U.S. patent application number 11/336344 was filed with the patent office on 2006-08-10 for soluble deverting agents.
Invention is credited to Syed Akbar, Patrick R. Okell, A. Richard Sinclair.
Application Number | 20060175059 11/336344 |
Document ID | / |
Family ID | 36590218 |
Filed Date | 2006-08-10 |
United States Patent
Application |
20060175059 |
Kind Code |
A1 |
Sinclair; A. Richard ; et
al. |
August 10, 2006 |
Soluble deverting agents
Abstract
Methods and compositions for stimulating single and multiple
intervals in subterranean wells by diverting well treatment fluids
into a particular direction or into multiple intervals using water
soluble coated diverting agents are described. The water soluble
coating of the diverting material is preferably a collagen,
poly(alkylene) oxide, poly(lactic acid), polyvinylacetate,
polyvinylalcohol, polyvinylacetate/polyvinylalcohol polymer or a
mixture thereof applied as a coating on any number of proppants.
The method allows for the diverting of the flow of fluids in a
downhole formation during a well treatment, such as during a
fracturing process. Following completion of a treatment such as a
hydraulic stimulation, the soluble diverting agent can be dissolved
and removed by the water component of the well production.
Inventors: |
Sinclair; A. Richard;
(Houston, TX) ; Okell; Patrick R.; (Bellaire,
TX) ; Akbar; Syed; (Houston, TX) |
Correspondence
Address: |
HOWREY LLP
C/O IP DOCKETING DEPARTMENT
2941 FAIRVIEW PARK DRIVE, SUITE 200
FALLS CHURCH
VA
22042-7195
US
|
Family ID: |
36590218 |
Appl. No.: |
11/336344 |
Filed: |
January 20, 2006 |
Related U.S. Patent Documents
|
|
|
|
|
|
Application
Number |
Filing Date |
Patent Number |
|
|
60646231 |
Jan 21, 2005 |
|
|
|
Current U.S.
Class: |
166/283 ;
166/313 |
Current CPC
Class: |
C09K 8/805 20130101;
E21B 43/261 20130101; E21B 43/14 20130101 |
Class at
Publication: |
166/283 ;
166/313 |
International
Class: |
E21B 43/26 20060101
E21B043/26; E21B 43/14 20060101 E21B043/14 |
Claims
1. A diverting material comprising: a particulate substrate; and a
water-soluble polymer coating, wherein the water-soluble polymer
coating forms a substantial outer coating on the particulate
substrate.
2. The diverting material of claim 1, wherein the particulate
substrate is selected from the group consisting of natural
materials, silica proppants, ceramic proppants, metallic proppants,
synthetic organic proppants, and mixtures thereof.
3. The diverting material of claim 1, wherein the particulate
substrate is a resin coated proppant.
4. The diverting material of claim 1, wherein the water-soluble
polymer is collagen, poly(alkylene) oxide, poly(lactic acid),
polyvinylacetate, polyvinylalcohol, polylactone, polyacrylate,
latex, polyester, periodic chart elements of group I or II (alkali
metal or alkaline earth metal) silicate polymers or admixtures
thereof.
5. The diverting material of claim 1, wherein the particulate
substrate has a particle size of from about 3 mesh to about 200
mesh.
6. The diverting material of claim 4, wherein the collagen is Type
I collagen, Type II collagen, Type III collagen, Type IV collagen,
or Type V collagen.
7. The diverting material of claim 4, wherein the water-soluble
collagen is crosslinked with a cross-linking agent selected from
the group consisting of aldehydes, carbodiimides, isocyanates, and
acyl azides.
8. The diverting material of claim 1, further comprising a
non-water-soluble polymer in combination with the water-soluble
polymer coating.
9. The diverting material of claim 8, wherein the non water-soluble
polymer is phenol-aldehyde novolac polymers and phenol-aldehyde
resole polymers.
10. The diverting material of claim 1, wherein the water-soluble
polymer is poly(alkylene) oxide, poly(lactic acid),
polyvinylacetate, polyvinylalcohol,
polyvinylacetate/polyvinylalcohol graft polymers or admixtures
thereof.
11. The diverting material of claim 10, wherein the poly(alkylene)
oxide is poly(ethylene) oxide, poly(propylene) oxide, poly
(ethylene oxide)-poly (propylene oxide) block copolymers, or
mixtures thereof.
12. A diverting fluid for diverting oil well treating liquids to
progressively less permeable portions of a subterranean formation,
said fluid comprising: an aqueous carrier liquid having dispersed
therein particulate diverting material of any one of claims
1-11.
13. The diverting fluid of claim 12, wherein the particulate
diverting material comprises varying densities greater or less than
the density of the carrier fluid.
14. The diverting fluid of claim 12, wherein the diverting material
is present in the carrier liquid in an amount from about 0.001
pounds per gallon to about 10 pounds per gallon of the carrier
liquid.
15. The diverting fluid of claim 12, wherein the carrier liquid is
water, brine, aqueous acid solutions, or gelled acid solutions.
16. A method of treating a subterranean formation during fracturing
treatment so as to increase the stimulation of the subterranean
formation, the method comprising: pumping into the subterranean
formation a diverting fluid of any one of claims 12-15; allowing
the carrier liquid to permeate into the formation so as to carry
the diverting material into the subterranean formation; and
allowing the diverting material to plug porous portions of the
formations thereby diverting flow of treating fluid to less
permeable portions of the formation.
17. The method of claim 16, wherein the formation has a temperature
from about 75.degree. F. to about 400.degree. F.
18. The method of claim 16, wherein the treating of the
subterranean formation is a fracturing treatment, and wherein the
stimulation increased is the length of the fractures.
19. A method treating a cased wellbore to divert flow of fluids
from one zone to another, the method comprising: pumping into said
wellbore a diverting fluid comprising an aqueous carrier liquid
having dispersed therein a particulate form of a water soluble
polymer, wherein the particulate polymer has a density greater than
or less than the density of the carrier liquid; allowing the
particulate polymer to divert flow of a treating fluid from one
zone to another.
20. The method of claim 19, wherein the treating fluid is diverted
to flow into a zone of higher pore pressure or lower
permeability.
21. The method of claim 19, wherein the wellbore has a temperature
from about 75.degree. F. to about 400.degree. F.
22. The method of claim 19, wherein the water-soluble polymer is
collagen, poly(alkylene) oxide, poly(lactic acid),
polyvinylacetate, polyvinylalcohol, polylactone, polyacrylate,
latex, polyester, polyvinylacetate/polyvinylalcohol graft polymer,
periodic chart elements of group I or II (alkali metal or alkaline
earth metal) silicate polymer, or mixtures thereof.
23. The method of claim 19, wherein the particulate polymer has a
particle size of from about 3 mesh to about 70 mesh.
24. The method of claim 22, wherein the poly(alkylene) oxide is
poly(ethylene) oxide, poly(propylene) oxide, poly (ethylene
oxide)-poly (propylene oxide) block copolymers, or mixtures
thereof.
25. The method of claim 19, wherein the particulate polymer is
comprised of varying densities greater or less than the density of
the carrier fluid.
26. The method of claim 19, wherein the particulate polymer is
present in the carrier liquid in an amount from about 0.001 pounds
per gallon to about 10 pounds per gallon of the carrier liquid.
27. The method of claim 19, wherein the carrier liquid is water,
brine, aqueous acid solutions, or gelled acid solutions.
Description
[0001] The present application claims priority benefit to U.S.
provisional application Ser. No. 60/646,231 filed Jan. 21, 2005,
the entire contents of which are incorporated by reference
herein.
FIELD OF THE INVENTION
[0002] The present invention provides methods and compositions for
treating subterranean wells and, more specifically, provides
methods and compositions for stimulating multiple intervals in
subterranean wells. In particular, this invention provides methods
and compositions for diverting well treatment fluids into multiple
intervals by introducing propping materials coated with a water
soluble polymer e.g. collagen, polyvinyl acetate/polyvinyl alcohol,
polyalkyl oxides, poly(lactic acid), periodic chart elements of
group I or II (alkali metal or alkaline earth metal) silicate
polymer, or combinations thereof with materials that are slowly
water soluble for use in redirecting the flow of stimulation fluids
from a tubing string into the subterranean environment.
DESCRIPTION OF RELATED ART
[0003] Well treatments, such as acid and fracture treatments of
subterranean formations are routinely used to improve or stimulate
the recovery of hydrocarbons. In many cases, a subterranean
formation may include two or more intervals having varying
permeability and/or injectivity. Some intervals may possess
relatively low injectivity, or ability to accept injected fluids,
due to relatively low permeability, high in-situ stress, and/or
formation damage. Such intervals may be completed through
preparations in a cased wellbore and/or may be completed open hole.
In some cases, such formation intervals may be present in a highly
deviated or horizontal section of a wellbore, for example, a
lateral open hole section. In any case, when treating multiple
intervals having variable injectivity it is often the case that
most, if not all, of the introduced well treatment fluid will be
displaced into one, or only a few, of the intervals having the
highest injectivity. Even if there is only one interval to be
treated, the tendency for the growth of the fracture can be either
up or down. This depends on the in situ formation stress and the
permeability variation in the formation layer. Below the created
fracture can be a water zone. If the created fracture breaks into
this zone, the well can be ruined due to excess water and a cut off
of the petroleum components of the productive interval. Above the
created fracture zone a gas cap may exist which would cause harm to
the production of the well because of gas bypassing the liquid
petroleum components of the well.
