MATRIX TREATMENT OF DAMAGED SANDSTONE FORMATIONS USING BUFFERED HF-ACIDIZING SOLUTIONS

TRAITEMENT DE LA MATRICE DE FORMATIONS DE GRES ENDOMMAGEES A L'AIDE DE SOLUTIONS D'ACIDIFICATION A L'ACIDE FLUORHYDRIQUE (HF) TAMPONNEES

English Abstract

Sandstone formations of oil and gas and geothermal wells are effectively stimulated when a buffered HF-sandstone acidizing solution is employed without the prior introduction of an acid containing preflush solution. By not using a preflush solution, buffered HF-sandstone acidizing solutions are highly effective in dissolving and removing siliceous material while minimizing the formation of calcium fluoride.

French Abstract

Les formations de grès pour le pétrole et le gaz naturel et les puits géothermiques sont efficacement stimulées lorsqu'une solution tampon d'acidification avec HF pour le grès est utilisée sans qu'une solution de bouchon de tête contenant de l'acide n'ait d'abord été introduite. Sans l'utilisation d'une solution de bouchon de tête, les solutions tampons d'acidification avec HF pour le grès dissolvent et enlèvent très efficacement les matériaux siliceux et, en même temps, réduisent au minimum la formation de fluorure de calcium.

Claims

CLAIMS
What is claimed is:
1. A method for dissolving acid-soluble siliceous material in a sandstone
formation of an oil or gas or geothermal well which comprises introducing into
the well,
in the absence of a preflush solution, a buffered HF-sandstone acidizing
solution.
2. The method of Claim 1, wherein the pH of the acidizing solution is
between from about 1.9 to about 4.8.
3. The method of Claim 2, wherein the pH of the acidizing solution is
between from about 2.5 to about 4.5.
4. The method of Claim 1, wherein the acidizing solution further comprises a
phosphonate of the formula:
<IMG>
wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl,
phosphonates, phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and
R5 are
16

independently selected from hydrogen, sodium, potassium, ammonium or an
organic
radical.
5. The method of Claim 2, wherein the acidizing solution further comprises a
phosphonate of the formula:
<IMG>
wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl,
phosphonates, phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and
R5 are
independently selected from hydrogen, sodium, potassium, ammonium or an
organic
radical.
6. The method of Claim 4, wherein the acidizing solution further comprises
citric acid or formic acid.
7. The method of Claim 6, wherein the acidizing solution comprises about 1
to about 50 weight percent citric acid, up to about 20 weight percent HF and
from about
0.5 to about 50 weight percent phosphonate compound.
17

8. The method of Claim 1, further comprising introducing into the well,
subsequent to the introduction of the acidizing solution, an overflush
solution.
9. The method of Claim 1, which further comprises introducing into the well
a neutral chelant pickling agent.
10. In a method of well remediation in which a wellbore fluid is employed, the
improvement comprising using a wellbore fluid comprising a buffered HF-
sandstone
acidizing solution.
11. The method of Claim 10, wherein the pH of the sandstone acidizing
solution is between from about 1.9 to about 4.8.
12. The method of Claim 10, wherein the sandstone acidizing solution further
comprises a phosphonate of the formula:
<IMG>
wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl,
phosphonates, phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and
R5 are
18

independently selected from hydrogen, sodium, potassium, ammonium or an
organic
radical.
13. The method of Claim 12, wherein the sandstone acidizing solution further
comprises citric acid or formic acid.
14. A method of stimulating or remediating a sandstone formation consisting
essentially of introducing into the formation a buffered HF-acidizing
solution.
15. The method of Claim 14, wherein the pH of the acidizing solution is
between from about 1.9 to about 4.8.
16. The method of Claim 14, wherein the acidizing solution further comprises
a phosphonate of the formula:
<IMG>
wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl,
phosphonates, phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and
R5 are
19

