ANALYSIS OF STRESS CORROSION CRACKING OF X65 OIL PIPELINE€¦ · design, materials and ......

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International Journal of Mechanical Engineering and Technology (IJMET) Volume 8, Issue 4, April 2017, pp. 212–222 Article ID: IJMET_08_04_025

Available online at http://www.iaeme.com/IJMET/issues.asp?JType=IJMET&VType=8&IType=4

ISSN Print: 0976-6340 and ISSN Online: 0976-6359

© IAEME Publication Scopus Indexed

ANALYSIS OF STRESS CORROSION CRACKING

OF X65 OIL PIPELINE

Elwaleed Awad Khidir

Department of Mechanical Engineering, Jubail University College,

Jubail Industrial City 31961, Kingdom of Saudi Arabia &

Department of Mechanical Engineering, Faculty of Engineering

University of Khartoum, Khartoum, Sudan

Syed Ameer Basha

Department of Mechanical Engineering, Jubail University College,

Jubail Industrial City 31961, Kingdom of Saudi Arabia

Hayder M. A. A. Al-Assadi

Faculty of Mechanical Engineering

Universiti Teknologi MARA

Shah Alam, Selangor, 40450, MALAYSIA

ABSTRACT

This paper presents the investigations that have been carried out by the University of

Khartoum to identify the root causes of the pipeline failure and to avoid the reoccurrence

of the failure. The transmission pipeline belongs to Greater Nile Petroleum Operating

Company (GNPOC) and has been commissioned in1999. The investigations showed that

the pipeline corrosion started after the disbondment of the Heat Shrinkable Sleeve (HSS)

coating around the girth weld. The study indicated that the material properties comply with

the requirements of the American Petroleum Institute (API) standards. It was observed that

the external surface of the pipeline lost its ductility due to the hydrogen embrittlement,

which contributed to crack growth beside the soil nature, the soil compaction and the

location of the concrete anchor. The failure was classified as Circumferential stress

corrosion cracking (C-SCC) of neutral-pH form and transgranular cracks morphology.

Key words: Pipeline Failure; Stress Corrosion Cracking; Hydrogen Embrittlement.

Elwaleed Awad Khidir, Syed Ameer Basha and Hayder M. A. A. Al-Assadi


Cite this Article: Elwaleed Awad Khidir, Syed Ameer Basha and Hayder M. A. A. Al-

Assadi, Analysis of Stress Corrosion Cracking of X65 Oil Pipeline. International Journal

of Mechanical Engineering and Technology, 8(4), 2017, pp. 212–222.

http://www.iaeme.com/IJMET/issues.asp?JType=IJMET&VType=8&IType=4

1. INTRODUCTION

Oil and gas transmission pipelines have a good safety record due to the combination of good

design, materials and operating practices. However, like any engineering structure, pipelines do

occasionally fail. The most common causes of damage and failures in onshore and offshore, oil

and gas transmission pipelines are external interface and corrosion [1]. Corrosion usually appears

as either general corrosion or locallised (pitting) corrosion. Corrosion causes metal loss. It can

occur on the internal or external surfaces of the pipe, in the base material, the seam weld, the girth

weld, and/or the associated heat affected zone (HAZ).

Most buried pipelines that have been in service for five or more years experience numerous

corrosion and metallurgical defects, in particular cracks. The sources of these cracks can be due to

randomly distributed defects induced by the manufacturing process or the degradation of carbon

steel components of pipelines. The combined action of stress (e.g., hoop and/or residual) and

natural soil environment containing varying amounts of moisture and oxygen further facilitates the

initiation of the crack(s) and accelerates their propagation through the pipe thickness by a factor

that may range up to many times. In general the heat affected zone (HAZ) of a weld (especially at

the region adjacent to the fusion line) is hardened after welding. The hardened microstructures are

usually sensitive to hydrogen embrittlement (HE) and stress corrosion cracking [2].

