Language selection

Search

Patent 2491934 Summary

Third-party information liability

Some of the information on this Web page has been provided by external sources. The Government of Canada is not responsible for the accuracy, reliability or currency of the information supplied by external sources. Users wishing to rely upon this information should consult directly with the source of the information. Content provided by external sources is not subject to official languages, privacy and accessibility requirements.

Claims and Abstract availability

Any discrepancies in the text and image of the Claims and Abstract are due to differing posting times. Text of the Claims and Abstract are posted:

  • At the time the application is open to public inspection;
  • At the time of issue of the patent (grant).
(12) Patent: (11) CA 2491934
(54) English Title: SELF-DIVERTING PRE-FLUSH ACID FOR SANDSTONE
(54) French Title: ACIDE DE PRELAVAGE AUTO-DETOURNANT POUR GRES
Status: Deemed expired
Bibliographic Data
(51) International Patent Classification (IPC):
  • E21B 43/27 (2006.01)
  • C09K 8/74 (2006.01)
(72) Inventors :
  • FU, DIANKUI (United States of America)
(73) Owners :
  • SCHLUMBERGER CANADA LIMITED (Canada)
(71) Applicants :
  • SCHLUMBERGER CANADA LIMITED (Canada)
(74) Agent: SMART & BIGGAR
(74) Associate agent:
(45) Issued: 2012-04-24
(86) PCT Filing Date: 2003-07-09
(87) Open to Public Inspection: 2004-01-15
Examination requested: 2008-07-02
Availability of licence: N/A
(25) Language of filing: English

Patent Cooperation Treaty (PCT): Yes
(86) PCT Filing Number: PCT/EP2003/007412
(87) International Publication Number: WO2004/005672
(85) National Entry: 2005-01-05

(30) Application Priority Data:
Application No. Country/Territory Date
10/191,179 United States of America 2002-07-09
10/370,633 United States of America 2003-02-20

Abstracts

English Abstract




Embodiments of the Present Invention relate to a reversibly thickenable non-
polymeric fluid that has low viscosity in strong acid, gels when the acid
concentration is reduced by only a small amount, and is subsequently
decomposed by the acid. In particular it relates to an aqueous mixture of
zwitterionic surfactants, inorganic acids, and organic acids Most particularly
it relates to the use of this fluid as a diverting agent for easily-damaged
sandstones, for example prior to matrix acidizing.


French Abstract

Certains modes de réalisation de cette invention ont trait à un liquide non polymère pouvant épaissir de manière réversible, ayant une faible viscosité dans un acide fort et se gélifiant lorsque la concentration d'acide n'est que peu réduite, puis qui est décomposé par l'acide. Cette invention porte, notamment, sur un mélange aqueux d'agents tensioactifs zwittérioniques, d'acides inorganiques et organiques. Elle concerne, plus précisément, l'usage qui est fait de ce liquide comme agent de dérivation pour grès endommagés, par exemple, avant une acidification de matrice.

Claims

Note: Claims are shown in the official language in which they were submitted.





CLAIMS:

1. A self-diverting pre-flush sandstone acid treatment composition
comprising

water,
an acid-hydrolyzable surfactant capable of forming a viscoelastic gel,
the surfactant having the following amide structure:

Image
wherein R1 is a hydrocarbyl group that is branched or straight chained,
aromatic, aliphatic or olefinic and has from about 14 to about 26 carbon atoms
and
may contain an amine; R2 is hydrogen or an alkyl group having from 1 to about
4
carbon atoms; R3 is a hydrocarbyl group having from 1 to about 10 carbon
atoms; and
Y is an electron withdrawing group rendering the amide group difficult to
hydrolyze;

an inorganic acid in an amount from about 6 to about 20 weight percent,
and

an organic acid in an amount from about 5 to about 20 weight percent,
wherein said self-diverting composition increases in viscosity of at least
about 50 cP at 170 sec-1 upon neutralization of less than about one third of
the total
acid, and hydrolysis of the surfactant in the gel, once formed, at a given
temperature
and pH takes more than at least one hour longer than the acid treatment, as
determined
by reduction of the viscosity of the fluid to less than 50 cP at a shear rate
of 100 sec-1.


2. The composition of claim 1 wherein Y comprises a functional group
selected from the group consisting of a quaternary amine, an amine oxide, a
sulfonate and a carboxylic acid.



32




3. The composition of claim 2 wherein the surfactant is a betaine having
the structure:

Image
wherein R is a hydrocarbyl group that is branched or straight chained,
aromatic, aliphatic or olefinic and has from about 14 to about 26 carbon atoms
and
may contain an amine; n=about 2 to about 10; and p=1 to about 5, and mixtures
of
these compounds.


4. The composition of claim 3 wherein the surfactant is a betaine in which
R is an alkene side chain having from about 17 to about 22 carbon atoms,
n=about 3
to about 5, and p=1 to about 3, and mixtures of these compounds.


5. The composition of claim 4 wherein the surfactant is a betaine having
the structure:

Image
wherein n=3 and p=1.


6. The composition of claim 4 wherein the surfactant is a betaine having
the structure:

Image
wherein n=3 and p=1.



33




7. The composition of claim 1 wherein the inorganic acid is selected from
the group consisting of hydrochloric acid, sulfuric acid, nitric acid, and a
mixture of
any of these acids with boric acid.


8. The composition of claim 7 wherein the inorganic acid is hydrochloric acid.


9. The composition of claim 1 wherein the organic acid is selected from
the group consisting of formic acid, citric acid, acetic acid, lactic acid,
methyl sulfonic
acid and ethyl sulfonic acid.


10. The composition of claim 9 wherein the organic acid is selected from
the group consisting of formic acid, acetic acid and citric acid.


11. The composition of claim 1 further comprising an alcohol selected from
the group consisting of methanol, ethanol, propanol, isopropanol, ethylene
glycol and
propylene glycol.


12. The composition of claim 11 wherein the alcohol concentration is from
about 1 to about 10 weight percent.


13. The composition of claim 12 wherein the alcohol is methanol.


14. The composition of claim 1 wherein the surfactant is present in an
amount between about 1 to about 6 weight percent active ingredient.


15. The composition of claim 1 wherein the inorganic acid is present in an
amount between about 6 to about 15 weight percent.


16. The composition of claim 1 wherein the organic acid is present in an
amount between about 5 to about 15 weight percent.


17. The composition of claim 1 further comprising one or more of a
corrosion inhibitor, an iron control agent, and a chelating agent.



34




18. A self-diverting pre-flush sandstone acid comprising
water,

an acid-hydrolyzable surfactant capable of forming a viscoelastic gel,
the surfactant having the following amide structure:

Image
wherein R1 is a hydrocarbyl group that is branched or straight chained,
aromatic, aliphatic or olefinic and has from about 14 to about 26 carbon atoms
and
may contain an amine; R2 is hydrogen or an alkyl group having from 1 to about
4
carbon atoms; R3 is a hydrocarbyl group having from 1 to about 10 carbon
atoms;
and Y is an electron withdrawing group rendering the amide group difficult to
hydrolyze;

an inorganic acid in an amount from about 6 to about 20 weight percent,
and an organic acid in an amount from 1 to about 20 weight percent; the fluid
capable
of an increase in viscosity of at least about 50 cP at 170 sec-1 upon
neutralization of
less than about one third of the total acid by reaction with carbonate ion,
wherein said
self-diverting composition increases in viscosity of at least about 50 cP at
170 sec-1
upon neutralization of less than about one third of the total acid, and
hydrolysis of the
surfactant in the gel, once formed, at a given temperature and pH takes more
than at
least one hour longer than the acid treatment, as determined by reduction of
the
viscosity of the fluid to less than 50 cP at a shear rate of 100 sec-1.


19. The composition of claim 2 wherein Y comprises an amine oxide.


35

Description

Note: Descriptions are shown in the official language in which they were submitted.



CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
Self-Diverting Pre-Flush Acid for Sandstone

Technical Field of the Invention

[001] This application relates to a reversibly thickenable fluid that has low
viscosity in
strong acid, gels when the acid concentration is reduced by only a small
amount, and is
subsequently decomposed by the acid. More particularly it relates to the use
of this fluid as a
diverting agent specifically for sandstone matrix acidizing.

Background of the Invention

[002] Hydrocarbons are produced from an underground reservoir formation in
which they
are trapped through a wellbore that is drilled into the formation. The term
"oil" is used
generically to include gas and condensate. The reservoir formations are
typically either
sandstones or carbonates. Formations that are considered to be carbonate may
contain some
sandstone and vice versa. Oil will flow through the formation rock if it has
pores of
sufficient size and number to allow a flowpath for the oil to move through the
formation. In
order for oil to be produced, that is, travel from the formation to the
wellbore (and ultimately
to the surface) there must also be a sufficiently unimpeded flowpath from the
formation to
the wellbore.

[003] One of the most common reasons for a decline in oil production is damage
to the
formation, which at least partially plugs the rock pores and therefore impedes
the flow of oil.
Sources of formation damage include: particles that have coated the wellbore
face or invaded
the near-wellbore matrix from the drilling and/or completion fluid; particles
that were part of
the formation that have been mobilized by drilling, completion or production;
and paraffins,
asphaltenes, or minerals that have precipitated due to mixing of incompatible
fluids or to
temperature or pressure changes (precipitated minerals are commonly called
scale). This
damage generally arises from another fluid deliberately injected into the
wellbore, for
CONFIRMATION COPY


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
instance, drilling or completion fluid. The natural effect of all of this
damage is to decrease
permeability to oil moving from the formation in the direction of the
wellbore.

