U.S. patent application number 16/165362 was filed with the patent office on 2020-04-23 for methods for enhancing effective propped fracture conductivity.
The applicant listed for this patent is HALLIBURTON ENERGY SERVICES, INC.. Invention is credited to Larry Steven Eoff, Vishwajit Manajirao Ghatge, Christopher Austin Lewis, Philip D. Nguyen, Baidurja Ray.
Application Number | 20200123437 16/165362 |
Document ID | / |
Family ID | 70279403 |
Filed Date | 2020-04-23 |
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United States Patent
Application |
20200123437 |
Kind Code |
A1 |
Nguyen; Philip D. ; et
al. |
April 23, 2020 |
METHODS FOR ENHANCING EFFECTIVE PROPPED FRACTURE CONDUCTIVITY
Abstract
The present disclosure relates to oil and gas well proppant
compositions and methods for enhancing the conductivity of a
propped fracture formed during a hydraulic fracturing operation.
The method introduces a micro-proppant slurry prepared with
slickwater containing both a low-density and a conventional
micro-proppant during injection of the pad fluid stages to prop the
natural and induced microfractures open and then injecting a
proppant slurry prepared with slickwater containing low-density
proppant and conventional frac sand during proppant slurry stage to
prop the dominant fractures or large branches, provide open flow
paths to keep them connective with the wellbore.
Inventors: |
Nguyen; Philip D.; (Houston,
TX) ; Ray; Baidurja; (Jersey Village, TX) ;
Ghatge; Vishwajit Manajirao; (Katraj, IN) ; Eoff;
Larry Steven; (Porter, TX) ; Lewis; Christopher
Austin; (Houston, TX) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
HALLIBURTON ENERGY SERVICES, INC. |
Houston |
TX |
US |
|
|
Family ID: |
70279403 |
Appl. No.: |
16/165362 |
Filed: |
October 19, 2018 |
Current U.S.
Class: |
1/1 |
Current CPC
Class: |
C09K 8/80 20130101; E21B
43/267 20130101 |
International
Class: |
C09K 8/80 20060101
C09K008/80; E21B 43/267 20060101 E21B043/267 |
Claims
1. A method of treating a wellbore, comprising: isolating a first
interval extending from a wellbore in a subterranean formation;
introducing a first fluid into the first interval at a first
pressure sufficient to create or enhance at least one fracture in
the first interval; after introducing the first fluid, introducing
a second treatment fluid into the fracture, the second treatment
fluid comprising a first base fluid and a first proppant
composition, the first proppant composition comprising: a
low-density micro-proppant consisting essentially of proppant
particles with particulate sizes of from about 0.5 microns to about
100 microns, the low-density micro-proppant having a specific
gravity of from about 0.8 to about 1.3 grams per cubic centimeter;
and a conventional micro-proppant consisting essentially of
proppant particles with particulate sizes of from about 0.5 microns
to about 100 microns, the conventional micro-proppant having a
specific gravity of from about 2.1 to about 4.5 grams per cubic
centimeter; and after introducing the first fluid and the second
treatment fluid, introducing a third treatment fluid into the
fracture, the third treatment fluid comprising a second base fluid
and a second proppant composition, the second proppant composition
comprising: a low-density proppant consisting essentially of
proppant particles with particulate sizes of from about 100 microns
to about 2 millimeters, the low-density proppant having a specific
gravity of from about 0.8 to about 1.3 grams per cubic centimeter;
and a conventional proppant consisting essentially of proppant
particles with particulate sizes of from about 100 microns to about
2 millimeters, the conventional proppant having a specific gravity
of from about 2.1 to about 4.5 grams per cubic centimeter.
2. The method of claim 1, where the first fluid is selected from a
hydraulic fracturing fluid and a non-viscous aqueous treatment
fluid.
3. The method of claim 1, wherein the conventional proppant is frac
sand.
4. The method of claim 1, wherein the low-density micro-proppant is
present in the first proppant composition in an amount of from
about 1% to about 10% by weight of the conventional
micro-proppant.
5. The method of claim 1, wherein the conventional micro-proppant
is present in the first proppant composition in an amount of from
about 0.01 pound mass per gallon (lbm/gal) of the first base fluid
to about 0.2 lbm/gal of the first base fluid.
6. The method of claim 1, wherein the low-density proppant is
present in the second proppant composition in an amount of from
about 1% to about 10% by weight of the conventional proppant.
7. The method of claim 1, wherein the conventional proppant is
present in the second proppant composition in an amount of from
about 0.2 lbm/gal of the second base fluid to about 4 lbm/gal of
the second base fluid.
8. The method of claim 1, wherein the first and second proppant
compositions are substantially free of consolidating agents;
wherein the low-density and conventional micro-proppants are not
agglomerated and do not form proppant aggregates; and wherein the
low-density and conventional proppants are not agglomerated and do
not form proppant aggregates.
9. The method of claim 2, wherein the first fluid is a treatment
fluid and the first fluid, the first base fluid and the second base
fluid include slickwater.
10. A method of treating a wellbore, comprising: isolating a first
interval in a wellbore; introducing a first treatment fluid into
the first interval at a first pressure sufficient to create or
enhance at least one fracture in the first interval, the first
treatment fluid being substantially free from proppant
agglomerations; wherein introducing the first treatment fluid
comprises at least a first micro-proppant stage, the first
micro-proppant stage comprising introducing: a first base fluid; a
low-density micro-proppant having proppant particles with
particulate sizes of from about 0.5 microns to about 100 microns
and a specific gravity of from about 0.8 to about 1.3 grams per
cubic centimeter; and a conventional micro-proppant having proppant
particles approximately the same particulate size as the proppant
particles of the low-density micro-proppant and a specific gravity
of from about 2.1 to about 4.5 grams per cubic centimeter; after
introducing the first treatment fluid, introducing a second
treatment fluid into the first interval, the second treatment fluid
being substantially free from proppant agglomerations; wherein
introducing the second treatment fluid comprises at least a first
proppant stage, the first proppant stage comprising introducing: a
second base fluid; a conventional proppant having a specific
gravity of from about 2.1 to about 4.5 grams per cubic centimeter
and having proppant particles with particulate sizes of greater
than 100 microns; and a low-density proppant having proppant
particles approximately the same particulate size as the proppant
particles of the conventional proppant and a specific gravity less
than the specific gravity of the conventional proppant.