In particular, weldments of thermomechanical-control processed (TMCP) steels such as the

API X65 steel show a greater difference between weld metal and HAZ properties than other

structural steel welds because of the HAZ softening effect, due to the thermal cycle experienced

in the welding process. This leads to further tempering of the already quenched and tempered

region. Therefore the difference in material properties between the different weld regions

influences how plasticity develops at flaws and hence the relationship between the crack driving

force and applied loading [3].

Stress corrosion cracking can be defined as the interaction of a tensile stress and an aqueous

environment acting on a susceptible metallic surface to initiate and propagate cracks. Since the

first discovery of Stress Corrosion Cracking (SCC) on the exterior surface of a buried high-

pressure natural gas transmission pipeline in 1965, SCC has continued to make a significant

contribution to the number of leaks and ruptures experienced by several countries throughout the

world (Argentina, Australia, Iran, Iraq, Italy, USA, Canada, the former Soviet Union, Pakistan,

Saudi Arabia and The Netherland) [4-6].

Two forms of SCC in the external surface of buried pipelines have been identified: high-pH or

“classical SCC” and low-pH or “near neutral SCC”. Both types of SCC have only been observed

under disbonding coatings [7]. High-pH SCC is by far the most reported form of SCC and is

characterized by the presence of numerous fine longitudinal intergranular. Cracking is associated

with relatively concentrated carbonate (CO3-) -bicarbonate (HCO3

- ) solution having pH in the

range 9 to 12.5. Low-pH SCC (or near neutral pH) on the outer surface of pipelines is associated

with specific soil conditions at free corrosion potential, where cathodic protection is ineffective.

Low-pH SCC occurs in the presence of dilute ground waters containing free carbon dioxide (CO2)

having a pH of around 6-8 [4, 8]. Pipeline steels becomes susceptible to near-neutral pH stress

Analysis of Stress Corrosion Cracking of X65 Oil Pipeline


corrosion cracking only when coatings on pipeline steels are damaged. This usually happens after

5 – 10 years of operation. During this 5-10 years period, the pipeline steels have been mechanically

conditioned by stress variations in the pipe that could be a key factor to the cracking after the

coating is damaged [9]. Marr et al. [10] wrote ‘‘the failure of a coating system is a primary factor

in the initiation and propagation of SCC.’’

Different types of coatings have been used to protect oil and gas pipelines over the past 50

years, such as coal tar or asphalt enamels, polyolefin tapes, two layer extruded polyethylene

coatings, single or dual layer fusion bonded epoxy coatings, heavy three or multi-layer polyolefin

coatings [11].

2. EXPERIMENTAL

3.1. Visual Inspection

The Greater Nile Petroleum Operating Company (GNPOC) 28” crude oil transmission pipeline

has been commissioned in1999. The design temperature and pressure are 55oC – 75oC and 97.24

bar, respectively.

On the 15th March, leakage of oil was observed on the 28” (API-5L WT 10.72/16.36mm)

buried pipeline. The location of the leakage is approximately 45.17 meters at the discharge side of

pump station 1. It was reported that the cracked zone was between 11:00 to 12:00 o’clock positions.

A mechanical leak repair clamp was installed as a temporary repair but the pipe was still leaking.

A permanent repair has been carried out by welding the same clamp and the leak was still there.

Then the defected spool pipe was replaced by a 4m new spool pipe and the pipeline was back to

normal operation.

The pipeline corrosion started after the disbondment of the Heat Shrinkable Sleeve (HSS)

coating around the girth weld. Figures 1 shows the corroded area around the girth weld. The

fractured side represents the pipe of 10.72 mm thickness (Figure 1 a). This side contained small to

large wide shallow pits, while the side of the 16.36mm thickness spool contained relatively small

pits (Figure 1 b). The crack lies in the Heat Affected Zone (HAZ) around 10 to 15 mm from the

girth weld. The crack is in the circumferential direction that initiated from external surface of the

pipe toward the internal surface. The length of the crack is about 16 cm.

