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AbstractBecause the world demand for energy is expected to continue growing, exploration is turning to deeper and high-temperature

reservoirs. Such reservoirs include fields with high bottomhole static temperatures (BHSTs), such as the Ursa (250F) andThunder Horse (280F) in Gulf of Mexico (GOM). Acid stimulation of such reservoirs at high temperature is a challenging

task. Emulsified acid systems are expected to perform better in reservoirs with BHSTs ranging from 275 to 375F compared to

nonretarded acids and gelled acid systems. However, fluid stability and the inhibition of corrosion are major challenges toovercome for successful implementation of this technology. Emulsion instability and the corrosion rate are interrelated, and

both increase with higher temperature. Also, fluid stability decreases as a result of corrosion of the metal surfaces. At the same

time, an excessive addition of corrosion inhibitor destabilizes the fluid system. Hence, the proper selection and balancebetween the corrosion inhibitor and emulsifiers are required. Three different types of corrosion inhibitors were evaluated, and

an emulsified system was designed with proper optimization of various ingredients, including corrosion inhibitor, an

intensifier, and a cationic emulsifier. The system was tested for stability and corrosion loss with static corrosion test using P-

110 coupons. After reviewing the literature, it is believed that this emulsified system is the only one to pass static corrosiontests at 275F for 4 hr and remain stable at 300F for 2 hr with 28% acid strength. This enables the acid stimulation of

carbonate reservoirs having BHSTs up to 300F while reducing the corrosion rate. As per the study, the effect of the intensifier

was different to that found in plain acid, suggesting possible interactions of the additives with the emulsifier. Because fluid

stability and the rate of corrosion are interrelated, they should be evaluated together, especially for designing emulsified acidsystems for stimulation of very high-temperature carbonate reservoirs.

IntroductionAcid is predominantly used to remove damage near the wellbore and to stimulate the well, which in turn improves the rate of

hydrocarbon production (Sayed et al. 2012). In a carbonate reservoir, acid is mainly used to create linear flow for acid

fracturing and to create wormholes. An emulsified acid is mainly used for matrix acidizing because it lowers the diffusion rateby two orders of magnitude. The first reduces the acid transfer rate, caused by an increase in the viscosity of the fluid. The

second disperses the acid phase into the oil, which results in a slow reaction when it contacts the carbonate reservoir (Buijse

and Vandolmen 1998). When using emulsified acid, the inhibitor components adsorb to the metal surface and can undergo

polymeric-type film forming on the metal surface because of reactions initiated by the hydrogen radicals (Navarrete et al.

2000). The corrosion inhibitor system is selected based on the metallurgy, acid type, acid concentration, temperature, and theexposure time. Most corrosion inhibitors are organic compounds containing nitrogen, sulphur, and oxygen and are selected

based on the desired application temperature range (Rostami and Nasr-El-Din 2009). It is observed that a higher dosage of

corrosion inhibitor leads to destabilization of the emulsified acid system (Hill and Jones 2003). Even at high temperatures,emulsified acid becomes destabilized because of the release of corrosion products (Fe

+2, etc.). The unstable emulsion then

behaves as a plain acid (Sabhapondit et al. 2012). Hence, the proper corrosion inhibitor system should be selected carefully for

an emulsified acid system. The inhibition action is dependent on various factors, such as solubility in acid. If the solubility is

very low, then the acid phase cannot carry the corrosion inhibitor to the target location under downhole conditions. If thesolubility is too high, then adsorption of the corrosion inhibitor might not occur on the metal surface. Both of these conditions

lead to high corrosion losses. Mutual solvents, as well as the ionic nature of the surfactant used to provide chemical

compatibility, can also over-solubilize the corrosion inhibitor, which leads to excessive corrosion. As a result, corrosion testsare conducted to identify any performance issues related to other chemicals added into the emulsified acids (Pandya et al.

IPTC 16452

A Novel Emulsi fied Acid System for St imulat ion of Very High-Temperature

Carbonate ReservoirsNisha Pandya and Sushant Wadekar, Halliburton

Copyright 2013, International Petroleum Technology Conference

This paper was prepared for presentation at the International Petroleum Technology Conference held in Beijing, China, 2628 March 2013.

