U.S. patent application number 13/520328 was filed with the patent office on 2013-06-27 for proppant placement.
This patent application is currently assigned to SCHLUMBERGER TECHNOLOGY CORPORATION. The applicant listed for this patent is Evgeny Borisovich Barmatov, Christopher N. Fredd, Jill F. Geddes, Trevor Hughes, Sergey Mikhailovich Makarychev-Mikhailov. Invention is credited to Evgeny Borisovich Barmatov, Christopher N. Fredd, Jill F. Geddes, Trevor Hughes, Sergey Mikhailovich Makarychev-Mikhailov.
Application Number | 20130161003 13/520328 |
Document ID | / |
Family ID | 44226683 |
Filed Date | 2013-06-27 |
United States Patent
Application |
20130161003 |
Kind Code |
A1 |
Makarychev-Mikhailov; Sergey
Mikhailovich ; et al. |
June 27, 2013 |
PROPPANT PLACEMENT
Abstract
Embodiments of hydraulic fracturing methods disclosed herein use
fine mesh proppant. In one embodiment the method is used to
fracture a low permeability formation. In one embodiment the method
uses flocculation to improve conductivity of a fracture. In one
embodiment fluid flow through the fine mesh proppant in the
fracture creates a network of connected channels to improve the
fracture conductivity.
Inventors: |
Makarychev-Mikhailov; Sergey
Mikhailovich; (St. Petersburg, RU) ; Fredd;
Christopher N.; (Westfield, NY) ; Hughes; Trevor;
(Cambridge, GB) ; Barmatov; Evgeny Borisovich;
(Cambridge, GB) ; Geddes; Jill F.; (Cambridge,
GB) |
|
Applicant: |
Name |
City |
State |
Country |
Type |
Makarychev-Mikhailov; Sergey Mikhailovich
Fredd; Christopher N.
Hughes; Trevor
Barmatov; Evgeny Borisovich
Geddes; Jill F. |
St. Petersburg
Westfield
Cambridge
Cambridge
Cambridge |
NY |
RU
US
GB
GB
GB |
|
|
Assignee: |
SCHLUMBERGER TECHNOLOGY
CORPORATION
SUGAR LAND
TX
|
Family ID: |
44226683 |
Appl. No.: |
13/520328 |
Filed: |
December 31, 2009 |
PCT Filed: |
December 31, 2009 |
PCT NO: |
PCT/RU09/00756 |
371 Date: |
March 12, 2013 |
Current U.S.
Class: |
166/280.1 |
Current CPC
Class: |
C09K 8/685 20130101;
E21B 43/267 20130101; C09K 8/805 20130101; C09K 8/80 20130101; C09K
8/74 20130101; C09K 2208/30 20130101 |
Class at
Publication: |
166/280.1 |
International
Class: |
E21B 43/267 20060101
E21B043/267 |
Claims
1. A method, comprising: injecting well treatment fluid comprising
fine mesh proppant material into a fracture in a low-permeability
subterranean formation thereby forming a proppant pack; and
concurrently or subsequently introducing non-uniformity in the
proppant pack to form a conductive flow path for fluid flow through
the propped fracture, wherein the non-uniform proppant pack has a
higher conductivity relative to the uniform proppant pack at an
identical closure stress whereby the fine mesh proppant material
has a particle size less than 105 microns (140 US mesh).
2. (canceled)
3. The method of claim 1 wherein the fine mesh proppant material is
selected from the group consisting of: silica, muscovite, biotite,
limestone, Portland cement, talc, kaolin, barite, fly ash,
pozzolan, bauxite, alumina, zirconia, titanium oxide, iron oxides,
zeolites, graphite, carbon black, aluminosilicates, biopolymer
solids, synthetic polymer solids and combinations and mixtures
thereof.
4. The method of claim 1 wherein the non-uniformity is introduced
by proppant flowback subsequent to injection.
5. The method of claim 1 wherein the non-uniformity is formed by
proppant washout.
6. The method of claim 1 wherein the non-uniformity is formed by
alternating proppant concentration during the well treatment fluid
injection.
7. The method of claim 1 wherein the treatment fluid comprises
different sized proppant materials to facilitate the introduction
of the non-uniformity.
8. The method of claim 1 wherein the treatment fluid injection
comprises a plurality of stages of alternating treatment fluid
rheology to introduce the non-uniformity.
9. The method of claim 1 further comprising aggregating the fine
mesh proppant material to introduce the non-uniformity.
10. The method of claim 9 wherein the well treatment fluid
comprises flocculating agent.
11. The method of claim 9 wherein the well treatment fluid
comprises flocculating agent selected from the group consisting of
polymers and copolymers of at least one monomer selected from the
group consisting of acrylamide, methacrylamide,
N-vinylmethylacetamide, N-vinylmethylformamide, vinyl acetate,
acrylate esters, methacrylate esters, cyanoacrylate esters, vinyl
pyrrolidone and combinations thereof.
12. The method of claim 9 wherein the fine mesh proppant material
is hydrophobic and the well treatment fluid comprises a hydrophobic
binding liquid to agglomerate the proppant.
13. The method according to claim 12 wherein the fine mesh proppant
material is made hydrophobic by a surface coating.
14. The method of claim 1 wherein the fine mesh proppant material
is coated with a tackifying agent.
15. The method of claim 1 wherein the well treatment fluid further
comprises degradable material selected from the group consisting of
substituted and unsubstituted lactide, glycolide, polylactic acid,
polyglycolic acid, copolymers of polylactic acid and polyglycolic
acid, copolymers of glycolic acid with other hydroxy-, carboxylic
acid-, or hydroxycarboxylic acid-containing moieties, copolymers of
lactic acid with other hydroxy-, carboxylic acid-, or
hydroxycarboxylic acid-containing moieties and mixtures
thereof.
16. The method of claim 15 wherein the degradable material
comprises fiber.
17. The method of claim 1, wherein proppant in the treatment fluid
comprises at least 60 percent by weight, based on the total weight
of proppant.
18. The method of claim 1 wherein the well treatment fluid
comprises at least about 4.8 g/L (0.04 ppg) of the fine mesh
proppant material added.
19. The method of claim 1 wherein the well treatment fluid
comprises slickwater.
20. The method of claim 1 wherein the well treatment fluid
comprises an effective amount of a friction reducer.
21. The method of claim 1 wherein the formation comprises a
permeability less than one millidarcy.
22. The method of claim 1 wherein the non-uniformity comprises a
branched network of open channels.
23. A method, comprising: injecting well treatment fluid comprising
fine mesh proppant material and flocculating agent into a fracture
in a subterranean formation to form a proppant pack; aggregating
the fine mesh proppant material thereby forming a hydraulically
conductive proppant pack in the fracture.
24. The method of claim 23 wherein the aggregation occurs before,
during, or subsequent to the injection step, or a combination
thereof.
25. The method of claim 23 wherein the treatment fluid comprises
flocculant selected from the group consisting of polymers and
copolymers of at least one monomer selected from the group
consisting of acrylamide, methacrylamide, N-vinylmethylacetamide,
N-vinylmethylformamide, vinyl acetate, acrylate esters,
methacrylate esters, cyanoacrylate esters, vinyl pyrrolidone and
combinations thereof.
26. The method of claim 22 wherein the fine mesh proppant material
is hydrophobic and the well treatment fluid comprises a hydrophobic
binding liquid to agglomerate the proppant.
27. The method of claim 25 wherein the fine mesh proppant material
comprises a hydrophobic surface coating.
28. The method of claim 23 wherein the flocculation facilitates
creation of a branching complex network of channels in the proppant
pack.
29. The method of claim 23 wherein the flocculation facilitates
creation of a branched network of open channels in the proppant
pack.
30. The method of claim 23 wherein the formation comprises a
permeability less than one millidarcy.
31. A method, comprising: injecting well treatment fluid comprising
proppant material into a fracture in a low-permeability
subterranean formation thereby forming a proppant pack, wherein the
proppant is a fine mesh material with a median particle size less
than 105 microns (140 US mesh); and concurrently or subsequently
introducing non-uniformity in the proppant pack to form a
conductive flow path for fluid flow through the propped fracture,
wherein the non-uniform proppant pack has a higher conductivity
relative to the uniform proppant pack at an identical closure
stress.
32. The method of claim 31 wherein at least 60 wt % of the proppant
material has a particle size less than 105 microns (140 US
mesh).
33. The method of claim 31 wherein at least 90 wt % of the proppant
material has a particle size less than 105 microns (140 US mesh).
Description
FIELD OF THE INVENTION
[0001] The invention relates to stimulation of wells penetrating
subterranean formations, and more specifically to fracturing with
injection of proppant into the fracture to form one or more paths
of reduced resistance to flow for the production of fluids.
Embodiments of this invention are concerned with the placing of
proppant in a fracture formed in a formation of low porosity such
as a tight gas reservoir.
BACKGROUND
[0002] Hydraulic fracturing is an important method of reservoir
stimulation, which allows significant hydrocarbon production
increase. The fracturing treatment usually includes a step of
pumping a fracturing fluid loaded with suspended solid particles,
referred to as proppant, downhole into a subterranean formation at
a pressure exceeding formation fracturing pressure. The resulting
fracture is filled with the proppant material. When pumping ceases
and the fracture is allowed to close, the solid proppant prevents
complete closure the proppant pack further provides a conductive
path for reservoir fluids to flow to the wellbore. High hydraulic
conductivity of proppant packs in the fracture is considered to be
a key objective of reservoir stimulation.
[0003] It is normal practice to employ solid proppant of controlled
particle size distribution in order that the proppant pack has
adequate fluid conductivity, i.e. is adequately porous, and to
mitigate the flowback of fine particles. Post-fracture proppant
flowback to the wellbore is generally regarded as a problem and an
occurrence to be avoided, since it can cause proppant accumulation
in the casing, a failure or fast depreciation of electrical
submersible pumps, and reduced fracture conductivity due to
fracture thickness loss, e.g., from the collapse of unstable
moleholes. Although many materials have been used as proppants, for
the fracturing of oil reservoirs it is commonplace to use so-called
20-40 sand which has a particle size distribution such that 90% by
weight passes a 20 US mesh sieve but is retained by a 40 mesh
sieve. Finer materials have been used and API standards recognise
proppant sizes down to a size range of 70-140 US mesh. Materials
which are smaller than 70-140 US mesh have been regarded as too
small to use as proppants.
