SPE 73705

Effect of Acidizing Additives on Formation Permeability During Matrix Treatments

Wayne W. Frenier and Donald G. Hill, SPE, Schlumberger

Copyright 2002, Society of Petroleum Engineers Inc.

the tests was to determine if the additives are damaging the
This paper was prepared for presentation at the SPE International Symposium and Exhibition formations due to adsorption or precipitation or altering the
on Formation Damage Control held in Lafayette, Louisiana, 20–21 February 2002.
removal of damage or the dissolution mechanisms. Two major
This paper was selected for presentation by an SPE Program Committee following review of
information contained in an abstract submitted by the author(s). Contents of the paper, as
techniques were used: linear core flood tests and rotating disk
presented, have not been reviewed by the Society of Petroleum Engineers and are subject to tests. Using these methods, we have determined the effects of
correction by the author(s). The material, as presented, does not necessarily reflect any
position of the Society of Petroleum Engineers, its officers, or members. Papers presented at selected additives of the effectiveness and kinetics of
SPE meetings are subject to publication review by Editorial Committees of the Society of
Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper
reaction of HCl and chelating agents on limestone and
for commercial purposes without the written consent of the Society of Petroleum Engineers is Berea sandstone.
prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300
words; illustrations may not be copied. The abstract must contain conspicuous The effects of the additives depend on their individual
acknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.
Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.
chemical structure as well as the fluid and the formation being
penetrated. In general, additives that are highly soluble in the
fluid had less effect than agents that are insoluble or
Abstract dispersible in the fluid. We have also shown that some
Matrix acidizing treatments are performed to increase the additives can change the break-through volume during
permeability of oil and gas formations and to remove various carbonate stimulation tests, thus altering the effectiveness of
types of damage. Mineral acids, organic acids and chelating the treatment. In the paper, we will describe tests conducted at
agents are used to stimulate carbonate formations and to various temperatures, including tests run at 350 oF to evaluate
remove damage. Sandstone formations are usually treated with hydroxy chelating agent formulations14, 15 for use in matrix
mineral acids (usually containing some HCl and HF) to stimulation of carbonates.
remove damaging solids or liquids. Usually, stimulation in
sandstone is not achieved. While a reactive fluid must be Introduction
present to dissolve the damage or to remove part of the Acidizing fluids include formulations based on hydrochloric
formation, numerous “additives” can be used to aid the acid (HCl), various hydrochloric acid and hydrofluoric acid
penetration of the fluid or to perform other important tasks. To (HF) mixtures (i.e., Mud Acids), organic acids and chelating
enable the reactive fluid to be pumped from the surface agents. The major function of these fluids is to remove
through the tubing and into the formation, corrosion inhibitors damage by dissolving scales and formation fines and to
usually will be required to protect the metal from attack by the stimulate the formation.
fluid itself. Surfactants, solvents, iron control agents, non- Various acidizing formulations also are used to treat
emulsifiers and several other types of agents also may carbonate and silicate formations and to remove scale from
be present. tubulars or surface equipment. By definition, these fluids are
There is increasing concern and some evidence (H. A. reactive; therefore, they will react with well tubulars or
Nasr-El-Din, SPE 56712) that the additives adsorb onto the pumping equipment as well as with the formation. As a result,
formation (or scale) and may actually be a cause of increased most of these reactive fluids require addition of a corrosion
damage. Stimulation of carbonates frequently results in the inhibitor to preferentially protect the metal surfaces from
formation of highly permeable wormholes, so adsorption of corrosive attack1.
the additive may not be as important as damage caused in While the major task of the reactive fluid is to dissolve
sandstone formation where damage removal is the primary damage and to open channels for improved production,
goal. However, it is very possible that the additives may alter additional “additives” may be included in the system to
the surface kinetics during limestone acidizing, and thus enhance the injectivity and return of the stimulation fluids.
change the degree of penetration or the efficiency of The additives commonly employed include surface-active
wormhole formation. agents (surfactants) that are used to reduce surface and
To understand some of the effects of additives on interfacial tensions. The benefits of these chemicals is very
acidizing operations, we have studied some commercial broad for acidizing applications, as outlined by Ali and Hinkel
corrosion inhibitors, surfactants and solvents during treatments in a recent review.2 These applications include uses as wetting
of simulated sandstone and carbonate formations. The goal of agents, foaming agents, silt-suspending agents, anti-sludging
2 W. W. FRENIER AND D. G. HILL SPE 73705