independently selected from hydrogen, sodium, potassium, ammonium or an
organic radical.
17. The method of Claim 14, wherein the acidizing solution further comprises
citric
acid or formic acid.
18. A process for dissolving acid-soluble siliceous material in a sandstone
formation
of an oil or gas or geothermal well consisting essentially of introducing into
the well a buffered
HF-acidizing solution.
19. The process of Claim 18, wherein the pH of the acidizing solution is
between
from about 1.9 to about 4.8.
20. The process of Claim 18, wherein the acidizing solution further comprises
at least
one member selected from the group consisting of:
(a.) a phosphonate of the formula:
<IMG>
21. A method for dissolving acid-soluble siliceous material in a sandstone
formation
of an oil or gas or geothermal well wherein the sandstone formation contains
carbonate minerals
which comprises introducing into the well, in the absence of a preflush
solution, a buffered HF-

sandstone acidizing solution and thereby minimizing the formation of calcium
fluoride from the
carbonate minerals.
22. The method of Claim 21, wherein the pH of the acidizing solution is
between
from about 1.9 to about 4.8.
23. The method of Claim 22, wherein the pH of the acidizing solution is
between
from about 2.5 to about 4.5.
24. The method of Claim 21, wherein the acidizing solution further comprises a
phosphonate of the formula:
<IMG>
wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl,
phosphonates,
phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and R5 are
independently selected
from hydrogen, sodium, potassium, ammonium or an organic radical.
25. The method of Claim 22, wherein the acidizing solution further comprises a
phosphonate of the formula:
<IMG>
wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl,
phosphonates,
phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and R5 are
independently selected
from hydrogen, sodium, potassium, ammonium or an organic radical.
21

26. The method of Claim 24, wherein the acidizing solution further comprises
citric
acid or formic acid.
27. The method of Claim 26, wherein the acidizing solution comprises about 1
to
about 50 weight percent citric acid, up to about 20 weight percent HF and from
about 0.5 to
about 50 weight percent phosphonate compound.
28. The method of Claim 21, further comprising introducing into the well,
subsequent
to the introduction of the acidizing solution, an overflush solution.
29. The method of Claim 21, which further comprises introducing into the well
a
neutral chelant pickling agent.
30. A method of stimulating or remediating a sandstone formation by
introducing into
the formation a wellbore fluid consisting essentially of a buffered HF-
acidizing solution.
31. The method of Claim 30, wherein the pH of the acidizing solution is
between
from about 1.9 to about 4.8.
32. The method of Claim 30, wherein the acidizing solution further comprises a
phosphonate of the formula:
<IMG>
wherein R1, R2 and R3 are independently selected from hydrogen, alkyl, aryl,
phosphonates,
phosphates, acyl, amine, hydroxy and carboxyl groups and R4 and R5 are
independently selected
from hydrogen, sodium, potassium, ammonium or an organic radical.
33. The method of Claim 30, wherein the acidizing solution further comprises
citric
acid or formic acid.
22

