CORROSION REVIEW, A CASE OF STUDY ON A PEMEX 14” PIPELINE IN NORTHERN MEXICO. Jorge Cantó, Lorenzo Martinez Martinez Javier Godoy Simon Lorenzo Martinez-Gomez ABSTRACT. Great industrial complexes allocated in northern Mexico require a vast supply of oil products. Pipelines running thousands of kilometers through out the country, from refineries to industrial complexes are representing the main column of the fuel transportation infrastructure.

The 14” pipeline studied, that runs almost 320 km from Satélite, Nuevo León to Gómez Palacio Durango in México, is one of the main fuel transportation in use today at northern Mexico.

To assure a continuous hydrocarbons supply a key factor to be consider is corrosion. Thereby PEMEX performed a whole set of inline inspections at this pipeline; those reports prove that internal corrosion is a major central problem.

Corrosion distribution is found at the bottom of the internal wall of the pipeline. With loses of wall thickness pipe up to 92 % in few cases and many reports of pitting that lower the maximum operating pressure to less than 25% of the design pressure. Some of the most common types of corrosion are found in this study, such as Hydrogen pitting, reducing sulfur bacteria and stress corrosion cracking.

Finding the source of this problem and designing a strategy of control, represents a key factor at the integrity of the pipeline and the economy of the region.

1.- Introduction This work details the study of 20 segments recovered directly from the pipeline. This study includes the analysis of the corrosion samples using Scanning Electron Microscope and Energy Dispersive Spectrometer (SEM/EDS). Evidence of Stress Corrosion Cracking (SCC) was found and characterized.

Sulfate reducing bacteria was found, the genus and specie is established thru genomic characterization methods Transported products were retrieved from the pipeline and storage tanks. Product corrosion reactivity was analyzed both at the field and in specialized laboratories. Analyses of fuel sediments allowed the recover of scales of iron oxides and hydroxides.

Actual internal corrosion inhibitor is evaluated by using electrochemical techniques and results presented.

The design of the control strategy is presented as a conclusion; based in the mentioned analysis and prior integrity reports.

2.-Pipeline integrity overview.

Along the near 320 Km. that shape this pipeline very different landscapes are found.

The pipeline has to cross approximately 100 Km. of mountain areas known as Sierra Madre Oriental, one of the highest and escarped mount formation in Mexico. In contrast the last trace of the pipeline is a very shallow desert area that used to be an enormous lagoon known as Laguna de Mayran.

Internal corrosion anomalies, are found in every section of the pipeline, but as showed in Error: Reference source not found, the biggest allocation is found at the lower and more shallow areas, near the final stages of the pipeline.

Figure 1. Location map of the area where is the pipeline under study

3.- Inhibitor properties The only internal corrosion inhibitor injection point is allocated at the beginning of the 320 Km. also near the area with less corrosion anomalies.

The inhibitor is designed to create a protective film over the metallic wall that resists the corrosive attack of carbonic and sulfhydric acid, in addition contains biocides to control the development of sulfate reducing bacteria. The inhibitor is dispersible in water and highly soluble in hydrocarbon.

Inhibitor characteristics are shown in Table 1.

Property

Manufacturer Report Data

Appearance

Liquid

Color

Dark brown

Solubility

Complete in hydrocarbon

Water dispensability

1ml / 100 ml

Density

0.95 gr / ml

Boiling point

70 C @ 1 atm

Viscosity

500 to 650 cps

Table 1. Characteristics of the inhibitor used in the 24 Northern pipeline Testing was performed in laboratories using NACE –TM -0172 methodology, proving that efficiencies up to 98.8% are achieved (efficiencies over 90% are accepted by PEMEX internal normative).

However, testing methods require a continuous turbulent environment where inhibitor solubility in hydrocarbons allows it to reach the testing electrodes. This condition is not probed to be found in shallow areas, far from pumping stations areas were laminar flux is expected.

An integrity assessment, performed in 2004, show that internal corrosion is a problem with corrosion velocities between 13.9 to 20 mpy, that are up to ten times the 2 mpy value acceptable by PEMEX standard.

Inline inspection, confirms that internal corrosion is concentrated at the lower parts of the pipeline (Error: Reference source not found). Thus, suggesting the presence of water inside the pipeline. The presence of water in a laminar flux, will not allow the corrosion inhibitor to reach the lower wall, where corrosion process is actually taking place. Corrosion inhibitors with low solubility in water may not be adequate to protect this pipeline, especially in the lower areas.

Sampling the pipeline to confirm water presence was not possible due to operational factors, however in the tanks that feed the pipeline with Diesel were possible to inspect, finding enough water, to perform a SRB, test that came out positive in concentration from moderate to elevated (10,000 to 100,000 colonies / ml). Bacteria growth was achieved using a specially formulated kit with tubes that contain a Media specifically formulated to promote the growth of anaerobic sulfate reducing bacteria.

After promoting the growth of the SRB, Scanning Electron Microscope analyses confirmed the presence of the bacteria, as illustrated in , the genus and specie was established thru genomic characterization methods.

Figure 2.- Anomalies distribution as a function of the deep in mpy.

Figure 2.- Micrography of the sulfur reducing bacteria, SRB.