[0004] Hydraulic fracturing of very low permeability formations,
also known as tight formations (including tight gas formations),
such as the Barnett, Woodford, or Fayetteville shale formations, is
common. Wells are often drilled horizontally to access the tight
formations and production is then stimulated by one or usually a
plurality of fracture treatments. Many of the tight gas reservoirs
were fractured utilizing crosslinked gelled fluids; however, in an
effort to reduce treatment costs, slick water fracturing which can
also facilitate a reduced fracture height growth because of the
lower fluid viscosity has emerged as the method of choice. Still,
further enhancement of the stimulation of tight formations is
desired.
[0005] The statements in the preceding section merely provide
background information related to the present disclosure and may
not constitute prior art.
SUMMARY OF THE INVENTION
[0006] We have now found that a tight formation can be fractured
successfully using a fine mesh solid of smaller size than has been
conventionally recognized to be suitable for use as a proppant,
combined with non-uniformity in the proppant pack.
[0007] In a first aspect, this invention provides a method of
fracturing a low-permeability subterranean reservoir formation
penetrated by a wellbore, comprising injecting well treatment fluid
comprising proppant material into a fracture in the formation
thereby forming a proppant pack therein, wherein the proppant
material has a particle size distribution such that the proppant
material has a median particle size less than 105 microns (140 US
mesh). The proppant material may have a particle size and size
distribution such that at least 90% by weight of the proppant
material has a particle size less than 105 microns.
[0008] A fracture in a tight formation which is propped with a
small particle size proppant may have a low final hydraulic
conductivity, and yet this may be a greater conductivity than that
of the unfractured formation, so that the fracturing process leads
to effective stimulation despite the low conductivity achieved. In
some embodiments of this invention, the method can include the
steps of: fracturing a tight gas formation wherein a treatment
fluid comprising fine mesh proppant materials is injected into the
formation to form a fracture with a consolidated proppant pack
having a relatively higher conductivity than the formation. Within
embodiments of this invention, the fracturing step may be followed
by producing gas, gas condensate or a combination thereof from the
formation through the fracture and into a production conduit in
fluid communication therewith.
[0009] Conductivity may be enhanced by non-uniformity of the
proppant within the fracture. In one embodiment, the invention
relates to a method, comprising: injecting well treatment fluid
comprising fine mesh proppant material into a fracture in a
low-permeability subterranean formation thereby forming a proppant
pack; and concurrently or subsequently introducing non-uniformity
in the proppant pack to form a conductive flow path for fluid flow
through the propped fracture, wherein the non-uniform proppant pack
has a higher conductivity relative to the uniform proppant pack at
an identical closure stress (with the same proppant loading and
fracture face).
[0010] Non-uniformity of the proppant distribution may arise
spontaneously, for instance in the course of proppant flowback
subsequent to pumping proppant into a fracture. In some forms of
this invention additional steps may be taken to induce or enhance
non-uniformity of proppant distribution. Thus, some embodiments of
the present invention relate to a method of proppant placement in a
low-permeability formation, which relies on creation of conductive
channels in a proppant pack that is made of fine mesh materials. In
some embodiments, methods of placement of fine proppant
particulates can control the formation of stable channels in a fine
proppant pack and enhance fracture conductivity.
[0011] Some forms of this invention include a step of flocculating
or agglomerating a fine mesh proppant material and disposing or
forming the aggregates in a formation to enhance flow of reservoir
fluid therefrom. In some embodiments, the invention relates to a
method comprising: injecting well treatment fluid comprising fine
mesh proppant material into a fracture in a subterranean formation
and providing in the fracture either a flocculating agent or a
binding liquid to flocculate or agglomerate the fine mesh proppant
material thereby forming a hydraulically conductive proppant pack
in the fracture. Flocculation may be brought about using a
flocculating agent, which may be a polymeric flocculating agent.
Agglomeration using a binding liquid may be brought about by
providing a binding liquid in the fracture such that the binding
liquid and the fine mesh proppant are similar to each other in
hydrophobic/hydrophilic character but opposite to the well
treatment fluid.
BRIEF DESCRIPTION OF THE DRAWINGS
[0012] FIG. 1 is a schematic representation of a branched channel
network formed in a silica flour pack by washout in a standard
conductivity cell according to an embodiment of the invention as
described in Example 1 below.
[0013] FIG. 2 is time-trace plot of the pressure drop through a
silica flour proppant pack according to an embodiment as described
in Example 1 below.
[0014] FIG. 3 is a graph of the conductivity of uniform mica packs
in a test cell at different fluid flow rates and closure stresses
according to an embodiment as described in Example 2 below.
[0015] FIG. 4 schematically illustrates an 11-pillar arrangement of
mica in preparation for testing in a conductivity test cell
according to an embodiment of Example 3 below.
[0016] FIG. 5 schematically illustrates a 72-pillar arrangement of
mica in preparation for testing in a conductivity test cell
according to an embodiment of Example 3 below.
[0017] FIG. 6 is a graph of the conductivity of uniform and the
pillared mica packs of FIGS. 4 and 5 and in a test cell at the same
fluid flow rate and different closure stresses according to an
embodiment as described in Example 3 below.
DETAILED DESCRIPTION
[0018] At the outset, it should be noted that in the development of
any such actual embodiment, numerous implementation--specific
decisions must be made to achieve the developer's specific goals,
such as compliance with system related and business related
constraints, which will vary from one implementation to another.
Moreover, it will be appreciated that such a development effort
might be complex and time consuming but would nevertheless be a
routine undertaking for those of ordinary skill in the art having
the benefit of this disclosure.
[0019] The description and examples are presented solely for the
purpose of illustrating the preferred, embodiments of the invention
and should not be construed as a limitation to the scope and
applicability of the invention or embodiments thereof. While the
compositions of embodiments of the present invention are described
herein as comprising certain materials, it should be understood
that the composition could optionally comprise two or more
chemically different materials. In addition, the composition can
also comprise some components other than the ones already cited. In
the summary of the embodiments of invention and this detailed
description, each numerical value should be read once as modified
by the term "about" (unless already expressly so modified), and
then read again as not so modified unless otherwise indicated in
context. Also, in the summary of the embodiments of invention and
this detailed description, it should be understood that a
concentration range listed or described as being useful, suitable,
or the like, is intended that any and every concentration within
the range, including the end points, is to be considered as having
been stated. For example, "a range of from 1 to 10" is to be read
as indicating each and every possible number along the continuum
between about 1 and about 10. Thus, even if specific data points
within the range, or even no data points within the range, are
explicitly identified or refer to only a few specific, it is to be
understood that inventors appreciate and understand that any and
all data points within the range are to be considered to have been
specified, and that inventors possession of the entire range and
all points within the range.
[0020] As used herein, the expression "and/or" in a series is
inclusive of any one, plurality or all of the series members,
including all combinations and permutations thereof.
[0021] As used herein, the term "low-permeability formation" refers
to formations having a permeability less than 1 millidarcy, and in
various embodiments, less than 100 microdarcy, less than 10
microdarcy, less than 1 microdarcy, or less than 500 nanodarcy.
These formations have such low permeability that the wells can be
effectively stimulated in one embodiment with an overall or primary
final fracture conductivity on the order of 0.3 to 30 mD-m (1 to
100 mD-ft) and/or with secondary and/or tertiary fractures on the
order of 0.003 to 30 mD-m (0.01 to 100 mD-ft), where secondary
fractures are understood to refer to usually relatively smaller
fractures in length and/or width branching from the primary
fractures, and tertiary fractures to usually relatively smaller
fractures in length and/or width branching from the secondary
fractures.
[0022] As used herein, the term "open channels" refers to
interconnected passageways formed in the proppant-fracture
structure. Open channels are distinct from interstitial passages
between individual proppant particles in the proppant matrix in
that the channels are relatively large scale flow paths that exceed
the dimensions of a proppant grain in at least one direction. Such
open channels generally have a hydraulic radius, and hence a
hydraulic conductivity larger than that of interstitial flow
passages through the proppant matrix, and that in one embodiment is
at least an order of magnitude larger than that of interstitial
flow passages through the proppant matrix.
[0023] As used herein the term "fine mesh materials" refers to
proppant materials having a relatively smaller grain size than
proppant sizes recognized under American Petroleum Institute
Recommended Practices (API RP) standards 56 and/or 60. These
standards call for particle sizes to be determined by a sieve
analysis procedure. They recognize a number of sizes of sand or
other proppant for fracturing, denoting them as falling between
upper and lower sieve mesh sizes stated as X/Y and require that at
least 90 wt % of the particles pass the sieve of size X which
defines an upper boundary but are retained on a sieve of size Y
which defines the lower boundary. Mesh sizes recognized under API
RP standard 56 are 6/12, 8/16, 12/20, 16/30 20/40, 30/50, 40/70,
and 70/140 for sand. Some of these are also recognized under RP 60
for other proppant materials. The smallest of these recognized
sizes is 70/140 (sieve openings of 210 and 105 micron). The full
specification for 70/140 sand requires that not more than 0.1 wt %
is retained on a 50 mesh (300 micron) sieve, 90 wt % passes 70 mesh
but is retained on 140 mesh and not more than 1% passes a 200 mesh
(75 micron) sieve. All mesh sizes provided herein refer to the mesh
size as measured using the US Sieve Series unless otherwise stated.
It will be appreciated that the sieve analysis procedure does not
determine the value of the median or mean particle size but of
course if 90 wt % of the particles lie between 70 and 140 mesh then
the median particle size will also lie between these mesh
sizes.
[0024] The fine mesh proppant used in embodiments of this invention
may be such that at least 90 wt % is smaller than an upper limit
selected from approximately 150 microns (100 US mesh),
approximately 125 microns (120 US mesh), approximately 105 microns
(140 US mesh), approximately 88 microns (170 US mesh),
approximately 74 microns (200 US mesh), approximately 63 microns
(230 US mesh), approximately 53 microns (270 US mesh),
approximately 44 microns (325 US mesh), and approximately 37
microns (400 US mesh).
[0025] It may be the case that the median particle size is not
greater than 105 micron or perhaps not greater than 90 or 75
micron. Median particle size, denoted as d.sub.50 may be determined
by the commonly used technique of low angle laser light scattering,
more commonly known as laser diffraction. Instruments for carrying
out this technique are available from a number of suppliers
including Malvern Instruments Ltd., Malvern, UK. The Malvern
Mastersizer is a well known instrument which determines the volumes
of individual particles, from which mean and median particle size
can be calculated using computer software which accompanies the
instrument. When determining particle sizes using such an
instrument, the size of an individual particle may be taken as the
diameter of a spherical particle of the same volume, the so-called
"equivalent sphere". Volume median diameter denoted as D[v,05] or
d.sub.50 is a value of particle size such that 50% (by volume) of
the particles have a volume larger than the volume of a sphere of
diameter d.sub.50 and 50% of the particles have a volume smaller
than the volume of a sphere of diameter d.sub.50.