Description

CA 02530325 2005-12-16
APPLICATION FOR PATENT
INVENTORS: PHILdP JAMES RAE; GINO DI LULLO ARIAS; ATIKAH
JANIILAH BTE KUNJU AHMAD
TITLE: 1VIATRIX TREATMENT OF DAMAGED SANDSTONE
FORMATIONS USING BUFFERED HF-ACIDIZING
SOLUTIONS
SPECIFICATION
Field of the Invention
The invention relates to a method of stimulating or remediating sandstone
formations of oil and gas and geothermal wells without the use of preflush
acidizing
solutions.
Background of the Invention
In the course of drilling, or during production or workover, the vast majority
of oil
and gas wells are exposed to conditions that ultimately lead to formation
damage.
Formation damage limits the productive (or injective) capacity of the well.
The reduction
in well performance is generally due to changes in near-wellbore permeability
which may
be caused by a number of factors, such as rock crushing, invasion of drill
solids, swelling
of pore-lining clays, migration of mobile fines and changes in wettability.
It is known that permeability impairment may be improved by injecting acid
formulations containing HF into the formation. Such treatments are capable of
attacking
and dissolving those siliceous minerals, such as clays and quartz fines, that
are commonly
associated with plugging of formation pore spaces. Unfortunately, the process
of
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CA 02530325 2005-12-16
dissolving siliceous minerals is not simple. Further, during the process,
numerous
chemical species are generated by the interactions between the initial
reactants and first,
second and third stage reaction products. Driven by the unstable nature of
many of these
chemical interactions, voluminous solid precipitates or colloidal amorphous
gels are often
generated in the reaction mixture. The generation timing of such secondary
and/or
tertiary precipitates as well as their placement in critical locations, such
as the near
wellbore, ultimately may cause further formation damage and negate the benefit
of the
acid treatment. In an effort to mitigate these problems, several different
approaches have
been adopted. These include the use of:
(a.) HF formulations containing excess HCI. Exemplary of such formulations
are those having a combination of HC1:HF in a 4:1 weight ratio. Recently,
formulations
having ratios as high as 9:1 have been adopted. This methodology lowers the pH
of the
HF mixture to levels at which some reaction products exhibit higher
solubility.
(b.) delayed acid formulations. Such formulations only generate HF slowly,
generally due to hydrolysis of one or more components. Deeper penetration of
HF into
the formation is the resulting effect. This effectively dilutes the
concentration of the
reaction product which, in turn, minimizes precipitation. Such formulations
include
fluoroboric acid, HBF4.
(c.) half-strength mud acids. This strategy dilutes the concentration of
reaction products per unit volume of acid treating solution but,
unfortunately, also
reduces the total quantity of siliceous minerals that can be dissolved per
unit volume of
acid.
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CA 02530325 2008-07-16
(d.) buffered acid systems. Such systems essentially limit the availability of
hydrogen ions for generation of HF. They allow deeper penetration due to lower
reactivity. However, since the pH of such systems is high, additional measures
must be
adopted to prevent the generation of precipitates. Such measures include the
incorporation of materials, such as phosphonates, into the system. Such
materials inhibit
the generation of precipitates. Preferred buffered acid systems include those
sandstone
acidizing solutions set forth in U.S. Patent No. 7,059,414.
(e.) overflush fluids. Such fluids are typically dilute HCI or ammonium
chloride brine. They serve to push HF-containing acid stages, along with the
unstable,
dissolved reaction products dissolved in such acid stages, away from the near-
wellbore
region prior to precipitation of unwanted materials.
(f.) rapid flowback techniques. Such techniques serve to bring the treating
formulations out of the formation and the well as quickly as possible. This
typically
occurs while the systems are characterized by a low pH when unwanted
precipitation is
less likely to occur.
Unfortunately, the secondary and tertiary precipitates generated by the
interaction of HF
with siliceous minerals are not the only problematic byproducts encountered
when acid
formulations containing HF enter a sandstone rock matrix. Most sandstones
contain
varying quantities of carbonate minerals (calcite, dolomite, etc) along with
quartz, clays
and feldspars that usually form the bulk of the rock. In the presence of
acids, the
carbonate minerals dissolve and release calcium ions that, in turn, react with
fluoride ions
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CA 02530325 2005-12-16
to produce highly insoluble calcium fluoride, CaF2. Calcium fluoride
precipitates quickly
and, instead of stimulating the formation, causes formation damage by
blockage.
Production is therefore dramatically decreased.
For this reason, traditional mud acid matrix treatments in sandstone
formations
are preceded by a preflush, usually consisting of HCl or other non-fluoride
containing
acid, to dissolve the carbonates. The preflush is pumped in sufficient volume
to
theoretically remove all carbonates within a radius of two to three feet from
the wellbore.
This dramatically reduces the risk of the principal HF-containing acid stage