(a)



(b)

Figure 1 Corrosion on the (a) 10.72 mm thickness side (b) the 16.36 mm side (the coin in the picture is of

20 mm diameter)

2.2. Chemical Composition of X65 Steel

The chemical composition of the steel by weight is shown in Table 1 (wt%). The microstructure

is composed of polygon ferrites and a few pearlites as shown in Figure 2. The X65 steel was

characterized as being susceptible to near-neutral pH stress corrosion cracking [9].

Table 1 Chemical Composition

Element Average (wt%)

Magnitude API 5L X65

C 0.077 0.28 max

Mn 1.58 1.40 max

P 0.014 0.03 max

S 0.0026 0.03 max

Si 0.355 -

Nb 0.036 -

Cr 0.021 -

Ti <0.001 -

Mo <0.002 -

V 0.0016 -

Ni 0.019 -

Al 0.032 -

Cu 0.0092 -



Figure 2 Microstructure of X65 Steel

2.3. Mechanical Properties of X65 Steel

Three samples were prepared from both pipes of different thickness to check their mechanical

properties. The mechanical properties of the material under investigation are shown in Table 2.

The pipe material complies with the requirements of the API 5L X65 [12].

Table 2 Chemical Composition

Property Average API 5L X65 range

Tensile strength (MPa) 649.0 531-758

Yield strength (MPa) 555.8 448-600

2.4. Soil Analysis

The soil at Heglig is black cotton soil, which is characterized by high swelling on wetting and

excessive shrinkage on drying due to the high content of montmorillonitic (beidellite) groups of

clay minerals. Although the soil is very hard in the dry state, nearly all its strength is lost when

saturated. This behavior is attributed generally to the presence of a high percentage of colloidal

material [13]. pH values of the soils range between 7 and 9. Figure 3 shows the areas of black soil

deposits in warm climates [14].



Figure 3 Areas of black soil deposits in warm climates shown in black [14]

A sample was taken from the soil surrounding the buried pipeline at Heglig. The soil was

analyzed at the Faculty of Engineering, University of Khartoum. The laboratory results are shown

in Table 3. The results show that the soil pH is 7.8. The soil resistivity is 3.1 Ohm-m, which

indicates the highest corrosion environment along the pipeline [15].

Table 2 Soil properties

Property Average

pH 7.8000

Chloride (%) 0.0020

Sulphate (%) 0.0031

Carbonate (%) 0.0420

Organic Matter (%) 4.0480

3. DISCUSSION

It is very clear that the pipeline corrosion started after the disbondment of the HSS coating around

the girth weld and in the HAZ. The fractured side represents the pipe of 10.72 mm thickness, which

contained small to large wide shallow pits, while the side of the 16.36mm thickness spool

contained relatively small pits. The length of the crack is about 16 cm (Figure 4). The crack

initiated and propagated in the circumferential direction from external surface of the pipe toward

the internal surface.



Figure 4 Sketch for the corroded area welding joint and the crack position

The crack feature from outside is very clear. The internal surface of the spool showed that the

crack started with a neck-like shape before opening (Figure 5). This could be attributed to that the

ductility of the inside surface of the spool was not affected by the embrittlement occurred at the

outside surface.

It was proved that the application of Cathodic Protection (CP), when pipeline failure is

imminent, is not always advisable because CP results in the steel becoming charged with hydrogen.

When sufficient hydrogen concentrates in pipeline steel, the metal loses its ductility – a

phenomenon known as hydrogen embrittlement. In reported cases, after one to two years of

service, more than a sixfold increase of hydrogen content occurred in the external surface of pipes

and, after 15 years, there was approximately a tenfold increase of hydrogen content [16]. As such,

it is hardly a coincidence that almost all failures in cathodically protected pipelines were

encountered in pipes installed for more than 10 years [17].