[0026] The fine mesh proppant used in embodiments of this invention
may be such that at least 90 wt % is larger than a lower limit
selected from approximately 0.5 microns, approximately 1 microns,
approximately 2 microns, approximately 5 microns, approximately 10
microns, approximately 20 microns, approximately 30 microns,
approximately 37 microns (400 US mesh), approximately 44 microns
(325 US mesh), approximately 53 microns (270 US mesh),
approximately 63 microns (230 US mesh), approximately 74 microns
(200 US mesh), and approximately 88 microns (170 US mesh).
[0027] In one embodiment, the injected treatment fluid is
essentially free of proppant and/or other solids larger than fine
mesh materials, e.g., to the extent that the larger materials do
not adversely impact the ability to form channels in the resulting
proppant pack by fluid flowback or washout. In an embodiment, the
treatment fluid does not contain any larger materials that are
deliberately added to the treatment fluid or proppant material. In
other embodiments, the injected treatment fluid can contain a
relatively small proportion of solids that are larger than the fine
mesh materials, such as for example, less than about 10, 5, 3, 2,
1, 0.5, 0.2, 0.1 or 0.01 weight percent of larger solid materials,
by total weight of solids. In other embodiments, the weight
percentage of fine mesh materials relative to the total weight of
solids in the treatment fluid, can range from above a lower limit
of from 5, 10, 20, 30, 40, 50, 60, 75, 80, 90, 95, 97, 98, 99,
99.5, 99.8, 99.9 or 99.99 weight percent, up to any higher upper
limit selected from 50, 60, 75, 80, 90, 95, 97, 98, 99, 99.5, 99.8,
99.9, 99.99 or 100 weight percent.
[0028] Proppant used in this application may not necessarily
require the same permeability and conductivity properties as
typically required in conventional treatments because the overall
fracture permeability will at least partially develop from
formation of stable, open channels. For example, within API RP
standard 60, the sphericity of a proppant particle may be evaluated
by the method of Section 6.2, and the roundness may be evaluated by
the method of Section 6.3. Standard 60 recommends a minimum
sphericity of 0.7 and minimum roundness of 0.7. In embodiments of
this invention, however, the fine mesh proppant material can have
sphericity less than 0.7, 0.6, 0.5, 0.4, or 0.3, roundness less
than 0.7, 0.6, 0.5, 0.4, or 0.3, or sphericity and roundness both
less than 0.7, 0.6, 0.5, 0.4, or 0.3, or any such combination of
sphericity and roundness. In addition, the proppant material can be
of other shapes such as cubic, rectangular, plate-like, or
combinations thereof.
[0029] Suitable fine mesh or larger proppant materials can include
sand, gravel, glass beads, ceramics, bauxites, glass, and the like
or combinations thereof. In an embodiment, the fine mesh proppant
material can be selected from silica, muscovite, biotite,
limestone, Portland cement, talc, kaolin, barite, fly ash,
pozzolan, alumina, zirconia, titanium oxide, zeolite, graphite,
carbon black, aluminosilicates, biopolymer solids, synthetic
polymer solids, and the like, including combinations and mixtures
thereof. Thus, various proppant materials like plastic beads such
as styrene divinylbenzene, and particulate metals may be used.
Other proppant materials may be materials such as drill cuttings
that are circulated out of the well. Also, naturally occurring
particulate materials may be used as fine mesh or larger proppants,
including, but not necessarily limited to: ground or crushed shells
of nuts such as walnut, coconut, pecan, almond, ivory nut, brazil
nut, etc.; ground or crushed seed shells (including fruit pits) of
seeds of fruits such as plum, olive, peach, cherry, apricot, etc.;
ground or crushed seed shells of other plants such as maize (e.g.,
corn cobs or corn kernels), etc.; processed wood materials such as
those derived from woods such as oak, hickory, walnut, poplar,
mahogany, etc., including such woods that have been processed by
grinding, chipping, or other form of comminution, processing, etc,
some nonlimiting examples of which are proppants made of walnut
hulls impregnated and encapsulated with resins. Resin coated
(various resin and plastic coatings) or encapsulated proppants
having a base of any of the previously listed propping materials
such as sand, ceramics, bauxite, nut shells, etc. may be used in
accordance with embodiments of the invention.
[0030] Essentially, the proppant can be any fine mesh material that
will hold open the propped portion of the fracture.
[0031] The selection of proppant may involve balancing proppant
long-term strength, proppant distribution characteristics and
proppant cost. Relatively inexpensive, low-strength materials, such
as sand, can be used for hydraulic fracturing of formations with
small internal stresses. Materials of greater cost, such as
ceramics, bauxites and others, may be used in formations with
higher internal stresses.
[0032] As already mentioned, in some forms of this invention the
proppant is not placed uniformly in the fracture. The proppant may
be placed in spaced pillars that resist crushing upon being
subjected to the fracture closure stress. In another embodiment,
flow channels can be formed in the fine mesh proppant, by washout,
for example, and the remaining proppant pack or matrix bounding the
channels can sufficiently resist crushing to prevent the fracture
closure stress from completely closing off the flow channels.
[0033] Non uniform placing of the proppant relaxes some constraints
on the choice of proppant material because flow conductivity is
provided by channels between `islands` or pillars of proppant
rather than by the porosity or permeability of the packed proppant
matrix. The availability of the option to select a wider range of
proppant materials can be an advantage in embodiments of the
present invention. For example, proppant can have a range of mixed,
variable diameters or other properties that yield a high-density,
high-strength pillar, which can form a proppant matrix that has
high or low porosity and high or low permeability (proppant
porosity and permeability are not so important in an embodiment of
this invention because fluid production through the proppant matrix
is not required). Or, an adhesive or reinforcing material that
would plug a conventional proppant pack can be employed in the
interstitial spaces of the fine mesh proppant matrix herein, such
as, for example, a polymer which can be further polymerized or
crosslinked in the proppant.
[0034] In one embodiment, a non-uniformity, such as, for example,
at least one open channel or a branching complex network of open
channels is introduced into the proppant pack by fluid flow before,
during or after fracture closure. The fine mesh proppants can have
a higher ratio of drag force to mass than relatively larger
particles such as conventional proppant, which ratio is generally
inversely proportional to the particle diameter, such that they are
more easily mobilized. Moreover, smaller particles provide
relatively more particle layers which can be conducive to the
formation of non-uniform stresses in the proppant pack. By flowing
a proppant-lean or proppant-free fluid through the proppant pack,
it is relatively easy to form and wash out a connected network of
flow channels through the proppant pack. In various embodiments of
this invention, a proppant-lean fluid which induces non-uniformity
can be injected from the wellbore or can comprise backflow to the
wellbore, or fluid produced from the formation into the fracture
and toward the wellbore, or some combination thereof.
[0035] One known method for heterogenous proppant placement which
may be used in this invention is to pump a fluid containing
suspended proppant alternately with a fluid containing less of the
suspended proppant or none at all. This approach is the subject of
U.S. Pat. No. 6,776,235. Another known method which may be employed
is to pump the proppant together with a removable material,
referred to as a `channelant`. After pumping has ceased and the
fracture has closed onto proppant in the fracture, removal of the
channelant leaves open pathways between islands or pillars of the
proppant. This approach is the subject of WO2008/068645, the
disclosure of which is incorporated herein by reference.
[0036] Characteristics of the proppant and channelant can be
selected to facilitate segregation of proppant from the
channelant-rich regions depending on the manner in which
segregation is effected, downhole conditions, the channelant, the
treatment fluid, etc. In an embodiment, a degradable channelant
material is selected from substituted and unsubstituted lactide,
glycolide, polylactic acid, polyglycolic acid, copolymers of
polylactic acid and polyglycolic acid, copolymers of glycolic acid
with other hydroxy-, carboxylic acid-, or hydroxycarboxylic
acid-containing moieties, copolymers of lactic acid with other
hydroxy-, carboxylic acid-, or hydroxycarboxylic acid-containing
moieties, and mixtures of such materials. Representative examples
are polyglycolic acid or PGA, and polylactic acid or PLA. These
materials function as solid-acid precursors, and upon hydrolytic
degradation in the fracture, can form acid species which can have
secondary functions in the fracture.
[0037] A further possibility for creating non-uniformity of the
proppant in the fracture is to cause the proppant particles to
cluster together after they have been placed in the fracture. This
approach facilitates travel of the proppant into and along a
fracture, because the particles are small and separately suspended
in a fracturing fluid, which may be particularly important in the
context of fracturing a tight gas shale, but then brings the
particles together to form islands or pillars within the fracture.
These serve to prop the fracture while leaving open flow paths
between them. The proppant particles could also be made to cluster
while being pumped in the wellbore or in the fracture.
[0038] Clustering particles into aggregates, so that they are no
longer uniformly distributed within the fracture may be done in
several ways. One way to aggregate proppant particles is to use
particles which have been precoated with an adhesive so that the
proppant can have a self-adherent surface, e.g. by coating the
proppant with an adhesive or tackifier, or grafting an adhesive or
tackifying compound to the proppant. In one version of the
self-adherent proppant, the proppant is loosely held together in
cohesive slugs or globules of a gel or lightly crosslinked,
flowable polymer for which the proppant has a differential
affinity, e.g. the proppant can be grafted to the gel-forming
polymer.
[0039] In one embodiment the proppant can be present in the
treatment fluid that is injected into the fracture in the form of
an immiscible fluid packet or globule dispersed in a more or less
continuous phase of a second fluid. The immiscible fluid proppant
packets can each contain sufficient proppant to form a suitably
sized island, singly from isolated packet placement or in
combination with one or more additional proppant packets where
cumulative packet placement can occur. Because the open channels to
be formed must interconnect between the wellbore and the remote
exposed surfaces in the fracture, it can be convenient to provide
the proppant-lean fluid in a continuous phase in the treatment
fluid in which the proppant packets are a dispersed or
discontinuous phase. In one version, the proppant packets can be
provided with a thin encapsulating skin or deformable bladder to
retain the proppant and remain flowable during injection, and the
bladder can be optionally ruptured or chemically or thermally
removed during placement in the fracture and/or during closure of
the fracture.
