybrid method, the
method may further comprise injecting one or more substantially
proppant-free stages between successive ones of the proppant
stages, as described in Patent Publication U.S. 2008/0135242,
herewith incorporated by reference in its entirety.
[0052] According to some embodiments of the hybrid method, the one
or more proppant stages comprise carrier fluid, proppant and
agglomerant, wherein injection of the one or more proppant stages
forms a substantially uniformly distributed mixture of the proppant
and the agglomerant, and wherein the proppant and the agglomerant
have dissimilar velocities in the fracture system to transform the
substantially uniformly distributed mixture into areas that are
rich in proppant and areas that are substantially free of proppant,
as described in U.S. application Ser. No. 13/832,938, filed Mar.
15, 2013, herewith incorporated herein by reference in its
entirety.
[0053] According to some embodiments of the hybrid method, the one
or more proppant stages comprise proppant and shapeshifting
particles dispersed in a carrier fluid, and further comprising
changing a conformation of the shapeshifting particles in the
fracture system, as described in U.S. application Ser. No.
14/056,665, filed Oct. 17, 2013 herewith incorporated herein by
reference in its entirety.
[0054] According to some embodiments of the hybrid method, the
method may further comprise: continuously distributing the proppant
into the fracture system during the injection of the one or more
proppant stages; aggregating the proppant distributed into the
fracture to form spaced-apart clusters in the fracture system;
anchoring at least some of the clusters in the fracture system to
inhibit aggregation of at least some of the clusters; and reducing
pressure in the fracture system to form interconnected,
hydraulically conductive channels between the clusters in the
propped region of the fracture system, as described in U.S.
application Ser. No. 13/974,203, filed Aug. 23, 2013, herewith
incorporated herein by reference in its entirety.
[0055] According to some embodiments of the hybrid method, the
method may further comprise: injecting the one or more proppant
stages at a continuous rate with a continuous proppant
concentration; while maintaining the continuous rate and proppant
concentration, successively alternating concentration modes of an
anchorant in the one or more proppant stages between a plurality of
relatively anchorant-rich modes and a plurality of anchorant-lean
modes, as also described in U.S. application Ser. No. 13/974,203,
filed Aug. 23, 2013, herewith incorporated herein by reference in
its entirety.
[0056] According to some embodiments of the hybrid method, the
method may further comprise: providing a treatment slurry
comprising an energized fluid, the proppant and an anchorant,
injecting the treatment slurry into a fracture to form a
substantially uniformly distributed mixture of the solid
particulate and the anchorant, and transforming the substantially
uniform mixture into areas that are rich in solid particulate and
areas that are substantially free of solid particulate, as
described in U.S. provisional Application Ser. No. 61/873,185,
filed Sep. 3, 2013, herewith incorporated herein by reference in
its entirety.
[0057] According to some embodiments of the hybrid method, the
proppant stage(s) may be injected into the fracture system using
any one of the available heterogeneous proppant placement
techniques, such as, for example, those disclosed in U.S. Pat. No.
3,850,247; U.S. Pat. No. 7,281,581; U.S. Pat. No. 7,325,608; U.S.
Pat. No. 7,044,220; WO 2007/086771; each of which is hereby
incorporated herein by reference in its entirety.
[0058] According to some embodiments of the hybrid method, the
early stage is injected as a pre-pad stage and the method further
comprises injecting a foam or liquid pad stage into the fracture
system following the pre-pad stage prior to the one or more
proppant stages. According to some embodiments of the hybrid
method, the method may further comprise injecting a flush stage
into the fracture system following the one or more proppant
stages.
[0059] According to some embodiments, a reservoir fluid production
system comprises a wellbore penetrating a subterranean formation;
and the fracture system obtained by the hybrid method described
herein in fluid communication with the wellbore. According to some
embodiments, the branched tip region of the fracture system is
substantially proppant-free.
[0060] According to some embodiments, a system to treat a
subterranean formation, comprises: a subterranean formation
penetrated by a wellbore; a gas injection unit to supply a gas
treatment fluid stage, substantially free of proppant and
comprising a continuous gas phase, to the formation above a
fracturing pressure to form a fracture system comprising a branched
tip region; and a pump system to supply one or more proppant
stages, comprising a treatment fluid comprising proppant and having
a viscosity greater than the gas treatment fluid stage, into the
fracture system behind the gas treatment fluid stage to form a
propped region of the fracture system to communicate between the
wellbore and the branched tip region.