This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, aspresented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarilyreflect any position of the International Petroleum Technology Conference, its officers, or members. Papers presented at IPTC are subject to publication review by Sponsor SocietyCommittees of IPTC. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the International Petroleum TechnologyConference is 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 conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax +1-972-952-9435


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IPTC 16452 3

(a) (b) (c)

Fig. 1(a) Stable emulsion, (b) bottom water separation (destabilized emulsion), and (c) bottom water and top oil separation(destabilized emulsion).

Results and Discussion

Comparative Study of I-G, I-N, and I-C. Emulsion stability testing was carried out in an HP/HT visual cell using three

different corrosion inhibitors (I-G, I-N, and I-C) at 275F for 3 hr. The effect the concentration of these corrosion inhibitors

had on the stability of the emulsified acid is shown in Table 1.The experimental data indicated that higher dosages (20gal/1,000 gal and above) of corrosion inhibitors decrease the stability of the emulsified acid system for high-temperature

applications. The destabilization of the emulsion by I-N and I-C was found to be lower than I-G. These corrosion inhibitors

contain various solvents (e.g., methanol, isopropanol) as well as surfactants that solubilize the water-insoluble materials, suchas cinnamaldehyde, benzaldehyde, etc. The surfactants interfere with the emulsifier action by shifting the overall HLB value ofthe system from the required set value.

TABLE 1CEA TEST RESULTS OF 28% HCl EMULSIFIED ACID IN STA AT 275F

AND 1,000 PSI (IN ABSENCE OF ALLOY SPECIMEN):

EFFECT OF DIFFERENT INHIBITORS

Sr.No.

Time,hr

Emulsifier,gal/1,000 gal Corrosion Inhibitor Emulsion Stability

1 3 10 Nil Stable

2 3 10 I-G (10 gal/1,000 gal) Unstable

3 3 10 I-C (10 gal/1,000 gal) Stable

4 3 10 I-N (10 gal/1,000 gal) Stable

5 3 10 I-C (20 gal/1,000 gal) Unstable6 3 10 I-N (20 gal/1,000 gal) Unstable

7 3 10 Methanol (3.5 gal/1,000 gal) Unstable

Effect of I-G on the Emulsified Acid System. The effect of the concentration of I-G on the stability of the emulsified acid

system at 275F is shown in Table 2.The test data indicated that higher concentration (25 gal/1,000 gal) of emulsifier is

required to stabilize the emulsified acid system containing 10 gal/1,000 gal of I-G. This indicates that the components present

in I-G also absorbed at the interface between diesel and acid. These components compete with the emulsifiers for absorption atthe interface. At lower concentrations of emulsifier, a weak interfacial film formed as a result of the increased proportion of

the components of I-G at the interface. At higher concentrations of emulsifier, a stable interfacial film formed as a result of a

sufficient amount of surfactants present at the interface. The stability of the emulsified acid system was also affected by theuse of additional corrosion inhibitor intensifiers IN-O and IN-H. These intensifiers are charged molecular species that interfere

in the action of cationic emulsifiers. I-G can be used up to 250F with acceptable corrosion loss (Table 3). The use of

additional corrosion inhibitor intensifier did not result in further improvement. I-G cannot be used at 275F because of

instability of the emulsion.


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4 IPTC 16452

TABLE 2TESTS IN STA WITHOUT COUPON AT 275F WITH I-G

Sr.

No.

Time,

hr

I-G,

gal/1,000 gal

IN-H,

lbm/1,000 gal

IN-O,

gal/1,000 gal

Emulsifier,

gal/1,000 gal Emulsion Stability

1 3 10 0 0 10 Unstable

2 3 10 0 0 20 Unstable

3 3 10 0 0 25 Stable

4 6 10 0 0 25 Unstable

5 3 10 10 40 25 Unstable

TABLE 3EFFECT OF TEMPERATURE ON EMULSION STABILITY AND CORROSION LOSS FOR P110 AL LOY INPRESENCE OF I-G IN EMULSIFIED 28% HCl ACID

Sr.No.