[004] Another reason for lower-than-expected production may be that the.
formation is
naturally "tight" (low permeability); that is, the pores are sufficiently
small that the oil
migrates toward the wellbore only very slowly. The common denominator in both
cases
(damage and naturally tight reservoirs) is low permeability. Techniques
performed by
hydrocarbon producers to increase the net permeability of the reservoir are
referred to as
"stimulation techniques." Essentially, one can perform a stimulation technique
by: (1)
injecting chemicals through the wellbore and into the formation to react with
and dissolve
the wellbore and/or near-wellbore damage (2) injecting chemicals through the
wellbore and
into the formation to react with and dissolve small portions of the formation
to create
alternative flowpaths for the hydrocarbon (thus rather than removing the
damage, redirecting
the migrating oil around the damage); or (3) injecting chemicals through the
wellbore and
into the formation at pressures sufficient to actually fracture the formation,
thereby creating a
large flow channel through which hydrocarbon can more readily move from the
formation
and into the wellbore. Processes (1) and (2) are called "matrix stimulation,"
commonly
"matrix acidizing" since the chemicals are usually acids or acid-based fluids
(although they
may be other formation-dissolving materials such as certain chelating agents
such as
aminopolycarboxylic acids), and process (3) can be either "acid fracturing" or
"hydraulic
fracturing". Process (1) is typically applied in sandstone reservoirs because
sandstones are
usually as difficult or more difficult to dissolve than are the contributors
to the damage.
Process (2) is typically applied in carbonates because carbonates are usually
easier to
dissolve than some or all of the damaging materials. Process (3) is applied to
both
lithologies.

[005] Embodiments of the Present Invention are directed primarily to the first
of these three
processes. At present, matrix acidizing treatments, including the sandstone
matrix acidizing
treatments that are the subject of the remainder of this discussion, are
plagued primarily by
four very serious limitations: (1) inadequate radial penetration; (2)
incomplete axial
distribution; (3) corrosion of the pumping and well bore tubing (which will
not be considered
further here); and (4) damage to the formation caused by the acid itself.
Embodiments of the
Present Invention are directed primarily to the second and fourth problems.

2


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
[006] The first problem, inadequate radial penetration, is caused by the fact
that when the
acid is introduced into the formation it reacts with the damaging material
and/or formation
matrix, with which it first comes into contact. (This is usually at or near
the wellbore, and
we will discuss the problem as though that were the case, although in some
instances -- for
example where there are natural fractures -- the location at which the
majority of first contact
of the treatment fluid with the formation occurs may be distant from the
wellbore.) The
formation near the wellbore that first contacts the acid is adequately
treated, though portions
of the formation more distal to the wellbore (as one moves radially, outward
from the
wellbore) remain untouched by the acid-since all of the acid reacts before it
can get there.
For instance, sandstone formations are often treated with a mixture of
hydrofluoric and
hydrochloric acids at sufficiently low injections rates as to avoid fracturing
the formation.
This acid mixture is often selected because it will dissolve clays (found in
drilling mud) as
well as the primary constituents of naturally occurring sandstones (e.g.,
silica, feldspar, and
calcareous material). In fact, the dissolution may be so effective that the
injected acid is
essentially spent by the time it reaches a few inches beyond the wellbore.
Thus, one can
calculate that over 100 gallons of acid per foot is required to fill a region
five feet from the
wellbore (assuming 20% porosity and 6-inch wellbore diameter). In fact, due to
such limited
penetration, it is believed that sandstone matrix treatments do not provide
significant
stimulation beyond what is achieved through near-wellbore damage removal.. Yet
damage at
any point along the hydrocarbon flowpath can impede flow (hence production).
Therefore,
because of the prodigious fluid volumes required, these treatments are
severely limited by
their cost.

[007] A second major problem that severely limits the effectiveness of matrix
acidizing
technology is incomplete axial distribution. This problem relates to the
proper placement of
the acid-containing fluid-i.e., ensuring that it is delivered to the desired
zone (i.e., the zone
that needs stimulation) rather than another zone. (Hence this problem is not
related per se to
the effectiveness of the acid-containing fluid.) More particularly, when an
oil-containing
formation is injected with acid, the acid begins to dissolve the damage and/or
the matrix.
Depending upon the reactivity of the acid with the matrix and the flow rate of
acid to the
reaction location, as one continues to pump the acid into the formation, a
dominant channel
through the matrix is very often created. As one continues to pump acid into
the formation,
the acid will naturally flow along that newly created channel-i.e., the path
of least
3


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
resistance-and therefore leave the rest of the formation substantially
untreated. In matrix
stimulation, the formation of such channels, commonly called wormholes, is
usually
undesirable. This behavior is exacerbated by intrinsic permeability
heterogeneity (common
in many formations) especially natural fractures in the formation and high
permeability
streaks. Again, these regions of heterogeneity in essence attract large
amounts of the
injected acid, hence keeping the acid from reaching other parts of the
formation along the
wellbore-where it is actually desired most. Thus, in many cases, a substantial
fraction of
the productive, oil-bearing intervals within the zone to be treated are not
contacted by acid
sufficient to penetrate deep enough (laterally in the case of a vertical
wellbore) into the
formation matrix to effectively increase its permeability and therefore its
capacity for
delivering oil to the wellbore. This problem of proper placement is a
particularly vexing one
since the injected fluid will preferentially migrate to higher permeability
zones (the path of
least resistance) rather than to the lower permeability zones-yet it is those
latter zones
which require the acid treatment (i.e., because they are low permeability
zones, the flow of
oil through them is diminished). In response to this problem, numerous,
disparate techniques
have evolved to achieve more controlled placement of the fluid-i.e., to divert
the acid away
from naturally high permeability zones and zones already treated, and towards
the regions of
interest.

[008] The techniques to control acid placement (i.e., to ensure effective zone
coverage) can
be roughly divided into either mechanical or chemical techniques. Mechanical
techniques
include ball sealers (balls dropped into the wellbore and that plug the
perforations in the well
casing, thus sealing the perforation against fluid entry); packers and bridge
plugs,
particularly including straddle packers (mechanical devices that plug a
portion of the
wellbore and thereby inhibit fluid entry into the perforations around that
portion of the
wellbore); coiled tubing (flexible tubing deployed by a mechanized reel,
through which the
acid can be delivered with more precise locations within the wellbore); and
bullheading
(attempting to achieve diversion by pumping the acid at the highest possible
pressure just
below the pressure that would actually fracture the formation). Chemical
techniques can be
further divided into ones that chemically modify the wellbore adjacent to
portions of the
formation for which acid diversion is desired, and ones that modify the acid-
containing fluid
itself. The first type involve materials that form a reduced-permeability cake
on the wellbore
face which upon contact with the acid, will divert it to higher permeability
regions
4


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
particulate material. These are typically either oil-soluble or water-soluble
particulates that
are directed at the high permeability zones to plug them and therefore divert
acid flow to the
low permeability zones. The second type includes foaming agents, emulsifying
agents, and
gelling agents. Mechanical methods and chemical methods that chemically modify
the
wellbore adjacent to portions of the formation for which acid diversion is
desired will not be
considered further here.

[009] Emulsified acid systems and foamed systems are commercially available
responses to
the diversion problem, but they are fraught with operational complexity which
severely
limits their use-e.g., flow rates of two fluids, and bottom hole pressure must
be
meticulously monitored during treatment. That leaves gelling agents-the class
of diverters
to which Embodiments of the Present Invention belong. Though they are
commercially
available, gelling agents are quite often undesirable in matrix acidizing
since the increased
viscosity makes the fluid more difficult to pump (i.e., the same resistance to
flow that
confers the pressure build-up in the formation and results in the desired
diversion, actually
makes these fluids difficult to pump). Some commercially available systems are
polymeric
cross-linked systems-i.e., they are linear polymers when pumped but a chemical
agent
pumped along with the polymer causes the polymers to aggregate or cross-link
once in the
wellbore, which results in gelling. Unfortunately, these systems leave a
residue in the
formation, which can damage the formation, resulting in diminished hydrocarbon
production. Severe well plugging, particularly in low pressure wells, caused
by these
systems has been well documented. In addition, the success of these systems is
naturally
dependent upon a very sensitive chemical reaction-the cross-linking-which Js
very
difficult to optimize so that it is delayed during pumping but maximized once
the chemicals
are in the wellbore. This reaction is easily perturbed by formation chemistry,
contaminants
in the pumping equipment, and so forth. And again, once these systems are in
place, they are
difficult to remove-to do so requires that they be somehow un-cross linked
and/or that the
polymer be destroyed.

[0010] Viscoelastic surfactant-based gelling systems can avoid these problems.
One
viscoelastic surfactant-based gelling system is disclosed in U. S. Patent Nos.
5,979,557 and
6,435,277, which have a common assignee as the present application. This
system differs
from Embodiments of the Present Invention in that it is not a self-diverting
system-i.e., the
treatment is performed in two steps: (1) injecting the diverter, followed by
(2) injecting the


CA 02491934 2010-11-08
51650-4

acid.. The treatments based on the fluids of Embodiments of the Present
Invention are based
on a single step-hence it is chemically very different because the diverter is
contained
within the acid-containing fluid.

[0011) Another viscoelastic surfactant-based gelling system is disclosed in U.
S. Patent No.
6,399,546, and U. S_ Patent No. 7,119, 050, which also have a common
assignee as the present application. This system, which we will call "VDA"
here (for
"viscoelastic diverting acid") was developed for carbonate matrix acidizing
and may contain
one of certain zwitterionic surfactants,- such as those based on betaines
(which are described
in U. S. Patent No. 6,258,859, and which we will call BET surfactants), an
acid that . is
hydrochloric, hydrofluoric, a mixture of hydrochloric and hydrofluoric, acetic
or formic acid,
and (for some BET surfactants) a required co-surfactant or (for other BET
surfactants)
optional methanol, ethanol or isopropanol. The acid is not a mixture of
inorganic and
organic- acids. The initially injected fluid has a nearly water-like.
viscosity,. but. after a
considerable portion of the acid "spends," or has been -consumed, (which is
possible because
it is being injected into a carbonate formation that will react with a large
amount of acid) the
viscosity increases substantially. Thus, when first injected, VDA's.enter.the
most permeable
zone(s); but when they gel they block that zone or zones and divert
subsequently injected
fluid into previously less-permeable zones. The success of such systems
depends upon the.
ability of the formation to react with a large amount, of acid. Consequently,
they are most - -
useful with carbonates that have a large capacity to react with acid

[0012) SPE paper 80274, "Application of Novel Diversion Acidizing Techniques
To
Improve Gas Production in Heterogeneous Formation," describes a "diversion
acid" that is a
strong gel when injected. There is no indication of the chemistry; a,breaker
is required.