[0061] With reference to FIG. 1, an initial gas fracturing stage
involves injecting the gas stage as described herein through the
wellbore 10 into the formation 12 to form a fracture system 14
having a relatively branched, dendritic tip region 16 extending
away from the wellbore. The width of the fracture is generally
dependent on the viscosity of the fracturing fluid, and since in
embodiments herein the continuous gas phase has a low viscosity,
e.g., less than 100 .mu.Pa-s, the tip region 16 may have fractures
that are too narrow to receive proppant.
[0062] FIG. 2 shows the fracture of FIG. 1 following subsequent
injection of one or more proppant stages into the fracture system
14 forming a relatively wide fracture, i.e., one which is capable
of receiving a treatment stage containing proppant in the
near-wellbore fracture region 18 of the fracture system 14'. In
some embodiments, the proppant is placed or formed into clusters
according to any of various heterogeneous proppant placement
techniques, e.g., by introducing alternating cluster-forming and
channel-forming substages, such as, for example, alternating
proppant-laden and proppant-lean substages.
[0063] FIG. 3 schematically illustrates the near-wellbore portion
18 of the fracture system 14' as seen along the lines 3-3 of FIG.
2, following formation of proppant pillars 20 generally
corresponding to proppant clusters placed or formed in accordance
with a heterogeneous proppant placement technique, and fracture
closure, according to some embodiments to form the ultimate
fracture system 14''. In the fracture system 14'' the gas fractured
tip region 16 (see FIG. 2) is in fluid communication with the
propped fracture region 18 via intersections 24 with gas-fractured
regions and/or via intersections 26 with additional propped
fracture regions, which may communicate with further regions of the
fracture network. Reservoir fluid from the tip region 16 may flow
through hydraulically conductive channels 22 around the pillars 20
(and/or through proppant pillars 20 and/or proppant filling the
fracture region 18, according to some embodiments where the
proppant pillars or other fracture fill mode is permeable).
[0064] Accordingly, the present disclosure provides the following
embodiments, among others: [0065] 1. A method for treating a
subterranean formation penetrated by a wellbore, comprising: [0066]
injecting a substantially proppant-free early stage comprising a
continuous gas phase into the formation above a fracturing pressure
to form a fracture system comprising a branched tip region; and
[0067] injecting one or more proppant stages, comprising a
treatment fluid comprising proppant and having a viscosity greater
than the early stage, into the formation behind the early stage to
form a propped region of the fracture system to communicate between
the wellbore and the branched tip region. [0068] 2. The method of
embodiment 1, wherein the early stage comprises particles dispersed
in the continuous gas phase as a fluid loss control agent, forming
a mist phase. [0069] 3. The method of embodiment 2, wherein the
mist phase comprises particles having a size of less than 100
microns, or less than 50 microns, or less than 20 microns, or less
than 10 microns, or from 1 to 10 microns, or less than 1 micron, or
from 1 to 1000 nm, wherein the particles comprise monophasic
liquid, emulsion, foam, solids or a combination thereof. [0070] 4.
The method of embodiment 2 or embodiment 3, wherein the mist phase
is aqueous. [0071] 5. The method of any one of embodiments 2 to 4,
wherein the mist phase comprises a hydrocarbon. [0072] 6. The
method of any one of embodiments 2 to 5, wherein the mist phase
comprises a hydrolyzable compound. [0073] 7. The method of any one
of embodiments 2 to 6, wherein the mist phase comprises a
degradable oil. [0074] 8. The method of any one of embodiments 2 to
7, wherein the mist phase comprises a material selected from the
group consisting of esters, polyamines, polyethers and combinations
thereof. [0075] 9. The method of any one of embodiments 2 to 8,
wherein the mist phase comprises a foaming agent. [0076] 10. The
method of any one of embodiments 2 to 9, wherein the mist phase
comprises fine solids, or ultrafine solids. [0077] 11. The method
of any one of embodiments 2 to 10, further comprising degrading the
mist particles deposited on the formation surface to facilitate
conductivity. [0078] 12. The method of any one of embodiments 2 to
11, wherein the mist phase comprises from 0.5 to 10 percent by
volume, or less than 5 percent by volume, based on the total volume
of the gas treatment fluid stage. [0079] 13. The method of any one
of embodiments 2 to 12, wherein the mist phase comprises less than
5 percent by volume of the gas treatment fluid stage, based on the
total volume of the gas treatment fluid stage. [0080] 14. The
method of any one of embodiments 1 to 13, wherein the one or more
proppant stages comprise slickwater and a proppant loading from
0.01 to 0.6 g/mL of carrier fluid (0.1-5 ppa). [0081] 15. The
method of any one of embodiments 1 to 13, wherein the one or more
proppant stages comprise an aqueous or oil-based carrier fluid, a
viscosifier and a proppant loading of at least 0.6 g/mL of carrier
fluid (5 ppa). [0082] 16. The method of any one of embodiments 1 to
15, wherein the one or more proppant stages comprise a high solid
content fluid. [0083] 17. The method of any one of embodiments 1 to
16, wherein the one or more proppant stages comprise alternating
proppant concentration between successive proppant stages. [0084]
18. The method of any one of embodiments 1 to 17, further
comprising injecting one or more substantially proppant-free stages
between successive ones of the proppant stages. [0085] 19. The
method of any one of embodiments 1 to 18, wherein the one or more
proppant stages comprise carrier fluid, proppant and agglomerant,
wherein injection of the one or more proppant stages forms a
substantially uniformly distributed mixture of the proppant and the
agglomerant, and wherein the proppant and the agglomerant have
dissimilar velocities in the fracture system to transform the
substantially uniformly distributed mixture into areas that are
rich in proppant and areas that are substantially free of proppant.