Figure 3.- Two types of characteristic corrosion.

4.- Experimental From the 20 pipeline sections recovered, the most representative corrosion forms were selected for microanalysis. The corrosion pitting area was cut transversally in 9 square centimeter pieces.

Metallographic preparation was performed, to reveal the type of microstructure and analyzed using Scanning Electron Microscope techniques in complement with x ray diffraction microanalysis.

The corrosion cavity in Error: Reference source not found shows several layers of iron oxide, and presents typical inverse triangle shape formed by CO2 corrosion. The cavity is 2.6 cm wide and 1.8 cm. from top to bottom, representing up to 40% of wall lose.

Processing option : All elements analysed (Normalised) Spectrum

C

O

Al

Si

S

Mn

Fe

Total

Superior Medio

4.35 6.28

26.04 30.56

0.27 0.47

0.36 0.32

0.23 0.59

0.56 0.67

68.19 61.11

100.00 100.00

Fondo 6.52 28.02 0.40 0.19 0.93 0.69 All results in weight%, The increase in Sulfur is towards the center.

63.25

100.00

Figure. 5. The corrosion cavity presenting several layers of iron oxide by CO2 corrosion

X Ray diffraction patterns show higher concentrations of Carbon and Sulfur at the lower areas of the cavity, indicating the presence of Sulfate Reducing Bacteria and H2S. This observable fact is also found in the corrosion bulbs like that presented in Figure 4, but different from the cavities since the bulbs have the higher concentrations of Carbon and Sulfur at the center. (Figure 4).

C I

B

Spectrum

C

O

Al

Si

S

Cl

Mn

Fe

Total

Centro 10.90 47.81 0.96 1.85 1.34 0.43 0.82 35.89 intermedia 4.62 32.18 3.01 3.18 0.41 0.32 0.57 55.70 Borde 2.84 32.51 0.37 0.26 0.00 0.12 0.80 63.11 All results in weight%. The sulfur and chloride concentrations are bigger in the center.

100.00 100.00 100.00

Figure 4.- Bulbs with higher concentrations of Carbon and Sulfur at the center.

Figure 7.- Evidence of the hydrogen induced cracking on the surface of the corrosion bulb

Spectrum 3 pm 2n part blancas inclusion Inclusión 2

C 5.70 5.63 1.28 2.33

O 24.89 8.96 0.41 19.14

Al 22.37 4.24 0.66 23.41

Si 0.48 0.79 0.15 0.05

S 0.48 1.05 6.05 9.59

Ca

0.53

Mn 1.25 2.87 12.09 15.06

Fe 44.83 76.47 79.36 29.88

Total 100.00 100.00 100.00 100.00

Spectra show the association of corrosion propagation with MnS inclusions. Aluminum migth be present by the alumina used to polish the pipeline before the coating.

Figure 8.- Corrosion propagation associated with MnS.

Figure 9.- Wall cavity aspects with a preferential point of corrosion propagation.

4

3

1

2

Figure 10. Details of different parts of the corroded region. Spectrum 1 show the inclusion of MnS, inducing the corrosion attack.

Error: Reference source not found.- Lateral walls elements on the cavities within corrosion bulbs, diameters from 10 up to 30 μm.

Figure 11.- Profile of the inner zone of the cavity where it is possible to observe the corrosion propagation through out the ferrite grain.

Figure 12.- Cavity lower zone with the corrosion profile through out the perlite colony associated with non-metallic inclusions.

Figure 13.- Cavity right profile with oxidation region developing along with the crystallographic planes.

Figure 14.- Transversal section of the pipe wall. There is a 40 % reduction of the pipe thickness due to the corrosion attack.

Conclusions From the 20 sections obtained and studied, different corrosion types were found. Hydrogen induced pitting and cracking was detected in some of the pipeline parts. Sulfur reduced bacteria corrosion was found as evidence that optimal conditions for the inhibitor effect were not obtained. In some cases the corrosion oxidation profile was the same as the crystallographic planes through the perlite colonies with non-metallic inclusions. In the most inner bulbs of corrosion the sulfur and chloride concentration was bigger than that in the surface of the bulb. In other cases the corrosion also extended through the ferrite grain. However it is worth to note that more that 40 % of the pipe thickness is corroded in some areas, thus the design pressure is reduced to 25 % for working operation.

These facts prompted the Pemex management to replace more that 2000 sections of the pipeline to be sure that failures and leakages do not take place in the near future.

References.

1.- Peabody’s Control of pipeline corrosion, A. W. Peabody, 2nd Edition, ed. By R. L. Bianchetti, NACE International, The corrosion Society, 2001.

2- J. H. Morgan, “Cathodic Protection” 2nd edition NACE 1987.

3.- “Ferrous PipelinenCorrosion Processes Detection and Mitigation” , Office of Pipeline Safety, US Department of Transportation, Technical Report No. UPS-TR-71-001. Oct. 1971.

4.- K. Kasahara, T. Sato, H. Adachi, Materials Performance, September, 1980, pp 45-51.

5.- J. Soldevilla, Proc. 14th International Conference on Pipeline Protection, BHR Group, Barcelona, September 2001, pp11-23.