[0013] A need exists for a diversion system that will be effective in
sandstones-i.e., a fluid that
is not damaged by shear, has a low. viscosity during pumping, that gels
quickly once it contacts
sandstone, that forms a gel of sufficient strength to allow diversion to
occur; and that is
immediately and nearly completely "broken". or returned to the un-gelled
state, without theneed - .:
for a breaker, after the treatment has ceased so the well can be put back on
production.
Furthermore, this fluid must not only be self-diverting, but it 'must also
divert subsequently-
injected fluids until a treatment is completed.

6


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
Summary of Embodiments of the Invention

[0014] One embodiment of the invention is a self-diverting pre-flush sandstone
acid made by
combining water, an acid-hydrolyzable surfactant capable of forming a
viscoelastic gel, an
inorganic acid, and an organic acid. The surfactant may have the following
amide structure:

li 12
R1 C-N-R3-Y

in which R1 is a hydrocarbyl group that may be branched or straight chained,
aromatic,
aliphatic or olefinic and has from about 14 to about 26 carbon atoms and may
contain an
amine; R2 is hydrogen or an alkyl group having from 1 to about 4 carbon atoms;
R3 is a
hydrocarbyl group having from I to about 10 carbon atoms; and Y is an electron
withdrawing group, especially a quaternary amine, an amine oxide, a sulfonate
or a
carboxylic acid, that renders the amide group difficult to hydrolyze.
Preferably, the
surfactant is a betaine having the structure:

H3 CH3 O

O"
Y (CH2) NN-11 NN""(CH2)p rl-
R

O
in which R is a hydrocarbyl group that may be branched or straight chained,
aromatic,
aliphatic or olefinic and has from about 14 to about 26 carbon atoms and may
contain an
amine; n = about 2 to about 10; and p = 1 to about 5, or mixtures of these
compounds. A
preferred surfactant is a betaine in which R is an alkene side chain having
from about 17 to
about 22 carbon atoms, n = about 3 to about 5, and p = 1 to about 3, and
mixtures of these
compounds. Most preferred surfactants are those in which the surfactant is a
betaine having
the structure:

H H3 \ CH3 O
C17H33
Y N'*,N(CH2)n N\(CH2)p O"
O

7


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
in which n = 3 and p = 1, or a betaine having the structure:

H H3C CH3 0
C21 H41 N \N+ _
~(CH2)n \(CH2)p O
O

in which n=3andp=1.

[0015]. In preferred embodiments, the inorganic acid is hydrochloric acid,
sulfuric acid, or
nitric acid (especially hydrochloric acid); the organic acid is formic acid,
citric acid, acetic acid,
boric acid, lactic acid, methyl sulfonic acid or ethyl sulfonic acid
(especially formic acid, acetic
acid and citric acid).

[0016] In another preferred embodiment, the self-diverting pre-flush sandstone
acid -also
contains an alcohol selected from the group consisting of methanol, ethanol,
propanol,
isopropanol, ethylene glycol and propylene glycol (especially methanol).

[0017] In particularly preferred embodiments, the surfactant is present in an
amount between
about 1 to about 6 weight percent active ingredient, preferably from about 2
to about 4%, most
preferably about 3%; the inorganic acid is present in an amount between about
6 to about 20
weight percent, preferably from about 6 to about 15%, most preferably about
12%; and the
organic acid is present in an amount between about 1 to about 20 weight
percent, preferably from
about 5 to about 10%, most preferably about 6%. The self-diverting pre-flush
sandstone acid
may also contain one or more of a corrosion inhibitor, an iron control agent,
and a chelating
agent.

[0018] In another embodiment, the self-diverting pre-flush sandstone acid is
made by combining
water, an acid-hydrolyzable surfactant (as above) capable of forming a
viscoelastic gel, an
organic acid (as above), and an inorganic acid (as above) and the fluid is
capable of an increase
in viscosity of at least about 50 cP at 170 sec-1 upon neutralization of less
than about one third of
the total acid by reaction with carbonate ion. In yet another embodiment, the
self-diverting pre-
flush sandstone acid is made by combining water, an acid-hydrolyzable
surfactant (as above)
capable of forming a viscoelastic gel, and an organic acid (as above), and the
fluid is capable of
8


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
an increase in viscosity of at least about 50 cP at 170 sec-1 upon
neutralization of less than about
one third of the total acid by reaction with carbonate ion.

[0019] Yet another embodiment is a method of treating a sandstone formation
having a non-
target zone or zones and a target zone or zones penetrated by a wellbore
involving injecting a
self-diverting pre-flush sandstone acid comprising water, an acid-hydrolyzable
surfactant capable
of forming a viscoelastic gel, an inorganic acid, and an organic acid into the
wellbore to
selectively block the pore structure in the non-target zone or zones. Yet
another embodiment is a
method of treating a sandstone formation having a non-target zone or zones and
a target zone or
zones penetrated by a wellbore involving injecting a self-diverting pre-flush
sandstone acid
comprising water, an acid-hydrolyzable surfactant capable of forming a
viscoelastic gel, an
inorganic acid, and an organic acid into the wellbore to selectively block the
pore structure in the
non-target zone or zones in order to selectively retard entry of fluid into
the non-target zone or
zones and thus to allow entry of fluid into the target zone or zones; and then
injecting a matrix
stimulation fluid into the formation, so that the matrix stimulation fluid is
diverted from the non-
target zone or zones into the target zone or zones. Other embodiments include
the above
methods in which the self-diverting pre-flush sandstone acid does not contain
an inorganic acid.
Yet other embodiments include the above methods in which the self-diverting
pre-flush
sandstone acid contains an alcohol as described above. Yet other embodiments
include the
above methods in which the surfactant, organic acid, and inorganic acid are of
the types and in
the concentrations as described above.

[0020] Other embodiments include any of the above methods in which a mutual
solvent,
selected from low molecular weight esters, ethers and alcohols (especially
ethylene glycol
monobutyl ether) is injected prior to injecting the self-diverting pre-flush
sandstone acid. Other
embodiments include any of the above methods in which the step of injecting a
self-diverting
pre-flush sandstone acid forms a plug of a viscous fluid in the pore structure
of the non-target
zone or zones; any of the above methods in which an organic acid pre-flush
fluid or an inorganic
acid pre-flush fluid (optionally containing an organic acid) is injected after
the step of injecting
the self-diverting pre-flush sandstone acid and before the step of injecting
the matrix stimulation
fluid into the formation; any of the above methods in which an acidic pre-
flush fluid is used and
the pre-flush fluid and the self-diverting pre-flush sandstone acid include
the same organic acid
and the same inorganic acid, each at about the same concentration; and any of
the above methods
in which the surfactant hydrolyzes after the injection of the matrix
stimulation fluid.

9


CA 02491934 2011-09-27
51650-4

In another embodiment, there is provided a self-diverting pre-flush
sandstone acid treatment composition comprising

water,
an acid-hydrolyzable surfactant capable of forming a viscoelastic gel,
the surfactant having the following amide structure:

O R2
11 RI-C-N-R3-Y

wherein R1 is a hydrocarbyl group that is branched or straight chained,
aromatic, aliphatic or olefinic and has from about 14 to about 26 carbon atoms
and
may contain an amine; R2 is hydrogen or an alkyl group having from 1 to about
4
carbon atoms; R3 is a hydrocarbyl group having from 1 to about 10 carbon
atoms; and
Y is an electron withdrawing group rendering the amide group difficult to
hydrolyze;

an inorganic acid in an amount from about 6 to about 20 weight percent,
and

an organic acid in an amount from about 5 to about 20 weight percent,
wherein said self-diverting composition increases in viscosity of at least
about 50 cP at 170 sec' upon neutralization of less than about one third of
the total
acid, and hydrolysis of the surfactant in the gel, once formed, at a given
temperature
and pH takes more than at least one hour longer than the acid treatment, as
determined
by reduction of the viscosity of the fluid to less than 50 cP at a shear rate
of 100 sec'.

In another embodiment, there is provided a self-diverting pre-flush
sandstone acid comprising

water,
an acid-hydrolyzable surfactant capable of forming a viscoelastic gel,
9a


CA 02491934 2011-09-27
51650-4

the surfactant having the following amide structure:
O R2
11 R1-C-N-R3-Y

wherein R1 is a hydrocarbyl group that is branched or straight chained,
aromatic, aliphatic or olefinic and has from about 14 to about 26 carbon atoms
and
may contain an amine; R2 is hydrogen or an alkyl group having from 1 to about
4
carbon atoms; R3 is a hydrocarbyl group having from 1 to about 10 carbon
atoms;
and Y is an electron withdrawing group rendering the amide group difficult to
hydrolyze;

an inorganic acid in an amount from about 6 to about 20 weight percent,
and an organic acid in an amount from 1 to about 20 weight percent; the fluid
capable
of an increase in viscosity of at least about 50 cP at 170 sec -1 upon
neutralization of
less than about one third of the total acid by reaction with carbonate ion,
wherein said
self-diverting composition increases in viscosity of at least about 50 cP at
170 sec -1
upon neutralization of less than about one third of the total acid, and
hydrolysis of the
surfactant in the gel, once formed, at a given temperature and pH takes more
than at
least one hour longer than the acid treatment, as determined by reduction of
the
viscosity of the fluid to less than 50 cP at a shear rate of 100 sect.

