Corrosion Management: A Key Issue In Pipeline Integrity
Authors: Roche Marcel 
Published: February 2016

The presentation summarises the basic principles of Pipeline Corrosion Management and updates the experience of one of the major integrated international Oil & Gas companies which cumulates experience feed-back of successes and problems in corrosion and integrity for more than 50 years.

External corrosion risks are addressed based on the behavior of plant-applied and field joint coatings used in conjunction with cathodic protection (CP) for protecting buried or immersed onshore and offshore pipelines. The overall performance of this protection system is high. However, disbondment of coatings from steel surface with time is the major threat encountered, because it may prevent cathodic protection current to reach the surface of steel ("CP shielding effect"). The major corrosion risk is related to massive disbonding of heat shrinkable sleeves (HSS) used for Field Joint Coating (FJC) at moderately elevated temperatures after 10 to 15 years in the ground. 3-Layer Polyolefin coatings (3LPO) have also been found disbonded from steel at the epoxy interface without significant corrosion underneath. The results of on-going R & D efforts carried out to understand the mechanisms leading to disbondment of 3LPO coatings and to assess the parameters influencing corrosion under disbonded coatings are presented. No corrosion has been identified so far in the submerged zone of offshore pipelines because of the high conductivity and homogeneity of the environment. The present main issue to be addressed is related to possible reduction of CP calculation hypotheses for optimizing the cost of protection for the design life of the pipeline. The most critical zone for offshore pipelines is the transition area between riser thick coatings and atmospheric paint system where accelerated corrosion may occur.

Pipelines operated by Total are practically always made of carbon steel. Very few leaks due to internal corrosion have been encountered so far, including on flow-lines, due to an efficient prevention and inspection policy. Most of these failures have been explained by Microbiologically Induced Corrosion (MIC) or by ingress of O2 traces combined with H2S. Top-of-Line Corrosion (TLC) has been encountered in some acidic hot wet gas pipelines: its causes and the ways to mitigate and prevent it are discussed. The general policy of the Company for selecting materials and prevention methods for internal corrosion and Environmentally Assisted Cracking (especially in "sour" environments containing H2S) is summarised. Finally, the policy used for inspection of pipelines using intelligent pigs or external electrical methods is explained.

Introduction

Pipelines constitute the safest method for transporting liquid and gaseous petroleum products or chemicals and represent a major part of surface facilities investments. An efficient Integrity Management System has to be implemented in order to prevent as much as possible any risk of failure. Internal and external corrosion phenomena represent a large part of the threats that pipeline operators have to face, together with third-party mechanical damage for onshore pipelines.

All internal and external corrosion cases affecting pipelines used in the Oil & Gas industry are of electrochemical nature. It means that they necessitate the presence of liquid water in contact with steel and of an oxidizing species dissolved in water for feeding corrosion cells. Corrosion risks consecutive to exposure of external side of pipelines to natural environments are mainly due to dissolved oxygen whereas the major cases of corrosion cases occurring on the internal side are due to H+ ion (acidic corrosion at low pH). A specific cause of corrosion failures is MIC (Microbiologically Induced Corrosion), encountered when growth of "sulfidogenic" bacteria (producing H2S) is significant on steel surface (local anaerobia, generally in moderate conditions of salinity, temperature and pH).

Environmentally Assisted Cracking failures may also occur in the form of Stress Corrosion Cracking (SCC) or Hydrogen Embritllement phenomena. SCC is an anodic process where cracks initiate from depassivated areas. For pipelines, this concerns mainly stainless steels in presence of chloride ions and carbon steels in buried conditions under a combination of specific kinds of disbonded coatings, soils and dynamic or static stresses (high pH and near neutral pH SCC). Hydrogen Embrittlement is a cathodic process consecutive to production of atomic hydrogen. Failures may be mainly due to the presence of H2S ("sour service") for internal side or to cathodic protection on sensitive steels such as martensitic or duplex stainless steels for external side (risk of HISC).