[0040] A further possibility is that an adhesive coating is
over-coated by a layer of non-adhesive substance which is
degradable or dissolvable in the fracture as the fracture treatment
fluid or another fluid it passes through the fracture. A
non-adhesive substance inhibits the formation of proppant
agglomerates prior to entering the fracture, and allows for control
of a time moment in the fracture when, corresponding to a place
where, a proppant particle gains its adhesive properties.
[0041] An adhesive coating can be cured at the formation
temperature. Bonding particles together within proppant pillars can
inhibit erosion of the proppant pillar as formation fluids flow
past, and minimize ultimate proppant island destruction by
erosion.
[0042] Another possibility for aggregating proppant is to contact
the proppant particles, in the fracture, with a material which
causes them to aggregate. Such material may enhance attractive
forces between particles, reduce repulsive forces or create bridges
joining particles together. The effect of aggregation is of course
to reduce the number of particles by clustering them into particles
as part of a larger size. As used herein, the term `degree of
aggregation` refers to the ratio of the number of particles in a
system before aggregation divided by the number of aggregates after
aggregation. In embodiments, the degree of aggregation may range
from a low limit of 2, 3, 5, or 10, up to infinity, i.e.,
monolithicity or one aggregate.
[0043] Aggregation of particles may be brought about with
flocculating agents, i.e., a chemical agent such as a coagulant
like alum and/or a flocculant like a polyacrylamide, which act on a
molecular level on the surface chemistry of the particles to
facilitate attractive forces and/or to inhibit repulsive
forces.
[0044] Flocculating agents in one embodiment are inorganic, such as
trivalent salts of aluminum and iron, activated silica or the like,
or organic, such as natural organic flocculants including
water-soluble starch, e.g., corn and potato, guar gum, alginates,
chitin derivatives, glue, gelatin and the like, and such as
synthetic polymers, which may be nonionic or ionic. Flocculating
agents in an embodiment can include alum, prepolymerized or
preoligomerized aluminum compounds, polyaluminum chloride,
polyaluminum-silicate-sulfate, ferric chloride, ferric sulfate,
ferrous sulfate, polyferric sulfate, polyphosphorous iron chloride,
lime, starch, albumin, polysaccharides, and polymers and copolymers
of at least one monomer selected from acrylamide, methacrylamide,
N-vinylmethylacetamide, N-vinylmethylformamide, vinyl acetate,
acrylate esters, methacrylate esters, cyanoacrylate esters, vinyl
pyrrolidone, and the like, and combinations and mixtures
thereof.
[0045] Specific representative examples of nonionic polymers can
include polyacrylamide, poly(ethylene oxide), polymers of
l-vinyl-2-pyrroiidone, polymers of N-vinylformamide, polymers of
methoxyethylene, hydrolyzed polymers of poly(vinyl acetate) (i.e.,
polyvinyl alcohol), and the like.
[0046] Anionic polymeric flocculants in an embodiment are prepared
as homopolymers or acrylamide copolymers of the alkali metal or
ammonium salts of acrylic acid, methacrylic acid, ethylenesulfonic
acid, 4-styrenesulfonic acid,
2-methyl-2-[(l-oxo-2-propenyl)amino]-l-propanesulfonic acid,
2-acrylamido-2-propanesulfonic acid, and the like.
[0047] Cationic polymeric flocculants in an embodiment can include
polymers comprising monomers and/or comonomers such as substituted
acrylamide and methacrylamide salts, e.g.,
methacrylamidopropyltrimethylammonium chloride,
acryloyloxyethyltrimethylammonium chloride,
methacryloyloxyethyltrimethylammonium chloride and
N,N-dimethylaminoethyl methacrylate, N-vinylformamide and
N-vinylacetamide which are hydrolyzed in alkaline or acid to
vinylamine copolymers, salts of N-vinylimidazole, 2-vinylpyridine,
4-vinylpyridine, dialkyldiallylammonium chlorides (e.g.,
diallyldimethylammonium chloride), and the like. Polyamines, e.g.,
prepared by polycondensation of alkylene dichlorides or
epichlorohydrin and ammonia, low molecular weight alkylene
polyamines, or polyaminoamides.
[0048] Specific representative examples of ionic polymers can
include poly(sodium acrylate), poly[2-(N,N,N-trimethylamino)-ethyl
acrylate] (chloride salt), polyethylenimine,
poly[N-(dimethylamino-methyl)acrylamide], and the like. Functional
groups on embodiments of modified polyacrylamides can include
Mannich amines formed by reaction with dimethylamine and
formaldehyde, quaternized Mannich amines, carboxylate formed by
acid or base catalysis, hydroxamate formed by transamination with
hydroxylamine, and the like. Further, combinations and mixtures of
flocculating agents can be used.
[0049] Polymeric flocculating agents are commercially available, in
embodiments, as solid, dry powders or granules, invert emulsions,
two-phase aqueous solutions. Additional information on flocculants
is available from, for example, Howard Heitner, "Flocculating
Agents," Kirk-Othmer Encyclopedia of Chemical Technology, 5th Ed.,
John Wiley & Sons, Inc., vol. 11, pp. 623-647 (2004); and Hans
Burkert et al., "Flocculants," Ullmann's Encyclopedia of Industrial
Chemistry, 5th Ed., Wiley-VCH Verlag GmbH & Co. KGaA, Weinheim
10.1002/14356007.all 251 (2005); both of which are incorporated
herein by reference in their entirety in jurisdictions where
permitted.
[0050] The flocculating agents serve in an embodiment to bind the
fine mesh materials together in a floc. Where high molecular weight
ionic polymers are used in an embodiment, some segments of the
polymer adsorb on a surface of the fine mesh proppant, and large
segments extend into the liquid phase where other segments are
adsorbed onto other fine mesh particles, linking the particles
together by polymer bridges. The size of the flocs in an embodiment
is controlled by the ratio of polymer to fine mesh proppant, charge
densities of the polymer and fine mesh particles, mixing conditions
such as shear rate, addition point, polymer concentration and
dilution, pH, ionic strength, temperature, viscosity and the like.
In one embodiment, the flocs are reversibly shear sensitive so that
only limited or small floc formation occurs under high shear
conditions such as during pumping down the wellbore, and large
flocs form after the high shear condition is removed, for example,
after placement in a fracture and during shut-in and fracture
closure. The flocculation process in the fracture promotes a
heterogeneous proppant placement resulting in the formation of
channels between proppant clusters and/or between proppant
flocs.
[0051] In one embodiment, a combination of cationic and anionic
polymers is used, for example, an initially added cationic polymer
can neutralize cationic charges on the fine mesh particles and form
charge patches that present adsorption sites for the later added
anionic polymer. In embodiments, flocs produced by bridging with
high molecular weight polymers can be stronger or harder than other
types of flocs, while charge patch neutralization can allow the
bridges to reform if broken, for example, by high shear conditions.
In an embodiment, larger flocs are more conducive to heterogeneity,
the formation of a connected network of channels between the floc
clusters, and/or conductivity of the propped fracture.
[0052] Yet another possibility for the aggregation of proppant
particles is the use of a binding liquid. We have found that
agglomeration can be caused by providing a binding liquid which
exists as a separate phase within the fracturing fluid and where
the binding liquid and proppant are similar to each other but
opposite to the fracturing fluid in hydrophilic/hydrophobic
character such that agglomerates of the solid proppant held
together by the binding liquid are formed at the subterranean
location.
[0053] The agglomeration of solid particles by one liquid in the
presence of another is a known phenomenon. The agglomeration takes
place if there is sufficient similarity in surface polarity between
the two constituents which agglomerate, namely the binding liquid
and the particulate proppant, and also sufficient contrast between
both of these and the fracturing fluid, so that agglomeration leads
to a reduction in the total surface energy of the system.
Generally, when all three materials are present together, the
contact angle of the binding liquid to the solid surface should be
low, while the contact angle of the fracturing fluid on the solid
is high. The binding liquid then serves to hold the agglomerated
solid particles in proximity to each other. The contact angle of
the binding liquid on the surface of the solid may be sufficiently
low that the binding liquid wets and spreads on the solid surface.
The fracturing fluid and the binding liquid must of course remain
as separate phases when placed in contact with each other.
[0054] The binding liquid and the particulate proppant may be
transported as such in the fracturing fluid from the surface to the
subterranean location. However, it is also possible that one or the
other of them will be transported from the surface in the form of a
precursor which then undergoes transformation below ground to
become the binding liquid or the particulate proppant having the
required hydrophilic/hydrophobic character. It is also possible to
mix the binding liquid and proppant particle downhole, for example
by pumping the binding liquid down coiled tubing while the proppant
travels down the annulus around the coiled tubing.
[0055] The fracturing fluid may be hydrophilic and indeed may be
aqueous, while the solid particles, the binding liquid and the
agglomerates which form are all hydrophobic. The inverse
arrangement is also possible, however, in which the fracturing
fluid is hydrophobic while the binding liquid and the solid
particles are both hydrophilic. Whether they are hydrophilic or
hydrophobic, the agglomerates which are formed will be made up of
the solid particles wetted by the binding liquid and thereby
agglomerated together. When the agglomerates are hydrophobic, the
dispersed binding liquid may be a hydrocarbon. A vegetable oil
might possibly be used. A silicone oil such as a non-volatile
polydimethylsiloxane would also be a possibility. Although they are
somewhat more expensive than hydrocarbon mixtures such as kerosene,
silicone oils have the useful property of being very hydrophobic.
Fluorocarbon oils are also very hydrophobic and would be a further
possibility.
[0056] It is possible that the viscosity of the binding liquid
phase might be increased by using an oil thickened with oil-soluble
polymer(s) and/or other oil-soluble thickening agents
[0057] In order that there is spontaneous agglomeration, the
dispersed binding liquid and the particulate proppant must be
sufficiently similar in hydrophobicity (or where appropriate
hydrophilicity) that the binding liquid selectively wets the solid
when they are both submerged within the fracturing fluid. A
sufficiently hydrophobic particulate proppant may be a material
which is inherently hydrophobic (rubber for example) or it may be a
material to which a surface treatment has been applied in order to
make it more hydrophobic (or where appropriate more hydrophilic) in
order that agglomeration occurs. We have observed that particulate
solids which are very hydrophobic form tight agglomerates with the
solid particles closely packed together, whereas solids which are
only just sufficiently hydrophobic to be agglomerated by a
hydrophobic oil tend to form loose agglomerates characterised by a
high volume fraction of oil within them and the solid particles
lying at the oil-water interface.