9b


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
Brief Description of the Drawings

(0021] Figure 1 shows the initial viscosity of aqueous fluids made with 7.5
weight % as-
received BET-E-40 vs. weight % HC1 concentration at about 23 T.

[0022] Figure 2 shows the viscosity of fluids of Embodiments of the Present
Invention as the
acid concentration is decreased by reaction with carbonate.

[0023] Figure 3 shows the pressure drops across a core during injection of an
aqueous self-
diverting pre-flush sandstone acid and then a matrix stimulation fluid.

[0024] Figure 4 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which one core is saturated with oil.

[0025] Figure 5 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which one core is saturated with oil.

[0026] Figure 6 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which the cores have different perm abilities.

[0027] Figure 7 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which the cores have different permeabilities.

[0028] Figure 8 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which the cores have different permeabilities.

[0029] Figure 9 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which the cores have different permeabilities.



CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
[0030] Figure 10 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which the cores have different permeabilities.

[0031] Figure 11 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which the cores have different permeabilities.

[0032] Figure 12 shows the weight percent of an aqueous self-diverting pre-
flush sandstone
acid, and then of a matrix stimulation fluid, entering each core in a dual-
core experiment in
which the cores have different permeabilities.

Detailed Description of Preferred Embodiments

[0033] We have identified a fluid that is self-diverting and non-damaging when
it is injected
into sandstones. On reaction with the small amount of acid-soluble material
found in
sandstones, it forms a gel that is viscous enough and stable enough to divert
mud-acid (or
any other matrix stimulation fluid) and that then decomposes after the mud-
acid treatment.
By this (stable enough to divert mud-acid and then decomposing after the mud-
acid
treatment) we mean that the hydrolysis of the surfactant in the gel, once
formed, at a given
temperature and pH takes more than at least one hour longer than the mud acid
treatment, as
determined by reduction of the viscosity of the fluid to less than 50 cP at a
shear rate of 100
sec". This material is used as a pre-flush before a mud acid treatment, and is
called here a
"self-diverting pre-flush sandstone acid". Since it has a low viscosity as
formulated and
pumped, it preferentially enters the high-permeability zone or zones in the
formation; these
are generally the undamaged and high water-cut zones from which the operator
wishes to
exclude a main matrix stimulation fluid. Not only is it self-diverting, but it
diverts
subsequently-injected fluids such as an HCl pre-flush, the main mud-acid (or
other matrix
stimulation fluid) and any post-flushes. By diversion of a fluid we mean that
more of the
fluid enters the low permeability zone(s) than would be expected from a simple
calculation
based on the relative permeabilities of the different strata to the treatment
fluid. Ideally,
subsequently injected fluid is diverted from high permeability zones to low
permeability
zones; from undamaged zones or zones with little damage to highly damaged
zones or zones
having more damage; and from zones containing all or primarily water to zones
containing
all or primarily hydrocarbons. Preferably, the self-diverting pre-flush
sandstone acid should
11


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
be stable under downhole conditions for at least about 2 hours but should
decompose within
about 1 to 3 hours after shut-in at the completion of the job. The fluid
contains water, a
selected surfactant (such as BET-E-40 betaine), an inorganic acid, and a
selected organic
acid. It preferably contains a corrosion inhibitor, and optionally contains an
alcohol such as
methanol. Most importantly, it is strongly acidic, gels when only a small
amount of the acid
has been spent, is safe for use in easily-damaged sandstone formations, and
cleans up
readily.

[0034] It was known that sandstones typically may contain only small amounts
of material
that would react with acid, that is, would have the capability of reducing the
acidity of an
injected material by only a small amount. It was also known that the viscosity
of certain
viscoelastic surfactant gel-precursor fluid mixtures containing high amounts
of inorganic
acids would increase dramatically if substantial amounts of that acid were
removed (for
example by consumption in a reaction). It was also known that certain gelled
surfactants
could be decomposed for clean-up if the acidity was high enough. It has now
been found
that certain viscoelastic surfactant gel-precursor fluid mixtures containing
intermediate
amounts of inorganic acids increase dramatically in viscosity when the
inorganic acid
concentration is reduced by only a small amount. Consequently, if the proper
amounts of the
proper organic acids are incorporated in the mixture, the amount of inorganic
acid can be
kept low enough to be in the range where a small change will cause gellation
while the total
acidity of the mixture can be kept high enough to cause adequately rapid
subsequent gel
decomposition.

[0035] It has been found that certain organic acids will keep the viscosity of
these
surfactant/inorganic acid/organic acid fluids low at inorganic acid
concentrations at which
the viscosity would otherwise be high. For example, Figure 1 shows
schematically the
viscosity of viscoelastic fluids made with 7.5 weight percent as-received BET-
E-40 and
varying amounts of concentrated HCI. It can be seen that the viscosity is
extremely low at
HCl concentrations above about 20%; the viscosity then begins to increase
gradually as the
HCl concentration is reduced down to about 12%; the viscosity then rises more
rapidly until
the HCl concentration is reduced to about 10%; and the viscosity then rises
rapidly and
remains high at lower HCl concentrations. The exact shape of this curve would
vary
somewhat depending upon such factors as the choice of surfactant, and the
presence and
concentration of additives such as corrosion inhibitors. Figure 2 shows the
affect of the
12


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
addition of 6 weight percent of either formic acid or citric acid to a fluid
containing 7.5
weight percent as-received BET-E-40, 12 weight percent HCI, and no added salt.
This figure
shows experimental data on the viscosity of each of these two fluids as the
HCl
concentration is reduced by adding the appropriate amount of calcium carbonate
to react
with and consume some of the HCI. It can be seen that when these fluids
contact even a
small amount of carbonate, the viscosity immediately begins to rise. Again,
the exact shape
would be influenced by many factors, but for each fluid of Embodiments of the
Present
Invention there would be a point at which the reduction of the acid
concentration would
result in a dramatic increase in the viscosity. Other experiments have shown
that these
effects are governed substantially by the total acid concentration, and are
not temperature-
sensitive.

[0036] Many surfactants are known to form viscoelastic gels in aqueous
solutions. Some
require added salts and/or co-surfactants and/or alcohols for the gels to be
sufficiently
viscous and/or stable to be useful under oilfield treatment conditions. Such
gels and their
uses are described, for instance in U. S. Patents 6,306,800; 6,035,936;
5,979,557 and others.
Most viscoelastic gel systems are broken by disruption of the micelle
structure; this occurs
when the system is diluted, by water or especially by hydrocarbons. If the
conditions of use
are such that this does not occur, breakers for the surfactant molecule
itself, such as
oxidizers, are sometimes added. Such surfactants are well known. However, not
all can be
used in Embodiments of the Present Invention, because the surfactants and
micelles of
Embodiments of the Present Invention must be stable for a sufficient period of
time in strong
inorganic acid and then must be broken by that acid.

[0037] The surfactants useful in Embodiments of the Present Invention have
cleavable
chemical linkages, preferably but not limited to amide linkages, that are
stabilized by nearby'
chemical functional groups. In particular, these surfactants have cationic or
electron-
withdrawing groups within about 3 atoms of the amide nitrogen. The first step
in acid
hydrolysis of amides is protonation of the amide functionality. The nearby
electron-
withdrawing group inhibits this protonation and greatly slows the acid
hydrolysis, whereas
other surfactants that do not have this aspect to their structure are either
too stable or too
unstable in strong acids to be useful. Thus the surfactants useful in
Embodiments of the
Present Invention can be cleaved, but not too easily. The choice of surfactant
structure and
13


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
of the nature and concentration of other components of the fluid can be
adjusted so that the
rate of surfactant cleavage under the conditions of use is, suitable.

[0038] Certain zwitterionic surfactants have been found to be particularly
useful in forming
the aqueous self-diverting pre-flush sandstone acid. Preferred surfactants
have the following
amide structure:

II 12

R1 C--N-R3 Y

in which R1 is a hydrocarbyl group that may be branched or straight chained,
aromatic,
aliphatic or olefinic and has from about 14 to about 26 carbon atoms and may
contain an
amine; R2 is hydrogen or an alkyl group having from 1 to about 4 carbon atoms;
R3 is a
hydrocarbyl group having from 1 to about 5 carbon atoms; and Y is an electron
withdrawing
group. Preferably the electronic withdrawing group is a quaternary amine, a
sulfonate, a
carboxylic acid or an amine oxide.

[0039] Two particularly preferred examples are betaines called, respectively,
BET-O and
BET-E. One is designated BET-O-30 because as obtained from the supplier
(Rhodia, Inc.
Cranbury, New Jersey, U. S. A.) it is called Mirataine BET-O-30 because it
contains an oleyl
.acid amide group (including a C17H33 tail group) and contains about 30%
active surfactant;
the remainder is substantially water, a small amount of sodium chloride, and
isopropanol.
An analogous material, BET-E-40, is also available from Rhodia and contains a
erucic acid
amide group (including a C21H41 tail group) and is 40% active ingredient, with
the remainder
again substantially water, a small amount of sodium chloride, and isopropanol.
A generic
betaine surfactant is shown below. These surfactants will be referred to as
BET-O and BET-
E (and generically as "BET surfactants"); in the examples, BET-O-30 and BET-E-
40 were
always used. The surfactants are supplied in this form, with an alcohol and a
glycol, to aid in
solubilizing the surfactant in water at these high concentrations, and to
maintain it as a
homogeneous fluid at low temperatures. However, the surfactants could be
obtained and
used in other forms. In field use, after dilution, the amounts of the other
components of the
as-received materials are not important. BET surfactants, and others, are
described in U. S.
Patent No. 6,258,859. The generic structure is

14


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412

H3 \ ~CH3 0

-
N~(CH2)n N\(CH2)p 0
R Y
O
in which R is a hydrocarbyl group that may be branched or straight chained,
aromatic,
aliphatic or olefinic and has from about 14 to about 26 carbon atoms and may
contain an
amine; n = about 2 to about 4; and p = 1 to about 5, and mixtures of these
compounds. Most
preferably the. surfactant is the betaine in which R is the straight-chained
olefinic group
C17H33 (BET-O-30) or the straight-chained olefinic group C21H41 (BET-E-40),
and n = 3 and
p=1.