[0004] In an effort to more evenly distribute displaced well
treatment fluids into each of the multiple intervals being treated,
methods and materials for diverting treatment fluids into intervals
of lower permeability and/or injectivity have been developed.
However, conventional diversion techniques may be costly and/or may
achieve only limited success. In this regard, mechanical diversion
techniques are typically complicated and costly. Furthermore,
mechanical diversion methods are typically limited to cased hole
environments and depend upon adequate cement and tool isolation for
achieving diversion.
[0005] The efficient and simultaneous treatment of multiple sets of
perforations over an extended vertical section has thus been a
problem in well stimulation for numerous years. Numerous treatment
diversion methods, such as oil-soluble calcium soap, sulfuric acid,
and Dowell's "Fixafrac" (a mixture of lime, kerosene, a graded
calcium chloride soap, and a gelling agent, and Dowell's FLAX-2.TM.
as described by Harrison in his comprehensive review Journal of
Petroleum Technology, pp. 593-598 (1972), have been used to treat
multiple zones with a wide variety of effectiveness. A great
variety of chemical based diverting agents have been used in
attempts to plug formation openings and divert treating fluids to
other zones of the formation. For example, wax beads have been used
as diverting agents. However, the wax beads have limited melting
points, from about 138.degree. F. to about 192.degree. F., making
them useless if the formation temperature exceeds their melting
point.
[0006] Naphthalene (moth balls) and sodium chloride particles have
also been described to be useful as effective diverting agents.
Naphthalene particles are readily soluble in oil, but melt at about
180.degree. F., thereby limiting their use to applications in
lower-temperature formations. Sodium chloride, having a melting
point of about 1,470.degree. F., while useful at high temperatures,
requires that the well be cleaned with water or dilute acid after
the formation has been treated in order to fully remove the sodium
chloride particles. Furthermore, sodium chloride cannot be used
with hydrofluoric acid to treat subterranean wells due to the
formation of insoluble precipitates which can problematically block
the wellbore.
[0007] Alternatively, diversion agents such as polymers, suspended
solid materials and/or foam have been employed when simultaneously
treating multiple intervals of variable injectivity. Such diversion
agents are typically pumped into a subterranean formation prior to
a well treatment fluid in order to seal off intervals of higher
permeability and divert the well treatment fluid to intervals of
lower permeability. However, the diverting action of such diversion
agents is often difficult to predict and monitor, and may not be
successful in diverting treatment fluid into all desired intervals.
These problems may be further aggravated in open hole completions,
especially in highly deviated completions having large areas of a
formation open to the wellbore. The presence of natural fractures
may also make diversion more difficult.
[0008] Several attempts to address the issues of areas of differing
permeability within a wellbore have been addressed over the years.
U.S. Pat. No. 2,803,306 to Hower offers a process for increasing
the permeability of an underground formation having several zones
of varying permeability. The steps described include introducing
into a well bore a treatment fluid containing hydrochloric acid
which has oil-soluble particles dispersed therein, the material
being selected from gilsonite, naphthalene, para-dichlorobenzene,
anthracene, and .beta.-naphthol. Upon treatment, the particles
provide a partial blockage of the more permeable zones of the
subterranean formation, allowing the treatment fluid to enter the
less-permeable zones.
[0009] U.S. Pat. No. 3,797,575 assigned to Halliburton discloses
diverting-forming additives comprised of relatively water insoluble
solid material dissolved in a solvent such as methanol or
isopropanol. When the additive is combined with an aqueous
treatment fluid, the solid material, dissolved in the additive, is
precipitated in the aqueous treating fluid into a finally divided
form, which then act as a diverting agent. U.S. Pat. No. 3,724,549,
also assigned to Halliburton, describes a diverting agent material
for diverting aqueous treatment fluids into progressively less
permeable subterranean formations. The material is composed of a
carrier liquid and graded particles of cyclic or linear hydrocarbon
resins having between about 20 and about 1,400 carbon atoms, and a
melting point of about 200.degree. F. This material is described as
being largely water and acid insoluble, but soluble in oil, such
that the resin can be removed by the produced oil after the
completion of the oil treatment operation.
[0010] The use of radiation-induced polymers as either temporary or
permanent diverting agents has been described by Knight, et al. in
U.S. Pat. No. 3,872,923. According to the specification, temporary
or permanent reductions in permeability can be obtained by
injecting an aqueous solution containing a water-soluble polymer
obtained by radiation-induced polymerization of acrylamide and/or
methacrylamide and acrylic acid, methacrylic acid, and/or alkali
metal salts of such acids. The resultant polymeric diverting agent
has properties, such as temperature and pH stability, so as to
effect a reduction of permeability of the porous medium.
Permeability within the formation can be restored by subsequent
treatment with a chemical to break down the polymer, such as
hydrazine hypochlorite solution or strong mineral acids.
[0011] U.S. Pat. Nos. 3,954,629 and 4,005,753 to Scheffel, et al.,
offer polymeric diverting agents, and methods of treating
subterranean formations with such polymeric diverting agents,
respectively. The polymeric composition is described to comprise
solid particles of a homogenous mixture of polyethylene,
ethylene-vinyl acetate copolymer, a polyamide, and a softening
agent such as long chain aliphatic diamides. These polymeric
diverting agents are reported to be suitable for use in
subterranean formations where formation temperatures are
350.degree. F. or greater.
[0012] Methods of temporarily plugging a subterranean formation
using a diverting material comprising an aqueous carrier liquid and
a diverting agent comprising a solid azo component and a methylenic
component are described by Dill, et al. in U.S. Pat. No. 4,527,628.
The diverting agent is preferably Hansa Yellow G (Fanchon Yellow
YH-5707 pigment) or Fast Yellow 4RLF dye, both of which have an azo
component and a methylenic component and are further characterized
as having a melting point of at least 332.6.degree. F., a degree of
solubility in water at a temperature of water from about 200 to
about 425.degree. F., and a degree of solubility in kerosene at a
temperature of from about 200.degree. F. to about 425.degree.
F.
[0013] In U.S. Pat. No. 6,367,548, Purvis, et al. describes methods
and compositions for stimulating multiple intervals in subterranean
wells by diverting well treatment fluids into multiple intervals.
According to the specification, this is accomplished by alternately
displacing diverting agent from the annulus of the wellbore into a
subterranean formation and displacing treatment fluid from a tubing
string into the subterranean formation.
[0014] Other methods for diverting a fracture treatment include the
limited-entry technique described by LaGrone, et al., SPE 530, pp.
695-702 (1963), and the Technique of Multi-Fracture Fracturing
Using a Diverting Agent (TMFUD) suggested by Dingxiang, et al., SPE
30816, pp. 80-86 (1988), the latter of which has shown an average
oil production improvement of 15.0 t/d for each well, and a
cumulative production improvement of 340.3.times.10.sup.4 tons. A
viscoelastic surfactant-based diverting agent for use in acid
stimulations has also been described (Alleman, D., et al., SPE
80222 (2003)), which is a VES gel (polyQuat) characterized by a
distinctive vesicle structure stable at high pH and a thermal
stability of about 250.degree. F. This gel-type diversion agent is
typically pumped into a subterranean formation prior to a well
stimulation fluid in order to seal off intervals of high
permeability and divert the well treatment fluid to intervals of
low permeability.
[0015] In light of all these advances and new techniques, the
diverting action of diverting agents is often difficult to predict
and monitor, and may not be successful in diverting treatment fluid
into all the desired intervals, thereby failing to allow maximum
benefit from the fracture procedure. These problems can be further
aggravated in open hole completions, especially in highly-deviated
completions having large areas of a formation open to the wellbore.
The presence of natural fractures within the subterranean formation
can also serve to make diversion more challenging. Thus, there
exists a need for new compositions and methods for diverting well
treatment fluids into multiple intervals of varying permeability
within a subterranean formation.
SUMMARY OF THE INVENTION
[0016] The present invention provides a method of using particles
having a soluble outer coating as diverting agents in subterranean
formations. The soluble outer coating will dissolve after a desired
period of time at downhole temperatures and pressures in the
presence of standard downhole fracturing fluids and breaker
compositions. Examples of the soluble outer coating include
collagen, poly(alkylene) oxides, poly(lactic acid),
polyvinylacetate, polyvinyl alcohol,
polyvinylacetate/polyvinylalcohol, polylactone, polyacrylate,
latex, polyester, group I or II silicate polymer or mixtures
thereof.
[0017] The present invention provides water soluble polymer coated
proppants as diverting agents and methods of using such diverting
agents for treating a subterranean formation. The diverting agent
together with a carrier liquid is introduced into a subterranean
formation. The liquid carrier flows into fractures and/or intervals
within the subterranean formation. The fractures or intervals
present varying degrees of permeability. In accordance with the
methods of the present invention, the liquid carrier with diverting
agent will flow to the most permeable interval first. The
temperature of the formation will cause the water soluble polymer
coating of the diverting agent to soften and swell, thereby
plugging the fracture.
