Effect of Asphaltene Deposition on the Internal …proceedings.asmedigitalcollection.asme.org/.../ASMEP/89953/269_1.pdfThe purpose of this paper to describe the causes that enhance

International Pipeline Conference — Volume 1ASME 1996

EFFECT OF ASPHALTENE DEPOSITION ON THE INTERNAL CORROSION IN TRANSMISSION LINES

José L. Morales, Alfredo VllorlaINTEVEP, S.A.

Gerencia de Tecnología de Materiales Apartado 76343, Caracas

VENEZUELA

Carlos A. Palacios T.CORPOVEN S.A.

Gerencia de Ingeniería de Petróleo Puerto La Cruz, Los Teques

VENEZUELA

A B S T R A C T

Crude oil from Norte de Monagas field, in Venezuela, contains large amounts of asphaltenes, some of them are very unstable with tendency to precipitate. Because of liquid is carried over from the separation process in the flow stations, asphaltenes are also present in the gas gathering and transmission lines, precipitating on inner wall of pipelines. The gas gathering and transmission lines contain gas with high partial pressures of CO2 , some H2 S and are water saturated; therefore inhibitors are used to control the internal corrosion. There is uncertainty on how inhibitors perform in the presence of asphaltene deposition. To protect the pipelines from external corrosion, cathodic protection is used. Since asphaltenes have polar properties, there exists an uncertainty on whether it enhances asphaltene precipitation and deposition. The purpose of this paper to describe the causes that enhance asphaltene deposition on gas and some of the preliminary result from an ongoing research project carried out by Intevep and Corpoven.

Copyright © 1996 by ASME

IPC1996-1832

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IN T R O D U C T IO NIN T R O D U C T IO N -

Crude oil from Norte de Monagas field in Venezuela contains large amounts of asphaltenes, some of them are very unstable and with tendency to precipitate. They also have foaming characteristics. Asphaltenes are hydrocarbon constituents of crude oil, with high molecular weight. These polycyclic, aromatic substances are coloidally dispersed in the crude oil as it was shown by Thrower (1989).

Due to the foaming characteristics of the crude oil and a low efficiency of the oil/gas separation process of the separators in the flow stations, liquid carried over (crude oil) is often present in the gas gathering and transmission lines. Once this liquid is inside the gas lines, the asphaltenes present in this liquid may precipitate and deposit onto the inner wall of the pipelines producing the following operational problems as it was shown by Palacios and Moreno (1991).

Asphaltene deposition in gas pipelines is affected by mechanical, thermodynamic, chemical and electrical factors. Mechanical factors such as friction, shear forces and forces produced by the impact between asphaltene molecules cause pressure and temperature drops that affect the stability of the asphaltene molecule, resulting on precipitation. Thermodynamic factors [Kokal, 1995] include changes on pressures and temperatures caused by flow velocities, obstruction on the path of the flow caused by valves, changes in flow direction due to the different geometries on the pipeline. Chemical factors include changes in pH, solubility characteristics of the liquids, the presence of acids (Lichaa, 1977), (i.e. carbonic acid) the use of organic compounds, i.e. corrosion inhibitors.

Since asphaltenes have polar characteristics, they are influenced by the electrical behavior (Lichaa, 1977, 1975) fluids may have as they flow through pores such as in the reservoirs, but in the gas lines they may be influenced by the use of cathodic protection systems used for external corrosion control.

Corpoven, the operating company of the Norte de Monagas field, has established a number of asphaltene control methods (Palacios 1994, Marin 1990) including the development and application of a chemical additive, designed as an asphaltene dispersant and to remove the asphaltene deposits from gas pipelines. Another control method has been the modification of the internal components of oil/gas separators to increase their efficiency and thus reducing the amount of liquid carried over.

In addition to the above, there are potential corrosion problems in the gas gathering and transmission lines. The characteristics of the gas show that it is water saturated with a CO2 content of 6 to 7% and 25 to 35 ppm of H2 S. These conditions along with the average operating pressures (1,200 psi) of the gas lines, result on 75 to 90 psi of CO2 partial pressure and 0.03 to 0.038 psia of H2 S partial pressure; that in the presence of condensed water and light hydrocarbons, lead to potential internal corrosion problems.

Studies (Morales 1994, Palacios 1995) have shown that the main corrosion are flow induced localized corrosion (Stegmann, 1990), due to the presence of CO2 with superficial gas velocities, in some areas, as high as 30 m/s and with liquid holdup as high as 25,000 absolute barrels. Despite the presence of H 2 S, its contribution to produce SSCC is less, according to NACE MR-0175-95 (1995). Theoretical predictions (Morales 1994, Palacios 1995, Nace 1995) estimated that the C 0 2 corrosion rates range between 1 .3 -1 .53 mm/y (50 - 60 mpy).

From the above discussion, uncertainty still remains regarding the protection of the gas gathering and transmission lines where there exists asphaltene precipitation and deposition on the following issues: Do asphaltene deposits protect against internal corrosion?; How is the interaction between asphaltene deposits and the metal underneath?; Is the use of corrosion inhibitors affected by the asphaltenes?; Do they interfere with the precipitation or deposition of asphaltenes?; How is the behavior of corrosion inhibitors in the presence of the chemical additive used for asphaltene dispersion and removal?.