[0040] These betaine surfactants can form aqueous viscous high-temperature
acid-
degradable gels in any electrolyte concentration; they will form gels with no
added salt or
even in heavy brines. The fluids can generally be prepared, for example, with
municipal
water, lake or creek water, or seawater. Co-surfactants may be useful in
extending the brine
tolerance, and to increase the gel strength and to reduce the shear
sensitivity of the fluid,
especially for BET-O. An example of such a co-surfactant is sodium
dodecylbenzene
sulfonate (SDBS). For a given surfactant and conditions (especially the
temperature and the
time for which a suitable viscosity is required) the salinity and the -
presence and nature of
co-surfactants can be adjusted to ensure that the gel will have the desired
stability.

[0041] The inorganic acid can be any inorganic or inorganic acid except for
hydrofluoric
acid (which could cause the precipitation of undesirable solid fluorides).
Thus the acid is, by
non-limiting example, hydrochloric, sulfuric, or nitric acid. The rheology is
affected
primarily by the acid strength, not by the type of anion.

[0042] The organic acid is preferably formic acid, acetic acid, or citric
acid. Other acids
such as acetic acid, boric acid, lactic acid, methyl sulfonic acid and ethyl
sulfonic acid may
be used, although the gels formed using formic acid, acetic acid or citric
acid are more
stable. In sandstone matrix stimulation treatments, the choice of the acid
used as a pre-flush
to a main treatment depends on the absolute and relative silt and clay
contents of the


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
formation, its permeability, and the presence of HCl-sensitive minerals such
as chlorite,
glauconite and zeolites. These pre-flush acids commonly contain HCI and an
organic acid.
The organic acid replaces some of the HCI, because high HCl concentrations may
damage
formations by mobilizing fines and/or disaggregating sands. For operational
simplicity, it is
advantageous, although not required, to use the same organic acid/inorganic
acid choice and
combination in the self-diverting pre-flush sandstone acid as in the HCI pre-
flush (that will
actually follow the self-diverting pre-flush sandstone acid).

[0043] The alcohol is preferably methanol. Ethanol, propanol, isopropanol,
ethylene glycol
and propylene glycol may be used for low temperature applications. The purpose
of the
alcohol is to prevent the formation of sludge when the temperature is low and
one of the
decomposition products is a high-melting fatty acid such as a C22 fatty acid
that could be a
solid. The amount of alcohol needed depends upon the temperature and the
chemical
structure of the hydrophobic tail of. any fatty acids formed. For example,
above about 93 C,
typically only about 1% methanol is required to prevent sludge formation fore
BET-E.

[0044] The surfactant concentration in the aqueous self-diverting pre-flush
sandstone acid is
typically from about 1 to about 6 weight percent (active ingredient);
preferred is from about
2 to about 4%; most preferred is about 3%. The amount of surfactant is chosen
so that the
fluid builds sufficient viscosity to act effectively as a diverter, but
degradation of the
surfactant will reduce that viscosity after the desired time. The inorganic
acid concentration,
for example HCI, is from about 6 to about 20 weight percent, preferably from
about 6 to
about 15%; most preferably about 12%. The organic acid concentration, for
example formic
acid, is from about 0 to about 20 weight percent, preferably from about 5 to
about 10%; most
preferably about 6%. The alcohol concentration, for example methanol, is from
about 0 to
about 10 weight percent, preferably from about 1 to about 6%; most preferably
about 6%.
The alcohol concentration is chosen to prevent sludge formation.

[0045] For sandstone formation stimulation, the preferred fluid is a
hydrochloric/hydrofluoric acid ("mud acid") mixture, in which case the
treatment is
commonly called "matrix acidizing". The major drawbacks of mud acids are that
they react
too quickly and hence penetrate (as unspent acid) into the formation poorly
and that they are
highly corrosive to wellbore tubular components. Organic acids are a partial
response to the
limitations of inorganic acids. The principal benefit of the organic acids are
lower
16


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
corrosivity and lower reaction rate (which allows greater radial penetration
of unspent acid).
The organic acids used in conventional treatments are formic acid and acetic
acid. Both of
these acids when used alone have numerous shortcomings. First, they are far
more
expensive than inorganic acids. Second, while they have a lower reaction rate,
they also
have a much lower reactivity-in fact, they do not react to exhaustion of the
starting
materials, but rather remain in equilibrium with the formation rock. Hence one
mole of HCl
yields one mole of available acid (i.e., H+), but one mole of acetic acid
yields substantially
less than one mole of available acid.

[0046] By "matrix acidizing" is meant the treatment of a reservoir formation
with a
stimulation fluid containing a reactive acid. In sandstone formations the acid
reacts with
soluble substances that were either present in the original formation matrix
(especially
materials cementing the sand grains together or loose between the sand grains,
although
some sand can also be dissolved) or were introduced (invaded the matrix) from
the fluids
used during drilling or completion. This cleans out or enlarges the pore
spaces. The matrix
acidizing treatment improves the formation permeability to enable enhanced
production of
reservoir fluids.. Matrix acidizing operations are ideally performed at a high
flow rate, but at
treatment pressures below the fracture pressure of the formation. This enables
the acid to
penetrate the formation and extend the depth of treatment while avoiding
damage to the
reservoir formation.

[0047] By "sandstone" we mean a clastic sedimentary rock whose grains are
predominantly
sand-sized. The term is commonly used to imply consolidated sand or a rock
made of
predominantly quartz sand, although sandstones often contain feldspar, rock
fragments, mica
and numerous additional mineral grains, held together with silica or another
type of cement.
Sandstone formations usually contain small amounts of carbonates, commonly
about 1 to 2%
as a cement between sand grains. By "carbonate" we mean a material whose chief
mineral
constituents (typically 95% or more) are calcite (limestone) and aragonite
(both CaCO3) and
dolomite [CaMg(C03)2], a mineral that can replace calcite during the process
of
dolomitization. HCl essentially reacts only with carbonates; HF also reacts
with silicates and
silica.

[0048] It is recommended that the diversion be carried out so that the aqueous
self-diverting
pre-flush sandstone acid of Embodiments of the Present Invention penetrates to
a radial
17


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
distance of at least 10% of the depth of invasion of the mud acid treatment in
order to obtain
satisfactory diversion. However, deeper invasion is to be avoided so that the
efficiency of
the use of the aqueous self-diverting pre-flush sandstone acid is maximized
and damage to
the formation is minimized. In a properly designed treatment, after the
aqueous self-
diverting pre-flush sandstone acid injection, there will be a long plug of
aqueous self-
diverting pre-flush sandstone acid gel in the high permeability (and/or
undamaged, and/or
water-containing) zone(s) (that we will define as the "non-target" zone or
zones for a matrix
stimulation fluid) and a short aqueous self-diverting pre-flush sandstone acid
gel plug in the
low permeability (and/or damaged and/or oil-containing) zone(s) (that we will
define as the
"target" zone or zones for the matrix stimulation fluid). Note that by "plug"
we do not mean
that the formation becomes impermeable; rather we mean that the plug is a
region of reduced
permeability due to the presence of a viscous gel. The aqueous self-diverting
pre-flush
sandstone acid is designed not to decompose until after the injection of the
matrix
stimulation fluid (so that it can block entry of the matrix stimulation fluid
into the non-target
zone), so the low-viscosity matrix stimulation fluid must finger through the
short plug of
high-viscosity aqueous self-diverting pre-flush sandstone acid in order to
treat the target
zone. Thus, for success, there must be the right amount of aqueous self-
diverting pre-flush
sandstone acid injected and the right viscosity contrast between the aqueous
self-diverting
pre-flush sandstone acid and the matrix stimulation fluid.

[0049] Because sandstones inevitably contain at least small amounts of
carbonates that
contain calcium, when sandstone matrix stimulation treatments involve HF in
order to
dissolve silica, then some way must be devised to prevent the interaction of
Ca' .and F, or
else CaF2 will precipitate. This inevitably means injecting a sequence of
different fluids.
[00501 The preferred sequence of injection of fluids in sandstone acidizing is
an optional
mutual solvent pre-flush, then an optional brine spacer, then the aqueous self-
diverting pre-
flush sandstone acid, then an optional HCl pre-flush (which will go into the
zone to be
stimulated), then an HCI/HF main acid fluid (mud acid) which will go into the
zone to be
stimulated, then a post flush. Any sandstone-dissolving acid may be used, that
is mud acids
having various concentrations and ratios of HCl and HF, acids in which HF is
generated
from a precursor rather than added directly, and acids containing chelating
agents for
aluminum such as polycarboxylic acids and aminopolycarboxylic acids. The
mutual solvent
pre-flush (such as about 10% ethylene glycol monobutyl ether in water) is used
in oil wells