11. The method of claim 10, wherein introducing the first treatment
fluid further comprises a second micro-proppant stage and
introducing the second treatment fluid comprises a second proppant
stage.
12. The method of claim 10, wherein the conventional proppant is
frac sand.
13. The method of claim 10, wherein the low-density micro-proppant
is present in the first micro-proppant stage in an amount of from
about 1% to about 10% by weight of the conventional micro-proppant;
or the conventional micro-proppant is present in the first
micro-proppant stage in an amount of from about 0.01 pound mass per
gallon (lbm/gal) of the first base fluid to about 0.2 lbm/gal of
the first base fluid.
14. The method of claim 10, wherein the low-density proppant is
present in the first proppant stage in an amount of from about 1%
to about 10% by weight of the conventional proppant; or the
conventional proppant is present in the first proppant stage in an
amount of from about 0.2 lbm/gal of the second base fluid to about
4 lbm/gal of the second base fluid.
15. A method of treating a wellbore, comprising: isolating a first
interval extending from a wellbore in a subterranean formation, the
first interval comprising at least one fracture; introducing a
first treatment fluid into the first interval, the first treatment
fluid comprising a first base fluid and a conventional
micro-proppant comprising particles with particulate sizes of from
about 0.5 microns to about 100 microns and having a specific
gravity of from about 2.1 to about 4.5 grams per cubic centimeter;
introducing a first low-density micro-proppant into the first
treatment fluid, the first low-density micro-proppant comprising
particles with particulate sizes of from about 0.5 microns to about
100 microns and having a specific gravity of from about 0.8 to
about 1.3 grams per cubic centimeter; after introducing the first
treatment fluid, introducing a second treatment fluid into the
first interval, the second treatment fluid comprising a second base
fluid and a conventional proppant comprising proppant particles
with particulate sizes greater than about 100 microns and having a
specific gravity of from about 2.1 to about 4.5 grams per cubic
centimeter; and introducing a first low-density proppant into the
second treatment fluid, the first low-density proppant comprising
proppant particles with particulate sizes greater than about 100
microns and having a specific gravity of from about 0.8 to about
1.3 grams per cubic centimeter; wherein the first and second
treatment fluids are substantially free of consolidating
agents.
16. The method of claim 15, wherein introducing the first
low-density micro-proppant into the first treatment fluid comprises
pulsing the first low-density micro-proppant into a stream of the
first treatment fluid.
17. The method of claim 15, wherein introducing the first
low-density proppant into the second treatment fluid comprises
pulsing the first low-density proppant into a stream of the second
treatment fluid.
18. The method of claim 15, wherein the first low-density
micro-proppant is added to the first interval in an amount of from
about 4% to about 10% by weight of the conventional micro-proppant;
or the conventional micro-proppant is added to the first treatment
fluid in an amount of from about 0.01 pound mass per gallon
(lbm/gal) of the first base fluid to about 0.2 lbm/gal of the first
base fluid.
19. The method of claim 15, wherein the first low-density proppant
is added to the first interval in an amount of from about 1% to
about 10% by weight of the conventional proppant; or the
conventional proppant is added to the first treatment fluid in an
amount of from about 0.2 lbm/gal of the second base fluid to about
4 lbm/gal of the second base fluid.
20. The method of claim 15, further comprising: after introducing
the second treatment fluid, introducing a third treatment fluid
into the first interval, the third treatment fluid comprising a
third base fluid and a second low-density micro-proppant comprising
particles with particulate sizes of from about 0.5 microns to about
100 microns and having a specific gravity of from about 0.8 to
about 1.3 grams per cubic centimeter; and after introducing the
third treatment fluid, introducing a fourth treatment fluid into
the first interval, the fourth treatment fluid comprising a fourth
base fluid and a second low-density proppant comprising proppant
particles with particulate sizes greater than about 100 microns and
having a specific gravity of from about 0.8 to about 1.3 grams per
cubic centimeter.
Description
FIELD OF THE INVENTION
[0001] The present disclosure relates to oil and gas well proppant
compositions and, more particularly, to methods for enhancing the
conductivity of a propped fracture formed during a hydraulic
fracturing operation.
BACKGROUND
[0002] Hydraulic fracturing is a stimulation technique used to
increase the production of hydrocarbons from subterranean
formations. During hydraulic fracturing, a fracturing fluid and/or
pad fluid is pumped into a subterranean formation at a rate and
pressure sufficient to break down or erode the formation thereby
initiating and/or propagating one or more hydraulic fractures.
While pad fluids generally do not contain particulates, fracturing
fluids typically carry and deposit solids, such as proppant, into
the fracture. When properly deposited, proppant acts as a physical
barrier to prevent the propped portions of the fractures from
closing. After the completion of a hydraulic fracturing treatment,
properly propped fractures provide a pathway for hydrocarbons
and/or other formation fluids to flow into the wellbore. Unpropped
fractures, on the other hand, close back allowing little, if any,
fluid flow. Accordingly, the hydrocarbon production potential of a
hydraulically fractured well depends upon the transport properties
of the fracturing fluid--more particularly, the ability of the
fracturing fluid to transport and deposit proppant along the full
length and height of the fracture--as well as the conductivity of
the propped fracture.
[0003] While traditional hydraulic fracturing operations rely on
relatively high viscosity fracturing fluids (e.g., aqueous gels,
oil-based fluids, viscoelastic surfactant gels, and emulsions) to
transport proppants, current fracturing operations often utilize
low-viscosity fracturing fluids (e.g., slickwater) to enhance the
generation of complex fracture networks in unconventional
formations such as shale. Additionally, the use of such
low-viscosity fluids can reduce operational costs and formation
damage. Unfortunately, low-viscosity fracturing fluids typically
exhibit poor transport properties compared to relatively high
viscosity fracturing fluids. Specifically, conventional proppants
and/or proppant mixtures (e.g., frac sand) tend to settle out of
low-viscosity fluids.
[0004] Proppant settling reduces the effective length and height of
a propped fracture as well as the final conductivity of the propped
fracture. In addition, when proppant settles, it prematurely drops
out of solution leaving less proppant in the fracturing fluid,
resulting in unpropped or under-propped fractures and reducing the
effective length of the propped fracture. By depositing proppant
preferentially on the bottom side of the fracture, settling also
leaves much of the fracture's height unpropped, effectively
reducing the height of the propped fracture. Like wholly unpropped
fractures, the unpropped portions of a propped fracture are
susceptible to complete or partial close back. Thus, by reducing
the effective length and height of a propped fracture, settling can
significantly reduce the fracture's conductivity. Moreover, as the
unpropped portions of the fracture close, the settled proppant may
be crushed under the fractures' closing stresses, thereby further
diminishing the fracture conductivity and flow potential of any
fluid flowing through the propped fracture.