[0018] In one embodiment, a diverting agent suitable for diverting
well treatment fluids into a single or a multiple interval is
described, wherein the diverting agent is comprised of a
particulate substrate and a water-soluble outer layer. Such water
soluble outer layer polymer is exemplified, without limitation, by
collagen, poly(alkylene) oxides, poly(lactic acid)
polyvinylacetate, polyvinylalcohols,
polyvinylacetate/polyvinylalcohol, polymeric lactones,
water-soluble acrylics, latex, polyester, group I or II silicate
polymer, and admixtures thereof.
[0019] In a further embodiment, a diverting agent suitable for
diverting well treatment fluids into a single or a multiple
interval is described, wherein the diverting agent is comprised of
a particulate substrate an intermediate water insoluble layer and a
water soluble polymer outer layer. The water soluble outer layer
polymer is exemplified, without limitation, by collagen,
poly(alkylene) oxides, poly(lactic acid), polyvinylacetate,
polyvinylalcohols, polyvinylacetate/polyvinylalcohol, polymeric
lactones, water-soluble acrylics, latex, polyester, group I or II
silicate polymer and admixtures thereof. The water insoluble
intermediate layer is exemplified by phenol-aldehyde novolac
polymers and phenol-aldehyde resole polymers.
[0020] In yet another embodiment, a diverting agent suitable for
diverting well treatment fluids into a single or a multiple
interval within a wellbore is described, wherein the diverting
agent is substantially a water-soluble polymer particle such as a
collagen bead or granular particles of poly(alkylene) oxide,
poly(lactic acid), polyvinylacetate, polyvinylalcohol,
polyvinylacetate/polyvinylalcohol, polymeric lactones,
water-soluble acrylics, latex, polyester, group I or II silicate
polymer, or mixtures thereof.
[0021] In a further embodiment, a method of stimulating individual
intervals of a subterranean formation is disclosed, the method
including the steps of introducing a diverting agent having a
water-soluble component on its outer layer into an inner pipe of a
wellbore in combination with a low viscosity fluid or a fracturing
fluid; displacing the diverting agent and fracturing fluid into the
subterranean formation, allowing the diverting agent to
progressively plug portions of the formation being treated; and
repeating the process as necessary, adding the diverting agent to
the carrier fluid in slugs during the fracturing operation.
DESCRIPTION OF THE FIGURES
[0022] The following figures form part of the present specification
and are included to further demonstrate certain aspects of the
present invention. The invention may be better understood by
reference to one or more of these figures in combination with the
detailed description of specific embodiments presented herein.
[0023] FIG. 1 shows an elevational cross-sectional view of a
downhole portion of a subterranean formation having a vertical
casing and a single treatment interval, wherein variously coated
diverting agents are being injected into the hydrocarbon-bearing
formation in accordance with an aspect of the present
disclosure.
[0024] FIG. 2 illustrates the elevational cross-sectional view of
the subterranean formation of FIG. 1, wherein proppants are being
injected into a hydrocarbon-bearing formation having diverting
agents of the present invention injected.
[0025] FIG. 3 shows a well with a vertical casing and multiple
treatment intervals 58, 60 and 62 and variously coated diverting
agents being injected, in accordance with an aspect of the present
disclosure.
DEFINITIONS
[0026] The following definitions are provided in order to aid those
skilled in the art in understanding the detailed description of the
present invention.
[0027] The term "carrier liquid" as used herein refers to oil or
water based liquids that are capable of moving particles (e.g.,
proppants) that are in suspension. Low viscosity carrier fluid have
less carrying capacity and the particles can be affected by gravity
so that they either rise if they are less dense than the liquid or
sink if they are more dense than the liquid. High viscosity liquids
can carry particles with less settling or rising since the
viscosity overcomes gravity effects.
[0028] The term "crosslinker" or "cross-linking agent", as used
herein, refers to those compounds used to covalently modify
proteins, such as collagen, and includes both homobifunctional
crosslinkers that contain two identical reactive groups, and
heterobifunctional crosslinkers which contain two different
reactive groups.
[0029] The term "diverting agent", as used herein, means and refers
generally to an agent that functions to prevent, either temporarily
or permanently, the flow of a liquid into a particular location,
usually located in a subterranean formation, wherein the agent
serves to seal the location and thereby cause the liquid to
"divert" to a different location.
[0030] The term "proppant", as used herein, refers to those sized
particles that are used in well work-overs and treatments, such as
hydraulic fracturing operations, to hold fractures open following
the treatment. Such sized particles are often mixed with fracturing
fluid(s) to hold fractures open after a hydraulic fracturing
treatment or similar downhole well treatment. In addition to
naturally occurring sand grains and nut hulls, the term "proppant"
includes man-made or specially engineered proppants, such as
resin-coated sand or high-strength ceramic materials like sintered
bauxite. Resin coated proppants are typified by those that are
coated with phenol-aldehyde novolac polymers or phenol-aldehyde
resole polymers. Typically, but not necessarily, proppant materials
are carefully sorted for size and sphericity to provide an
efficient conduit for production of fluid from the reservoir to the
wellbore.
[0031] In embodiments described and disclosed herein, the use of
the term "introducing" includes pumping, injecting, pouring,
releasing, displacing, spotting, circulating, or otherwise placing
a fluid or material within a well, wellbore, or subterranean
formation using any suitable manner known in the art. Similarly, as
used herein, the terms "combining", "contacting", and "applying"
include any known suitable methods for admixing, exposing, or
otherwise causing two or more materials, compounds, or components
to come together in a manner sufficient to cause at least partial
reaction or other interaction to occur between the materials,
compounds, or components.
[0032] The term "water soluble" as used herein refers to resins,
polymers, or coatings which are stable (do not dissolve) under
ambient, surface conditions, but which become soluble after a given
time (usually over several hours or several days) when placed in a
subterranean environment.
[0033] The term "treatment", as used herein, refers to any of
numerous operations on or within the downhole well, wellbore, or
reservoir, including but not limited to a workover type of
treatment, a stimulation type of treatment, such as a hydraulic
fracturing treatment or an acid treatment, isolation treatments,
control of reservoir fluid treatments, or other remedial types of
treatments performed to improve the overall well operation and
productivity.
[0034] The term "stimulation", as used herein, refers to
productivity improvement or restoration operations on a well as a
result of a hydraulic fracturing, acid fracturing, matrix
acidizing, sand treatment, or other type of treatment intended to
increase and/or maximize the well's production rate or its
longevity, often by creating highly conductive reservoir flow
paths.
DETAILED DESCRIPTION OF THE INVENTION
[0035] In embodiments of the disclosed diverting agent, single and
multiple intervals of a subterranean formation can be treated or
stimulated in stages by successively introducing the diverting
agent comprising a particulate substrate and a slowly water-soluble
outer coating comprising collagen or a combination of collagen and
a slowly water-soluble, non-collagenous material.
[0036] The invention provides particle compositions comprising
soluble material coatings comprising collagen, as well as processes
for preparing such compositions. These compositions are useful in
subterranean formations for diverting well treatment fluids in a
single interval to increase the fracture length or in multiple
intervals of a subterranean formation having varying permeability
and/or injectivity during a hydraulic fracturing operation. In
using the diverting agents of the present invention in fracturing
processes, the proppant (or particulate substrate) coated with a
slowly water-soluble coating such as a collagen alone or in
combination with a non-collagenic water-soluble, plastic coating
material acts to divert the fracture, as the coatings on the
proppants act as the defining boundaries of the initial fracture.
Following the fracturing treatment, the coating can be removed due
to the slow-dissolution characteristics of the coating, leaving
standard propping agents with high permeability to flow into the
fracture and act as proppants.
[0037] While compositions and methods are described in terms of
"comprising" various components or steps, the compositions and
methods can also "consist essentially of" or "consist of" the
various components and steps.
A. Substrate
[0038] Particulate material, also referred to herein as substrate
material, suitable for use with the present invention includes a
variety of particulate materials known to be suitable or
potentially suitable propping agents which can be employed in
downhole operations. In accordance with the present invention, the
particulate material (or substrate material) which can be used
include any propping agent suitable for hydraulic fracturing known
in the art. Examples of such particulate materials include, but are
not limited to, natural materials, silica proppants, ceramic
proppants, metallic proppants, synthetic organic proppants,
mixtures thereof, and the like.
[0039] Natural products suitable for use as proppants include, but
are not limited to, nut shells such as walnut, brazil nut, and
macadamia nut, as well as fruit pits such as peach pits, apricot
pits, olive pits, and any resin impregnated or resin coated version
of these. Typical resin coatings or impregnations include
bisphenols, bisphenol homopolymers, blends of bisphenol
homopolymers with phenol-aldehyde polymer, bisphenol-aldehyde
resins and/or polymers, phenol-aldehyde polymers and homopolymers,
modified and unmodified resoles, phenolic materials including
arylphenols, alkylphenols, alkoxyphenols, and aryloxyphenols,
resorcinol resins, epoxy resins, novolak polymer resins, novolak
bisphenol-aldehyde polymers, and waxes, as well as the precured or
curable versions of such resin coatings.