18


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
to remove oil from the rock to be contacted with the aqueous self-diverting
pre-flush
sandstone acid; this is done to prevent contact of the surfactant with the
oil, because the oil
would act as a micelle breaker. If a mutual solvent is used, it is followed by
a brine spacer
(such as about 3 to about 5% ammonium chloride) to displace the mutual solvent
from the
rock to be contacted with the aqueous self-diverting pre-flush sandstone acid,
because the
mutual solvent would also act as a micelle breaker. It is common that the HCl
or HCl/HF
also includes an organic acid such as acetic acid or formic acid. Mutual
solvent, such as
10% ethylene glycol monobutyl ether in water, is used as the post flush to
strip any oil
wetting surfactant from the surface and leave it water wet. In prior art
conventional
sandstone acidizing, the HCl pre-flush is commonly a 5 to 15% HCI solution
containing a
corrosion inhibitor. It displaces Na+ and K+ and dissolves calcite (calcium
carbonate). This
prevents subsequent precipitation of sodium or potassium fluosilicates or
calcium fluoride
when HF is introduced, and saves more-expensive HF. The aqueous self-diverting
pre-flush
sandstone acid of Embodiments of the Present Invention replaces some or all of
the
conventional HCl pre-flush. Usually, a conventional HC1 pre-flush will still
be used after the
aqueous self-diverting pre-flush sandstone acid, because it is necessary to
pre-flush the zone
that will be stimulated. The post flush (for oil wells a hydrocarbon like
diesel, or 15% HCI;
for gas wells, acid or a gas like nitrogen or natural gas) also isolates the
reacted HF from
brine that may be used to flush the tubing, as well as restores a water-wet
condition to the
formation and to any precipitates that did form. If the post flush is a gas,
any clean-up
additives are put in the last HCl/HF stage. The sequence of stages may be
repeated, for
example sequentially treating sections of a formation penetrated by a
borehole, for example
at about 15 to about 25 feet at a time. The pre-flush and/or post flush also
help to minimize
any incompatibilities between chemical diverters, treatment fluids, and oil.
Depending upon
the fluid formulation, the duration of the treatment, and the temperature,
after the last fluid is
injected the well may be shut in for a short period of time sufficient for the
decomposition of
the surfactant in the aqueous self-diverting pre-flush sandstone acid before
the well is turned
around and fluid production is begun.

[00511 The inorganic acid concentration in the aqueous self-diverting pre-
flush sandstone
acid is selected based on the temperature, the times for which the gel should
be stable and
then the time after which it should degrade, the volume of aqueous self-
diverting pre-flush
sandstone acid fluid that will contact a given volume of rock, whether the
rock contains
19


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
inorganic acid-sensitive minerals (especially HO-sensitive minerals) and the
amount of acid
with which a given volume of the rock will react. All but the last piece of
information are
determined from geologic information and the job design; the last can be
determined by a
simple laboratory experiment if a rock sample is available, or can be
calculated if the rock
composition is known. With this information the inorganic acid concentration
can readily be
determined so that the fluid has low viscosity when pumped, the reaction with
the rock will
lower the acid concentration sufficiently that the viscosity will increase
significantly (for
example by at least 50 cP), and that sufficient acid will remain in the gel to
degrade the
surfactant in a suitable time. The optimal inorganic acid concentration is, by
non-limiting
example, about 12% HCI.

[0052] The trend is that the higher the total acid concentration in the
initial fluid, the lower
its viscosity as formulated. This is desirable because lower-viscosity fluids
are easier to
inject and because there will be a greater viscosity- contrast (and hence
better diversion)
between the as-pumped fluid and the higher viscosity achieved after some of
the acid has
been spent. However, on the one hand, for many HO-sensitive formations, the
HCl
concentration should be kept as low as possible and extra acid needed should
be provided
with an organic acid, but on the other hand, if the formation is not HCI
sensitive and contains
a high amount of carbonate (so that the HCl content will be reduced a lot by
spending),, then
a higher HO concentration may be used, optionally with no organic acid at all.
Another
balance must be struck between the ability of the fluid to increase in
viscosity at the
appropriate time and place, and the subsequent tendency of the fluid to
decompose. A
formulation is most desirable if it works over a broad temperature range. The
generation of
the viscosity increase of the fluid of Embodiments of the Present Invention is
not
temperature-dependent but is dependent on the decrease in the total acid
concentration;
however, the fluid stability depends upon both the temperature and the acid
concentration.
[0053] The aqueous self-diverting pre-flush sandstone acid of Embodiments of
the Present
Invention can also be used as a diver-ter for another form of matrix
stimulation, sandstone
treatment by chelating agents, a treatment analogous to sandstone acidizing.
In sandstone
treatment by chelating agents, fluids containing high concentrations of such
chelating agents
as, by non-limiting example, ethylenediaminetetraacetic acid,
hydroxyethylethylenediaminetriacetic acid or hydroxyethyliminodiacetic acid or
their
various salts, or mixtures of these acids and/or their salts, are injected
into a sandstone matrix


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
to dissolve carbonate damage. These treatments can be performed over a very
broad pH
range, from about 2 to about 10. Commonly, the chelating agents or their salts
are present in
the treatment fluid at their upper solubility limit for the pH used. One
preferred method of
sandstone treatment by chelating agents is the use of such chelating agents in
the presence of
strong inorganic acids such as HCI. Sandstone treatment by chelating agents is
to be
distinguished from other oilfield stimulation treatments, such as fracturing
or acidizing, in
which much smaller amounts of these chelating agents may be present as
stabilizers or metal
control agents.

[0054] The fluids and methods of Embodiments of the Present Invention are used
at
temperatures above which the surfactant decomposes in strong acid in a time
that is long
enough to complete the mud acid matrix acidizing treatment but short enough to
begin
flowback and production within a reasonable time thereafter. For each
surfactant/acid
combination there is a temperature above which the gel will not remain
sufficiently stable for
sufficiently long for a mud acid matrix acidizing treatment to be performed.
For each
surfactant there is a temperature below which the decomposition is too slow
for the treatment
to be practical because even very high concentrations of inorganic acid would
not destroy the
surfactant in a short enough time. As examples, the surfactant BET-E-40 is
stable to 15%
HC1 for over 34 hours at 27 C; decomposes in 2 hours at 66 C. in 4% HCl; and
decomposes
in 1 hour at 88 'C in 7% HCI. A gelled fluid containing 7.5 weight percent as-
received BET-
E-40, about 7.5 weight percent HCl, 6 weight percent formic acid, and 2.6
weight percent of
a mixture of corrosion inhibitors is stable for more than 100 minutes at 66
C. Of course, it
should be understood that the acid concentration of a self-diverting pre-flush
sandstone acid
after it has been injected into a formation will be much less than the acid
concentration of the
initial fluid, because of the reaction of the acid with the formation.
Therefore the
decomposition of the surfactant in a formation (or in a core in an experiment
in a laboratory)
will be much slower. On the other hand, if the subsequently-injected matrix
stimulation
fluid is a strong acid, it will increase the decomposition rate of the
surfactant where it fingers
through the viscous gelled self-diverting pre-flush sandstone acid and fresh
stimulation fluid
contacts the gel. This will aid in the clean-up of the diverter, and since
there is less diverter
in the oil-containing and/or damaged and/or low permeability zone or zones,
and more
stimulation fluid being injected into that zone or zones, that zone or zones
will clean up
21


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
faster. Furthermore, in the zone or zones in which there is a shorter diverter
plug, matrix
stimulation fluid will break through more readily and contact the formation
more effectively.
J00551 The compositions and methods of Embodiments of the Present Invention
are
particularly advantageous because no damage is caused to the subterranean
formation or to
the environment. It also does not require solids-handling surface equipment.
Many
materials used as diverting gents, such as inorganic salts, starch, and cross-
linked polymers
can cause damage by forming filter cakes on wellbore surfaces or by plugging
the pores of
the formation. This damage can be difficult or impossible to remove. Some
components of
diverting agents can be toxic to humans or to the environment. Even some
diverting agents
based on viscoelastic surfactants can be harmful. Some surfactants are toxic
to some marine
life; some surfactants can cause undesired wetability changes to mineral
surfaces; and some
surfactants can cause emulsions to form when water and oil mix in the
formation or on the
surface. However, the surfactants in the fluids of Embodiments of the Present
Invention,
when used as described, decompose into small non-toxic products that are not
surfactants.
They do not interfere with fluid flow in the formation or in surface
equipment, provided that
under certain circumstances an alcohol is included to prevent sludge formation
as described
above.

[0056] The compositions of Embodiments of the Present Invention are more
environmentally friendly than compositions previously used, because injected
fluids returned
to the surface do not contain surfactants and the decomposition products do
not include any
materials that are not soluble in either water or oil. Furthermore, the
decomposition products
(for example the erucic acid and the amine formed by the hydrolysis of the
surfactant of
BET-E-40) are believed to be non-toxic to humans.

[0057] There are no restrictions on the order of addition of the components
when the
aqueous self-diverting pre-flush sandstone acids are being made up. The as-
received
surfactant mixture; water; inorganic acid; and organic acid; and optional
materials such as
alcohols; co-surfactants; chelating agents; and salt may be blended in any
order either in the
field or at a separate location. Alternatively, any combination of some of the
components
can be premixed on site or at a separate location and then another component
or components
may be added later. The fluids may be batch mixed or mixed on the fly.
Standard mixing
equipment and methods may be used; heating and special agitation are normally
not
22


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
necessary but may be used. Heating may be employed under extremely cold
ambient
conditions. The exact amounts of components and the specific surfactant or
mixture of
surfactants to be used will depend upon the viscosity desired, the temperature
of use, the
time desired before the viscosity has dropped below a predetermined value, and
other similar
factors.