[0005] Thus, there is a continuing need for hydraulic fracturing
methods utilizing low-viscosity fluids that provide improved and/or
additional connective flow paths through propped fractures.
BRIEF DESCRIPTION OF THE DRAWINGS
[0006] The following figures are included to illustrate certain
aspects of the present disclosure, and should not be viewed as an
exclusive embodiment. The subject matter disclosed is capable of
considerable modification, alteration, and equivalents in form and
function, as will occur to those of ordinary skill in the art and
having the benefit of this disclosure.
[0007] FIG. 1 illustrates a land-based drilling and production
system;
[0008] FIG. 2 shows an enlarged portion of an interval of the well
depicted in FIG. 1;
[0009] FIG. 3 depicts a method of fracturing a subterranean
formation according to one or more embodiments of the present
invention;
[0010] FIG. 4A depicts the results of slot flow tests;
[0011] FIG. 4B depicts the results of slot flow tests; and
[0012] FIG. 5 is a graphical representation of the area of settled
sand versus frames in a slot flow test.
DETAILED DESCRIPTION
[0013] In the following description, numerous specific details are
set forth. However, it is understood that embodiments of the
invention may be practiced without these specific details. In other
instances, well-known structures and techniques have not been shown
in detail in order not to obscure the understanding of this
description.
[0014] Unless indicated otherwise, all measurements have metric
units.
[0015] Unless indicated otherwise, the terms "a," "an," or "the"
can refer to one or more than one of the noun they modify.
[0016] The term "interval" refers to a length of wellbore that can
be closed off from a down-hole portion of the wellbore.
[0017] The term "density" refers to the measure of the amount of
mass per volume of a particular substance. The term "specific
gravity," as used herein in relation to proppant particles, is the
weight per unit volume (grams per cubic centimeter) of the
particles, including the internal porosity. The apparent specific
gravity values given herein were determined by the Archimedes
method of liquid (water) displacement according to API RP60, a
method which is well known to those of ordinary skill in the art.
For purposes of this disclosure, methods of testing the
characteristics of the proppant in terms of apparent specific
gravity are the standard API tests that are routinely performed on
proppant samples.
[0018] The term "about" indicates a range which includes .+-.5%
when used to describe a single number. When applied to a range, the
term "about" indicates that the range includes -5% of a numerical
lower boundary and +5% of an upper numerical boundary. For example,
a range of from about 100.degree. C. to about 200.degree. C.
includes a range of from 95.degree. C. to 210.degree. C. However,
when the term "about" modifies a percentage, then the term means
.+-.1% of the number or numerical boundaries, unless the lower
boundary is 0%. Thus, a range of 5-10% includes 4-11%. A range of
0-5% includes 0-6%.
[0019] The term "conductivity," as used herein, is defined as the
product of the width of the created fracture and the permeability
of the proppant that remains in the fracture.
[0020] According to several embodiments, the effective length and
height of a propped fracture can be enhanced without significant
increases in operational costs by combining small amounts of
low-density proppant with higher-density micro-proppant and/or
other conventional proppants. First, low-density proppant has a
hindered settling effect on higher-density proppant particulates
(i.e., higher-density micro-proppant, frac sand, and other
conventional proppants). Thus, a proppant slurry containing small
amounts (e.g., less than 10 weight percent) of low-density proppant
in combination with higher-density proppant enhances the effective
propped fracture length by allowing the placement of higher-density
and low-density proppant deeper in the fractures. Second,
low-density proppant is buoyant in low-viscosity (e.g., water and
other Newtonian fluids) fracturing fluids whereas higher-density
proppant often is not, therefore low-density proppant is better
able to form partial packs or pillars on the upper side of the
fractures. Consequently, a proppant slurry containing small amounts
of low-density proppant in combination with higher-density proppant
will include pillars on the upper side of the fracture in addition
to the pillars formed by the higher-density proppant on the bottom
side of the fracture, thereby enhancing the effective propped
fracture height.
[0021] Methods are provided for the hydraulic fracturing of
subterranean formations using sequential proppant stages. According
to several embodiments, the method includes isolating a first
interval extending from a wellbore in a subterranean formation.
According to several embodiments, a pad fluid stage is performed by
injecting a first treatment fluid into the first zone of the
subterranean formation at a pressure sufficient to create or extend
at least a portion of a first fracture in the first interval.
According to several embodiments, the pad fluid may be a
low-viscosity fluid such as slickwater or a high-viscosity fluid
including a gelled or cross-linked polymer such as xanthan or guar
gum. According to several embodiments, a second treatment fluid is
then injected into the first fracture. According to several
embodiments, the second treatment fluid includes a micro-proppant
slurry prepared with a first base fluid, such as slickwater or
another low-viscosity fracturing fluid and a micro-proppant
mixture. The term "slickwater" as used herein refers to a mixture
of water and a friction reducer, selected from a variety of
monomeric units, including acrylamide, acrylic acid,
2-acrylamido-2-methylpropane sulfonic acid, N,N-dimethylacrylamide,
vinyl sulfonic acid, N-vinyl acetamide, N-vinyl formamide, itaconic
acid, methacrylic acid, acrylic acid esters, methacrylic acid
esters, quaternized aminoalkyl acrylate, such as a copolymer of
acrylamide and dimethylaminoethyl acrylate quaternized with benzyl
chloride, and mixtures thereof. Slickwater may optionally include a
clay control additive selected from a salt, a polymer, a resin, a
soluble organic stabilizing compound, and any combination thereof
and other chemicals as required but does not include gelling
agents. According to several embodiments, the micro-proppant
mixture includes a low-density micro-proppant and a higher-density
micro-proppant. The injection of the second treatment fluid with
the micro-proppant mixture will be referred to herein as the
"micro-proppant stage". According to several embodiments, a third
treatment fluid is then injected into the first fracture. According
to several embodiments, the third treatment fluid includes a
conventional proppant slurry prepared with a second base fluid,
such as slickwater or another low-viscosity fracturing fluid and a
conventional proppant mixture. According to several embodiments,
the conventional proppant mixture includes a low-density
conventional proppant and a higher-density conventional proppant.