[0040] Silica proppants suitable for use with the present invention
include, but are not limited to, glass spheres and glass
microspheres, glass beads, silica quartz sand, and sands of all
types such as white or brown. Typical silica sands suitable for use
include Northern White Sands (Fairmount Minerals, Chardon, Ohio),
Ottawa, Jordan, Brady, Hickory, Arizona, St. Peter, Wonowoc, and
Chalfort, as well as any resin coated version of these sands. In
the case of silica fibers being used, the fibers can be straight,
curved, crimped, or spiral shaped, and can be of any grade, such as
E-grade, S-grade, and AR-grade. Examples of suitable resin-coated
silica proppants for use with the present invention include
deformable proppants such as FLEXSAND LS.TM. and FLEXSAND MS.TM.
(available from BJ Services, Inc., Houston, Tex.) and Tempered
HS.RTM., Tempered LC.RTM., Tempered DC.RTM., and Tempered TF.RTM.
tempered proppants, all available from Santrol, Fresno, Tex.
[0041] Ceramic proppants suitable for use with the methods of the
present invention include, but are not limited to, ceramic beads;
spent fluid-cracking catalysts (FCC) such as those described in
U.S. Pat. No. 6,372,378, which is incorporated herein in its
entirety; ultra lightweight porous ceramics; economy lightweight
ceramics such as "ECONOPROP.TM." (Carbo Ceramics, Inc., Irving,
Tex.); lightweight ceramics such as "CARBOLITE.TM."; intermediate
strength ceramics such as "CARBOPROP.TM." (available from Carbo
Ceramics, Inc., Irving, Tex.); high strength ceramics such as
"CARBOHSP.TM." and "Sintered Bauxite" (Carbo Ceramics, Inc.,
Irving, Tex.), and HYPERPROP G2.TM., DYNAPROP G2.TM., or OPTIPROP
G2.TM. encapsulated, curable ceramic proppants (available from
Santrol, Fresno, Tex.) as well as any resin coated or resin
impregnated versions of these, such as described above.
[0042] Metallic proppants suitable for use with the embodiments of
the present invention include, but are not limited to, aluminum
shot, aluminum pellets, aluminum needles, aluminum wire, iron shot,
steel shot, and the like, as well as any resin coated versions of
these metallic proppants.
[0043] Synthetic proppants are also suitable for use with the
present invention. Examples of suitable synthetic proppants
include, but are not limited to, plastic particles or beads, nylon
beads, nylon pellets, SDVB (styrene divinyl benzene) beads, carbon
fibers such as PANEX.TM. carbon fibers from Zoltek Corporation (Van
Nuys, Calif.), and resin agglomerate particles similar to "FLEXSAND
MS.TM." (BJ Services Company, Houston, Tex.), as well as resin
coated versions thereof.
[0044] Additionally, soluble materials suitable for use as
proppants are also envisioned to be useful with the methods of the
present invention. For example, soluble proppants which are placed
in the channels of the created perforations include, but are not
limited to, marble or limestone chips or any other suitable
carbonate particulates. Additionally, wax, plastic, or resin
particles, either coated or uncoated, which are either soluble
through contact with a treatment chemical or can melt and flowback
from the fracture are suitable for use as proppants with the
present invention.
[0045] Suitable with the present invention, propping agents are
typically used in concentrations from about 1 to about 18 pounds
per gallon (about 120 g/L to about 2,160 g/L) of fracturing fluid
composition, but higher or lower concentrations may also be used as
required.
[0046] Similarly, the particulate substrate suitable for use with
the present invention has a particle size in the range of USA
Standard Testing screen numbers from about 4 to about 200 (i.e.,
screen openings of about 0.18 inch to about 0.003 inch). More
particularly, particulate substrate sizes suitable for use with the
present invention include size ranges from about 4 mesh (4750
microns) to about 200 mesh (75 microns). Also suitable for use with
the present invention are particulate materials or proppants having
size-designations of 6/12, 8/16, 12/18, 12/20, 16/20, 16/30, 20/40,
30/50, 40/70 and 70/140, although any desired size distribution can
be used, such as 10/40, 14/20, 14/30, 14/40, 18/40, and the like,
as well as any combination thereof (e.g., a mixture of 10/40 and
14/40). The preferred mesh size, in accordance with the present
invention, is 20/40 mesh.
B. Soluble Coating
[0047] The soluble coatings used in accordance with the present
invention can be any number of known soluble agents that are slowly
soluble in downhole, subterranean formations over a period of time.
Soluble polymer materials used in accordance with the present
invention should be soluble (that is, capable of dissolving in) in
brines, water, oil, organic solvents, acid or acidic media, and/or
in fluids having a pH in the range from about 1 to about 14, as
well as mixtures thereof under the conditions found in downhole,
subterranean formation.
[0048] Preferably, the soluble coating is a structural protein such
as collagen or atelocollagen, a vegetable protein such as found in
wheat, maize, oat or almonds, or a collgen originating from a
marine environment. The latter type of collagen can be extracted
from fish, algae, plankton, micro-plankton, and the like. More
preferably, the soluble coating is collagen, including Type I
collagen, Type II collagen, Type III collagen, Type IV, or Type V
collagen, as well as combinations thereof. Most preferably, in
accordance with the present invention, the soluble coating is a
Type I collagen or an atelocollagen.
[0049] Type I collagens or atelocollagens suitable for use as
soluble coatings in accordance with the present invention are those
collagens containing at least one hydroxyproline residue. Such Type
I collagens or atelocollagens include collagens found in tendons,
skin, bone, scar tissue, and the like, such as tropocollagens, as
well as products derived from the controlled, enzymatic or chemical
reduction of collagen proteins. Such collagens preferably have a
molecular weight from about 10,000 Daltons to about 500,000
Daltons, and more preferably from about 100,000 Daltons to about
300,000 Daltons. Suitable molecular weights of about 100,000
daltons, 125,000 daltons, 150,000 daltons, 175,000 daltons, 200,000
daltons, 225,000 daltons, 250,000 daltons, 275,000 daltons, 300,000
daltons, as well as molecular weights between any two of these
values, e.g., collagens having a molecular weight from about
225,000 to about 275,000 daltons. For example, a preferred Type I
collagen suitable for use with the present invention is
tropocollagen with a molecular weight of about 250,000 as supplied
by Milligans and Higgins, Inc. (Johnstown, N.Y.).
[0050] Collagens suitable for use within the present invention have
Bloom strengths from about 100 psi to about 900 psi, and more
preferably from about 300 psi to about 700 psi. Most preferably,
collagens suitable for use with the present invention have Bloom
strengths from about 400 psi to about 600 psi. Suitable Bloom
strengths, in accordance with the present invention, are about 400
psi, about 410 psi, about 420 psi, about 430 psi, about 440 psi,
about 450 psi, about 460 psi, about 470 psi, about 480 psi, about
490 psi, about 500 psi, about 510 psi, about 520 psi, about 530
psi, about 540 psi, about 550 psi, about 560 psi, about 570 psi,
about 580 psi, about 590 psi, and about 600 psi, as well as Bloom
strengths between any two of these values, e.g., from about 400 psi
to about 520 psi, such as 512 psi.
[0051] Bloom strength, as used herein, refers to the measured value
of the strength and/or rigidity of a gelatinous substance, such as
collagen, formed by a standard solution of definite concentration
that has been retained at a constant temperature for a specified
period of time, in accordance with standardized bloom testing
procedures, such as BS757:1975, GMIA Testing Standard B5757,
International Standard ISO9665 for testing adhesive animal glues,
or similar standards as described in "Official Methods of Analysis
of AOAC INTERNATIONAL (OAM)", 17th Edition, Volume II; AOAC
International Publications (2003). Bloom strength values are
typically given in "pounds per square inch" (psi) or grams,
reflecting the force required to depress a chosen area of the
surface of the sample a distance of 4 mm. In a typical procedure, a
gel product, such as collagen or gelatin, is formed to a specified
consistency (e.g., 6 and 2/3% solution) and kept at a constant
temperature in a constant temperature bath at 10 C. for 18 hours. A
device called a Texture Analyzer (e.g., the TA.XT2i Texture
Analyzer, Scarsdale, N.Y.) then measures the weight in grams (or
the pressure, in psi) required to depress a standard AOAC.RTM.
[Associateion of Official Analytical Chemists] gelometer plunger
having a sharp, lower edge 4 mm into the gel; alternatively, a BS
plunger which has a bottom edge rounded to a radius of 0.4 mm can
be used as the plunger. For example, if this procedure requires 200
grams to depress the plunger, then the gelatin has a Bloom strength
of 200.
[0052] Type I collagens suitable for use within the present
invention have a sieve distribution/size designation of 6/12, 8/16,
12/1.8, 12/20, 16/20, 16/30, 20/40, 30/50, 40/70 and 70/140, as
well as sieve distributions between any two of these designations,
although any desired size distribution can be used, such as 8/40,
10/40, 14/20, 14/30, 14/40, 18/40, and the like, as well as any
combination thereof (e.g., a mixture of 10/40 and 14/40). The
preferred mesh size, in accordance with the present invention, is
8/40 mesh.