E X P E R IM E N T A L

A sphaltenes and Corrosion

To simulate in the laboratory the asphaltene precipitation process occurring in the gas gathering and transmission lines, a mixture having the same composition as the one found in this field, was prepared and its composition is listed in Table 1.

In order to study the corrosion behavior in the presence of asphaltenes, corrosion coupons were introduced in an autoclave in which they were exposed to the operational conditions and in the presence of the asphaltene mixture described above. The conditions of the tests were: CO2 partial pressure of 5bar (78 psi) and at a temperature of 42 °C (107 °F ). The coupons were made out of API-5LB pipe and exposed for a period 7 days. For these tests, corrosion rates were determined by weight loss.

TABLE 1. Asphaltene com position m ixture

C O M P O N E N T C O NTENT (% )WATER 60

n-HEPTANE 27CRUDE 6

ASPHALTENES 7

Tests were also performed to study the effects of asphaltene dispersant and n-heptane on the corrosion rates of the steel as well as inhibited corrosion rates.

Field tests were performed in a system designed as a 'by-pass corrosion field test facility’ to test all the gas segregations coming from different flow stations and compressing plants. This "by-pass" consists on a 50 m, 3 inch diameter test section, in which all the different gas mixtures mentioned before can be separately tested. In this test facility, corrosion rates are monitored using coupons located along the test section. An schematic diagram and photograph of this test facility are presented in figure 1.

Figure 1.-500 PSI

Photograph and Schem atic of the "By Pass Corrosion Field TestingF a c ility "


To study the effect of cathodic protection on asphaltene precipitation, crude oil containing asphaltenes was introduced on specially designed cells that were subjected to cathodic protection.

Inhibitors were also used in some of these cells to study the effect of asphaltene deposition in the presence of cathodic protection in crudes that were also treated chemically; For these kind of tests, the cells were subjected to the cathodic protection system for a period of eight (8) and thirty (30) days, after which the crude oil and liquid film adhered to the inside wall of the pipelines were analyzed for paraffines, asphaltenes and naphtenes. These analyses were performed with the idea that if cathodic protection had an influence on the precipitation of asphaltenes, the amount of asphaltenes present in the bulk solution of the crude oil should be less when compared to a cell containing the same crude oil but not exposed to cathodic protection.

R E S U L T S A N D D IS C U S S IO N

A s p h a lte n e s an d C o rro s io n

Figure 3 shows the corrosion rates for the API-5LB coupons immersed in water, water-crude oil, water- asphaltene dispersant and water n-heptane at CO2 partial pressure of 78 psi ant 107 °F . As shown in the figure, there is a decrease in corrosion rates for all the tests except for the water only test. These shows the inhibition characteristic of the crude oil as well as for the asphaltene dispersant . These tests also will serve as basis of comparison for the tests when inhibitors are used.

Figure 4 shows that when the asphaltene dispersant is present, the corrosion rates increase from 0.4 m m /y(16 mpy), for the nC7/crude/Asphaltene, to 0.7 mm/y (28 mpy). At this point one could speculate that in the presence of dispersant, asphaltenes are kept in solution, therefore they would not deposit onto the coupon allowing higher corrosion rates. Nevertheless, these values when compared to water only tests, corrosion rates decrease by almost two orders of magnitude.


Figure 5 shows how the different inhibitors decrease the corrosion rates. The concentrations shown in the figure were the optimal concentrations determined in previous tests. Inhibitors A' and 6 at a concentration of 60 ppm were the inhibitors that best performed under these conditions, reducing the corrosion rates to 0.05 mm/y (2 mpy). Figure 6 shows the efficiency of the inhibitors for the different conditions tested and it can be seen that for inhibitor B, the efficiency increases from 40 to 97%; on the other hand, the organic mixture alone shows a higher efficiency than any of the inhibitors used in a water only medium. This fact leads to think than the solely presence of asphaltenic crude oil, may decrease corrosion rates significantly.

Figure 7 compares the corrosion rates of inhibitors A and B, at the concentrations shown in figure 5, exposed in a water solution (3 % NaCI) and the organic mixture (nC7, asphaltene mixture, water, dispersant), and results from field tests. Coupons of the field test facility where exposed for two month at conditions.of total pressure of 82 bars (1,200 psi) and a temperature of 49°C (120°F). The gas segregation tested had inhibitor B being applied and asphaltenes present (from the liquid carried over); and under this condition the corrosion rate was 0.14 mm/y (5.5 mpy), while the inhibited corrosion rate tested in the laboratory was about 0.3 mm/y (12 mpy). In the field tests, it was noticed that the coupons had an asphaltene deposit covering its surface and therefore corrosion rates were lower than in the laboratory where an asphaltene deposit was only partially covering its surface.

Ycor(mntf>«i)

Figure 3. Corrosion Rates for the Reference Components.

Vcor (nun/year}

Figure 4. Corrosion Rates for the Different Mixtures.