[0058] Sand is frequently used as proppant in conventional
fracturing. Ordinary silica sand is not agglomerated by oil in the
presence of water. By contrast, we have found that sand which has
been treated to make it more hydrophobic will spontaneously
agglomerate in the presence of oil.
[0059] A range of different methods can be used to modify the
surface of solid particles to become more hydrophobic, and
preferably sufficiently hydrophobic to form tight
agglomerates--these include the following:
[0060] Organo-silanes can be used to attach hydrophobic
organo-groups to hydroxyl-functionalised mineral substrates such as
proppants composed of silica, silicates and alumino-silicates. The
use of organosilanes with one or more functional groups (for
example amino, epoxy, acyloxy, ethoxy or chloro) to apply a
hydrophobic organic layer to silica is well known. The reaction may
be carried out in an organic solvent or in the vapour phase (see
for example Duchet et al, Langmuir (1997) vol 13 pp 2271-78).
[0061] Organo-titanates and organo-zirconates such as disclosed in
U.S. Pat. No. 4,623,783 can also be used. Published literature
indicates that organo-titanates can be used to modify minerals
without surface hydroxyl groups, which could extend the range of
materials to undergo surface modification, for instance to include
carbonates and sulphates.
[0062] A polycondensation process can be used to apply a
polysiloxane coating containing organo-functionalised ligand groups
of general formula P--(CH.sub.2).sub.3--X where P is a
three-dimensional silica-like network and X is an organo-functional
group. The process involves hydrolytic polycondensation of a
tetraalkoxysilane Si(OR).sub.4 and a trialkoxy silane
(RO).sub.3Si(CH.sub.2).sub.3X. Such coatings have the advantage
that they can be prepared with different molar ratios of
Si(OR).sub.4 and (RO).sub.3Si(CH.sub.2).sub.3X, making it possible
to provide some control of the hydrophobicity of the treated
surface.
[0063] A fluidised bed coating process can be used to apply a
hydrophobic coating to a particulate proppant substrate. The
coating material would typically be applied as a solution in an
organic solvent and the solvent then evaporated within the
fluidised bed.
[0064] Adsorption methods can be used to attach a hydrophobic
coating on a mineral substrate. A surfactant monolayer can be used
to change the wettability of a mineral surface from water- to
oil-wet. Hydrophobically modified polymers can also be attached by
adsorption.
[0065] A waxy coating can be used to render a mineral substrate
hydrophobic. Typically, the wax is applied at a temperature above
its melting point and subsequent cooling forms a competent
hydrophobic coating.
[0066] The agglomerates which form consist of the solid particles
clustered together, with binding liquid in the spaces between
particles. The amount of binding liquid may or may not be
sufficient to fill completely the spaces between the solid
particles in the agglomerates.
[0067] We have observed that the ratio of binding liquid to solid
particles affects the equilibrium size of the agglomerates which
form. As the proportion of binding liquid is increased from zero,
the equilibrium size of the agglomerates increases until the
proportion of binding liquid approaches the amount (which can be
calculated) needed to fill the spaces between randomly close packed
particles in a large agglomerate. If the amount of binding liquid
is increased still further, some excess liquid may associate with
the agglomerates.
[0068] If non-uniformity of proppant distribution in a fracture is
induced or enhanced by contacting the proppant with a material
which causes it to aggregate, it will be desirable that this
material does not contact the proppant prematurely. It will
generally be necessary to provide some way to avoid or inhibit
agglomeration during transit but then permit or induce
agglomeration on arrival within the fracture. There are a number of
ways in which this can be done and these will be discussed in
turn.
[0069] Separate Flow Paths:
[0070] The flocculant or binding liquid is delivered by a flow path
within a wellbore which is separate from the flowpath for proppant.
This can be achieved by using coiled tubing within a wellbore to
deliver one of the two components which form aggregates while using
the annulus around the coiled tubing as the flow path for the other
of the two components. For instance, a suspension of the binding
liquid in fracturing fluid might be pumped through coiled tubing to
the point at which the materials pass from the wellbore into the
reservoir while a suspension of the particulate solid in fracturing
fluid is pumped through the annulus around the coiled tubing. It is
possible that the concentration of binding liquid might then be
cycled between higher and lower (or zero) concentrations in order
to promote the formation of discreet agglomerates for heterogeneous
proppant placement.
[0071] Sensitivity to Temperature:
[0072] This approach makes use of the difference between surface
temperatures and temperatures below ground, which are almost always
higher than at the surface. During transit to the subterranean
location, the carrier liquid and everything suspended in it will
pass through a wellbore exposed to subterranean temperatures and
will begin to heat up, but if the flow rate is substantial, the
flowing composition will leave the wellbore and enter the fracture
at a temperature significantly below the reservoir temperature.
[0073] One way to make use of this temperature difference is to
employ as a binding liquid a substance which is solid at surface
temperature but which melts to a liquid at the downhole
temperature. One example of such a material is eicosane which melts
at 35 to 37.degree. C. Various grades of paraffin wax, melting at
temperatures from 35 to 60.degree. C., are available commercially.
It is envisaged that the solid wax could be blended with the
particulate solid and pumped in as a suspension in aqueous carrier
liquid. Higher and lower (or zero) concentrations of the wax in the
carrier liquid could be pumped alternately in order to promote the
formation of discreet agglomerates for heterogeneous proppant
placement.
[0074] Encapsulation:
[0075] Encapsulation of either the binding liquid or the
particulate proppant to delay release and prevent them from
contacting each other prematurely could also be carried out with an
encapsulating material which dissolves slowly or undergoes chemical
degradation under conditions encountered at the subterranean
location, thereby leading to rupture of the encapsulating shell or
making the encapsulating material permeable. Degradation may in
particular be hydrolysis which de-polymerises an encapsulating
polymer. While such hydrolytic degradation may commence before the
overall composition has travelled down the wellbore to the
reservoir, it will provide a delay before significant amounts of
binding liquid or particulate proppant contact each other.
[0076] A number of technologies are known for the encapsulation of
one material within another material. Polymeric materials have
frequently been used as the encapsulating material. Some examples
of documents which describe encapsulation procedures are U.S. Pat.
No. 4,986,354, WO 93/22537, and WO 03/106809. Encapsulation can
lead to particles in which the encapsulated substance is
distributed as a plurality of small islands surrounded by a
continuous matrix of the encapsulating material. Alternatively
encapsulation can lead to core-shell type particles in which a core
of the encapsulated substance is enclosed within a shell of the
encapsulating material. Both core-shell and islands-in-matrix type
encapsulation may be used.
[0077] An encapsulating organic polymer which undergoes chemical
degradation may have a polymer chain which incorporates chemical
bonds which are labile to reaction, especially hydrolysis, leading
to cleavage of the polymer chain. A number of chemical groups have
been proposed as providing bonds which can be broken, including
ester, acetal, sulfide and amide groups. Cleavable groups which are
particularly envisaged are ester and amide groups both of which
provide bonds which can be broken by a hydrolysis reaction.
[0078] Generally, their rate of cleavage in aqueous solution is
dependent upon the pH of the solution and its temperature. The
hydrolysis rate of an ester group is faster under acid or alkaline
conditions than neutral conditions. For an amide group, the
decomposition rate is at a maximum under low pH (acidic)
conditions. Low pH, that is to say acidic, conditions can also be
used to cleave acetal groups.
[0079] Thus, choice of encapsulating polymer in relation to the pH
which will be encountered after the particles have been placed in a
fracture may provide a control over the delay before the
encapsulated material is released. Polymers which are envisaged for
use in encapsulation include polymers of hydroxyacids, such as
polylactic acid and polyglycolic acid. Hydrolysis liberates
carboxylic acid groups, making the composition more acidic. This
lowers the pH which in turn accelerates the rate of hydrolysis.
Thus the hydrolytic degradation of these polymers begins somewhat
slowly but then accelerates towards completion and release of the
encapsulated material. Another possibility is that a polymer
containing hydrolytically cleavable bonds may be a block copolymer
with the blocks joined through ester or amide bonds.
[0080] One possibility for making use of chemical degradation to
delay agglomeration would be to coat a hydrophobic proppant with a
degradable coating. The coating would need to be hydrophilic in
order to prevent agglomeration. Degradation of the coating would
expose the hydrophobic solid inside and allow agglomeration to
proceed.
[0081] Another possibility would be to apply a degradable coating
to particles of a substance which is solid at surface temperature
but melts to become a binding liquid at downhole temperatures. The
solid state at the surface will facilitate coating and availability
of the binding liquid he is delayed until degradation of the
coating and exposure to downhole temperature have both taken
place.
[0082] A further possibility would be to encapsulate a flocculating
agent within a polymer which degrades to release the flocculating
agent.
[0083] Precursor Converts to Binding Liquid:
[0084] One approach to delaying agglomeration by means of a binding
liquid and so providing time for transport to a fracture before
agglomeration takes place, is to transport binding liquid in the
form of a precursor and induce it to transform from the precursor
to the binding liquid below ground. This may be done by using a
long chain carboxylic acid as the binding liquid, transporting it
at a pH above the pK.sub.a of the acid so that it is in the form of
an ionised salt, and then lowering the pH after a delay.
[0085] Suitable monocarboxylic acids may have the formula RCOOH
where R is a saturated or unsaturated aliphatic carbon chain of at
least 8 carbon atoms. Possibly R has a chain length of 8 or 12
carbon atoms up to 24 carbon atoms. Also suitable are dimeric and
oligomeric carboxylic acids based on linked surfactant monomer
subunits, each monomer subunit having the formula R.sub.aCOOH where
R.sub.a is a C.sub.10-C.sub.50 aliphatic group comprising a
C.sub.10-C.sub.25 aliphatic chain and the R.sub.a groups of the
monomer subunits are connected together to form the dimeric or
oligomeric acid. These dimeric and oligomeric acids would provide a
very viscous binding liquid. Some structures of dimeric, trimeric
and oligomeric fatty acids are shown in U.S. Pat. No.
6,774,094.