[0053] Collagens, as used herein as soluble coatings, can be either
cross-linked, uncross-linked, or a combination of both, and the
type and degree of cross-linking will depend upon the specific
application of the collagen-based soluble coating. There are four
fundamental strategies for fixing collagenous materials and
materials constructed of processed collagen fibers or purified
collagen. These include exogenous chemical cross-linking using
agents that covalently couple neighboring collagen fibrils using
targeted reactive moieties in the collagen fibrillar system and the
cross-linking molecules themselves; physiochemical cross-linking
techniques such as photo-oxidation, microwave irradiation,
dehydration and dehydrothermal treatment, that covalently join
collagen fibrils via the naturally occurring reactive amino acid
side chains; chemical catalysis of intramolecular cross-links
between amino acid side chains on the collagen fibrils; and
polymerizing compounds mixed with collagenous assemblies and
forming polymeric non-covalent or covalent interactions that do not
chemically react with collagen fibrils [Koob, T. J., "Collagen
Fixation", in Encyclopedia of Biomaterials and Biomedical
Engineering, Wnek, G. E., Bowlin, G. L., Eds., 2004]. In accordance
with the present invention, the collagen used as a soluble coating
is preferably cross-linked using chemical cross-linking techniques.
These include, but are not limited to, aldehyde-based cross-linking
techniques, polyepoxy compound-based cross-linking techniques, the
use of isocyanates, carbodiimide cross-linking, and acyl azide
based crosslinking. More preferably, the collagen is cross-linked
using aldehyde-based cross-linking techniques, such as by using
glutaraldehyde or formaldehyde.
[0054] Aldehyde-based cross-linking techniques includes those
techniques using a reagent containing two reactive aldehyde groups
to form covalent cross-links between neighboring collagen proteins,
especially the e-amino groups of lysine residues in collagen [Khor,
E., Biomaterials, Vol. 18: pp. 95-105 (1997)]. Aldehydes suitable
for use with the present invention include but are not limited to
glutaraldehyde, formaldehyde, propionaldehyde, and
butyraldehyde.
[0055] Polyepoxy based cross-linking techniques and agents include
the use of compounds, such as short, branched polymers, terminating
in reactive epoxy functionalities. Polyepoxy compounds suitable for
use as cross-linking agents in the present invention include but
are not limited to glycerol ethers, glycol, and glycerol
polyglycidyl ethers.
[0056] Isocyanates are also suitable for use as cross-linking
agents in the present invention. Generally, the isocyanates (R-NCO)
react with primary amines to form a urea bond (R--H--CO--NH--R);
difunctional isocyanates therefore have the ability to cross-link
collagen via its lysine side chains. Isocyanates suitable for use
as cross-linking agents in the present invention are preferably
diisocyanates, including biphenyl diisocyanate,
dimethoxy-4,4'-biphenyl diisocyanante, dimethyl-4,4'-biphenyl
diisocyanate, 1,3-bis(isocyanatomethyl)benzene, phenyl
diisocyanate, toluene diisocyanate, tolylene diisocyanate,
diisocyanato hexane, diisocyanato octane, diisocyanato butane,
isophorone diisocyanante, xylene diisocyanate, hexamethylene
diisocyanante, octamethylene diisocyanante, phenylene diisocyanate,
and poly(hexamethylene diisocyanate). Preferably, the isocyanate
used as a cross-linking agent of the collagen molecules of the
present invention is hexamethylene diisocyanate.
[0057] Carbodiimide cross-linking agents and techniques can also be
used within the scope of the present invention. These agents react
with the carboxyl groups of aspartic and glutamic acid side chains
within the collagen to form isoacylurea derivatives/iso-peptide
bonds [Khor, E., ibid.]. Carbodiimides suitable for use as
cross-linking agents with the collagen of the present invention
include but are not limited to N,N'-dicyclohexylcarbodiimide (DCC);
N,N'-diisopropylcarbodiimide (DIC); N,N'-di-tert-butylcarbodiimide;
1-ethyl-3-(3-dimethylaminopropyl)carbodiimide (EDC; EDAC);
water-soluble EDC (WSC); 1-tert-butyl-3-ethylcarbodiimide;
1-(3-dimethylaminopropyl)-3-ethylcarbodiimide;
bis(trimethylsilyl)carbodiimide; 1,3-bis(2,2-dimethyl-
1,3-dioxolan-4-ylmethyl)carbodiimide (BDDC, as described in U.S.
Pat. No. 5,602,264); N-cyclohexyl-N'-(2-morpholinoethyl)
carbodiimide; N,N'-diethylcarbodiimide (DEC);
1-cyclohexyl-3-(2-morpholinoethyl)carbodiimide
methyl-p-toluenesulfonate [e.g., Sheehan, J. C., et al., J Org.
Chem., Vol. 21: pp. 439-441 (1956)]; oligomeric alkyl
cyclohexylcarbodiimides, such as those described by Zhang, et al.
[J. Org. Chem., Vol. 69: pp. 8340-8344 (2004)]; polymer bound DCC;
and polymer bound EDC, such as cross-linked
N-ethyl-N'-(3-dimethylaminopropyl)carbodiimide on JANDAJEL.TM..
Additionally, N-hydroxysuccinimide (NHS),
1-hydroxy-7-azabenzotriazole (HOAt), or similar reagents can be
utilized in conjunction with the carbodiimide to minimize internal
rearrangement of the activated isoacylurea derivative and provide
more efficient cross-linking.
[0058] As with carbodiimide treatment, acyl azide crosslinking
agents produce covalent bonds between the carboxylic acid side
chains of aspartic acid and glutamic acids and the .epsilon.-amino
groups of the lysines of collagen [Petit, H., et al., J. Biomed.
Mater. Res., Vol. 24: pp. 179-187 (1990)]. Following esterification
of the carboxyl groups in which a methyl group is added to the
acid, the biomaterial is treated with hydrazine to form the
corresponding hydrazide; sodium nitride is then added to react with
the hydrazide and form the acyl azide. Any number of hydrazines
known in the art can be used in this method, including
maleimidopropionic acid hydrazide (MPH).
[0059] Other chemical cross-linking agents suitable for use in the
present invention to provide cross-linked collagen molecules which
act as soluble coatings on proppant particles include but are not
limited to homobifunctional cross-linkers such as BMME, BSOCOES,
DSP (a thio-cleavable cross-linker), DSS, EGS, water-soluble EGS,
and SATA, as well as heterobifunctional cross-linking agents
including GMB, MBS, PMPI, SMCC, SPDP, and MPH (maleimidopropionic
acid hydrazide), MCH, EMCH (maleimidocaprionic acid hydrazide),
KMUH (N-(k-Maleimidoundecanoic acid)hydrazide), and MPBH
(4-(4-N-MaleimidoPhenyl)butyric acid hydrazide), all available from
Interchim (Cedex, France).
[0060] Other techniques suitable for crosslinking the collagen
fibers for use as soluble proppant coatings include but are not
limited to dehydration, UV irradiation at 254 nm, glucose-mediated
cross-linking (glycation) in conjunction with UV irradiation, and
biological cross-linking. The latter technique includes using
natural products such as genipin and its related iridoid compounds
which are isolated from the fruits of the gardenia plant (Gardenia
jasminoides), which are dialdehydes in aqueous solution and thereby
can react with the .epsilon.-amino groups on lysine side chains of
neighboring collagen molecules to provide a cross-link. Other
biological cross-linking systems suitable for use with the present
invention include catechol-quinone tanning systems, such as
3,4-dihydroxytyramine, and nordihydroguaiaretic acid (NDGA),
isolated from the creosote bush, which acts as a cross-linking
agent via the two catechols on NDGA [Koob, T. J., Comp. Biochem.
Physiol., Part A, Vol. 133: pp. 1171-1192 (2002)].
[0061] The slowly water-soluble coatings on the particulate
substrates, in accordance with the present disclosure, can also be
non-collagenic materials such as synthetic polymers that are slowly
water soluble. Such non-collagenic materials include but are not
limited to: polyethylene oxides, polypropylene oxides,
polycaprolactones; grafts of polyethylene/polypropylene and
polycaprolenes; grafts of polyethylene/polypropylene oxides and
polycaprolactones; water soluble or water reducible acrylics; water
reducible phenoxy resin; latex; polyesters; soluble block
copolymers; grafts of polyvinyl alcohol (PVA) and polyvinyl
acetates; polyactides and derivatives of polylactic acid;
polyglycolic acid (PGA); polyglycoliclactic acid (PGLA). Also
useful for a water soluble coating are periodic chart elements of
group I or II (alkali metal or alkaline earth metal) silicate
polymers, e.g. SOLOSIL.TM. (Foseco International, Ltd., Great
Britain), a sodium silicate polymer.