Previous studies of SCC of X-52 and X-80 pipeline steels in near-neutral pH solution showed

that SCC accelerated as the applied cathodic potential became more negative; and that hydrogen

diffused into the steel during SCC and concentrated around the crack tip, proving that crack growth

at cathodic potentials was due to the presence of occluded hydrogen in steels. On February 20,

2002, during a panel discussion on Cathodic Protection Myth-Conceptions held during the NACE

International Northern Area Western Conference in Edmonton, the subject ‘‘Cathodic Protection

Causes Hydrogen Embrittlement of Steel Pipelines’’ was voted as one of the 12 most important

subjects to be considered by the Canadian pipeline industry. It was a defining moment in the public

acknowledgement of the need to address the problem of cathodically induced hydrogen

embrittlement of pipeline steels [5].



Figure 5 The neck-like shape at internal surface of the spool before opening the crack started

As long as crack grows circumferentially at the corroded area, it can be classified as

circumferential stress corrosion cracking (C-SCC). This interpretation is supported by the

Canadian Energy Pipeline Association (CEPA) report [18], in which it was mentioned that most

cases the SCC appears to have been of the neutral-pH form (6-8 pH). The laboratory results showed

that the soil pH at the surroundings of the buried pipe is 7.8. Figure 6 shows how the crack

propagates circumferentially.

Figure 6 The crack propagation

The GNPOC Intelligent Pigging report in 2007 revealed that there is a metal loss at many

points along the pipeline. At the position of rupture the thickness of the pipe was reduced by 15%.

After the rupture the spool was replaced with a new one and the thickness at the same position was

measured and the reduction in thickness was estimated as 77%. Figure 7 shows the percentage

reduction of thickness from the year of commission in 1999 to the year of rupture 2007. It could



be observed from the figure that the rate of corrosion is high between 2007 and 2010 compared

with the rate of corrosion from 1999 to 2007.

Figure 7 Variation of thickness reduction with time

The corrosion of the pipe was at the HAZ on the spool of 10.72mm thickness. Due to the

thickness reduction this part became a stress concentration zone (Figure 8). The stress on the pipe

around this area was bending stress because of the black cotton soil nature (soil movement), as

mentioned in section 2.7. This stress was enhanced by the heavy compaction that the soil, above

the pipe, was exposed to. The anchor block supporting the pipeline was just 25m from the defected

part. As a result the pipe became like a cantilever along which the weakest part was the area of

high stress concentration. The defected spool pipe was replaced with a 4m spool. The old spool

was separated using a torch. According to witnesses the separation created a loud noise and the

new spool was aligned, for welding, with difficulty. This indicated that the pipe was under bending

stress.

It was reported that C-SCC initiated and grew under conditions of high axial stress generated

by slow, continuous soil movement and/or localized pipe bending in the vicinity of rocks and dents

on slopes. The soil movements associated with these cases of C-SCC can be termed as creep

movements, as opposed to catastrophic landslides. These slow and continuous movements can be

difficult to recognize in the field but, as evidenced by strain measurements, can with time generate

stresses in excess of Specified Minimum Yield Strength (SMYS) on the pipe. Clay soils and

moisture on and in slopes can be risk factors for soil creep. Periodic increases in axial tension on

the pipe may be a result of seasonal rain. Besides contributing to axial loading of the pipeline, soil

creep would also contribute to coating disbondment [19-21]. Construction practices can also

induce axial stress in the pipe. This may occur where pipe was forced into alignment for welding

at tie-in locations, for example at stream crossings, or at locations of field bends. Bending stress

can occur at road crossings where the loads are too great for the cover and strength of the pipe.



Figure 8 Sketch for the pipe and surrounding conditions enhancing the crack propagation

4. CONCLUSION

• The study showed that the material properties comply with the requirements of the API standards.

• The HSS coating defect, the hydrogen embrittlement, the soil nature and the soil compaction are

the main reasons for the rupture.

• The results show that the soil pH is 7.8. Therefore, the failure was classified as circumferential

stress corrosion cracking (C-SCC) of neutral-pH form and transgranular cracks morphology.

• In the future the IP report must be taken into consideration, especially in areas of the same

conditions such as different thickness joints (different internal diameters), at positions not far from

the anchor blocks and where the soil of similar properties.

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