[0058] As is usually the rule for acid treatments, the formulation will
typically comprise
corrosion inhibitors, most preferably small amounts of corrosion inhibitors
based on
quaternary amines, for example at a concentration of from about 0.2 weight
percent to about
1.5%, preferably about 0.4 to about 1.0%, and most preferably from about 0.2%
to about
0.6%. Formic acid can also be used as a corrosion inhibitor, typically at a
concentration of
from about 0.1 to about 2.0 weight percent. All other additives normally used
in oilfield
treatment fluids, such as, but not limited to, corrosion inhibitor aids; scale
inhibitors;
biocides; leak-off control agents; shale stabilizing agents such as ammonium
chloride,
tetramethyl ammonium chloride, or cationic polymers; monovalent and polyvalent
salts and
polyelectrolytes; other surfactants; buffers; non-emulsifiers; freezing point
depressants; iron
reducing agents; chelating agents for the control of certain multivalent
cations, and others
can also be included in the aqueous self-diverting pre-flush sandstone acids
as needed,
provided that none of them disrupts the structure, stability, or subsequent
degradability of the
surfactant gels. Similarly, other fluids used in conjunction with the fluid of
Embodiments of
the Present Invention, such as spacers, flushes, and the like may contain such
additives,
again provided that they do not interfere with the function of the aqueous
self-diverting pre-
flush sandstone acid. It would be expected, and within the scope of
Embodiments of the
Present Invention, to conduct laboratory tests or run computer simulations to
ensure that all
additives are suitable.

[0059] It should be noted that, although no tests have been run, the
formulation of
Embodiments of the Present Invention is expected to be sensitive to iron, in
particular to
ferric ions at a concentration of about 2000 ppm (parts per million) or more.
A preflush
treatment with iron reducing agent and chelating agent is therefore
recommended before the
acid treatment. Although the formulations of Embodiments of the Present
Invention are
compatible with small concentrations of non-emulsifying agents, to prevent
emulsions and
sludge, it is also a good practice to preflush the well with a mutual solvent,
preferably low
23


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
molecular weight esters, ethers or alcohols, and more preferably ethylene
glycol monobutyl
ether.

[0060] Most importantly, unlike many other viscoelastic surfactant-based gels,
the
formulations of Embodiments of the Present Invention do not require oil,
formation water or
mutual solvent to flow back from the formation for the gel to break, because
the inorganic
acid acts as a breaker. Therefore breaking of the gel in the low permeability
zone(s) will
occur at the same rate as breaking of the gel in the high permeability
zone(s). Breaking of
the gel by dilution is a much less efficient process than destruction of the
surfactant by acid,
so flow of formation water into the gel in the high permeability zone(s) zone
could delay
breaking of the surfactant in the water zone by the acid (by diluting the
acid) and thus
prolong rather than reduce the diverting action. Although the formulations of
Embodiments
of the Present Invention do not require added breakers for the micelles or for
the surfactants,
additional breakers may be added, especially at low temperatures.

[00611 The system is adjusted so that the break time is greater than the mud
acid pump time.
The break time will be a function of the choice of surfactant and its
concentration; the
temperature; the choice of acid and its concentration; the ionic concentration
and the nature
of both the anions and cations, including ionized forms of other additives
such as chelating
agents, if present; and the nature and amount of alcohol present. However, for
each given
surfactant type the stabilities are expected to be about the same (for example
for BET-O vs.
BET-E as a function of time, temperature and acid concentration) because they
have the
same electron withdrawing group in the degradable chemical functionality. (The
distance
between the electron withdrawing group and the bond that is broken would make
a
difference.) Surfactants having different electron withdrawing groups will
give different
ranges of stabilities. Variation in the amount of acid acting as surfactant
breaker can be used
to control the time at which the gel breaks at a given temperature. There will
be a certain
range of acid concentrations remaining after the aqueous self-diverting pre-
flush sandstone
acids have reacted with the carbonate in the sandstone and formed a diverting
gel, for
example from about 4% up to about 7%, for BET-E, at which the gel strength
will be about
the same at a given temperature, but the time to break will decrease with
increasing acid
concentration.

24


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
10062] The fluids can be foamed or energized if desired, for example with
nitrogen, carbon
dioxide, or mixtures of the two. BET surfactants themselves are foam formers,
but
additional foaming agents may be added provided that they do not interfere
with the function
of the aqueous self-diverting pre-flush sandstone acid. Other important uses
for these fluids
include as fluid loss pills, kill pills or for temporary selective water
shutoff. Viscosities of at
least about 30 to about 50 cP measured at a shear rate of 100 sec-1 are
preferred for these
uses. Although the uses are described in terms of producing wells for oil
and/or gas, the
fluids and methods may also be used for injection wells (such as for enhanced
recovery or
for storage or disposal) or for production wells for other fluids such as
carbon dioxide or
water.

[0063] Example 1.. Experiments were performed in which fluids were pumped into
cores of
Berea sandstone and the permeabilities to water were determined before and
after the
treatments. The cores, which were 1 inch (2.54 cm) in diameter and 12 inch
(30.5 cm) in
length, were heated to the desired temperature through external heating tape
in two Hassler
cells. Data from the first set of experiments are shown in Table 1. The self-
diverting pre-
flush sandstone acid (SDSA) in each case was an aqueous solution of 7.5% as-
received BET-
E-40, 12% concentrated HCl, 6% formic acid, 1% methanol, 2% Corrosion
Inhibitor "A"
(85% formic acid in water) and 0.6% Corrosion Inhibitor "B" (an additive
package
containing corrosion inhibitors based on quaternary amines). This fluid will
be called
SDSA-1. The "matrix stimulation fluid" (MSF) in each case was an aqueous
solution of
15% concentrated HCl, 6% methanol, and 0.6% Corrosion Inhibitor B, except for
Experiment 4, in which there was no methanol in the MSF. (The HF was left out
of this
"matrix stimulation fluid" to avoid experimental complexities.) The fluid with
6% methanol
will be called MSF-1. Each fluid was injected at 2.5 ml/min. Shut-in was at
temperature
with the MSF in the core.



CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
Experiment 1 2 3 4 5
Temperature ( C) 93 93 93 121 121
Initial Permeability (mD) 64 65 56 140 64
Core.Pore Volume (ml) 26 28 28 29 28

Pore Volumes SDSA-1 Injected 1.7 1.6 1.6 1.7 2.3
Pore Volumes MSF-1 Injected 3.2 2.8 2.8 1.7 2.5
Shut-in Time (hr) 1 2 3 4 12
Regained Permeability (%) 31 42 97 45 137
Table 1. Single Core Experiments

The trend seen in tests 1-3 was due to hydrolysis of the surfactant; the
longer the shut-in
time, the more surfactant hydrolysis, the better clean-up, and therefore the
more regained
permeability. In Experiment 4, not to be limited by theory it is believed that
insufficient
MSF was injected, so the system probably did not maintain a great enough acid
concentration for sufficient hydrolysis. In Experiment 5, not to be limited by
theory it is
believed that the better result was due both to more hydrolysis and to more
stimulation
(greater CaCO3 dissolution) resulting from the longer shut-in time and from
the greater
amount of MSF relative to Experiment 4. These results show the importance. of
designing a
job to achieve all three of diversion, stimulation and clean-up.

[0064] Figure 3 shows the pressure drop across the core during fluid injection
during
Experiment 5. It can be seen that, during injection of the self-diverting pre-
flush sandstone
acid, the pressure drop across the core increased steadily, as the gel
viscosity increased
inside the core due to consumption of HCl by carbonate dissolution. When the
low-viscosity
matrix stimulation fluid was introduced, the pressure drop remained high,
indicating great
resistance to flow of this fluid. Not to be limited by theory, but it is
believed that in an
underground formation, the fluid would be diverted into a different zone; in
this case, where
26


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
there is no such alternative, the low-viscosity fluid fingered through the
diverter. It
apparently broke through at about 40 minutes after which the pressure drop
remained quite
significant and constant, indicating that there was still diverter in the core
pores. The
pressure drop during the water-permeability measurement at the start of the
experiment had
been 14 psi (0.097 MPa). In fact, it is this fingering (due to viscosity
contrast) that
contributes to the success of the method of Embodiments of the Present
Invention. In a
properly designed treatment, after the SDSA injection, there will be a long
plug of SDSA gel
in the high permeability (and/or undamaged, and/or water-containing) zone and
a short
SDSA gel plug in the low permeability (and/or damaged and/or oil-containing)
zone. The
SDSA is designed not to decompose until after the injection of the MSF (so
that it can block
entry of the MSF into the non-target zone), so the low-viscosity MSF must
finger through
the high-viscosity SDSA in order to treat the target zone.

[00651 Example 2. Many dual-core experiments were performed, in which the same
methods were used as in example 1, except that the fluid was injected through
a splitter so
that it had equal access to each of the two cores. Fluids were pumped into the
two cores at a
constant total flow rate. However, the flow rate into each core was dependent
upon the
relative permeabilities of the cores, the changes in fluid viscosity in the
cores during the
experiments (as gel plugs of different lengths built up), and clean-up as the
gel plugs were
destroyed. The amount of fluid entering each core (and the pressure drop
across the core)
was measured. Basic data from each experiment are shown in Table 2.

Experiment Number 6 7 8 9 10 11 12 13 14 15
Temperature C 93 93 66 66 66 66 93 121 121 149
Core 1 mD 67 88 27 29 79 131 39 73 63 19
Core 2 mD 94 76 67 254 201 266 97 166 178 42
Fluid in Core 2 diesel diesel water water * water water water water water
SDSA 1 1 2 2 2 1 1 1 1 1
SDSA Pore Volumes 1.1 0.7 1 1 1.4 1.3 1.3 1.2 1.3 1.1
MSF I 1 2 3 4 5 1 1 1 1
27


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
MSF Pore Volumes 0.8 0.7 0.7 0.7 2.9 2.1 1.2 1.0 1.1 1.3
Shut-in (hr) 12 - 12 12 4 12 12 12 - 0
Regained Perm T84- 76 108 102 23 81 72 - 108
Core 1, %

Regained Perm 17 50 104 1 47 14 - 35
Core 2, %

Figure Number 4 5 6 7 - 8 9 10 11 12
Table 2. Dual Core Experiments

*Both cores injected with over two pore volumes of a fluid consisting of 12%
HCl; 6%
formic acid; 2% A; 0.6% B; and 6% methanol before injection of the SDSA.