from
contacting carbonate minerals.
While theoretically sound, such preflushes are not always as successful as
desired.
Often, the highly reactive preflush opens up preferential flow paths into the
rock, due to
dissolution of carbonate. As a result, damaged zones of the formation may be
bypassed.
The HF-containing acid when subsequently introduced may therefore follow these
flow
paths and thus may not contact the plugging clays and other siliceous minerals
which it is
designed to dissolve. The most severe effects are often seen in multistage
treatments,
e.g., those featuring sequential diversion. Since treatments are very complex -
involving
many repeat stages of preflush, main HF-stage, overflush as well as diverter -
it is often
difficult to ensure that the acid stage is properly entering the desired zone
and
encountering the appropriate mineralogy. This may result in very poor zonal
coverage,
poor damage removal, creation of unexpected damage due to acid/rock
incompatibilities
and, ultimately, poor stimulation results. These problems are especially
evident when the
majority of commercial, HF-containing acid systems are employed.
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Alternative procedures for dissolving siliceous material in formations are
therefore desired.
Summary of the Invention
Sandstone formations of oil and gas and geothermal wells are more effectively
stimulated when a buffered HF-sandstone acidizing solution is employed without
the
prior introduction of an acid-containing preflush solution. Buffered HF-
sandstone
acidizing solutions are highly effective in dissolving and removing siliceous
material
while minimizing the formation of calcium fluoride.
In a preferred mode, the buffered HF-sandstone acidizing solution contains at
least one organic acid and/or salts or esters thereof. Preferred are citric
acid, formic acid
and phosphonate acids or salts as well as esters thereof, such as those of the
formula:
RI 0
R2-C-P-0-R4
R3 CJ ---- R5
(I)
wherein R1, R2 and R3 may be hydrogen, alkyl, aryl, phosphonates, phosphates,
acyl
amine, hydroxy and carboxyl groups and R4 and R5 may consist of hydrogen,
sodium,
potassium, ammonium or an organic radical.
The acidizing solution may further be employed in the remediation of oil and
gas
and geothermal wells by the removal of unwanted deposits from the wellbore and
production equipment.
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Brief Description of the Drawings
In order to more fully understand the drawings referred to in the detailed
description of the present invention, a brief description of each drawing is
presented, in
which:
FIGs. 1 and 3 illustrate the effect on permeability of a sandstone acidizing
solution when the acidizing solution is introduced into a core without a
preflush solution.
FIGs. 2 and 4 illustrate the effect on permeability when a preflush solution
is
introduced into the core prior to the introduction of the sandstone acidizing
solution.
Detailed Description of the Invention
Sandstone formations of oil and gas and geothermal wells may be stimulated,
without use of a preflush solution, with a buffered HF-acidizing solution. The
buffered
sandstone acidizing solution, highly effective in dissolving and removing
siliceous
material, typically exhibits a pH between from about 1.9 to about 4.8, more
typically
between from about 2.5 to about 4.5.
The amount of HF in the acidizing solution is generally between from about 0.5
to
about 20.0 weight percent, preferably between from about 1.5 to about 6.0
weight
percent. (HF acid is, by definition, a weak acid being only partially
dissociated in water,
pKa = 3.19.) In a preferred mode, the acidizing solution further contains an
organic acid
which assists in delaying reaction on clay minerals, thereby significantly
slowing the HF
acid reaction rate.
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Acidizing solutions may contain one or more phosphonate acids or salts as well
as
esters thereof. Such systems may contain phosphonate materials of the formula:
RI 0
\ 41
R2-C-P-0-R4
R3 t?-R5
(I)
wherein Rl, R2 and R3 may be hydrogen, alkyl, aryl, phosphonates, phosphates,
acyl
amine, hydroxy and carboxyl groups and R4 and R5 may consist of hydrogen,
sodium,
potassium, ammonium or an organic radical. The concentration of the
phosphonate acid
in the acidizing solution is generally between from about 0.25 to about 50.0,
preferably
from about 0.5 to about 6.0, more preferably about 3, percent by volume of the
total
solution without regard to the HF acid concentration.
Examples of these materials include aminotri (methylene phosphonic acid) and
its
pentasodium salt, 1-hydroxyethylidene-l,l-diphosphonic acid and its
tetrasodium salt,
hexamethylenediaminetetra (methylene phosphonic acid) and its hexapotassium
salt, and
diethylenetriaminepenta (methylene phosphonic acid) and its hexasodium salt.
Among
the commercial phosphonate materials, preferred are amino phosphonic acids,
such as 1
hydroxyethylidene-l,l-diphosphonic acid, otherwise known as "HV acid,"
available in
60% strength as DEQUEST 2010 TM from Monsanto Co.
Further suitable acids for the acidizing solution are organic acids, such as
citric acid,
acetic acid, or formic acid as well as those set forth in U.S. Patent No.
6,443,230. In a
preferred mode, the acidizing solution contains
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CA 02530325 2008-07-16
both a phosphonate acid (set forth above) as well as the organic acid of this