The injection of the third treatment fluid with the conventional
proppant mixture will be referred to herein as the "conventional
proppant stage". According to several embodiments, the methods
include repeating the isolation of additional intervals extending
from a wellbore in a subterranean formation followed by the
sequential injection of the first, second and third treatment
fluids described above.
[0022] As used herein, the term "low-density" in relation to
micro-proppant and conventional proppant means a specific gravity
in the range of from 0.8 to 1.3 g/cc.
[0023] As used herein, "higher-density" in relation to
micro-proppant or conventional proppant generally refers to
micro-proppant or conventional proppant having a specific gravity
greater than the specific gravity of any low-density micro-proppant
or conventional proppant included in the same composition. In
addition, the term "higher-density" in relation to micro-proppant
and conventional proppant means a specific gravity in the range of
from 2.1 to 4.5 g/cc.
[0024] The term "micro-proppant" means proppant having particle
sizes in the range of from 0.5 microns to 100 microns.
[0025] The term "conventional proppant" means proppant having
particle sizes greater than 100 microns.
[0026] According to several embodiments, the concentrations of
low-density micro-proppant or low-density conventional proppant in
the micro-proppant slurry or the conventional proppant slurry is
from about 1 to about 10 weight percent of the higher-density
micro-proppant or the higher-density conventional proppant.
[0027] According to several embodiments, the concentration of
higher-density micro-proppant in the slurry of micro-proppant is in
the range of 0.01 lbm/gal to about 0.2 lbm/gal of the first base
fluid.
[0028] According to several embodiments, the concentration of
higher-density conventional proppant or frac sand in the slurry of
conventional proppant is in the range of from about 0.2 lbm/gal to
about 4 lbm/gal of the second base fluid.
[0029] According to several embodiments, the method includes
isolating a first interval extending from a wellbore in a
subterranean formation. According to several embodiments, a
micro-proppant stage is injected concurrently with one or more pad
fluid stages, followed by the injection of a conventional proppant
stage.
[0030] According to several embodiments, the method includes
isolating a first interval extending from a wellbore in a
subterranean formation where the first interval includes at least
one fracture and introducing a first treatment fluid into the first
interval, wherein the first treatment fluid includes a first base
fluid and a conventional micro-proppant that includes particles
with particulate sizes of from about 0.5 microns to about 100
microns and having a specific gravity of from about 2.1 to about
4.5 grams per cubic centimeter. According to several embodiments,
the method then includes introducing a first low-density
micro-proppant into the first treatment fluid, wherein the
low-density micro-proppant includes particles with particulate
sizes of from about 0.5 microns to about 100 microns and having a
specific gravity of from about 0.8 to about 1.3 grams per cubic
centimeter. According to several embodiments, after introducing the
first treatment fluid, the method then includes introducing a
second treatment fluid into the first interval, wherein the second
treatment fluid includes a second base fluid and a conventional
proppant that includes proppant particles with particulate sizes
greater than about 100 microns and having a specific gravity of
from about 2.1 to about 4.5 grams per cubic centimeter. According
to several embodiments, the method then includes introducing a
first low-density proppant into the second treatment fluid, wherein
the low-density proppant includes proppant particles with
particulate sizes greater than about 100 microns and having a
specific gravity of from about 0.8 to about 1.3 grams per cubic
centimeter. According to several embodiments, the method then
includes introducing a third treatment fluid into the first
interval, wherein the third treatment fluid includes a third base
fluid and a second low-density micro-proppant comprising particles
with particulate sizes of from about 0.5 microns to about 100
microns and having a specific gravity of from about 0.8 to about
1.3 grams per cubic centimeter. According to several embodiments,
the method then includes introducing a fourth treatment fluid into
the first interval, the fourth treatment fluid including a fourth
base fluid and a second low-density proppant that includes proppant
particles with particulate sizes greater than about 100 microns and
having a specific gravity of from about 0.8 to about 1.3 grams per
cubic centimeter.
[0031] According to several embodiments, the micro-proppant stage
includes a micro-proppant slurry prepared with slickwater or
another low-viscosity fracturing fluid, having a viscosity of less
than 5 centipoise (cP). According to several embodiments, the
micro-proppant stage is operable to prop open the natural and
induced micro-fractures and create connective flow paths between
the micro-fractures and the dominant fractures and/or large
branches of the wellbore. According to several embodiments, the
conventional proppant stage includes a proppant slurry prepared
with slickwater or another low-viscosity fracturing fluid, having a
viscosity of less than 5 centipoise (cP). According to several
embodiments, the conventional proppant stage is operable to prop
the dominant fractures or large branches, providing open flow paths
to keep them connective with the wellbore. Accordingly, the
sequence of one or more micro-proppant stages followed by one or
more conventional proppant stages creates improved conductive flow
paths from the micro-fractures through the dominant fractures to
the wellbore. Additionally, the sequence of one or more
micro-proppant stages followed by one or more conventional proppant
stages reduces the number of micro-fractures that close back after
the pressure of the fracturing fluid is reduced, creating
additional conductive flow paths from the micro-fractures to the
wellbore.
[0032] Accordingly, hydraulic fracturing methods that include
sequential proppant stages of a first micro-proppant slurry
including a low-density micro-proppant and a higher-density
micro-proppant followed by a conventional proppant slurry including
a low-density conventional proppant and a higher-density
conventional proppant enhances the effective length and height of
the propped fracture and creates additional conductive flow paths
increasing the overall production of the wellbore.
[0033] Turning to FIG. 1, shown is an elevation view in partial
cross-section of a wellbore drilling and production system 10,
utilized to produce hydrocarbons from wellbore 12 extending through
various earth strata in an oil and gas formation 14 located below
the earth's surface 16. Drilling and production system 10 may
include a drilling rig or derrick 18 to perform various activities
related to drilling or production, such as the methods described
below. Likewise, drilling and production system 10 may include
various types of tools or equipment 32 supported by rig 18 and
disposed in wellbore 12 for performing these activities.
[0034] A working or service fluid source 52, such as a storage tank
or vessel, may supply a working fluid 54 that is pumped to the
upper end of tubing string 34 and flows through tubing string 34.