agents, non-emulsifiers, mutual solvents as well as emulsifiers cores. These experiments were conducted with and without
for emulsified treating fluid applications. These products aid acidizing additives. Core flood tests were also run using Berea
in the removal of organic and inorganic deposits as well as sandstone to determine the amount of formation damage
improve injectivity and return of the reactive fluid. caused by various additives in KCl brine. Corrosion tests
Discussions by Gidley and co-workers3, 4 and by Sutton5 were completed to determine the corrosiveness of each of
and Hall6 demonstrate the benefits of mutual solvents and the fluids.
surfactants for improving the production of oil and gas wells. The additives used in this study and their structures are
The benefits of these surface-active products include the shown in Fig. 1, while the descriptions are in Table 1. All of
removal of paraffin deposits, prevention of emulsions and the non-proprietary materials were reagent grade chemicals
control of sludge and iron precipitation. Surfactants are also purchased from chemical supply firms. The additives were
required for the effective inhibition of these reactive fluids by used as received from the vendors.
improving the dispersion of the inhibitor product in the acid
and by providing an effective barrier to minimize corrosion. Rotating Disk (RD) Kinetic Studies. Fig. 2 shows the
While these additives perform useful and necessary schematic description of the RD test and the controlling
functions, they frequently interfere with each other. Crowe7 equations. Fig. 3 describes the equipment from Parr
demonstrated that some corrosion inhibitors adversely affect Instrument Co. that utilized the RD methodologies. It consists
matrix stimulation of sandstone formations due to inhibitor of a reaction chamber (modified Parr Instrument 1-L Hastelloy
adsorption onto the rock matrix, limiting the reactivity of the reactor), a heated transfer flask for the reagents and necessary
fluid. Application of mutual solvents and surfactants were transfer piping. A spindle terminates with a 1-inch diameter
beneficial in minimizing this effect. King8 demonstrated that disk (316 stainless steel (SS), 0.25 inch thick) that extends into
the application of mutual solvents is limited due to adsorption the chamber. The tests were performed with Carrara marble
and reaction with concentrated acids to form undesirable disks (1-inch-diameter) mounted on the SS disk. To perform
products and limits the application of these products. the test, the disk was mounted on the spindle, the rpm was set
Application of surfactants with stimulation fluids can also and rotation started. The reactor was closed and heated to the
have an adverse effect on the inhibition of corrosion. Smith test temperature. The test fluid (usually 850-mL) was loaded
and coworkers9 initially demonstrated this effect. This effect into the transfer flask and heated to the test temperature. When
is dramatically affected by temperature and acid strength. both vessels were at the same temperature, the test fluid was
Jasinski10 also proved that some of these surface active pushed into the test vessel using nitrogen pressure. The
materials (especially mutual solvents) may dramatically backpressure regulator was set at 600 psig and the test was
increase the observed corrosion and required additional started. Samples were taken at intervals, and the rate of
inhibitor be added to achieve acceptable corrosion inhibition. reaction was determined from the slope of the [Ca] Vs time
More recently, several papers by Nasr-el-Din11 and plot. The [Ca] was determined using Atomic Absorption
Dabbousi and coworkers12 have shown that acidizing additives Spectrophotometry (AAS) or Inductively Coupled Plasma
may affect dissolution of some types of scale or cause changes Optical Emission Spectrophotometry (ICPOES).
in the surface tension of the fluids.
To understand some of the effects of additives on Dynamic Core Flood Studies. Dynamic core flood tests
acidizing operations, we have studied representative were run using the equipment, shown in Fig. 4. The Indiana
commercial corrosion inhibitors, surfactants and solvents limestone core (1.0-inch diameter and about 6 in long) was
during treatments of simulated sandstone and carbonate placed in a Hassler sleeve before being placed in the heated
formations. The goal of the study was to determine if the test chamber. The temperature of the tests was maintained at
additives are damaging the formations due to adsorption or 65 oC for HCl and 175 oC for HEDTA (150 oF and 350 oF).
precipitation or altering the removal of damage or the Various flow rates were used. A backpressure of 1000 psig
dissolution mechanisms. Two major techniques were used: was maintained to keep CO2 in solution. The volume to break-
linear core flood tests and rotating disk tests. Using these through (Vbt) was determined from the onset of dramatic
methods, we have determined the effects of selected additives permeability increase. Samples of the effluent were collected
on the effectiveness of stimulation and on the kinetics of at 10-mL intervals and sent for chemical analyses (Fe and Ca)
reaction of HCl and chelating agents on limestone. Adsorption using AAS or ICPOES methods. The cores were photographed
on Berea sandstone also was examined. We will describe and reweighed after the test was completed.
laboratory tests conducted at various temperatures, up to 350 Dynamic core flood tests also were run using 1in diameter
o
F, to evaluate an alternative chelating agent formulation for x 6-inch Berea sandstone cores using this same equipment.
use in matrix stimulation of carbonates.13, 14,15
Corrosion Inhibition Studies. Corrosion weight loss tests
Experimental Procedures were run in Chandler autoclaves using the procedures
The experimental program included tests to determine the described by Jasinski10. The corrosion tests completed with the
kinetic parameters for dissolution of calcite using the rotating sodium HEDTA (pH 2.5 and 4) inhibited with Inhibitor B
disk (RD) methods, and for determining the extent of were compared with 15% HCl inhibited with Inhibitor A with
wormhole formation using core flood tests with limestone Inhibitor Aid C. Testing was completed with N80 and 13%
SPE 73705 Effect of Acidizing Additives on Formation Permeability During Matrix Treatments 3