C. Method of Using
[0062] In embodiments of the disclosed method, single or multiple
intervals of a subterranean formation may be treated or stimulated
in stages by successively introducing diverting agent of the
present invention into the formation followed by introduction of
well treatment fluid into the formation. As used herein, "wellbore"
includes cased and/or open hole sections of a well, it being
understood that a wellbore may be vertical, horizontal, or a
combination thereof. The term "pipe string" refers to any conduit
suitable for placement and transportation of fluids into a wellbore
including, but not limited to, tubing, work string, drill pipe,
coil tubing, etc. Furthermore, it will be understood with benefit
of this disclosure that the disclosed diversion agents and
diversion treatment techniques are suitable for use with any type
of well treatment fluid including, but not limited to, acid
treatments, condensate treatments, hydraulic fracture treatments,
and the like. Furthermore, it will be understood that the benefits
of the disclosed methods and compositions may be realized with well
treatments performed below, at, or above a fracturing pressure of a
formation.
[0063] First: WELLBORE USE: In this aspect of the invention, the
use of fully soluble particles in the wellbore (such as collagen or
other water soluble polymer plastics or mixtures of these) to
divert fluid flow from one zone to another and then dissolve is
disclosed. The use of collagen (in both the uncrosslinked and
crosslinked form) and soluble plastics are useful in diverting the
flow of fluids in the well. These diverting materials should be in
the range of 1 to 100 mesh size, preferably 4 to 50 mesh size and
can be used in combination with other additives or plastic
materials to enhance performance by diverting the flow of fluids
from one zone to another.
[0064] These materials have been used as diverting ball sealers but
recent tests have shown that the material could be used as a
diverting agent to block fluid from flowing into one zone and into
another of either higher pore pressure or lower permeability.
[0065] The present invention provides a method treating a cased
wellbore to divert flow of fluids from one zone to another. The
method involves pumping into a wellbore a diverting fluid that is
made up of an aqueous carrier liquid having dispersed therein a
particulate form of a water soluble polymer and wherein the
particulate polymer has a density greater than or less than the
density of the carrier liquid. As the diverting fluid is pumped
into the wellbore the particulate polymer settles into zones of the
wellbore and thereby diverts flow of a treating fluid from one zone
to another. Generally the treating fluid is diverted or blocked
from flowing into a zone of higher pore pressure or lower
permeability.
[0066] In the methods of this invention relating to wellbore use,
the water-soluble particulate polymer is collagen, poly(alkylene)
oxide, poly(lactic acid), polyvinylacetate, polyvinylalcohol,
polyvinylacetate/polyvinylalcohol, polylactone, polyacrylate,
latex, polyester, periodic chart elements of group I or II (alkali
metal or alkaline-earth metal) silicate polymer or mixtures
thereof. Typically the particulate polymer is present in the
carrier liquid in an amount from about 0.001 pounds per gallon to
about 10 pounds per gallon of the carrier liquid. Advantageously,
the particulate polymer is comprised of varying densities greater
or less than the density of the carrier fluid. Typically, the
carrier liquid is water, brine, aqueous acid solutions, or gelled
acid solutions.
[0067] Second: GENERATED FRACTURE USE: In this aspect of the
invention, the use of coated particles of various propping agents
(coated with either fully soluble or a mix of soluble and insoluble
collagen or polymeric plastic materials) can be pumped into the
fractured formations to prevent fractures from diverting out of the
producing zone. For example, a dense sintered bauxite particle with
a soluble or partially soluble coating would fall to the bottom of
the fracture and divert the fracture from the lower strata or a
water zone. Also, a low-density walnut shell with a soluble or
partially soluble coating would tend to rise inside the fracture to
divert the fracture from upward growth into a gas or water zone.
The coating can be either fully or partially soluble since the
proppant will remain in place in the fracture and provide
conductivity in the fracture after the frac job is completed. Some
of the coating on the proppant should be soluble but a mixture of
both soluble and insoluble plastics or collagen is desirable to
prevent movement of the propping agent in the fracture.
[0068] The use of diverting agents in fractures is that a proppant
or propping agent would be coated with a soluble or partially
soluble coating--using a collagen and/or polymeric plastic coating
material or any mixture of these. The fracture would be diverted by
using these soluble coatings on proppants as the defining
boundaries of the initial fracture. After the fracturing treatment,
the coating would disappear and the previously coated particles
would return to normal propping agents, which have high
permeability. Coatings on various density proppants could cause the
fracture boundaries to be set early in the fracture process since a
low viscosity fluid would allow a high density coated proppant to
settle or fall inside the fracture to make a lower boundary on the
fracture and divert it out from the wellbore to make a longer
fracture and increase the productivity of the well. Likewise, a low
density coated proppant would tend to rise to the top part of the
growing fracture to form a top boundary and divert the growing
fracture away from upper zones that may harm the production of the
well. With the fracture contained at top and bottom the fracture
could grow outward and a longer contained fracture would improve
the well potential productivity.
[0069] FIG. 1 illustrates a well with a vertical cased wellbore
section and a single interval formation that is to be treated in
accordance with one embodiment of the present disclosure. The well
10 of FIG. 1 has a casing 12 extending from the wellhead 11 for at
least a portion of its length and is cemented around the outside
with cement sheath 14 to hold the casing 12 in place and isolate
the penetrated formation or intervals. The cement sheath 14 extends
upward from the bottom of the wellbore in the annulus between the
outside of the casing 12 and the inside wall of the wellbore at
least to a point above the producing strata/hydrocarbon bearing
formation 18. The reasons for the inclusion of this sheath are
many, but essentially the cement sheath 14 helps to ensure the
integrity of the well-bore (i.e., so it does not collapse), or to
isolate specific, different geologic zones (i.e., an oil-bearing
zone from an (undesirable) water-producing zone). The wellbore is
also optionally equipped with a casing or liner shoe 16 so as to
help guide the casing string 12 past ledges or obstacles during its
placement in the wellbore. For the hydrocarbons in the producing
strata 18 to be produced, it is necessary to establish fluid
communication between the producing strata 18 and the interior of
casing 12. This is accomplished by perforations 15 made through
casing 12 and the cement sheath 14 by means known to those of
ordinary skill in the art. Such means include, but are not limited
to, perforation guns, shaped charge devices, and phase charge
devices, such as those described in U.S. Pat. Nos. 6,755,249,
5,095,099, and 5,816,343; Horizontal Oriented Perforating Systems
(HOPS), such as those manufactured by Owen Oil Tubes, Inc. (Ft.
Worth, Tex.); mechanical perforating devices such as laterally
movable punches (U.S. Pat. No. 2,482,913), needle punch
perforators, and toothed wheel perforators such as those described
in U.S. Pat. No. 4,220,201; and shearable plugs such as described
in U.S. Pat. No. 4,498,543. The perforations 15 form a flow path
for fluid from the formation into the casing 12, and
vice-versa.
[0070] The hydrocarbons flowing out of the producing strata 18
through the perforations 15 and into the interior of the casing 12
can be transported to the surface through a production tubing 20. A
production packer, 22, can optionally be installed near the lower
end of the production tubing 20 and above the highest perforation
15 in order to achieve a pressure seal between the production
tubing 20 and the casing 12. Optionally, and equally acceptable in
accordance with the present invention, production tubings 20 need
not be used, in which case the entire volume of casing 12 is used
to conduct the hydrocarbons to the surface of the earth.
[0071] When diversion is needed during a well treatment operation,
heavy weight proppant diverting agents 26a and/or light weight
proppant diverting agents 26b, both of which are substantially
coated with a soluble coating in accordance with the present
invention (i.e., have a collagen-containing coating), are used to
substantially seal the upper and lower sections of the producing
strata 18. This substantial sealing, or border formation, occurs
when the temporary diverting agents 26a and/or 26b are introduced
into the casing 12 at a predetermined time during the treatment.
When the diverting agents 26a and/or 26b are introduced into the
fluid upstream of the perforated parts of the casing 12, they are
carried down the production tubing 20 or casing 12 by the treating
fluid 24 flow. Once the treating fluid 24 arrives at the perforated
interval in the casing, it flows outwardly through the perforations
15 and into the strata 18 being treated. The flow of the treating
fluid 24 through the perforations 15 carries the temporary
diverting agents 26a and/or 26b through the perforations and out
into the strata 18. At this point, the heavy weight proppant
diverting agents 26a, having a density greater than that of the
treating fluid 24, settle to the bottom of the created fracture (as
indicated by the arrows), forming a temporary "lower border"
between the fracture and, for example a sand, shale or clay layer
19 or other area to which it is desirable to seal off from the
producing strata. Similarly, light weight proppant diverting agents
26a, having a density less than that of treating fluid 24, rise to
the top of the created fracture (as indicated by the arrows),
thereby forming another temporary "upper border" between the
fracture and an undesirable layer, such as a shale or clay band of
strata.
[0072] FIG. 2 illustrates the next step of this aspect of the
present invention. Once the temporary diverting agents 26a and 26b
are seated at the top and/or bottom of the created fracture,
respectively, the fluid flow rate and viscosity of the treating
fluid 24, containing regular proppant particles 28, is increased.
In this manner, the fracture can grow outward, away from the
wellbore (in the direction of the arrow) and in doing so increase
the overall length of the fracture, thereby aiding in increasing
the stimulation and/or longevity of the well. At the completion of
the well treatment, the soluble coating on the temporary diverting
agents 26a and 26b will dissolve, allowing the remaining proppant
particles to be removed with the treating fluid 24 through
perforations 15, or to remain and act as additional proppants in
propping open the fractured strata.