Working fluid source 52 may supply any fluid utilized in wellbore
operations, including without limitation, drilling fluid, slurry,
acidizing fluid, liquid water, steam, hydraulic fracturing fluid,
propane, nitrogen, carbon dioxide, natural gas, or any other type
of fluid.
[0035] Wellbore 12 may be formed of a single or multiple bores
extending into the formation 14, and disposed in any orientation,
such as the horizontal wellbore 12 illustrated in FIG. 1. In
several embodiments, wellbore 12 has at least one interval. In
several embodiments, wellbore 12 has two or more intervals, for
example, first interval 20 and second interval 22. According to
several embodiments, each interval of wellbore 12 may include any
number of fractures and/or fracture systems. Alternately, an
interval may be free from fractures. For example, and as shown in
FIGS. 1 and 2, first interval 20 includes fractures 24, 26, 28, and
30, whereas second interval 22 is not fractured.
[0036] FIG. 2 shows is an enlarged portion of interval 20 of FIG.
1. As in FIG. 1, interval 20 includes fractures 24, 26, 28, and 30.
However, as shown in FIG. 2 according to several embodiments,
fractures 24, 26, 28, and 30 form a fracture system which includes
several interconnected fractures of varying size. In several
embodiments, fractures 24, 26, 28, and 30 include one or more
larger or dominant fractures such as dominant fracture 212. In
several embodiments, fractures 24, 26, 28, and 30 also include one
or more micro-fractures, such as micro-fracture 214. As used
herein, the term "fracture" is not limited, and includes any single
crack, fissure, or breach in the formation of any size, including
but not limited to micro-fractures and dominant fractures.
Likewise, the term "fracture" may also refer to an interconnected
series of fractures or a fracture system. However, the term
"micro-fracture" is limited to the extent that a micro-fracture is
any single fracture with a width that is less than 100 microns.
[0037] With continued reference to FIGS. 1 and 2, wellbore 12 may
be prepared by isolating interval 20 from interval 22 and any other
points of entry located further downhole. Interval 20 is isolated
by any suitable apparatus or method. In several embodiments,
interval 20 is isolated by a bridge plug, a fracturing plug, or the
like. In such an embodiment, the bridge or fracturing plug may be
positioned within the wellbore 12 via a work string, a wireline, or
any suitable conveyance. The bridge or fracturing plug may be set
(e.g., actuated), for example, mechanically, hydraulically, or by
the expansion of a swellable member.
[0038] In several embodiments, fluid 54 is introduced into interval
20. The term "introducing" is not limited, and includes any method
of adding or placing a fluid into the wellbore or any method of
adding or placing a fluid into interval 20. Suitable methods for
introducing a fluid to the wellbore and/or interval 20 include
injecting, pumping, pouring, and pulsing. As will be understood by
those of ordinary skill in the art, pulsing involves intermittently
adding or removing additives, chemicals or proppants into the flow
stream.
[0039] In several embodiments, fluid 54 is introduced into interval
20 at a pressure sufficient to create or enhance at least one
fracture (e.g., fracture 24) within interval 20. In several
embodiments, the pressure sufficient to create or enhance at least
one fracture and fracture face in the subterranean formation
surrounding a wellbore interval varies depending on the properties
of the subterranean formation, the depth of the interval, the
designed fracture parameters, and the properties of the fracturing
fluid. It is understood that the pressure can be the same or
different for each interval to be subjected to hydraulic
fracturing.
[0040] Fluid 54 may be a fracturing fluid, a stimulation fluid, a
treatment fluid, or a base or a carrier fluid and a proppant
composition. In several embodiments, fluid 54 is a traditional
fracturing fluid. Often used in a gel-like state, traditional
fracturing fluids generally consist of water and polymers, or other
molecules that form a viscous liquid. Traditional fracturing fluids
may also include oil-based fluids, viscoelastic gels, and emulsions
as well as foam-based viscous and/or non-viscous fluids that use
nitrogen bubbles or carbon dioxide to create or induce
fractures.
[0041] In several embodiments, fluid 54 is a treatment fluid. In
several embodiments, the treatment fluid includes a base fluid and
a proppant composition. In several embodiments, the treatment fluid
includes an aqueous fluid. In several embodiments, the base fluid
is an aqueous fluid. The aqueous fluid can be fresh water, salt
water (e.g., water containing one or more salts, such as potassium
chloride, dissolved therein), brine (e.g., saturated salt water),
or seawater. Examples of suitable salts include, but are not
limited to, chloride, bromide, acetate, and formate salts of
ammonium, alkyl ammonium, potassium, sodium, calcium, magnesium,
and zinc. In several embodiments, the aqueous fluid, base fluid,
and/or treatment fluid includes slickwater.
[0042] Slickwater is a non-viscous, low-density aqueous fluid that
includes low concentrations of one or more chemical additives, most
often a friction reducer. Hydraulic fracturing methods that include
slickwater-based treatment fluids may include low proppant
concentration, high fluid-efficiency, and high pump rates (often
60-120 bbl/minute), and are known to yield highly complex fracture
systems. Moreover, unlike many conventional gelled fracturing
fluids, the performance (friction reduction) of slickwater-based
treatment fluids is generally less sensitive to the quality of the
base aqueous fluid (i.e., the mix-water). In several embodiments,
slickwater includes an aqueous fluid and a friction reducer. In
several embodiments, slickwater includes an aqueous fluid and a
friction reducer that includes a polyacrylamide derivative and/or
copolymer. In several embodiments, slickwater includes an aqueous
fluid, a friction reducer, and one or more chemical additives. In
several embodiments, the chemical additives for slickwater include
a biocide, a surfactant (for wettability modification), and a scale
inhibitor.
[0043] As will be understood by those of ordinary skill in the art,
a variety of conventional additives can be included in the
treatment fluid and proppant composition, including bactericides,
fluid loss additives, and the like, so long as the additives do not
adversely react with the treatment fluids or prevent their use in a
desired manner. However, as used herein, "treatment fluids" are low
viscosity, low-density aqueous-based fluids rather than aqueous
gels, oil-based fluids, viscoelastic gels, emulsions, and other
viscous fluids traditionally thought of as suitable for use as a
conventional fracturing fluid. Similarly, as used herein, "base
fluids" are low viscosity, low-density aqueous fluids rather than
aqueous gels, oil-based fluids, viscoelastic gels, emulsions, and
other viscous fluids traditionally thought of as suitable for use
as conventional fracturing fluids. As noted above, in several
exemplary embodiments, a "low viscosity" fluid has a viscosity of
less than about 5 centipoise (cP). Without being bound by theory,
the use of a low viscosity fluid is thought to promote fracture
complexity by increasing the created fracture surface area and by
increasing the fracture density in the reservoir. Low viscosity
fluids provide increased fracture network complexity and enhanced
oil recovery. Accordingly, unlike the traditional hydraulic
fracturing fluids described above, the treatment fluids, base
fluids, proppant compositions, and proppant stages according to
several embodiments are substantially free from gelling additives
and gelling agents, including but not limited to galactomannan
gelling agents, guar, hydroxyethylguar, hydroxypropylguar,
carboxymethylguar, carboxymethylhydroxyethylguar, and carboxymethyl
hydroxypropylguar.