chrome steels at 300°F or 400°F and 3,000 psi for 6 hours and phosphonates had the largest effect on the surface reaction
4 hours, respectively. Total acid to steel exposure time was rates and on the core flood test results. In the tests with the
approximately 8 hours and 6 hours, respectively, to include chelating fluid, the scale inhibitor DETPA plugged the cores,
only heat-up and cool-down of the test. The maximum while in HCl, the DETPA did not increase the break-through
allowable corrosion rate recommended for these test volume. These data are significant because there are
conditions is 0.05 lb/ft2 with no unacceptable pitting. proposals16 suggesting that scale inhibitors (SCI) be added to
Acceptable pitting is represented by a pitting index (PI) of 3 or scale dissolution fluids.
less. The Pitting Index (PI) is described as follows. Test The other additives generally had less effect than the
results are shown in Figures: SCI’s. The inhibitors and surfactants had no effect on the V (bt)
or the core weight loss. EGMBE and methanol had the most
influence in the chelant fluid, especially at high
Description Pitting concentrations. Note that EGMBE is not soluble in this fluid at
Index room temperature, so it may be causing a two-phase fluid to
None 0 be present. Figure 10 shows the inlet core wormholes for
Minor edge corrosion 1 several of the fluids. The surface-active agents changed the
Pitting on edge only 2 entrance hole form conical to a dominant, flat hole in HCl.
pin point pits on surface <25 3 The scale inhibitor DETPA did not increased the size of the
pin point pits on surface >25 4 entrance hole (similar effect to F0), but EGMBE did increase
the size of the hole. There was no visual effect on the
N80 and 13% Cr steel test coupons measured wormholes formed in the chelant fluids with the exception of
approximately one inch in width and 1.75 inches in length and DETPA, which prevented formation of any wormholes.
were machined from sections of oilfield grade steel. Coupons
were bead blasted to remove mill scale. No additional surface Tests Using KCl on Sandstone and Limestone Cores.
polishing or treatment was done prior to the test. All coupons Figure 7 shows the results of tests with KCl injected into
were numbered for identification. Prior to use, the coupons sandstone or limestone. Most of the additives had minimal
were cleaned, rinsed in acetone, dried and weighed. After effect on the core permeability. Exceptions were KCl (with no
exposure, the coupons were cleaned as above and reweighed additives), which damaged the limestone core and high
to determine the rate of corrosion. concentrations of F3, which damaged the low perm sandstone
core.
Results and Discussion
Tests Using Limestone and Marble. These tests were Corrosion Inhibition Comparison. The tubulars present in a
conducted to simulate treatments of carbonate formations. well often dictate the inhibited acid system required to achieve
Rotating disk kinetic tests using marble were run in 7.5% HCl acceptable inhibition. The tendency of the high chrome steels
and 20% Na3HEDTA. Table 2 and Figure 5 show the to corrode excessively in hydrochloric acid compared to N80
formulations and the calculated reaction rates. All were steel and the effect of high chloride content on the integrity of
measured at 600 rpm. The phosphonates increased the the steel may result in the selection of lower strength acids.
dissolution rates of some of the fluids and decreased the rates The corrosivity of 15% HCl and the chelating agent,
of other fluids. The surfactants and inhibitors increased some sodium HEDTA (pH 2.5 and 4), were tested at 300°F for a
of the dissolution rates. We would not expect much changes to protection time of 6 hours in contact with N80 and 13% Cr
the measured reaction rates in 7.5% HCl at 150 oF because the steel. As shown in Figure 11, acceptable inhibition of 15%
rate will be diffusion-limited at this rotation rate. Using the HCl is easily achieved. The recommended inhibitor
data from Lund17 the surface reaction rate of 7.5% HCl (2.1 concentration is moderately high: requiring 1.0% Inh. A1 and
m) should be 1.58 x 10-4 mole/cm2/sec at 25 oC and 5 x 10-3 1.0% or 4.0% Inh. Aid C for the inhibition of the N80 or 13%
mole/cm2/sec at 65 oC. Some of the surface-active agents Cr, respectively. The effect of additives typically used in
seemed to increase the rates at 65 oC. These fluids decrease acidizing applications can also affect inhibitor performance
the surface tension, and thus may decrease the thickness of the resulting in moderately higher corrosion rates. Corrosion
boundary layer. None of the additives significantly decreased inhibition at 400°F is also possible for 15% HCl; however,
the reaction rates in HCl. In HEDTA, several of the agents inhibitor concentrations have to be dramatically increased and
(especially the phosphonate) reduced the rates at 65 oC. the exposure time limited to one hour or less for this acid
Core flood tests were run in HCl, KCl and in Na3HEDTA. system (data not reported in this document).
The HCl and KCl tests were performed at 150 oF. The two The inhibition of sodium HEDTA (pH 2.5 and 4) for
fluids were tested to determine the effects of the additives oilfield applications is much more easily achieved than the
during stimulation (HCl) and non-stimulation (KCl) hydrochloric acid systems and does not have the high
conditions. Sodium HEDTA (pH 4) was tested only at 350 oF. concentration of chloride ion found in HCl. For chelant
The effects of the additives depended on the fluid and systems, different inhibitor chemistry (A2) is required, and we
chemical structure of the additive. See Figures 6-9. The are able to use lower inhibitor concentrations. The inhibition
4 W. W. FRENIER AND D. G. HILL SPE 73705