[0086] 20. The method of any one of embodiments 1 to 19, wherein
the one or more proppant stages comprise proppant and shapeshifting
particles dispersed in a carrier fluid, and further comprising
changing a conformation of the shapeshifting particles in the
fracture system. [0087] 21. The method of any one of embodiments 1
to 20, further comprising: [0088] continuously distributing the
proppant into the fracture system during the injection of the one
or more proppant stages; [0089] aggregating the proppant
distributed into the fracture to form spaced-apart clusters in the
fracture system; [0090] anchoring at least some of the clusters in
the fracture system to inhibit settling and/or aggregation of at
least some of the clusters; [0091] reducing pressure in the
fracture system to form interconnected, hydraulically conductive
channels between the clusters in the propped region of the fracture
system. [0092] 22. The method of any one of embodiments 1 to 21,
further comprising: [0093] injecting the one or more proppant
stages at a continuous rate with a continuous proppant
concentration; [0094] while maintaining the continuous rate and
proppant concentration, successively alternating concentration
modes of an anchorant in the one or more proppant stages between a
plurality of relatively anchorant-rich modes and a plurality of
anchorant-lean modes. [0095] 23. The method of any one of
embodiments 1 to 22, wherein the early stage is injected as a
pre-pad stage and the method further comprises injecting a foam or
liquid pad stage into the fracture system following the pre-pad
stage prior to the one or more proppant stages. [0096] 24. The
method of any one of embodiments 1 to 23, further comprising
injecting a flush stage into the fracture system following the one
or more proppant stages. [0097] 25. A reservoir fluid production
system comprising: [0098] a wellbore penetrating a subterranean
formation; and [0099] the fracture system obtained by the method of
any one of embodiments 1 to 24 in fluid communication with the
wellbore. [0100] 26. The system of embodiment 25, wherein the
branched tip region of the fracture system is substantially
proppant-free. [0101] 27. A system to treat a subterranean
formation, comprising: [0102] a subterranean formation penetrated
by a wellbore; [0103] a gas injection unit to supply a gas
treatment fluid stage, substantially free of proppant and
comprising a continuous gas phase, to the formation above a
fracturing pressure to form a fracture system comprising a branched
tip region; and [0104] a pump system to supply one or more proppant
stages, comprising a treatment fluid comprising proppant and having
a viscosity greater than the gas treatment fluid stage, into the
fracture system behind the gas treatment fluid stage to form a
propped region of the fracture system to communicate between the
wellbore and the branched tip region.
[0105] While the embodiments have been illustrated and described in
detail in the drawings and foregoing description, the same is to be
considered as illustrative and not restrictive in character, it
being understood that only some embodiments have been shown and
described and that all changes and modifications that come within
the spirit of the embodiments are desired to be protected. It
should be understood that while the use of words such as ideally,
desirably, preferable, preferably, preferred, more preferred or
exemplary utilized in the description above indicate that the
feature so described may be more desirable or characteristic,
nonetheless may not be necessary and embodiments lacking the same
may be contemplated as within the scope of the disclosure, the
scope being defined by the claims that follow. In reading the
claims, it is intended that when words such as "a," "an," "at least
one," or "at least one portion" are used there is no intention to
limit the claim to only one item unless specifically stated to the
contrary in the claim. When the language "at least a portion"
and/or "a portion" is used the item can include a portion and/or
the entire item unless specifically stated to the contrary.
* * * * *