paragraph.
The amount of organic acid in the acidizing solution is typically between from
about I to
about 50 weight percent.
Suitable as the sandstone acidizing solution are those acid systems known in
the
art for dissolving the silicate and clay formations of the sandstone to
increase its
permeability. Especially preferred are those acidizing solutions described in
U.S. Patent
No. 5,529,125.
A particularly preferred sandstone acidizing solution for use in the invention
is BJ
Sandstone Acid, a product of BJ Services Company, since it attacks calcium
carbonate
slowly and therefore is much less prone to the release of calcium ions and
subsequent
precipitation of calcium fluoride. In addition to being non-reactive with
carbonate
minerals, BJSSA does not require clay dissolution for stimulation response and
can be
formulated to have high HF strength and activity.
By not requiring use of a preflush solution, the method of the invention is
more
environmentally friendly than the methods of the prior art.
In addition to not requiring a preflush solution, in a preferred embodiment of
the
invention, an overflush solution is further not required. Where desired,
conventional
overflush solutions, such as ammonium chloride based overflush solutions, may
be used.
The use of no preflush, and optionally no overflush, solution, allows for
minimal risk of
undesired reactions with the reservoir rock.
Matrix acidizing in sandstone reservoirs is therefore greatly simplified in
accordance with
the invention. The need to pump multiple fluids in a carefully choreographed
sequence is
eliminated. Further, the invention improves acid placement
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CA 02530325 2005-12-16
and distribution and reduces equipment requirements, e.g., in terms of
tankage, etc. The
invention improves logistics, reduces cost, along with improved results, while
simultaneously rendering treatments which are easier to implement and control
at the
field level.
Further, the invention, by not requiring use of a preflush solution, reduces
the
generation of iron-based precipitates. Iron is ubiquitous in the oilfield due
to the use of
steel tanks, lines and well tubulars. While iron is often not a problem in HF-
containing
systems, due to the formation of soluble fluoroferrate complexes, it becomes a
great
concern when conventional HCl based preflush solutions are employed. It is
widely
recognized that iron-based precipitates are responsible for many problems
associated with
acid stimulation treatments. Steel, consisting mainly of iron, is readily
dissolved by
strong mineral acids to produce ferrous (Fe 2+) ions. Contact with atmospheric
oxygen
readily transforms these to ferric (Fe 3+) iron, which precipitates easily
from acid
solutions, even at low pH. Contact with steel reverses this oxidation effect,
to some
extent, reducing ferric iron back to the ferrous state.
However, depending on circumstances, the ferric iron concentration in HCl can
be
extremely high due to the dissolution of the ferric oxides (rust) that quickly
form when
steel is exposed to air. For this reason, it is very much preferred that the
well tubulars be
"pickled" with a suitable rust dissolver (e.g. dilute acid) and the string
contents reversed
out, ahead of any acid treatment on the formation. Failure to do so results in
the injection
of extremely high levels of (mainly) ferric iron into the formation with a
very high
probability of plugging the zone. Even when using pickled tubulars, however,
the level
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CA 02530325 2005-12-16
of iron in a mineral acid preflush can still reach several thousand mg/liter,
necessitating
the incorporation of high levels of iron-control agents to avoid
precipitation.
Thus, the invention minimizes the risk of iron formation and further minimizes
the need for use of rust dissolvers. By eliminating the use of a mineral acid
preflush and
using a buffered HF-acidizing solution in accordance with the invention,
problems
associated with iron dissolution and its subsequent precipitation are largely
mitigated.
Such an approach, when coupled with a tubing pickle, such as a neutral chelant
pickling
agent, significantly improves acidizing in many formations. A particular
advantage of
the invention is the ability to inject a neutral chelant pickling agent,
containing the
dissolved and complexed iron, etc., directly into the formation without having
to reverse
it out ahead of the acid treatment. Suitable neutral chelant pickling agents
include
conventional inert water-soluble polymeric chelants known in the art which are
capable
of chelating a polyvalent metal ion. These include polymeric chelants having a
molecular
weight of between about 600 and about 1,000,000.
In addition to its use in matrix acidizing, the invention is applicable in
remediation of oil and gas and geothermal wells by the removal of unwanted
deposits
from the wellbore and production equipment. Such unwanted deposits form and/or
accumulate in the wellbore, production and recovery equipment and well casing.
Such
accumulated deposits affect productivity and are typically removed prior to
cementing or
the introduction of completion fluids into the wellbore. Remediation treatment
fluids are
further typically used to remove such undesired deposits prior to the
introduction of
stimulation fluids. In a preferred embodiment, the invention is used to remove
siliceous
deposits inside well tubulars.