of sodium HEDTA at pH 2.5 and 4 are illustrated at 300°F, as solutions can be inhibited to higher temperatures, and
shown in Figures 12 and 13, respectively. Corrosion tests in with less inhibitor, compared with HCl. More studies are
this system with several acidizing additives, produced required to define the mechanisms of action in the
corrosion rates less than 0.01 lb/ft2 for 6 hours exposure time. presence of the various additives.
Corrosion rates are moderately higher at pH 2.5 as compared
to the pH 4 fluid. The additive EGMBE caused the most Acknowledgements.
change on corrosion inhibition in this system. With the The authors wish to acknowledge the assistance of Dawn
exception of EGBME, the corrosion observed for the N80 and Alamia, Andre Roberson, Tuan Nguyen, Melissa Raney and
13% Cr steels were approximately the same. Marieliz Garcia, who performed many of the lab experiments.
Inhibition of the sodium HEDTA (pH 2.5 and 4) fluids at We also appreciate the support from Schlumberger Oilfield
400°C is also possible for the N80 and 13% Cr steels (Figures Services and their permission to publish this report.
14 and 15). Corrosion rates observed for the pH 2.5 fluids are
dramatically higher than for the pH 4 fluids with most of the References
additives included in this study. With few exceptions, 1. Frenier, W. W. and Growcock, F., “Inhibitors for Chemical
corrosion rates greater than the maximum allowable corrosion Cleaning Solvents: recent Literature,” In Reviews of Corrosion
Science and Technology, A. Raman and P. Labine, Eds, HACE,
rate of 0.05 lb/ft2 were measured. Corrosion rates for the
Houston, (1992)
chelant at pH 4.0 are greater than observed at 300°F but 2. Ali, S. L and Hinkel, J. J., “Additives in Acidizing Fluids,” in
remain below 0.02 lb/ft2. The additive that exhibited the Reservoir Stimulation, 3rd Edition, M. Economidies and K.
greatest effect was F1. This material is an amphoteric Nolte, Eds, 15-1, John Wiley, and Sons, N. Y. N.Y (2001)
surfactant, and may undergo hydrolysis at these extreme (400 3. Gidley, John L., “Stimulation of Sandstone formations with the
o
F) temperatures. EGMBE allowed acceptable rates to be Acid-Mutual Solvent Method”, J. Pet. Tech., pp 551-558, (May
observed. These results may be influenced by the solubility 1971).
(or change in solubility) of F1 and EGMBE (or reaction 4. Gidley, J. L., et al., “A Field Study of Sandstone Acidizing”,
products) at these temperatures. SPE 5693, presented at AIME Symposium on Formation
Damage Control, Houston, TX, Jan 29-30, 1976.
5. Sutton, G. D., and Lasater, R. M., “Aspects of Acid Additive
Conclusions Selection in Sandstone Acidizing”, SPE 4114 (1972)
1) Acid additives that are highly soluble in the stimulation 6. Hall, B. E., “The Effect of Mutual Solvent Adsorption in