[0073] FIG. 3 illustrates a further embodiment of the present
invention. A well 50 having a vertical cased wellbore with a casing
54 extended from the wellhead 52 for at least a portion of the
length of the wellbore, and a cement sheath 56 extending upwards
from the bottom of the wellbore in the annulus between the outside
of the casing 54 and the inside wall of the wellbore, at least to a
point above the existing strata, similar to that shown in FIG. 1.
Exposed within the open hole section of the wellbore is a
subterranean formation having multiple treatment intervals 58, 60
and 62. Although three separated intervals are illustrated in FIG.
3, it will be understood with benefit of this disclosure that
anywhere from two treatment intervals up to any number of treatment
intervals can be treated using the presently disclosed methods and
compositions. Furthermore, it will be understood that such
treatment intervals can be contiguously disposed rather than
separated by relatively impermeable areas such as shale breaks.
Although FIG. 3 illustrates a fully cased wellbore, it will also be
understood that disclosed treatment methods may be utilized with
virtually any type of wellbore completion scenario. For example,
the disclosed methods may advantageously be employed to treat well
configurations including, but not limited to, vertical wellbores,
fully cased wellbores, horizontal wellbores, wellbores having
multiple laterals, and wellbores sharing one or more of these
characteristics.
[0074] In FIG. 3, treatment intervals 58, 60 and 62 represent
identified intervals of a subterranean formation that have been
identified for treatment. In this regard, any number of intervals
or only a portion thereof present in the subterranean formation may
be so identified. Alternatively, such intervals may also represent
perforated intervals in a cased wellbore. As shown in FIG. 3,
perforations 66 extend through casing 54 and cement sheath 56 by
means known to those of skill in the art, and in doing so form a
flow path for fluid from the formation into the casing 54, and
vice-versa.
[0075] The hydrocarbons flowing out of the producing strata in
treatment intervals 58, 60 and 62 through the perforations 66 and
into the interior of the casing can be transported to the surface
through a production tubing, 64. Further, and as illustrated in
FIG. 3, a production packer 68 can be optionally installed
substantially near the lower end of the production tubing 64 and
above the highest perforation 66 in order to achieve a pressure
seal between the production tubing 64 and the casing 54. Production
tubing 64 need not always be used, and in those instances the
entire interior volume of casing 54 is used to conduct the
hydrocarbons to the surface to wellhead 52.
[0076] When diversion is needed during a well treatment, diverting
agents 72 are used to substantially seal some of the perforations
66. Substantial sealing occurs when flow through a perforation 66
is significantly reduced, as often indicated by an increase in
wellbore pressure as a diverting agent 72 blocks off one or more
perforations 66. In accordance with this aspect of the present
invention, diverting agents 72 are preferred to be substantially
spherical in shape, although other geometries can be used. Using
diverting agents 72 of the present invention to plug some of the
perforations 66 is accomplished by introducing the diverting agents
72 into the casing 12 at a pre-determined time during the
treatment. When the diverting agents 72 are introduced into the
fluid upstream of the perforated parts (66) of the casing 12, they
are carried down the production tubing 64 or casing 12 by a flowing
fracturing fluid 70. Once the fracturing fluid 70 arrives at the
perforated interval in the casing, it flows outwardly through
perforations 66 and into the treatment intervals 58, 60, and 62
being treated. The flow of the fracturing fluid 70 through the
perforations 66 carries the diverting agents 72 toward the
perforations 66, causing them to seat on the perforations 66. Once
seated on the perforations 66, diverting agents 72 are held onto
the perforations 66 by the fluid pressure differential which exists
between the inside of the casing 54 and the treatment intervals 58,
60 and 62 on the outside of casing 54. The diverting agents 72 are
preferentially sized to substantially seal the perforations 66 when
seated upon them. The seated diverting agents 72 thereby serve to
effectively close those perforations 66 until such time as the
pressure differential is reversed and the diverting agents
released, or the diverting agents 72 dissolve over a period of time
due to changes in their environment (e.g., the introduction of
water).
[0077] The diverting agents 72 will tend to first seal the
perforations 66 through which the fracturing fluid 70 is flowing
most rapidly. The preferential closing of the high flow rate
perforations 66 tends to equalize treatment of the treatment
intervals 58, 60 and 62 over the entire, perforated interval. For
maximum effectiveness in seating on perforations 66, the diverting
agents 72 should have a density less than the density of the
treating fluid 70 in the wellbore at the temperature and pressure
conditions encountered in the perforated area downhole. Generally,
and in accordance with this aspect of the present invention, the
diverting agent 72 will have at least a substantial outer surface
comprised of collagen or a mixture of collagens. The number of
diverting agents 72 needed during a workover or well treatment
depends upon the objectives and characteristics of the individual
well and the stimulation treatment to be used, and can be
determined by one skilled in the art.
[0078] In the practice of disclosed methods, the diverting agent or
medium suitable for achieving diversion of fluids into the
identified treatment intervals that is employed is the diverting
agent of the present invention comprising a particulate substrate
and a slowly water-soluble collagen outer layer. In one embodiment,
a neutrally buoyant variation of this collagen-containing diverting
system can be employed, so as to reduce the chance of segregation
of the diverting agent and particulate diverting agent carrier
fluid. A "neutrally buoyant" diverting system is a system in which
a particulate diverting agent is suspended in a carrier fluid
having sufficiently close density or specific gravities to result
in a mixture in which solid components of the diverting agent do
not substantially settle or rise in the system under static
conditions. Such segregation can result in, for example,
accumulation of diverting agent at one or more locations in the
wellbore and sticking of the pipe string within wellbore sections.
Furthermore, segregation can result in loss of diversion action due
to movement of the diverting agent away from the intervals to be
treated. Neutrally buoyant diverting systems may be of particular
advantage in highly deviated or horizontal wells, where gravity
segregation of a non-neutrally buoyant diverting system may prevent
efficient blockage or reduction in permeability of the entire
circumference of formation face exposed in the wellbore due, for
example, to migration of diverting agent upwards or downwards in
the highly deviated or horizontal section of the wellbore.
[0079] Diverting agents which may be employed include the diverting
agents of the present invention, having a slowly water-soluble
outer coating, alone or in combination with any diverting agent
(e.g., oil soluble, acid soluble, etc.) suitable for diverting
subsequent treatment fluids into intervals having lower
injectivity. One suitable diverting agent in accordance with the
present invention is a diverting agent that is substantially
collagen. Examples of suitable diverting agents which can be
combined with the diverting agent of the present invention include,
but are not limited to, benzoic acid flakes, wax (such as "Divert
VI" available from BJ Services), cement grade gilsonite or
unitaite, polymers (including, but not limited to, natural polymers
such as guar, or synthetic polymers such as polyacrylate), rock
salt, and the like. Other types of suitable diverting agents that
can be employed include, but are not limited to, acid soluble
diverting agents such as those described in U.S. Pat. No.
3,353,874, and phtalimide particles such as those as described in
U.S. Pat. No. 4,444,264.
[0080] In one embodiment of the present invention, any type of
carrier fluid having a density suitable for forming a neutrally
buoyant diverter system may be employed, including natural or
synthetic brines (such as KCl water, etc.) and carrier fluids
including gelling agents (such as normal or synthetic polymers) or
other weighting materials known in the art. Cement grade gilsonite
(also known as "Uintate") is a natural variety of asphalt that is
crushed and sorted into multiple-size particles. This diverting
agent composition may be blended at the well site with specific
chemically-modified fresh water (water containing for example,
about 0.05% to about 1% of a wetting surfactant) to disperse the
gilsonite and optionally, a weighting agent (including but not
limited to salts such as KCl, NH.sub.4Cl, NaCl, CaCl.sub.2, etc.)
for density adjustment and/or formation-clay control, and a gelling
agent (a polymer such as guar gum, hydroxy propylguar, carboxy
methylhydroxy proprylguar, carboxy methyl hydroxyethyl cellulose,
xanthan gum, carboxy methyl cellulose, etc.) for viscosity
adjustment and/or drag reduction.
[0081] The diverting agent of the present invention is preferably
present in the carrier fluid in concentrations of from about 0.001
pounds per gallon to about 10 pounds per gallon of carrier liquid
but concentrations outside this range can also be used. The most
preferred concentrations of diverting agents are from about 0.01 to
about 6 pounds per gallon of carrier fluid. Diverting agent
concentrations of less than about 0.001 pound per gallon will not
as readily plug formations when used in carrier fluids volumes
which are normally available at an oil well site. A progressively
large volume of carrier fluid would be required to create adequate
formation plugs at concentrations of less than 0.001 pounds per
gallon.
[0082] Concentrations of diverting agent greater than about 10
pounds per gallon would not increase the diverting of the treating
fluid to an appreciable extent and therefore are not particularly
desirable in carrying out the present invention.
[0083] The carrier liquid is typically composed of water, brine,
aqueous acid solutions, or gelled acid solutions. The acid
solutions can be gelled with a celluloses, gums, polysaccharides,
polyacrylamides, alkoxylated fatty amines and mixtures thereof.