SDSA-1: 12% HCl; 6% formic acid; 2% A; 0.6% B; 1% methanol; 7.5% BET-E-40
SDSA-2: 12% HCI; 6% formic acid; 2% A; 0.6% B; 6% methanol; 7.5%o BET-E-40
MSF-1: 15% HCI; 0.6% B; 6% methanol

MSF-2: 3 % NH4C1.

MSF-3: 12% HCl; 0.6% B; 6% methanol

MSF-4: 12% HCl; 2% A; 0.6% B; 6% methanol; 6% formic acid
MSF-5: 12%HCI; 3% HF

[0066] The results of these experiments are shown in Figures 4-12. In these
figures, the
instantaneous weight percent of the fluid being injected that was going into
each core is
shown as a function of time. Each figure shows the injection of the SDSA,
followed by a
brief delay of a few minutes while the fluid being injected was changed,
followed by
injection of the MSF. For example, in Experiment 6 (Figure 4), SDSA-1 was
injected for the
first 25 minutes, then after a fluid-changing time of about 2 minutes, MSF-1
was injected for
about 18 minutes. Initially, almost 80% of the SDSA-1 went into the water-
containing core;
after about 11 minutes, equal amounts of DSDS-1 were entering each core; at
the end of the
28


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
diverter injection, 60% of the fluid was entering the oil-containing core. At
the start of the
MSF injection, almost 80% of the fluid was going into the water-containing
core, and as
injection of MSF continued, the amount of fluid going into the water-
containing core
increased.

[0067] Figures 4 and 5 show two experiments (6 and 7) in which in each case
one core was
first injected with over one pore volume of diesel after the initial
permeabilities were
measured with water. Therefore, at the start of the diversion experiments, one
core
contained diesel as the continuous phase and was at low water saturation; the
other core
contained only water. In each of these experiments, the initial permeabilities
of the two
cores were about the same. It can be seen that in each case, initially 80-90%
of the SDSA
went into the water-containing core, but as injection continued, more and more
of the SDSA
went into the oil-containing core. Not to be limited by theory, but it is
believed that this was
because initially the aqueous injected fluid would go into the water-
containing core, but in
time a plug of high-viscosity gel was forming in the water-containing core.
Injection of the
SDSA was stopped in Experiment 7 at just about the time at which equal amounts
of SDSA
were entering each core. When the injected fluid was switched to a MSF in that
experiment,
most of the MSF went into the oil-containing core, which is exactly what would
be desired,
for proper diversion in the field. However, in Experiment 6, the SDSA
injection was
continued well beyond the point at which equal amounts of SDSA were entering
each core;
although it is not shown, the pressure in both cores had become very high as
the pumping
had been continued. In this case, when the injected fluid was switched to a
MSF, most of the
MSF went into the water-containing core. Although not to be limited by theory,
it is
believed that too much diverter had been injected into the oil-containing
core, so that when
the aqueous MSF was started, it preferably entered the water-containing core.
These results
demonstrate that the right amount of SDSA must be selected and too much could
be used if
the job was not properly designed.

[0068] Experiments 8 and 9 (Figures 6 and 7) are excellent examples of
successful
treatments. In each case, the cores were saturated with brine, then about one
pore volume of
a SDSA was injected, then MSF was injected. In Experiment 8, the "MSF' was
NH4Cl; in
Experiment 9, it was mainly HCI. In each case, the SDSA primarily entered the
high-
permeability core, as would be expected. However, not to be limited by theory,
but since in
each experiment the total amount of SDSA injected was equal to the total pore
volume of
29


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
both cores, and about twice as much fluid entered the high-permeability core
as entered the
low-permeability core in Experiment 8 and about four times as much fluid
entered the high-
permeability core as entered the low-permeability core in Experiment 9, it is
believed that in
each case, the high-permeability core was filled with a viscous SDSA gel while
the low-
permeability core contained some gel only at the front end. Then, when MSF was
injected, it
initially went into the high-permeability core, but with time it fingered
through the smaller
amount of gel in the low-permeability core, and eventually more MSF was
entering the low-
permeability core, which is exactly what would be needed for successful
diversion. The
systems were then shut in at temperature for 12 hours and the permeabilities
of each core
were re-measured with water. The initially low-permeability core in each case
recovered a
much greater fraction of its permeability than did the initially high-
permeability core. In
fact, the low-permeability core, which is believed to have been filled with
acid when it was
shut in for 12 hours (even though the acid was HCI and did not contain HF),
was more
permeable after the experiment than before the experiment. This is probably
due to
dissolution of at least some of the carbonate in the core. This did not happen
when the
"MSF' contained no acid.

[0069] Experiment 10 (no Figure) shows that the sandstone must have some
ability to
consume acid in the SDSA. In that experiment, the cores were flooded with over
two pore
volumes of 12% HCl before the injection of the SDSA. This is believed to have
consumed
all of the carbonate. The SDSA did not cause any diversion. When the MSF was
started,
more of it went into the high-permeability core, and as MSF injection
continued, more and
more of it went into the high permeability core. By the end of the experiment,
a slightly
greater proportion of the MSF was entering the high-permeability core than
would have been
expected from the initial permeabilities. After the experiment, each core had
a permeability
to water slightly above the permeability before the experiment.

[0070] Experiments 11-15 (figures 8-12) all show core floods that demonstrate
successful
diversion by the SDSA. (Each of these figures shows, in the first few minutes,
injection of a
total of less than about 0.2 pore volumes of brine used to determine the
initial permeability.)
These experiments show a variety of temperatures, permeabilities, permeability
contrasts,
and shut-in times. In each case, the majority of the SDSA initially was
entering the high-
permeability core, but the majority of the MSF was eventually entering the low-
permeability


CA 02491934 2005-01-05
WO 2004/005672 PCT/EP2003/007412
core and the regained permeability of the low-permeability core after the
experiment was
greater because of more effective clean-up and more effective stimulation.

[0071] Although the methods have been described here for, and are most
typically used for,
hydrocarbon production, they may also be used in injection wells and for
production of other
fluids, such as water or brine.

31

Representative Drawing
A single figure which represents the drawing illustrating the invention.
Administrative Status

For a clearer understanding of the status of the application/patent presented on this page, the site Disclaimer , as well as the definitions for Patent , Administrative Status , Maintenance Fee  and Payment History  should be consulted.

Administrative Status

Title Date
Forecasted Issue Date 2012-04-24
(86) PCT Filing Date 2003-07-09
(87) PCT Publication Date 2004-01-15
(85) National Entry 2005-01-05
Examination Requested 2008-07-02
(45) Issued 2012-04-24
Deemed Expired 2018-07-09

Abandonment History

There is no abandonment history.

Payment History

Fee Type Anniversary Year Due Date Amount Paid Paid Date
Application Fee $400.00 2005-01-05
Registration of a document - section 124 $100.00 2005-02-10
Registration of a document - section 124 $100.00 2005-02-10
Maintenance Fee - Application - New Act 2 2005-07-11 $100.00 2005-06-07
Maintenance Fee - Application - New Act 3 2006-07-10 $100.00 2006-06-08
Maintenance Fee - Application - New Act 4 2007-07-09 $100.00 2007-06-05
Maintenance Fee - Application - New Act 5 2008-07-09 $200.00 2008-06-04
Request for Examination $800.00 2008-07-02
Maintenance Fee - Application - New Act 6 2009-07-09 $200.00 2009-06-09
Maintenance Fee - Application - New Act 7 2010-07-09 $200.00 2010-06-08
Maintenance Fee - Application - New Act 8 2011-07-11 $200.00 2011-06-07
Final Fee $300.00 2012-02-14
Maintenance Fee - Patent - New Act 9 2012-07-09 $200.00 2012-06-11
Maintenance Fee - Patent - New Act 10 2013-07-09 $250.00 2013-06-12
Maintenance Fee - Patent - New Act 11 2014-07-09 $250.00 2014-06-19
Maintenance Fee - Patent - New Act 12 2015-07-09 $250.00 2015-06-17
Maintenance Fee - Patent - New Act 13 2016-07-11 $250.00 2016-06-15
Owners on Record

Note: Records showing the ownership history in alphabetical order.

Current Owners on Record
SCHLUMBERGER CANADA LIMITED
Past Owners on Record
FU, DIANKUI
SCHLUMBERGER TECHNOLOGY CORPORATION
Past Owners that do not appear in the "Owners on Record" listing will appear in other documentation within the application.
Documents

To view selected files, please enter reCAPTCHA code :



To view images, click a link in the Document Description column. To download the documents, select one or more checkboxes in the first column and then click the "Download Selected in PDF format (Zip Archive)" or the "Download Selected as Single PDF" button.

List of published and non-published patent-specific documents on the CPD .

If you have any difficulty accessing content, you can call the Client Service Centre at 1-866-997-1936 or send them an e-mail at CIPO Client Service Centre.


Document
Description 
Date
(yyyy-mm-dd) 
Number of pages   Size of Image (KB) 
Abstract 2005-01-05 2 80
Drawings 2005-01-05 12 192
Claims 2005-01-05 2 102
Claims 2010-11-08 3 88
Description 2010-11-08 31 1,623
Description 2005-01-05 31 1,589
Representative Drawing 2005-04-05 1 14
Cover Page 2005-04-05 1 43
Claims 2011-09-27 4 126
Description 2011-09-27 33 1,686
Cover Page 2012-03-27 1 44
Assignment 2005-02-10 5 189
Prosecution-Amendment 2010-11-08 8 350
PCT 2005-01-05 13 456
Assignment 2005-01-05 2 82
Correspondence 2005-04-26 1 26
Assignment 2005-08-30 1 37
Prosecution-Amendment 2008-07-02 1 44
Prosecution-Amendment 2008-08-14 1 41
Prosecution-Amendment 2010-05-07 2 64
Prosecution-Amendment 2011-03-29 2 60
Prosecution-Amendment 2011-09-27 9 302
Correspondence 2012-02-14 2 58