fluid have minimal affect on the performance of the fluid Sandstone Acidizing,” J. Petro. Tech, 1399- 1442, December
or on formation damage. Surfactants, corrosion inhibitors (1975)
and low concentrations of alcohols have little impact on 7. Crowe, C. W., and Minor, S. S., “Effect of Acid Corrosion
the outcome of the stimulation process. While there is Inhibitors on Matrix Stimulation Results”, J. Petro. Tech., 1853-
some insoluble material in the corrosion inhibitors, there 1865 (1985)
was no effect on the fluid stimulation properties. 8. King, J. E., “Adsorption and Chlorination of Mutual Solvents
Used in Acidizing”, SPE 14432 (1985).
2) Additives that adsorb strongly on the mineral being 9. Smith, C. F., et al., “Acid Corrosion Inhibitors – Are We Getting
treated or are sparingly soluble in the test fluid may have What We Need?” SPE 5644 (1975).
a major effect on the fluid performance. Large amounts of 10. Jasinski, R., et al., “Inhibiting HCl Corrosion of High Chrome
mutual solvents or large amounts of scale inhibitors Tubular Steels,” NACE Corrosion 1988, # 188 (1988)
increased the breakthrough volume or plugged the 11. Nasr-El-Din, H. A., et al., “Investigation of Sulfide Scavengers
limestone core in the chelating solvent. The mutual in Well Acidizing Fluids, “ SPE 58712 (2000)
solvent was the only material that greatly affected HCl. 12. Dabbousi, B. O., et al., “Influence of Oilfield Chemicals on the
While this test is not directly applicable for scale removal Surface Tension of Stimulating Fluids,” SPE 50732 (1999)
from a sandstone core, the results emphasize the necessity 13. Frenier, W. W., “Novel Scale Removers Are Developed for
Dissolving Alkaline Earth Deposits,” SPE 65027 (2001).
of careful testing of all acid additives. 14. Frenier, et al., Hydroxyaminocarboxylic Acids Produce Superior
3) We found very little affect of any of the additives on Formulations for Matrix Stimulation of Carbonates SPE 68924
sandstone when flooded with KCl. (2001)
4) Kinetic tests as well as core flood tests are required to 15. Frenier, et al., Hydroxyaminocarboxylic Acids Produce Superior
characterize the effect of the additive. However, RD tests Formulations for Matrix Stimulation of Carbonates at High
using very reactive fluids (HCl) may not be predictive Temperatures, SPE 71696 (2001)
unless very high rotation rates are achieved to reveal the 16. Smith, P. S., and Clement, C. C., “Combined Scale Removal and
effect on the surface-reaction rates. Scale Inhibition Treatments, SPE 60222 (2000)
5) We have demonstrated the effect of several additives on 17. Lund, K., et al., “Acidization-II. Dissolution of Calcite in
Hydrochloric Acid,” Chemical Eng. Sci., 30, 825-835 (1975)
corrosion inhibition in HCl fluids. The chelating agent
SPE 73705 EFFECT OF ACIDIZING ADDITIVES ON FORMATION PERMEABILITY DURING MATRIX TREATMENTS 5