CA 02530325 2008-07-16
In well remediation applications, the acidizing solution is preferably
injected
directly into the wellbore through the production tubing or through the use of
coiled
tubing or similar delivery mechanisms. Once downhole, the solution remedies
damage
caused during well treating such as, for instance, by stimulation fluids and
drilling fluid
muds, by dispersing and removing siliceous materials from the formation and
wellbore.
Examples
The following examples are illustrative and should not be construed as
limiting
the scope of the invention or claims thereof.
Unless otherwise indicated, all percentages are expressed in terms of weight
percent.
BJ Sandstone Acid TM (BJSSA), a product of BJ Services Company, was
employed as the buffered HF-acidizing solution.
BJ HSSA refers to half-strength BJ Sandstone Acid.
Example 1:
About 100 ml of BJSSA and mud acid containing 12% HCl and 3% HF was
placed into separate beakers. Then 2 grams of carbonate chips was added into
the acids,
under static conditions, at room temperature and at 180 F and left to stand
for 24 hours.
The solubility of calcium carbonate in the HF-based acids is set forth in
Table I:
Table I
ACID SYSTEMS OBSERVATIONS
BJSSA No effervescence or precipitation even after 24 hrs when examined
at room temperature and at 180 F.
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Mud Acid Strong effervescence and formation of white precipitate after initial
15 minutes at room temperature as well as at 180 F.
Table I illustrates the low reactivity of buffered HF-containing acidizing
solution
versus the rapid reaction of mud acid with calcium carbonate and the
subsequent
precipitation of calcium fluoride. The solubility of calcium carbonate is
limited partly by
the higher-than-normal pH of the buffered HF-acidizing solution (which reduces
acid
attack on the carbonate) and partly by the low solubility of calcium fluoride
that is
formed as a surface reaction product from the reaction of HF with calcium
carbonate.
Examples 2-5:
These Examples illustrate the effect of core flow testing using BJSSA on
sandstone cores. Four separate core flow tests were conducted using 1.5 inch
diameter
and 2 inches length sandstone Berea core plugs with and without a preflush
solution.
Prior to analysis, plugs were seated in rubber sleeves at 1000 psi confining
pressure and flow saturated with filtered 3% NH4Cl containing a strongly water-
wetting
surfactant, NE- 118 TM (a nonionic surfactant, a product of BJ Services
Company) at 1
gpt. The surfactant was added to ensure that the sandstone was water wet and
to avoid
the formation of microemulsions.
The flow was established in an arbitrary formation to wellbore (production)
direction with 3% NH4C1 brine to establish initial permeability. The flow was
continued
until a stable flow rate and permeability was obtained.
1. When flowing preflush, it was injected at 50 pore volumes in the reverse
(injection)
direction at constant flow rate of about 1 ml/min. When not flowing preflush,
step 2
below was not followed.
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2. The Main HF-based Acid was injected at 50 pore volumes in the reverse
direction at
constant flow rate of about 1 ml/min.
3. The acid was then overdisplaced with 3% NH4C1 with 1 gpt Ne-118 brine at 25
pore
volumes.
4. Flow was re-established in the production direction with 3% NH4C1 until a
stable
flow rate and effective permeability to brine following treatment was