Temp.,F

Time,hr

I-G,gal/1,000 gal

IN-H,lbm/1,000 gal

IN-O,gal/1,000 gal

Emulsifier,gal/1,000 gal

Corrosion Loss,lbm/ft

2

EmulsionStability

1 250 3 10 25 0.037 Stable

2 250 4 10 25 0.23 Unstable

3 250 4 10 5 40 25 0.11 Unstable

4 250 4 20 5 40 20 0.1 Unstable

5 275 3 8 5 40 12 0.406 Unstable

6 275 4 8 5 40 12 0.5785 Unstable

7 275 3 8 5 40 20 0.9 Unstable

8 275 3 8 5 40 20 No coupon Unstable

9 275 3 10 5 40 25 0.321 Unstable

Effect of I-N on the Emulsified Acid System. The stability of the emulsified acid system and corrosion are interrelated

phenomenon. As corrosion progresses, corrosion products, such as Fe+2

, enter into the solution, which can cause emulsion

instability. If a corrosion inhibitor cannot provide enough of an inhibition effect, then the stability of the emulsion alsodecreases. This reduces any additional inhibition effect of the emulsified acid system because of the barrier for direct contact

between the acid and metal surface. As a result, corrosion becomes faster and the emulsion becomes unstable, even though a

corrosion inhibitor is not directly interfering in the stability of the system. The same effect was shown by I-N (Table 4).I-Ncan be used at 250F for 4 hr. For higher temperatures (275 and above), the inhibition effect of I-N becomes lower or lesser

because of a higher corrosion rate at higher temperatures. This results in breaking of the emulsion with higher corrosion loss.

TABLE 4EFFECT OF TEMPERATURE ON EMULSION STABILITY AND CORROSION LOSS FOR P110 AL LOY INPRESENCE OF I-N IN EMULSIFIED 28% HCl ACID

Sr.No.

Temp.,F

Time,hr

I-N,gal/1,000 gal

IN-H,lbm/1,000 gal

IN-O,gal/1,000 gal



2

EmulsionStability

1 250 3 10 10 40 14 0.0317 Stable

2 250 4 12 10 40 16 0.04424 Stable

3 275 3 8 10 40 12 0.2373 Unstable

4 275 3 17 30 40 22 0.21 Unstable

5 275 3 20 30 40 25 0.1 Unstable

6 275 3 20 0 40 25 0.1685 Unstable

7 275 3 25 0 40 30 0.0973 Unstable

Effect of I-C on the Emulsified Acid System.The effect of I-C on the stability and corrosion loss of 28% emulsified acid is

shown in Table 5.It displayed a similar effect on the stability and corrosion loss as I-N. With an increase in temperature, boththe instability of the system and corrosion became faster, resulting in higher corrosion loss. The effectiveness of the corrosion

inhibitor is another factor that becomes critical in this case. A higher concentration of corrosion inhibitor normally destabilizes

the system. Hence, there is a limit to the maximum concentration of corrosion inhibitor, above which the emulsion becomes

unstable. The balance between corrosion inhibition and stability can be properly adjusted if the corrosion inhibitor showsmaximum inhibition at minimum concentration. Therefore, I-C is a more effective corrosion inhibitor than I-N because the


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IPTC 16452 5

temperature limit of the emulsified acid can be increased to 275F using I-C as the corrosion inhibitor. As I-C is a cationic

corrosion inhibitor, its destabilizing effect on the emulsified acid system was reduced by using ionic intensifiers, such as IN-O

and IN-H. Corrosion inhibition was achieved up to 4 hr at 275F using I-C.

The system was stable at 300F for 2 hr. This enables the acidizing of carbonate reservoirs with BHSTs up to 275F usingan emulsified acid system.

TABLE 5EFFECT OF TEMPERATURE ON EMULSION STABILITY AND CORROSION LOSS FOR P110 AL LOY INPRESENCE OF I-C IN EMULSIFIED 28% HCl ACID

Sr.No.