J WATER ♦ nC7 + CRUDE ♦ ASPHALT «■ DISPER.

O :0 .6 - X 'o

c0.4 -,

$ to(4S ppm)

A B0 .2 - ( « ppm) (4S ppm)

B

oD

O (fio ppm) oY (60ppm)

Figure 5. Corrosion Rates for the Inhibitors Tested in the Presence of theA sphalten ic O rganic M ixture.

B ♦ Organic Mixture •

A ♦ Organic Mixture

Organic Mixrure

B + Waer

Figure 6. E ffic iency fo r the Inh ib itors Tested.

V cor (mia/ywi) Q T »!■ i i » a i i y

• FUI

Figure 7. Corrosion Rates for Inhibitors, from Laboratory and Field Tests.

< 5


Figure 8 shows results from the cathodic protection tests and its influence in asphaltene deposition. There are no significant differences in the amount of asphaltenes present in the bulk crude oil solution. The values of the amount of asphaltenes are between 1.93 to 2.02% for the eight day tests and 1.95 to 1.96% for the thirty day tests.

Paraffin, aromatics and naftenes analyses were performed to find out whether there were changes in the distribution of the different constituents of the crude oil due to the use of cathodic protection. In this case, the film of crude oil adhered to the inner wall of the test cells was also analyzed after each test. Results of this kind of tests are shown in Figure 9. The figure shows, there is an even distribution of the different constituents of the crude oil. Small differences in the amount of naftenes and aromatics are present, in the presence of an inhibitor. Since there was basically no difference in the naftenic and aromatic content of the samples tested, it could be concluded that cathodic protection did not have an influence on the deposition of asphaltenes.

Figure 8. Asphaltene Content After Exposure to Cathodic Protection.

Figure 9. Analyses of the D ifferent Com ponents of the Crude Oil for the DifferentM ix tu res Tested .


CO N C LU SIO N S

The presence of asphaltenes promotes a significant reduction on the corrosion rates. The mechanism by which asphaltenes deposit onto the inner wall of pipelines has not been determined yet; therefore, one can not predict how much of this deposit is actually covering the inner surface of pipelines nor the interaction between asphaltene deposits and the metal underneath.

The performance of the inhibitors tested in the presence of crude oils containing asphaltenes is improved.

Corrosion inhibitors do not seem to interfere with the precipitation or deposition of asphaltenes and the asphaltene dispersant used do not affect the inhibitor performance.

Cathodic does not influence the deposition of asphaltenes.

REFERENCES

Thaver R„ Nicoll D.C., Dick G.,1989, "Asphaltene Deposition in Production Facilities," SPE 18573, Houston, Tx., USA,

Palacios C.A., Moreno A., 1994, "Métodos de Control de Asphaltenos Empleados por Corpoven S.A. en al área Norte de Monagas," XI Jornadas de Gas, G.P.A., Caracas, Venezuela.

Kokal S.L., Sayegh S.G.,1995, "Asphaltene: The Cholesterol of Petroleum," SPE 29787, SPE Middle East Oil Show, Bahrain.

Lichaa P.M., 1977, "Asphaltene Deposition Problems in Venezuelan Crudes-Usage of Asphaltenes in Emulsion Stability," CIM Conference on the Oil Sands of Canada and Venezuela.

Lichaa P.M., Herrera L.,1975, "Electrical and Other Effects Related to the Formation and Prevention of Asphaltene Deposition," SPE-AIME, Paper No. 5304, International Symposium of Oilfield Chemistry, Dallas, Tx., U S A ..

Marín L., Mihura F., 1990, "Control de Asfáltenos en Tuberías de Gas Natural en el Oriente Venezolano," Vil! Jornadas de Gas, G.P.A., Caraballeda, Venezuela.

Morales J.L, Viloria A., Palacios C.A., 1994, "Control de la Corrosión en el Gasoducto Jusepín- Criogénico," INTEVEP S.A., CORPOVEN S.A., Venezuela.

Palacios C.A., Morales J.L., 1995, "Hydrodynamic Modeling for the Corrosion Control in the Oil and Gas Industry," NACE, Corrosion‘95, Paper No. 95104, Orlando, Fla. USA.

Stegmann D.W, Hausler R.H., Cruz C.I., Sutanto H., 1990, "Laboratory Studies on Flow Induced Localized Corrosion in CO2 /H 2 S Environments, I. Development of Test Methodology." NACE, Corrosion 90, Paper No. 5, Las Vegas, Nevada, USA.

NACE, 1995, "Standard Material Requirements Sulfide Stress Cracking Resistant-Metallic Materials for Oilfield Equipment" (MR0175-95), Houston, Tx. USA.

Marcano S., Vera J., Viloria A., 1993, “Bases Conceptuales para la Determinación de Correlaciones Predictivas de la Corrosividad por CO2 en Aceros al Carbono OCTG," INT-02617,93, Intevep S.A., Los Teques, Venezuela.


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Effect of Asphaltene Deposition on the Internal …proceedings.asmedigitalcollection.asme.org/.../ASMEP/89953/269_1.pdfThe purpose of this paper to describe the causes that enhance