[0044] The proppant composition includes any particles or
particulates suitable for use in subterranean operations as
proppant. Particulates suitable for use in subterranean operations
as proppant include but are not limited to: sand, frac sand,
bauxite, ceramic materials, glass materials, polymer materials,
polytetrafluoroethylene materials, nut shell pieces, cured resinous
particulates comprising nut shell pieces, seed shell pieces, cured
resinous particulates comprising seed shell pieces, fruit pit
pieces, cured resinous particulates comprising fruit pit pieces,
wood, composite particulates, and combinations thereof. Suitable
composite particulates include a binder and a filler material
wherein suitable filler materials include silica, alumina, fumed
carbon, carbon black, graphite, mica, titanium dioxide,
meta-silicate, calcium silicate, kaolin, talc, zirconia, boron, fly
ash, hollow glass microspheres, solid glass, and combinations
thereof.
[0045] As noted above, in several embodiments, the mean particle
size of the proppant particulates is greater than 100 microns. In
several embodiments, the mean particle size of the proppant
particulates ranges from about 100 microns to about 420 microns. In
several embodiments, the mean particle size of the proppant
particulates generally ranges from greater than 140 mesh to about
40 mesh on the U.S. Sieve Series; however, in certain
circumstances, other mean particle sizes may be suitable. In
several embodiments, the mean particle size distribution ranges of
the proppant particulates are one or more of 30/50, 30/70, 40/60,
40/70, or 50/70 mesh.
[0046] As noted above, in several embodiments, the proppant
composition includes micro-proppant. Generally, micro-proppant can
be made from any particles or particulates suitable for use in
subterranean operations as proppant; micro-proppant is limited
however, to proppant with particulate sizes from about 0.5 microns
to about 100 microns.
[0047] According to several embodiments, a higher-density proppant
is carried further (i.e. deeper) into a fracture(s) by injecting
small amounts of a low-density proppant together with a
higher-density proppant of the same or similar particulate size,
thus enhancing the placement of the higher-density proppant.
Without being bound by theory, it is believed that adding
low-density proppant to the carrier fluid hinders the settling of
the higher-density proppant allowing the higher-density proppant to
be carrier deeper into the fractures before it falls out of
solution. While settling may be counteracted by using a high pump
rate or by increasing the viscosity of the carrier fluid, such
methods often lose effectiveness once the fluid is placed into a
fracture and before the fracture pressure is released. Accordingly,
the addition of small amounts of a low-density proppant together
with a higher-density proppant of the same or similar particulate
size provides an effective means for deep proppant placement by
increasing the ability of the higher-density proppant to remain
suspended in the non-viscous carrier fluids.
[0048] According to several embodiments, the low-density proppant
and/or micro-proppant includes micro-particles selected from fly
ash, carbon powder, carbon black, glass bubbles, glass spheres and
fiberglass combined with a binder to form a particulate. The binder
used to form the micro-particles into particulates can be any of
the consolidating agents listed above, such as non-aqueous
tackifying agents, aqueous tackifying agents, emulsified tackifying
agents, silyl-modified polyamide compounds, resins, crosslinkable
aqueous polymer compositions, polymerizable organic monomer
compositions, consolidating agent emulsions, zeta-potential
modifying aggregating compositions, and binders. According to
several embodiments, the low-density proppant and/or micro-proppant
includes any of the traditional proppant particulate materials
listed above, so long as the density is correctly selected.
[0049] In several embodiments, the low-density proppant and/or
low-density micro-proppant include thermoplastic beads prepared
from polystyrenedivinylbenzene (SVDB), polyamide imides, nylon 6,
polyamide 66, acrylic, polyphenylene oxide, a blend of
polyphenylene oxide and nylon 6/6, acrylonitrile butadiene styrene
(ABS), ethylene vinyl alcohol, polycarbonate/PET polyester blend,
polyethylene terephthalate (PET), unreinforced
polycarbonate/polybutylene terephthalate (PC/PBT) blend,
polyethylene terephthalate glycol-modified copolymer,
polyetherimide polyphenylene ether, molded polyphenylene sulfide
(PPS), polyvinylbenzene, acrylonitrile-butadiene-styrene
copolymers, polyvinylchloride, fluoroplastics, polysulfide,
polypropylene, styrene acrylonitrile, polystyrene, phenylene oxide,
polystyrene divinylbenzene, polyfluorocarbons, polyetherketones,
polyamide-imides, or any combination thereof.
[0050] While at least some embodiments described herein relate to
methods of using proppants having two ranges of density (i.e.,
low-density proppants and higher-density proppant), this is not
intended to be limiting. For example, additional proppants (e.g.,
super-high-density proppants or super-low-density proppants) also
may be provided according to one or more embodiments. Similarly,
while at least some embodiments described herein relate to methods
of using proppants having two ranges of sizes (i.e., proppant and
micro-proppant), this is not intended to be limiting. For example,
the method may include the addition of micro-proppant (i.e.,
particulate sizes less than 1 micron), followed by the addition of
an intermediate proppant (i.e., particulate sizes less than 50
microns but greater than 5 microns), and a traditional proppant
(i.e., particulate sizes less than 1 mm but greater than 100
microns) may be provided according to one or more embodiments.
[0051] In several embodiments, the treatment fluid and the proppant
composition are substantially free of proppant aggregates. As used
herein, "aggregates" are agglomerations or clusters of smaller
particles--most often proppant--that are formed and move as a
single mass or collection within the wellbore and/or carrier fluid.
As discussed in more detail below, aggregates may be formed by the
addition of sufficient quantities of a consolidating agent.