obtained.
The results are set forth in Table II below:
Table II
# CORE TYPE ACID FLOWED
2 Berea Core BJ HSSA
Comp. Berea Core HCI Preflush & BJ HSSA
3
4 Core 4 BJ HSSA
Comp. Core 5 HCI Preflush & BJ HSSA
5
The mineralogy of the cores was determined prior to core flow analysis by x-
ray
diffraction analysis. X-ray powder diffraction (XRD) is an analytical
technique that
bombards a finely powdered rock sample with monochromatic Cu k radiation and
measures intensity of the scattered beam versus 2-theta angle of the
instrument. These
data are used in the Bragg equation to calculate d-spacing of the material(s)
present.
Bulk XRD samples are prepared by mechanically grinding the sample to a fine
powder
and backpacking the powder into a hollow-cavity sample mount. The results are
set forth
in Table III below:
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Table III
MINERALOGY APPROXIMATE WEIGHT %
TEST #/ CORES Ex. 2 Ex. 3 Ex. 4 Ex. 5
QUARTZ 98% 98% 65% 66%
CALCITE 2% 2% - -
DOLOMITE - - 18% 18%
SIDERITE - - 3% 1%
PLAGIOCLASE FELDS - - 2% 3%
ILLITE - - 5% 5%
KAOLINITE TRACE TRACE 6% 7%
The core flow analysis is set forth in Table IV below:
Table IV
Example # ACIDS INITIAL REGAIN RESULTS
PERM, md PERM, md
2 BJ HSSA 7.55 17.96 138% increase
NO PREFLUSH
3 BJ HSSA 7.80 17.96 130% increase
HCIPREFLUSH
4 BJ HSSA 2.69 4.73 76% increase
NO PREFLUSH
BJ HSSA 3.0 1 - Fines lu in
HCl PREFLUSH p gg g
5
The results are further set forth in FIG. 1(Ex. 2), FIG. 2 (Comp. Ex. 3), FIG.
3 (Ex. 4)
and FIG. 4 (Comp. Ex. 5). As set forth in the FIGs., permeability falls to
zero in the
preflushed core containing high carbonate levels. Note, in particular, FIG. 4.
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The data shows that buffered HF acidizing solution may be injected into a
sandstone matrix containing carbonate minerals without the use of a preflush.
Similar
responses are obtained in terms of permeability improvement of cores with
minor
carbonate content, regardless if preflushes are or are not employed. In the
case of cores
containing substantial quantities of carbonate, the buffered HF-containing
acidizing
solution with no preflush demonstrated a slight permeability improvement. The
use of a
preflush actually caused a reduction in permeability due to dissolution of
carbonate
cementitious minerals and the release of fines due to deconsolidation of the
rock. Thus,
the buffered HF-acidizing solution can beneficially be used in such
circumstances since it
requires no preflush. Conventional mud acid formulations, which require a
preflush,
cause significant problems with such cores. If a preflush is used, core
deconsolidation
will occur, as above, but if mud acid is injected into such cores with no
preflush, calcium
fluoride precipitation results along with impairment of permeability.
While the invention may be adaptable to various modifications and alternative
forms, specific embodiments have been shown by way of example and described
herein.
However, it should be understood that the invention is not intended to be
limited to the
particular forms disclosed. Rather, the invention is to cover all
modifications,
equivalents, and alternatives falling within the spirit and scope of the
invention.
From the foregoing, it will be observed that numerous variations and
modifications may be effected without departing from the true spirit and scope
of the
novel concepts of the invention.

Representative Drawing