[0084] The diverting agent may be added to the carrier fluid as the
treatment is started, continuously as the treating fluid is pumped
into the well bore or may be added in intervals in the carrier
fluid between stages of the treatment. For instance, in acidizing
procedures the diverting agent may be added to the acidizing fluid
continuously. Thus, the diverting agent will progressively plug
portions of the formation being treated, thereby frustrating the
tendency of the acid to flow only into the most permeable portions
of the formation and, instead, creating an evenly acidized
formation. When the treating fluid is pumped in stages, the first
stage is followed by a volume of the diverting material composed of
a carrier fluid, usually gelled or emulsified water or acid,
containing the bridging agent. The diverting agent seals off the
portion of the formation penetrated by the first stage of treating
fluid. The second stage of treating fluid is then pumped into
another portion of the formation. Alternating volumes of treating
fluid and diverting material may be continued to provide a
uniformly acidized formation. Although the same technique of
continuously introducing the diverting agent in the carrier fluid
may be used for fracturing treatments, it is usual for the
diverting agent to be added to the carrier fluid in slugs during
fracturing operations.
[0085] A fracturing liquid is known to preferentially flow into the
portion of the subterranean formation which most readily accepts
the liquid. After this portion of the formation is fractured, the
bridging agent may be added to the fracturing liquid so that it
will plug the already fractured portion of the formation. Because
the fracturing fluid is preferentially flowing into the fracture
zone, it will carry the bridging agent with it. The fractured zone
is thereby plugged and the fracturing fluid is diverted to the most
permeable portion of the formation that is still accepting
fluids.
[0086] This method of fracturing and diverting can, in one aspect
of the present invention, be repeated to obtain multiple
fractures.
[0087] The diverting agent is removed from the formation by means
of sublimation of the diverting agent or by solubilization of the
diverting agent by the produced fluids. Increasing formation
temperatures result in a greater rate of dissolution or sublimation
of the diverting agent. For instance, it has been found that at
about 250.degree. F., approximately 80 percent by weight of the
slightly water-soluble collagen sublimates in 24 hours, while at
300.degree. F., about 95 percent by weight sublimates in 24 hours,
and at a temperature of about 400.degree. F., about 99% of the
slightly water-soluble collagen sublimates/dissolves in about 24
hours. This shows that the rate of sublimation/dissolution of the
diverting agent increases with increasing formation
temperature.
[0088] The following examples are included to demonstrate preferred
embodiments of the invention. It should be appreciated by those of
skill in the art that the techniques disclosed in the examples
which follow represent techniques discovered by the inventors to
function well in the practice of the invention, and thus can be
considered to constitute preferred modes for its practice. However,
those of skill in the art should, in light of the present
disclosure, appreciate that many changes can be made in the
specific embodiments which are disclosed and still obtain a like or
similar result without departing from the scope of the
invention.
Examples
Example 1
Prophetic Example
[0089] The following prophetic example describes a method of how
the soluble coating on the propping agent or agents of the present
invention can be used to divert fracture growth and extend the
fractures into the productive zone of an oil or gas well. The
primary purpose of the soluble coated proppant is to define an
upper and lower boundary in the hydraulically generated vertical
fracture so that the main direction of growth continues to extend
outward in length away from the wellbore. This additional length of
the conductive fracture aids in draining additional areas of the
productive formation, allowing oil, gas, and/or water recovery
production to be improved and greater flow rates to be established
as a result of longer fracture length.
[0090] The following steps can be followed, using the soluble
coated proppant materials of the present invention.
[0091] 1. A fracture injection rate is established with a low
viscosity fracturing fluid.
[0092] 2. A soluble coated proppant, such as walnut hulls coated
with a cross-linked collagen, bauxite coated with cross-linked
collagen, or a combination of both, is added at the blender tub in
order to form a slurry in the fracturing fluid.
[0093] 3. The fracturing fluid containing the soluble coated
proppant is pumped downhole.
[0094] The first part of the slurry enters the initial crack,
taking the most fluid. In doing so, it slowly plugs the borders of
the created fracture due to the use of a soluble diverting agent,
such as collagen, that slowly softens and swells in the fluid.
[0095] 4. Once the flow rate is slowed or substantially reduced in
the first crack, pressure builds up until another flow path, crack,
or zone begins to take the soluble coated proppant-containing
slurry.
[0096] 5. In the instance that both the top and the bottom of the
fracture need to be contained by the soluble coated proppant, two
different proppant densities are preferably used. For example, a
high density bauxite particle is coated with a soluble, collagen
coating that slowly softens and swells as it falls in the fracture
to the bottom of the vertically-created fracture. To slow the
growth upwards in the vertical fracture, a second proppant of low
density, such as a soluble-coated walnut hull, is added to the
injection fluid. As the injection fluid enters the formation, the
low-density, soluble-material coated proppant rises in the vertical
fracture and slows down fluid loss and growth in an upward
direction.
[0097] 6. As the fracture is still being injected with fluid above
the fracture rate and pressure, the fracture continues to grow away
from the wellbore and control of the fracture growth is maintained
by controlling the flow rate of the fracturing fluid. Injection is
continued until the regular proppant fills the fracture, pressure
reaches a pre-set limit, or until the total planned volume is
injected.
[0098] 7. Standard, non-soluble coated proppants, such as Ottawa
Sand (20/40), ceramic, or any number of resin-coated proppants, are
injected into the formation, once the top and bottom growth is
diminished. Pumping is continued until the full amount of
designated proppant (or proppants) are placed in the created
fractures.
[0099] 8. The well is shut in, and the pumping equipment is
removed.
[0100] 9. The well is returned to production, and the soluble
collagen-coating on the walnut hulls or bauxite is removed as the
water in the formation dissolves the soluble coating on the
proppant over time.
Example 2
Procedure for determining the rate and degree of polymer
dissolution
[0101] Sand substrate was coated with various water-soluble
polymers: TABLE-US-00001 Chemical Name Trade Name Supplier
Poly(ethylene) oxide WSR 80 Dow Chemicals Poly(propylene) oxide
WSRN 750 Dow Chemicals Poly(proplylene) oxide UCAR309 Dow Chemicals
Poly(lactic acid) PLA6551-D E&M specialties Poly(lactic acid)
PLA5600 E&M specialties Poly(vinylacetate/alcohol)
PVA/Hydrolene Idroplax Inc. Collagen 1 Glue 512 Milligans and
Higgins Collagen 2 GM Bond Hormel foods
[0102] Thereafter, the following test procedure was used to
determine rate and degree of solubility:
[0103] Determine the total mass of the polymer on the sand by
regular LOI procedure. Add 500 grams of coated sand in 1 liter of
water. Take a 400 mm filter paper and weight it on an analytical
balance up to 4 decimal places. Prepare vacuum filtration apparatus
by using 400 mm filter paper, perforated ceramic funnel, 2 liters
Erlenmeyer flask with side opening connected to the vacuum pump by
a rubber tube. Filter the coated sand and water slurry through 400
mm filter paper after each one-minute interval. Remember to add
coated sand back in the "filtered" water. Remove the filter paper
from the perforated funnel after filtration is complete, and allow
it to dry by keeping it in desiccators. Weigh the filter paper.
This is the combined weight of dissolved polymer and filter paper,
and thus it should be greater than the weight of the filter paper
before it was used in filtration process. Calculate the % of
dissolved polymer by using the following formula:
X=((C-B)/A)).times.100
[0104] Where, [0105] X=the percentage of dissolved polymer [0106]
A=mass (gms) of the polymer on the sand grains [0107] B=mass (gms)
of the filter prior to filtration process
[0108] C=mass (gms) of the filter after filtration process
TABLE-US-00002 Particles that swell Particles that dissolve and
then dissolve without swelling UCAR309 WSR 80 COLLAGEN 1 WSRN750
COLLAGEN 2 PLA 6551-D PLA 5600
[0109] The results of this test procedure were that a polyethylene
oxide(WSR 80 from Dow Chemical) reach full dissolution at
80.degree. F. in about 300 minutes, at 150.degree. F. it required
about 180 minutes, and at 200.degree. F. it required about 90
minutes.
[0110] The same test was run using another polymer. These results
showed that the polypropylene oxide polymer(WSRN 750 from Dow
Chemicals) reached full dissolution at 80.degree. F. in about 390
minutes, at 150.degree. F. it required about 320 minutes, and at
200.degree. F. it required about 245 minutes to fully dissolve.
[0111] Polymers that swell show 100% solubility within 30 minutes,
but microscopic analysis shows retention on the filter paper due to
swelling instead of dissolution. Formation of gelatinous mass and
noticeable increase in the volume of the sand/water slurry indicate
polymer swelling instead of polymer dissolution.
[0112] All of the compositions, methods, and/or processes disclosed
and claimed herein can be made and executed without undue
experimentation in light of the present disclosure. While the
compositions and methods of this invention have been described in
terms of preferred embodiments, it will be apparent to those of
skill in the art that variations may be applied to the
compositions, methods, and/or processes and in the steps or in the
sequence of steps of the methods described herein without departing
from the concept and scope of the invention. More specifically, it
will be apparent that certain agents which are both chemically and
physiologically related may be substituted for the agents described
herein while the same or similar results would be achieved. All
such similar substitutes and modifications apparent to those
skilled in the art are deemed to be within the scope and concept of
the invention.
* * * * *