However, aggregates may also be formed by placing particles, such
as proppant, into gel bodies, superabsorbent polymers, swellable
polymers, or salts of polymeric material. Regardless of the method
of formation, proppant aggregates can be formed before or after the
proppant or proppant composition is introduced to the treatment
fluid. For example, the proppant may be agglomerated and then
introduced into the treatment fluid. As another example, the
proppant or proppant composition may be added to the treatment
fluid along with a sufficient quantity of a consolidating agent and
the proppant particles may agglomerate into aggregates while the
treatment fluid is moving throughout the wellbore.
[0052] Proppant aggregates are distinguishable from proppant
aggregation, which occurs when a propped fracture or a portion
thereof, closes onto proppant previously placed within the
fracture. Unlike proppant aggregates which are free to move within
the treatment fluid, the proppant particles coalesced by proppant
aggregation are generally held in place by the closing forces of
the fracture rather than a chemical added to the treatment fluid or
proppant composition (e.g., a consolidating agent) or by placing
the proppant in a viscous fluid (e.g., a gel body or polymer).
Likewise, proppant packs--tightly packed permeable collections of
proppant particles serving as a physical barrier that prevents the
fracture from fully closing--are distinguishable from proppant
aggregates because the proppant particles that form a proppant pack
are coalesced by fracture forces rather than chemical means (e.g.,
adding a consolidating agent or placing the proppant in a viscous
fluid).
[0053] In several embodiments, the proppant composition is
substantially free of consolidating agents. In several embodiments,
the treatment fluid is substantially free of consolidating agents.
Consolidating agents are often added to wellbore treatment fluids
that include proppant or other particles. When added in sufficient
quantities, consolidating agents assist proppant and/or other
particles to form aggregates. Examples of consolidating agents
known to aid in the formation of proppant aggregates include, but
are not limited to, non-aqueous tackifying agents, aqueous
tackifying agents, emulsified tackifying agents, silyl-modified
polyamide compounds, resins, crosslinkable aqueous polymer
compositions, polymerizable organic monomer compositions,
consolidating agent emulsions, zeta-potential modifying aggregating
compositions, silicon-based resins, binders, and combinations
and/or derivatives of the same.
[0054] According to several exemplary embodiments, a method of
treating a wellbore in a subterranean formation is provided.
Turning now to FIG. 3, the method 300 includes isolating a first
interval in step 302, introducing a fluid into the interval at a
pressure sufficient to create or enhance at least one fracture in
the interval in step 304; introducing a treatment fluid into the
interval, wherein the treatment fluid includes a base fluid, a
low-density micro-proppant, and a higher-density micro-proppant in
step 306; and introducing a second treatment fluid into the
interval, wherein the second treatment fluid includes a base fluid,
a low-density proppant, and a higher-density proppant at step
308.
[0055] According to several exemplary embodiments, while different
steps, processes, and procedures are described as appearing as
distinct acts, one or more of the steps, one or more of the
processes, and/or one or more of the procedures may also be
performed, simultaneously and/or sequentially. In one or more
embodiments, the steps, processes and/or procedures may be merged
into one or more steps, processes and/or procedures. In one or more
embodiments, one or more of the operational steps in each
embodiment may be omitted. For example, in one or more embodiments,
step 304 may be combined with step 306. In such an embodiment, the
treatment fluid described in step 306 will be introduced at a
pressure sufficient to create or enhance at least one fracture in
the interval and will also include a base fluid, a low-density
micro-proppant, and a higher-density micro-proppant. However,
generally the steps of method 300 will be performed in the order
described above. For example, generally, the treatment fluid of
step 308 will not be introduced before the treatment fluid of step
306. In some instances, some features of the present disclosure may
be employed without a corresponding use of the other features.
Moreover, one or more of the above-described embodiments and/or
variations may be combined in whole or in part with any one or more
of the other above-described embodiments and/or variations with the
exception described above.
[0056] Multiphase Simulations Using the Eulerian Granular Model
[0057] To demonstrate the improved flow of the proppant-laden
fluid, and specifically the increased transport of the proppant and
related increase of the effective propped length of a fracture, the
following simulations were modeled using Fluent Multiphase
Simulations.
[0058] Simulations 1 and 2: The Eulerian Granular model was used to
simulate the flow dynamics of two fluid mixtures of water and
proppant, a standard solution and an exemplary embodiment. The
standard solution included a fluid mixture with a primary phase of
water and a secondary phase of fracturing sand ("frac sand"). The
exemplary embodiment included a fluid mixture with a primary phase
of water and a secondary phase of fracturing sand with 4 wt. % of
FracBlack HT proppant. FracBlack HT is an ultra-light weight
proppant commercially available from Sun of Belle Chasse, La.
FracBlack HT is available in mesh size 14/40 and 30/80 and has a
density of 1.054 g/cc. Accordingly, FracBlack HT is a low-density
proppant. The physical model used is a slot channel with a length
of 200 mm, a height of 20 mm and a width of 4 mm. Each simulation
was allowed to run for approximately 30 seconds. Table 1, below,
correlates the simulation time in seconds to the area of the slot
channel covered by the secondary phase (i.e., proppant, most likely
frac sand), in square meters (m.sup.2). In order to cover the slot
channel with the secondary phase, the proppant and/or proppant
composition must fall out of solution or settle. Accordingly, the
results of Simulations 1 and 2 presented in Table 1 demonstrate
that the addition of the low-density proppant, FracBlack HT,
hinders the settling of the frac sand, thereby increasing the
amount of time the frac sand remains in solution.
TABLE-US-00001 TABLE 1 A Comparison of Simulation Time to Area
Covered by Phase 2 for Simulations 1 and 2 (4 mm slot width).
Standard Solution Exemplary Embodiment Time (sec.) Area (m.sup.2)
Time (sec.) Area (m.sup.2) 0.9476 0.00003488 0.99562 0.00003862
4.9476 0.00136685 4.9956 0.00138099 9.9476 0.00245242 9.9956
0.00244652 14.948 0.00372624 14.996 0.00370583 19.948 0.00481950
19.972 0.00479225 24.948 0.00549619 25.034 0.00530939 29.948
0.00577644 30.065 0.00567448
[0059] Simulations 3 and 4: Once again, the Eulerian Granular model
was used to simulate the flow dynamics of the standard solution and
the exemplary embodiment described above in reference to
Simulations 1 and 2. However, in Simulations 3 and 4, the physical
model used is a slot channel with a length of 200 mm, a height of
20 mm and a width of 1 mm. Each simulation was allowed to run for
approximately 10 seconds. As with the results of Simulations 1 and
2 shown in Table 1, above, the results of Simulations 3 and 4
presented in Table 2, below, demonstrate that the addition of
FracBlack HT, hinders the settling of the frac sand, thereby
increasing the amount of time the frac sand remains in
solution.