OH
O
Ethyleneglycol monobutyl ether

N CH2

Cl
O
O

OH

Benzylquinolinium chloride Dipropyleneglycol methyl ether

(O-CH2CH2) n-OH

Linear alcohol ethoxylate

O
(O-CH2CH2) n O S O

O
Linear alcohol ethoxysulfate, ammonium salt NH4

CO2Na

H CH CH PO3Na2

CO2Na n
Phosphonocarboxylic acid polymer

O O
O
(OH)2P P(OH)2 P(OH)2
O N N O
NH
(OH)2P P(OH)2

Diethylenetriamine pentamethylene phosphonic acid

Fig. 1 - Structures of Agents

6 W. W. FRENIER AND D. G. HILL SPE 73705

Rotating Disk
z Hydrodynamics are well defined
z Disk surface is uniformly accessible

Rotating Disk RA = ν kr [(Cs)n - (Cps)m /Keq ]

Reaction Rate
Limited

ite sfer
RA

Lim Tran
d
ss
RA = Kmt (Cb - Cs)

Ma
Acid
1
ω 2

Fig. 2- Description of rotating disk and controlling equations

N2 source
Transfer flask

N2

N2 bleed

N2 inlet

Back Pressure Regulator

Fluid inlet
Fluid outlet
Fluid inlet
N2 outlet
N2 inlet Fluid sample

Control Rupture disk

Thermocouple

Thermal
well
Dip
Reactor tube

PTFE liner Disk

(very corrosive only) Inlet pump
Drain valve
Fig. 3- Modified Parr reactor used with rotating disk holder for reaction kinetic tests
SPE 73705 EFFECT OF ACIDIZING ADDITIVES ON FORMATION PERMEABILITY DURING MATRIX TREATMENTS 7

A R C C o re T e s te r
C o m p u te r a n d c o n tro lle r

N2

B ack
Is c o P u m p p re s s .
R eg.
F lu id
A c c u m u la to r

W a s te A c c u m u la to r
T e s t flu id C o re in h e a te d
o r b rin e
N2
C o n fin in g P re s s u re h o ld e r

Fig. 4- Core Flood (Acid Reaction Curve) Tester

20% HEDTA, 20 C
Calcite Dissolution Rates 20% HEDTA, 65 C
600 RPM, RD 7.5% HCl, 20 C
1.0E-03 7.5% HCl, 65 C
Rate (mol Ca/cm2/ssec)

1.0E-04
1.0E-05
1.0E-06
1.0E-07
1.0E-08
1.0E-09
F0

F3
h
/A

PA

BE
PA

In
N

ET

M
PC

5%

4%
4%

EG
D

0.