Temp.,F

Time,hr

I-C,gal/1,000 gal

IN-H,lbm/1,000 gal

IN-O,gal/1,000 gal



2

EmulsionStability

1 250 6 8 10 40 12 0.0238 Stable

2 275 3 8 10 40 12 0.0458 Stable

3 275 3 8 0 40 12 0.039 Stable

4 275 4 8 0 40 12 0.16 Unstable

5 275 3 8 0 60 12 0.234 Unstable

6 275 3 8 0 20 12 0.161 Unstable

7 275 3 20 30 20 25 0.148 Unstable

8 275 4 8 60 40 12 0.050 Stable

9 275 6 12 15 40 20 0.449 Unstable

10 275 6 12 15 40 25 0.425 Unstable

11 300 2 8 40 40 12 Without coupon Stable

12 300 2 8 0 40 12 Without coupon Stable

ConclusionsOn the basis of the analysis presented, the following conclusions were drawn:

Three corrosion inhibitors, I-G, I-N, and I-C, were compared for their effect on the stability of an emulsified acidsystem. I-G showed more destabilization effects than I-N and I-C.

I-G can provide corrosion protection up to 250F in an emulsified acid system without affecting the stability of thesystem.

I-N showed corrosion inhibition up to 250F in an emulsified acid system.

I-C showed better corrosion inhibition than I-G and I-N in an emulsified acid system. I-C can be used up to 275Fwithout affecting the stability of the system.

A stable emulsified acid system was designed that passed the corrosion test at 275F for 4 hr and was also stable at300F for 2 hr.

This system enables the stimulation of carbonate reservoirs with BHSTs in the range 250 to 275F. This study is veryuseful for designing emulsified acid systems for high-temperature applications.

AcknowledgmentsThe authors thank Halliburton for permission to publish this research.

ReferencesBuijse, M.A. and Van Domelen, M.S. 1998. Novel Application of Emulsified Acids to Matrix Stimulation of Heterogeneous Formation.

Paper SPE 39583 presented at the SPE Formation Damage Control Conference, Lafayette, Louisiana, USA, 1819 February. doi:

10.2118/39583-MS.Hill, D. and Jones, A. 2003. An Engineered Approach to Corrosion Control During Matrix Acidizing of HTHP Sour Carbonate Reservoir.

Paper NACE 03121 presented at Corrosion 2003, San Diego, California, USA, March.

Navarrete, R.C., Holms, B.A., McConnell, S.B., and Linton, D.E. 2000. Laboratory, Theoretical and Field Studies of Emulsified AcidTreatment in High-Temperature Carbonate Formation. SPE Prod. & Fac.15(2): 96106.

Pandya, N., Wadekar, S., and Cassidy, J. 2012.A Unique Emulsified Acid System with Three Intensifiers for Stimulation of Very High

Temperature Carbonate Reservoirs. Paper SPE 163308 presented at Kuwait International Petroleum Conference and Exhibition,Kuwait, 1012 December. doi: 10.2118/163308-MS.

Rostami, A. and Nasr-El-Din, H.A. 2009.Review and Evaluation of Corrosion Inhibitors Used in Well Stimulation. Paper SPE 121726presented at SPE International Symposium on Oilfield Chemistry, The Woodlands. Texas, USA, 2022 April. doi:10.2118/121726-MS.

Sabhapondit, A., Vielma Guillen, J.R., and Prakash, C. 2012. Laboratory Optimization of an Emulsified Acid Blend For Stimulation of High

Temperature Carbonate Reservoir. Paper SPE 150337 presented at the North Africa Technical Conference and Exhibition, Cairo,

Egypt, 2022 February. doi: 10.2118/150337-MS.


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Sayed, M.A., Nasr-El-Din, H.A., Zhou, J., Holt, S., and Al-Malki, H. 2012. A Novel Emulsified Acid System to Stimulate Carbonate

Reservior. Paper SPE 151061 presented at the Formation Damage Control Conference, Lafayette, Louisiana, USA, 1517 February.

doi:10.2118/151061-MS.

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