TABLE-US-00002 TABLE 2 A Comparison of Simulation Time to Area
Covered by Phase 2 for Simulations 3 and 4 (1 mm slot width).
Standard Solution Exemplary Embodiment Time (sec.) Area (m.sup.2)
Time (sec.) Area (m.sup.2) 0.9596 0.00005 0.9617 0.00004 2.0827
0.00011 2.0848 0.00011 3.0454 0.00016 3.0474 0.00016 4.008 0.00022
4.01 0.00021 4.9706 0.00027 4.9727 0.00027 5.9333 0.00034 5.9353
0.00033 7.0564 0.00040 7.0584 0.00039 8.019 0.00046 8.0211 0.00045
8.9817 0.00052 8.9896 0.00050 9.9443 0.00057 10.0023 0.00054
Slot Flow Tests
[0060] To demonstrate the improved flow of the proppant-laden
fluid, and specifically, the increased transport of the proppant
and related increase to the effective propped length of a fracture
the following testing was performed using a glass slot with inner
flow path dimensions of 30 mm height, 3 mm width and 300 mm length
to model the fluid dynamics of the proppant-laden slickwater based
treatment fluids in a fracture.
[0061] Slickwater was formed by mixing a friction reducer (FR) with
water at a concentration of 1 mL of FR to 1000 mL of water.
Standard solution 2 was made by combining 400 mL of slickwater with
48 grams of 30/50 mesh US Silica White Fracturing Sand. Exemplary
Embodiment 2 was made by combining 400 mL of slickwater with 45.6
grams of 30/50 mesh US Silica White Fracturing Sand and 2.4 grams
of 30/80 mesh light-weight proppant (LWP). The slot flow test was
performed immediately after mixing the slickwater and adding the
sand.
[0062] Approximately 150 mL of standard solution 2 was pumped at a
rate of 120 mL/min through the slot, with the dimensions given
above, for approximately 1 minute and 15 seconds. In these tests, a
syringe pump was used to pull the slickwater/sand slurry through
the slot. The sand that was carried through the slot to the syringe
was collected, dried and weighed. The testing was completed three
times, and on average, 2.47 grams of frac sand was carried out of
the slot by standard solution 2. Next, approximately 150 mL of
exemplary embodiment 2 was pumped at a rate of 120 mL/min through
the slot for approximately 1 minute and 15 seconds. This test
utilized the same slot as in the previous test. Following the first
test the slot was rinsed with water until no sand was left in the
slot. Once again, the frac sand was collected and measured. The
testing was completed three times, and on average, 3.14 grams of
frac sand was carried out of the slot by exemplary embodiment 2.
These results demonstrate that the exemplary fluid exhibits better
proppant transport properties than the standard solution, and
consequently that the effective propped length of a fracture
treated with the exemplary fluid will be greater than the effective
propped length of the same fracture if treated with a standard
proppant solution.
[0063] FIGS. 4A and 4B are pictures of the slot following the slot
flow tests, FIG. 4A shows the slot after treatment with exemplary
embodiment 2 and FIG. 4B shows the slot after treatment with
standard solution 2. The grey material at the bottom of both
pictures is the proppant that has dropped out of solution during
the slot flow tests and therefore remains visible at the bottom of
the slot. It is worthwhile to note that LWP, the low-density
proppant, is distributed throughout the frac sand, as seen by the
black dots scattered throughout the grey region (settled frac sand
bed). As seen by comparing FIG. 4A to FIG. 4B, the total area of
the grey/black region in FIG. 4A is visibly less than the area of
total grey region in FIG. 4B, demonstrating that less proppant has
dropped out of the exemplary fluid than the standard fluid. This is
especially apparent toward the end of the slot (the right side
FIGS. 4A and 4B).
[0064] Although less obvious, FIG. 4A also demonstrates that the
addition of the low-density proppant has increased the effective
propped height of the fracture. Specifically, FIG. 4A shows a small
population of low-density proppant at the top of the slot. This is
consistent with the theory that low-density proppant is able to
form partial packs or pillars on the upper side of the
fractures.
[0065] FIG. 5 is a scatter plot of the area of settled proppant
(y-axis) by frame (x-axis) for standard solution 2 and exemplary
embodiment 2. As seen in FIG. 5, the settled area is less for the
exemplary fluid than with the standard solution. These results are
consistent with the pictures shown in FIG. 4A and FIG. 4B as well
as with the measured results--as expected, if more proppant is
carried out of the slot, then less proppant will drop out of the
treatment fluid and remain in the slot, thus the measured area of
settled proppant will be less. As discussed above, all the
presented results demonstrate that the effective propped length of
a fracture treated with the exemplary fluid will be greater than
the effective propped length of the same fracture if treated with a
standard proppant solution.
[0066] While the present invention has been described in terms of
certain embodiments, those of ordinary skill in the art will
recognize that the invention can be practiced with modification
within the spirit and scope of the appended claims.
[0067] Any spatial references such as, for example, "upper,"
"lower," "above," "below," "between," "bottom," "vertical,"
"horizontal," "angular," "upwards," "downwards," "side-to-side,"
"left-to-right," "left," "right," "right-to-left," "top-to-bottom,"
"bottom-to-top," "top," "bottom," "bottom-up," "top-down," etc.,
are for the purpose of illustration only and do not limit the
specific orientation or location of the structure described
above.
[0068] While the present invention has been described in terms of
certain embodiments, those of ordinary skill in the art will
recognize that the invention can be practiced with modification
within the spirit and scope of the appended claims.
[0069] The present disclosure has been described relative to
certain embodiments. Improvements or modifications that become
apparent to those of ordinary skill in the art only after reading
this disclosure are deemed within the spirit and scope of the
application. It is understood that several modifications, changes
and substitutions are intended in the foregoing disclosure and in
some instances some features of the invention will be employed
without a corresponding use of other features. Accordingly, it is
appropriate that the appended claims be construed broadly and in a
manner consistent with the scope of the invention.
* * * * *