0.
5%

0.
5%

5%
7.
7.

Additive

Fig. 5. Summary of RD dissolution rates. The inhibitor for HCl is “A1” and for HEDTA, “A2”
8 W. W. FRENIER AND D. G. HILL SPE 73705

Effect of Aditives on Acidizing PV Bt

15% HCl, 150 F Wt loss
6
5
4
Value

3
2
1
0
F3 l F5 F0
n e A1 S1 no BE TPA
no 4% 5% M h a M 5% 5 %
DE
0. 0. 5% et EG 0. 0.
+ + M % + + 5%
A1 A1 % 10 A1 A1 7.
% % 40 1
+ % % 1
+
4 4 + 4 4
0. 0. A1 %
A 0. 0. %
A
4 4
4% 0. 0.
0. Additives

Fig. 6 Effect of Acidizing Agents on Limestone at 150 F. 5 mL/min flow rate. 15% HCl

Formation Damage at 150 F

2% KCl

25
% Damage

20
15 Limestone
10 Sandstone
5
0
p)
5% hp)
5% F3

p)
F3

5
BE
F3 )

EG )
(lp

5% (lp

no % F

(h
(m

5% 1 (l

M
(
%
1%

F3

F0

d,
F0

F
25

5
ad
0.

0.
5
0.

0.
5%
0.

0.
0.
0.

Additive

Fig. 7 Core flood tests using 2% KCl, 150 F. Null data indicates no effect
SPE 73705 EFFECT OF ACIDIZING ADDITIVES ON FORMATION PERMEABILITY DURING MATRIX TREATMENTS 9

Effect of Additives on Stimulation

20% Na3HEDTA pH 4, 350 F

30
25
Additive

20
PV (bt)
15 Plugged
10 Wt. Loss, g
5
0
4% 2, 5 BE

PA
F1

F4

F0
PM
EG 2

S1

l
2
e

no
F
A
on

M
M

ET
%

5%
D

ha
4%

%
N

4% 4% 0.5

40 0.5
%

D
5

et

0.
0.

0.

10

5%
M
0. 5%

1,

2,

2,
2,

%
2,

A
A

7.
A

2,

A
4%

4%
4%

+
4%

2
2,
0.

0.

0.
4%

A
0.

A
0.

4%
0.

0.
0.

Value

Fig. 8 Effect of Acidizing Agents on Limestone at 350 oF, 5-mL/min-flow rate. 20% Sodium HEDTA, pH 4.0

Core Flood with 20% Na3HEDTA/pH 4/350 F

400
0.4% A2
350
300 No adds.
250
Perm, md

0.4% A2 + 0.5% F3
200
150 0.4% A + 5%
100 EGMBE
0.4% A2 + 5%
50
MS1
0
55 60 65 70 75 80 85
Time, minutes

Fig. 9 Breakthrough curves for 20% NaHEDTA, pH 4, 5 mL/min. Limestone cores

10 W. W. FRENIER AND D. G. HILL SPE 73705

Fig. 10. Photos of inlet wormholes of limestone cores treated in tests of Figures 6 and 8.

Corrosion Inhibition of Hydrochloric Acid

15% HCl - 300F - 6 hours
Inhibitor Concentration
N80: 1.0% Inh A1 + 1.0% Inh Aid C