[0086] If these carboxylic acids contain an aliphatic chain of
sufficient length, generally of at least 16 or 18 carbon atoms,
they are able to act as viscoelastic surfactants when the pH is
above their pK.sub.a values so that the surfactants are in ionised
form. In order to obtain viscoelastic behaviour it may be necessary
that the solution also contains some added salts such as potassium
chloride (KCl). Incorporating such carboxylic acids, when in the
form of viscoelastic surfactants at pH above their pKa values and
in the presence of a salt will have the effect of thickening the
carrier liquid. After a carrier liquid containing a carboxylate has
been transported downhole to a subterranean location, it will be
necessary to reduce pH to below the pK.sub.a value of the acid. One
possibility for this would be to pump in an acid solution
alternately with the carrier liquid and allowing them to mix.
However, a preferred way to reduce pH with a delay is to include
particles of a poly(hydroxyacid) such as polylactic acid or
polyglycolic acid in the composition transported down the wellbore.
The polymer will hydrolyse on contact with the aqueous carrier
liquid as described above, liberating the carboxylic acid groups of
the monomeric acid and thus lowering the pH of the solution.
[0087] Using a precursor which is a viscoelastic surfactant is
advantageous in hydraulic fracturing, where it is desirable that
the carrier liquid is a thickened aqueous fluid but it is also
desirable that it loses viscosity after the proppant has been
transported into the fracture. Lowering the pH when the composition
has been delivered to the fracture or other subterranean location
will take away the viscoelastic property of the precursor at the
same time as converting it from a viscoelastic surfactant into the
required binding liquid.
[0088] Another category of precursor capable of hydrolysis to form
a hydrophobic binding liquid is a molecule including the partial
formula
R.sub.1--X--
where R.sub.1 is a long chain aliphatic group and X is a cleavable
group such as an ester, amide or acetal group cleavable by
hydrolysis. Such a precursor compound may be a cleavable surfactant
having the structure
R.sub.1--X--Y--Z
where (i) R.sub.1 is a saturated or unsaturated, linear or branched
aliphatic chain of at least 8 carbon atoms, preferably at least 12
carbon atoms; (ii) X is a cleavable group such as an O(CO), (CO)O,
R.sub.7N(CO), or (CO)NR, group; (iii) Y is a spacer group which is
constituted by a short saturated or unsaturated hydrocarbon chain
comprising at least one carbon atom, preferably at least 2 but not
more than 6 carbon atoms and which may optionally be a branched if
the number of carbon atoms is sufficient for a branched chain; (iv)
Z is a hydrophilic head group which may be:
[0089] a cationic group of the formula
--N.sup.+R.sub.2R.sub.3R.sub.4;
[0090] a sulfonate or carboxylate anionic group: or
[0091] an amphoteric group of the formula
--N.sup.+R.sub.2R.sub.3R.sub.4--COO.sup.-; and
(v) R.sub.2, R.sub.3, R.sub.4 and R.sub.7 are each independently
hydrogen; a linear or branched, saturated aliphatic chain of at
least 1 carbon atom; or a linear or branched, saturated aliphatic
chain of at least 1 carbon atom with one or more of the hydrogen
atoms replaced by a hydroxyl group.
[0092] A further possibility for a precursor of a binding liquid is
an ionic complex formed between a polymer with multiple positive
charges and negatively charged carboxylate ions. When pH is reduced
the carboxylate ions will be converted to the un-ionised carboxylic
acid and be able to serve as binding liquid.
[0093] Emulsified Binding Liquid or Flocculating Agent:
[0094] Yet another approach to delaying aggregation is to emulsify
a flocculating agent or a binding liquid in the fracturing fluid,
thereby inhibiting interaction of the binding liquid or flocculant
with the particulate proppant, and then break the emulsion after
transport to the fracture. This approach may be implemented by
forming an emulsion with an emulsifier which undergoes hydrolytic
degradation, for example, a surfactant which includes a degradable
ester or degradable amide linkage.
[0095] There are a number of possibilities for additional features
and details. In one embodiment, reinforcing and/or consolidating
material can be introduced into the fracture fluid to increase the
strength of the proppant clusters formed and prevent their collapse
during fracture closure. The reinforcing material in one embodiment
can facilitate flocculation of the fine mesh proppant. If
proppant-rich and proppant-lean substages are pumped alternately
the reinforcement material can be added to either substage. The
concentrations of both proppant and the reinforcing materials can
vary in time throughout the proppant stage, and from substage to
substage. That is, the concentration of proppant reinforcing
material can be different at two subsequent substages. It can also
be suitable in some applications of the present method to introduce
the reinforcing material in a continuous or semi-continuous fashion
throughout the proppant stage, or during one or a plurality of
adjacent proppant-lean substages. Particularly, different
implementations can be preferable when the concentration of the
reinforcing material does not vary during the entire proppant
stage; monotonically increases during the proppant stage; or
monotonically decreases during the proppant stage.
[0096] On the other hand, a high permeability and/or high porosity
proppant pack can be suitably employed without detriment. In one
embodiment, the permeability of the fine mesh proppant can provide
some limited fracture conductivity in the event the channels are
not properly formed or do not fully interconnect. Additionally,
under some formation conditions it can be advantageous when using
the present method to perform a final tail-in stage of the
fracturing treatment involving continuous proppant introduction
into the fracturing fluid, with the proppant at this stage
consisting essentially of uniform particle size, which can be
larger than or free of fine mesh proppant materials, to obtain a
zone of continuous-porosity proppant adjacent to the wellbore. If
employed, the tail-in stage of the fracturing treatment resembles a
conventional fracturing treatment, where a continuous bed of
well-sorted conventional proppant is placed in the fracture
relatively near to the wellbore. The tail-in stage can involve
introduction of both an agent that increases the proppant transport
capability of the treatment fluid and/or an agent that acts as a
reinforcing material. The tail-in stage is distinguished from the
second stage by the continuous placement of a well-sorted proppant,
that is, a proppant with an essentially uniform particle size. The
proppant strength is sufficient to prevent its cracking (crumbling)
when subjected to stresses that occur at fracture closure. The role
of the proppant at this tail stage is to prevent fracture closure
and, therefore, to provide good fracture conductivity in proximity
to the wellbore.
[0097] One embodiment of the method of proppant placement includes
completion of a wellbore and perforations in the case of a cased
hole. Fine mesh proppant particles can be injected in a fracturing
fluid through the wellbore and into a fracture. A well treatment
fluid may comprise at least about 4.8 g/litre (0.04 ppg), or at
least about 48 g/litre (0.4 ppg) or even at least about 480 g/litre
(4 ppg) of added fine mesh proppant. After sufficient time for
flocculation to occur in an embodiment where a flocculating agent
is employed, the fracture can then be allowed to close, and the
flocculated proppant compressed in the fracture to prevent the
opposing fracture faces from contacting each other and provide an
interconnected network of flow channels around the proppant flocs
or aggregated flocs. In an alternative or additional embodiment, a
backflow of fluid from the formation is initiated through the fine
mesh proppant to the wellbore and the fluid washes out channels
around consolidated proppant clusters or islands.
[0098] Where a degradable or soluble material such as a channelant
is employed with the fine mesh proppant, the channelant can be
removed in various embodiments by flushing, dissolving, softening,
melting, breaking, or degrading the channelant, wholly or
partially, via a suitable activation mechanism, such as, but not
limited to, temperature, time, pH, salinity, solvent introduction,
catalyst introduction, hydrolysis, and the like, or any combination
thereof. The activation mechanism can be triggered by ambient
conditions in the formation, by the invasion of formation fluids,
exposure to water, passage of time, by the presence of incipient or
delayed reactants in or mixed with the channelant particles, by the
post-injection introduction of an activating fluid, or the like, or
any combination of these triggers.
[0099] In some fracturing embodiments, a solid acid-precursor can
be present in the fine mesh proppant or between proppant stages.
Suitable acid-generating dissolvable channelants can include for
example, and without limitation, PLA, PGA, carboxylic acid,
lactide, glycolide, copolymers of PLA or PGA, and the like and
combinations thereof. Provided that the formation rock is
carbonate, dolomite, sandstone, or otherwise acid reactive, then
the hydrolyzed product, a reactive liquid acid, can etch the
formation at surfaces exposed between the proppant pillars. This
etching can enlarge the open channels and thus further enhance the
conductivity between the pillars. Other uses of the generated acid
fluid can include aiding in the breaking of residual gel,
facilitating consolidation of proppant clusters, curing or
softening resin coatings and increasing proppant permeability.
[0100] In some embodiments, a fluoride source capable of generating
hydrofluoric acid upon release of fluorine and adequate protonation
can be present in the fine mesh proppant or between proppant
stages. Some nonlimiting examples of fluoride sources which are
effective for generating hydrofluoric acid include fluoboric acid,
ammonium fluoride, ammonium bifluoride, and the like, or any
mixtures thereof.
[0101] During hydraulic fracturing, high pressure pumps on the
surface inject the fracturing fluid into a wellbore adjacent to the
face or pay zone of a geologic formation. The first stage, also
referred to as the "pad stage" involves injecting a fracturing
fluid into a borehole at a sufficiently high flow rate and pressure
sufficient to literally break or fracture a portion of surrounding
strata at the sand face. The pad stage is pumped until the fracture
has sufficient dimensions to accommodate the subsequent slurry
pumped in the proppant stage. The volume of the pad can be designed
by those knowledgeable in the art of fracture design, for example,
as described in Reservoir Stimulation, 3rd Ed., M. J. Economides,
K. G. Nolte, Editors, John Wiley and Sons, New York, 2000.
[0102] Water-based fracturing fluids are common, with natural or
synthetic water-soluble polymers optionally added to increase fluid
viscosity, and can be used throughout the pad and subsequent
proppant and/or channelant stages. These polymers include, but are
not limited to, guar gums; high-molecular-weight polysaccharides
composed of mannose and galactose sugars; or guar derivatives, such
as hydroxypropyl guar, carboxymethy! guar,
carboxymethylhydroxypropyl guar, and the like. Cross-linking agents
based on boron, titanium, zirconium or aluminum complexes are
typically used to increase the effective molecular weight of the
polymer for use in high-temperature wells.
[0103] To a small extent, cellulose derivatives, such as
hydroxyethylcellulose or hydroxypropylcellulose and
carboxymethylhydroxyethylcellulose, are used with or without
cross-linkers. Two biopolymers--xanthan and scleroglucan--provide
excellent proppant suspension, but are more expensive than guar
derivatives and so are used less frequently. Polyacrylamide and
polyacrylate polymers and copolymers are typically used for
high-temperature applications or as friction reducers at low
concentrations for all temperatures ranges.
[0104] Friction reducers may also be incorporated into fluids in
one embodiment of the invention. Any friction reducer may be used.
In addition, polymers such as polyacrylamide, polyisobutyl
methacrylate, polymethyl methacrylate and polyisobutylene as well
as water-soluble friction reducers such as guar gum, guar gum
derivatives, hydrolyzed polyacrylamide, and polyethylene oxide may
be used. Commercial drag reducing chemicals such as those sold by
Conoco Inc. under the trademark "CDR" as described in U.S. Pat. No.
3,692,676 (Cutter et al.) or drag reducers such as those sold by
Chemlink designated under the trademarks FLO 1003, FLO 1004, FLO
1005 and FLO 1008 have also been found to be effective.
[0105] Polymer-free, water-base fracturing fluids can also be
obtained using viscoelastic surfactants. Usually, these fluids are
prepared by mixing in appropriate amounts of suitable surfactants,
such as anionic, cationic, nonionic, amphoteric, and zwitterionic.
The viscosity of viscoelastic surfactant fluids are attributed to
the three-dimensional structure formed by the fluid's components.
When the surfactant concentration in a viscoelastic fluid
significantly exceeds a critical concentration, and in most cases
in the presence of an electrolyte, surfactant molecules aggregate
into species, such as worm-like or rod-like micelles, which can
interact to form a network exhibiting viscous and elastic
behavior.
[0106] In another embodiment, a slickwater fracturing fluid
containing a friction reducer can be used in the pad and/or
proppant stages.
[0107] In one embodiment, after the fracture is induced, fine mesh
proppant and any flocculant can be injected into the fracture as a
slurry or suspension of particles in the fracturing fluid during
what is referred to herein as the "proppant stage." In the proppant
stage, proppant is injected in one or more segregated substages
having alternated proppant concentration, pumping rates and/or
fluid rheologies to facilitate a heterogeneous proppant placement
during the injection. As a result, the proppant does not completely
fill the fracture. Rather, spaced proppant clusters form as pillars
with channels between them, through which formation fluids can
pass. The volumes of proppant and carrier sub-stages as pumped can
be different. That is, the volume of the substages can be varied.
Furthermore, the volumes and order of injection of these substages
can change over the duration of the proppant stage. That is,
proppant substages pumped early in the treatment can be of a
smaller volume then a proppant substage pumped later in the
treatment. The relative volume of the substages can be selected by
the engineer based on how much of the surface area of the fracture
it is desired to be supported by the clusters of proppant, and how
much of the fracture area is desired as open channels through which
formation fluids are free to flow.
[0108] The use of an optional degradable material or channelant in
one embodiment can depend on the mode of channelant segregation and
placement in the fracture, as well as the mode of channelant
removal and channel formation. In its simplest form, the channelant
can be a solid participate that can be maintained in its solid form
during injection and fracture closure, and readily dissolved or
degraded for removal. Materials that can be used can be organic,
inorganic, glass, ceramic, nylon, carbon, metallic, and so on.
Suitable materials can include water- or hydrocarbon-soluble solids
such as, for example, salt, calcium carbonate, wax, or the like.
Polymers can be used in another embodiment, including polymers such
as, polylactic acid (PLA), polyglycolic acid (PGA), polyol,
polyethylene terephthalate (PET), polysaccharide, wax, salt,
calcium carbonate, benzoic acid, naphthalene based materials,
magnesium oxide, sodium bicarbonate, soluble resins, sodium
chloride, calcium chloride, ammonium sulfate, and the like, and so
on, or any combinations thereof. The channelant can be selected to
have a size and shape similar or dissimilar to the size and shape
of the proppant particles as needed to facilitate segregation from
the proppant. Channelant particle shapes can include, for example,
spheres, rods, platelets, ribbons, and the like and combinations
thereof. In some applications, bundles of fibers, or fibrous or
deformable materials, can be used. These fibers can additionally or
alternatively form a three-dimensional network, reinforcing the
proppant and limiting its flowback.
[0109] For example, the separation of injected proppant and
channelant as introduced and placed in the fracture can be induced
by differences (or similarities) in size, density or shape of the
two materials. The specific gravities and the volume concentrations
of proppant and channelant can be tailored to minimize mixing and
homogenization during placement. Properly sizing the channelant or
adding various weighting agents to the channelant-rich fluid can
facilitate segregation at the appropriate time and location.
[0110] The presence of the channelant in the fracturing fluid in
the proppant stage, e.g. in a mixed substage or in a segregated
channelant substage, can have the benefit of increasing the
proppant transport capability. In other words, the channelant can
reduce the settling rate of proppant in the fracture treatment
fluid. The channelant can in an embodiment be a material with
elongated particles having a length that much exceeds a diameter.
This material can affect the rheological properties and suppress
convection in the fluid, which can result in a decrease of the
proppant settling rate in the fracture fluid and maintain
segregation of the proppant from proppant lean regions.
[0111] The fibers injected with the fine mesh proppant in an
embodiment can be capable of decomposing in the water-based
fracturing fluid or in the downhole fluid, such as fibers made on
the basis of polylactic acid (PLA), polyglycolic acid (PGA),
polyvinyl alcohol (PVOH), and others. The fibers can be made of or
coated by a material that becomes adhesive at subterranean
formation temperatures. They can be made of adhesive material
coated by a non-adhesive substance that dissolves in the fracturing
fluid or another fluid as it is passed through the fracture. The
fibers used in one embodiment can be up to 2 mm long with a
diameter of 10-200 microns, in accordance with the main condition
that the ratio between any two of the three dimensions be greater
than 5 to 1. In another embodiment, the fibers can have a length
greater than 1 mm, such as, for example, 1 to 30 mm, 2 to 25 mm or
3 to 18 mm, e.g. about 6 mm; and they can have a diameter of 5 to
100 microns and/or a denier of about 0.1 to 20, preferably about
0.15 to 6. These fibers in one embodiment are desired to facilitate
proppant carrying capability of the treatment fluid with reduced
levels of fluid viscosifying polymers or surfactants, and in
another embodiment can facilitate flocculation. Fiber
cross-sections need not be circular and fibers need not be
straight. If fibrillated fibers are used, the diameters of the
individual fibrils can be much smaller than the aforementioned
fiber diameters.
[0112] The weight concentration of the fibers in the fracturing
fluid can be from 0.1 to 10 percent in one embodiment. The
concentration of the solid channelant material in the treatment
fluid in another embodiment is typically from about 0.6 g/L (about
5 ppt) to about 9.6 g/L (about 80 ppt).
[0113] In an embodiment, a fiber additive can provide reinforcement
and consolidation of the fine mesh proppant. This fiber type can
include, for example, glass, ceramics, carbon and carbon-based
compounds, metals and metallic alloys, and the like and
combinations thereof, as a material that is packed in the proppant
to strengthen the proppant pillars: In other applications, a second
type of fiber can be used that inhibits or accelerates flocculation
and/or settling of the proppant in the treatment fluid. The second
fiber type can include, for example, polylactic acid, polyglycolic
acid, polyethyleneterephthalate (PET), polyol, and the like and
combinations thereof, as a material that inhibits settling or
dispersion of the proppant in the treatment fluid and serves as a
primary removable fill material in the spaces between the pillars.
In another embodiment, a third fiber type can be insoluble and
provide surface charged sites to facilitate flocculation. Yet other
applications include a mixture of the first, second and/or third
fiber types.
[0114] The fibers can be hydrophilic or hydrophobic in nature.
Hydrophilic fibers are used in one embodiment where the fiber
modifies flocculation. Fibers can be any fibrous material, such as,
but not necessarily limited to, natural organic fibers, comminuted
plant materials, synthetic polymer fibers (by non-limiting example
polyester, polyaramide, polyamide, novoloid or a novoloid-type
polymer), fibrillated synthetic organic fibers, ceramic fibers,
inorganic fibers, metal fibers, metal filaments, carbon fibers,
glass fibers, ceramic fibers, natural polymer fibers, and any
mixtures thereof. Particularly useful fibers are polyester fibers
coated to be highly hydrophilic, such as, but not limited to,
DACRON.RTM. polyethylene terephthalate (PET) Fibers available from
Invista Corp. Wichita, Kans., USA, 67220. Other examples of useful
fibers include, but are not limited to, polylactic acid polyester
fibers, polyglycolic acid polyester fibers, polyvinyl alcohol
fibers, and the like.
[0115] If desired, a pH control agent can be used in the treatment
fluid, especially where a solid acid precursor is present and one
or more of the other treatment fluids are pH-sensitive. The pH
control agent can be selected from amines and alkaline earth,
ammonium and alkali metal salts of sesquicarbonates, carbonates,
oxalates, hydroxides, oxides, bicarbonates, and organic
carboxylates, for example sodium sesquicarbonate, triethanolamine,
or tetraethylenepentamine.
[0116] Suitable solid acids for use in viscoelastic surfactant
(VES) fluid systems include substituted and unsubstituted lactide,
glycolide, polylactic acid, polyglycolic acid, a copolymer of
polylactic acid and polyglycolic acid, a copolymer of glycolic acid
with other hydroxy-, carboxylic acid-, or hydroxycarboxylic
acid-containing moieties, a copolymer of lactic acid with other
hydroxy-, carboxylic acid or hydroxycarboxylic acid-containing
moieties, or mixtures of the preceding. Other materials suitable
for use in VES fluid systems are all those polymers of
hydroxyacetic acid (glycolic acid) with itself or other hydroxy-,
carboxylic acid-, or hydroxycarboxylic acid-containing moieties
described in U.S. Pat. No. 4,848,467; U.S. Pat. No. 4,957,165; and
U.S. Pat. No. 4,986,355. Suitable solid acids are also described in
U.S. Pat. No. 7,166,560, which is hereby incorporated by
reference.
[0117] Embodiments of the invention may use other additives and
chemicals that are known to be commonly used in oilfield
applications by those skilled in the art. These include, but are
not necessarily limited to, materials in addition to those
mentioned hereinabove, such as breakers, breaker aids, amino acids,
oxygen scavengers, alcohols, scale inhibitors, corrosion
inhibitors, fluid-loss additives, bactericides, iron control
agents, organic solvents, and the like.
[0118] A buffering agent may be employed to buffer the fluids
according to an embodiment, i.e., moderate amounts of either a
strong base or acid may be added without causing any large change
in pH value of the fracturing fluid. In various embodiments, the
buffering agent is a combination of a weak acid and a salt of the
weak acid; an acid salt with a normal salt; or two acid salts.