0.050
N80 13% Cr
0.040
Corrosion Rate (lb/ft2)

0.030

0.020

0.010

0.000
None 0.5% Add F0 0.5% Add F3 0.5% Add F1 5% EGMBE 5% DPM
Additive

Fig. 11. Effect of additives in 15% HCl, 300 oF

SPE 73705 EFFECT OF ACIDIZING ADDITIVES ON FORMATION PERMEABILITY DURING MATRIX TREATMENTS 11

Effect of Additives on Corrosion Inhibition

Sodium HEDTA (pH 4) - 300F - 6 hours

Inhibitor Concentration
N80 and 13% Cr: 0.2% Inh A2
0.050
N80 13% Cr

0.040
Corrosion Rate (lb/ft2)

0.030

0.020

0.010

0.000
None 0.5% Add F0 0.5% Add F3 0.5% Add F1 5% EGMBE 5% DPM
Additive

Fig. 12. Effect of additives in Na3HEDTA, 300 oF

Effect of Additives on Corrosion Inhibition

Sodium HEDTA (pH 2.5) - 300F - 6 hours

Inhibitor Concentration
N80 and 13% Cr: 0.4% Inh A2
0.09

0.08 N80 13% Cr

0.07
Corrosion Rate (lb/ft2)

0.06
0.05
0.04
0.03
0.02

0.01
0
None 0.5% Add F0 0.5% Add F3 0.5% Add F1 5% EGMBE 5% DPM
Additive

Fig. 13. Effect of additives in Na3HEDTA, 300 oF

12 W. W. FRENIER AND D. G. HILL SPE 73705

Effect of Additives on Corrosion Inhibition

Sodium HEDTA (pH 4) - 400F - 4 hours

Inhibitor Concentration
N80 and 13% Cr: 0.4% Inh A2
0.10
0.09 N80 13% Cr
0.08
Corrosion Rate (lb/ft2)

0.07
0.06
0.05
0.04
0.03
0.02
0.01
0.00
None 0.5% Add F0 0.5% Add F3 0.5% Add F1 5% EGMBE 5% DPM
Additive

Fig. 14. Effect of additives in Na3HEDTA at 400 oF

Effect of Additives on Corrosion Inhibition

Sodium HEDTA (pH 2.5) - 400F - 4 hours
Inhibitor Concentration
N80 and 13% Cr: 0.8% A2
0.18
0.16 N80 13% Cr

0.14
Corrosion Rate (lb/ft2)

0.12
0.1
0.08
0.06
0.04
0.02
0
None 0.5% Add F0 0.5% Add F3 0.5% Add F1 5% EGMBE 5% DPM
Additive

Fig. 15. Effect of additives in Na3HEDTA at 400 oF

SPE 73705 EFFECT OF ACIDIZING ADDITIVES ON FORMATION PERMEABILITY DURING MATRIX TREATMENTS 13

Table 1- Description of Additives

DETPA Diethylenetriaminepentamethylene phosphonic acid
PCPA Poly carboxyphosphonate
Inhibitor A1 Mixture of quinoline quats and acetylenic alcohols
Inhibitor A2 Mixture of nitrogen quats and sulfur compounds
Inhibitor Aid C Formic Acid
Additive F0 Alcohol ethyoxylates and perfluoro compound
Additive F1 Amphoteric surfactant mixture
Additive F3 Formulated blend of ethoxylated alcohols
Additive F4 Ammonium alcohol ethoxysulfate and ethoxylated alcohols
Additive F5 Formulated blend of ethoxylated alcohols
Mutual Solvent MS1 Formulated blend of alcohol ethoxylates and EGMBE
EGMBE Ethyleneglycol monobutyl ether
DPM Dipropyleneglycol methyl ether

Table 2- Dissolution of Marble at 600 rpm and 500 psig

Primary fluid 20% Na3HEDTA/pH 4 20% Na3HEDTA/pH 4 7.5% HCl 7.5% HCl
Temperature RT (~20 oC) 65 oC RT (~20 oC) 65 oC

Additive Rate (mol Ca/cm2/sec) Rate Rate Rate

N/A 2.6E-09 6.0E-07 3.2E-05 1.0E-04
7.5% DETAP 3.3E-09 3.0E-07 1.0E-05 1.0E-04
7.5% PCPA 6.8E-07 6.0E-07 2.9E-05 9.0E-05
0.4% Inh. N/a 1.0E-06 2.0E-05 3.0E-04
0.5% F0 N/a 1.0E-06 2.0E-05 2.0E-04
0.4% F3 N/a 9.0E-07 2.0E-05 2.0E-04
5% EGMBE N/a 1.0E-06 2.0E-05 1.0E-04