Examples of suitable buffering agents are sodium carbonate-sodium
bicarbonate, sodium bicarbonate, or other like agents. By employing
a buffering agent instead of merely a hydroxyl ion producing
material, a fracturing fluid is provided which is more stable to a
wide range of pH values found in local water supplies and to the
influence of acidic materials located in formations and the like.
In an exemplary embodiment, the pH control agent is varied between
about 0.6 percent and about 40 percent by weight of the
polysaccharide employed.
[0119] Some fluid compositions useful in some embodiments of the
invention may also include a gas component, produced from any
suitable gas that forms an energized fluid or foam when introduced
into an aqueous medium. See, for example, U.S. Pat. No. 3,937,283
(Blauer et al.). Preferably, the gas component comprises a gas
selected from nitrogen, air, argon, carbon dioxide, natural gas,
and the like, and any mixtures thereof. In an embodiment, the gas
component comprises nitrogen or carbon dioxide, in any quality
readily available. The gas component may assist in the fracturing
and acidizing operation, as well as the well clean-up process. The
fluid in one embodiment may contain from about 10% to about 90% or
more volume gas component based upon total fluid volume percent,
preferably from about 20% to about 80% volume gas component based
upon total fluid volume percent, and more preferably from about 30%
to about 70% volume gas component based upon total fluid volume
percent.
Example 1
[0120] Hydraulic differential pressure was measured in a silica
flour pack while pumping potassium chloride brine (2 wt %) at a
flow rate of 0.5 ml/min. The silica flour comprised 99.5% quartz,
measured by X-ray diffraction. The silica flour consisted of
particulates less than 44 microns (325 US mesh) with median
diameter of 18.4 microns. The loading comprised 4.9 kg/m.sup.2 (2.0
lb/ft) in an API recommended conductivity cell between two metal
cores under closure stress of 13.8 MPa (2000 psi). FIG. 1 is a
schematic drawing of a typical branched network channel 10 formed
around an island in the silica flour pack 12 by washout in the
conductivity cell. FIG. 2 shows a time-trace of the pressure drop
in the silica flour pack and illustrates the slow equilibration
rate to steady state. The spikes seen in FIG. 2 are due to washout
of silica flour from the pack.
Example 2
[0121] Conductivity of muscovite mica packs formed from mica with a
median particle diameter of 120 microns was measured by means of a
Chandler Engineering FRT Model 6100 formation response tester in a
split-core set-up. The mica was loaded uniformly at 0.5 kg/m (0.1
lb/ft) between two metal cores, which were compressed with closure
stresses of 13.8, 20.7, 27.6, and 34.5 MPa (2000, 3000, 4000 and
5000 psi). Potassium chloride brine (2 wt %) was pumped through the
cell with flow rates of 0.05, 0.1 and 0.5 ml/min. The steady state
conductivity data for the mica packs are presented in Table 1 and
shown graphically in FIG. 3. The formation of channels in the mica
packs was visually confirmed upon disassembly of the conductivity
cell, and it was seen that the higher flow rates resulted in
relatively larger channel formation.
TABLE-US-00001 TABLE 1 Conductivity of uniform mica packs at 0.5
kg/m. Closure Stress, MPa (psi) Flow Rate, 13.8 (2000) 20.7 (3000)
27.6 (4000) 34.5 (5000) ml/min Conductivity, mD-m (mD-ft) 0.50
0.069 (0.225) 0.41 (0.082) 0.25 (0.082) 0.015 (0.048) 0.10 0.036
(0.119) Not 0.010 (0.034) Not measured measured 0.05 0.023 (0.074)
0.013 (0.043) 0.008 (0.026) 0.005 (0.015)
Example 3
[0122] Conductivity of muscovite mica packs formed from mica with a
median particle diameter of 105 microns was measured in a
split-core set-up.
[0123] The mica was loaded uniformly or in pillars at 5 kg/m (0.01
lb/ft) between two Mancos shale cores, which were compressed with
closure stresses of 3.4, 6.9, 13.8, 27.6, 41.4 and 55.2 MPa (500,
1000, 2000, 4000, 6000 and 8000 psi). The pillars were arranged in
a triangular pattern of 11 pillars in longitudinal rows of 4, 3 and
4 pillars as seen in FIG. 4, or in a 6 by 12 square pattern of 72
pillars, as seen in FIG. 5. Potassium chloride brine (2 wt %) was
pumped through the cell with flow rates of 0.05-0.200 ml/min. The
steady state conductivity data for the mica packs are presented in
Table 2 and shown graphically in FIG. 6. The placement of the mica
in the pillar arrangement obtained a relatively higher conductivity
than the uniform mica placement. The placement of the mica in the
72-pillar configuration had a higher conductivity relative to the
11-pillar configuration, and both had higher conductivities than
the test situation where the mica was distributed uniformly on the
core surface.
TABLE-US-00002 TABLE 2 Conductivity of uniform and pillared mica
packs. Closure Stress, MPa (psi) Mica loading 6.9 (1000) 13.8
(2000) 27.6 (4000) 41.4 (6000) 55.2 (8000) configuration
Conductivity, mD-m (mD-ft) Uniform, 0.016 (0.051) 0.005 (0.018)
0.001 (0.004) less than less than 0.05 kg/m.sup.2, 0.001 0.001
11-Pillar 1.08 (3.53) 0.276 (0.907) 0.019 (0.062) 0.003 (0.011)
less than triangular, 0.001 0.05 kg/m2 72-Pillar 13.1 (42.9) 11.2
(36.6) 5.72 (18.8) 4.12 (13.5) 2.62 (8.60) square, 0.05 kg/m2
Example 4
[0124] An aqueous slurry of 60 g/L of muscovite mica in deionized
slickwater was flocculated with a commercial polyacrylamide
friction reducer with NaOH to adjust pH to 8.1, 11.9 and 12.5.
Visual inspection of the floc indicated that the higher the pH, the
larger the floc and the greater the spacing of the floc, indicating
that fracture conductivity can be enhanced by flocculation of a
fine mesh proppant material. Quantitatively, median particle size
was measured by means of an optical microscope. The relative number
of mica particles aggregated in the median-sized flocs at the
higher pH's was calculated based on the assumptions that each
multiparticle floc had a spherical shape and porosity of 0.5. The
results are presented in Table 3 below.
TABLE-US-00003 TABLE 3 Median particle size and relative number of
mica particles in flocs controlled by pH adjustment. Sample Mica
slurry Floc Floc pH 8.1 11.9 12.5 Median particle size, mm 0.12
0.74 1.17 No. of particles, n 1 117 463
Example 5
[0125] The procedure of Example 4 was repeated except using 60 g/L
silica flour at pH 8.1, 11.9 and 12.5, and the floc characteristics
are presented in Table 4. Again, the higher the pH, the larger the
floc and larger number of aggregated particles, indicating that
fracture conductivity can be enhanced by flocculation of a fine
mesh proppant material.
TABLE-US-00004 TABLE 4 Median particle size and relative number of
silica particles in flocs controlled by pH adjustment. Sample
Silica slurry Floc Floc pH 8.1 11.9 12.5 Median particle size, mm
0.018 0.33 0.42 No. of particles, n 1 2880 5950
Example 6
[0126] Settling and flocculation of muscovite mica slurry in
slickwater based on cationic polyacrylamide friction reducer was
observed without and with addition of sodium hydroxide to give
solution pH of about 8.1 and 12.5, and the relative rate of
settling was determined by taking measurements of the height of the
dense and dilute phases in a sample bottle after 3, 9 and 19
seconds following caustic addition. In general, the larger the floc
that is formed, the faster the settling rate. The results are
presented in Table 5, and show that the settling rate and floc size
can be controlled by adjusting the pH.
TABLE-US-00005 TABLE 5 Settling rates of muscovite mica flocs. pH
8.1 12.5 Elapsed Dilute Dense Dilute Dense time, phase phase phase
phase seconds height, mm height, mm height, mm height, mm 0 0 55 0
55 3 1 54 8 47 9 3 52 17 38 19 14 41 25 30
Example 7
[0127] The particle size of silica powder was determined (Malvern
Mastersizer). The values determined were: [0128] d.sub.10=6 micron,
[0129] d.sub.50=34 micron, and [0130] d.sub.90=84 micron.
[0131] This silica powder was hydrophobically modified by treatment
with an excess of reactive organosilane, using the following
procedure. 1 g silica, dried under vacuum, was added to 10 ml
trimethylchlorosilane at 20.degree. C. and stirred with a magnetic
stirrer for 30 minutes. Then the suspension was filtered and the
treated silica was washed on the filter with 50 ml anhydrous
toluene and 20 ml anhydrous hexane. After this the treated silica
was dried overnight in a vacuum desiccator.
[0132] This hydrophobically modified silica was placed in a bottle
containing 10 ml deionised water. As a control, 1 g of unmodified
silica was placed in a second bottle, also containing 20 ml
deionised water. 1 ml dodecane was added to each bottle, and the
bottles were shaken vigorously and then left to stand. The
unmodified silica in the control bottle was observed to settle to a
layer at the base of the bottle. The hydrophobically modified
silica formed a single agglomerated mass in its bottle.
Example 8
[0133] Inorganic substrate, silica gel (Merck Type 9385
Sigma-Aldrich, Cat. No.: 22, 719-6) having particle size between
230 and 400 US mesh (63 micron and 40 micron) and GPC glass beads
(100 mesh) was dried under vacuum overnight and given a surface
coating of polymer by the following procedure. A quantity of
polymer was dissolved in 6 ml dichloromethane (DCM). The
polymer/DCM solution was added to 30 g substrate in a small beaker.
The mixture was then stirred for approx. 10 min in a fume hood;
during this period the DCM evaporated, depositing the polymer as a
coating on the surface of the silica. The resulting coated silica
was dried at room temperature overnight.
[0134] This polymer coating procedure was carried out using
polystyrene (PS) and polymethylmethacrylate (PMMA). The amounts of
polymer were 0.15 wt % by weight of the silica (or glass beads).
Agglomeration by oil was demonstrated as in the previous example
with both polymer-coated granular materials. Polystyrene is more
hydrophobic than polymethylmethacrylate and was considered the more
suitable of the two materials, producing tighter agglomerates.
[0135] The foregoing disclosure and description of the invention in
various embodiments is illustrative and explanatory thereof and it
can be readily appreciated by those skilled in the art that various
changes in the size, shape and materials, as well as in the details
of the illustrated construction or combinations of the elements
described herein can be made without departing from the spirit of
the invention.
* * * * *