Corrosion Management




  • Challenges
  • Sour Service
  • Inhibition
  • Corrosion Management Services
Corrosion specialists continue to be challenged by new developments in oil and gas production systems. High reliability corrosion prevention, flow assurance in deep water and reservoir souring from sulfate reducing bacteria (SRB) are still major issues in hydrocarbon production and water injection systems. The composition of deepwater reservoirs may not be known during the design stage, hence, equipment material selection needs to be on the conservative side, as reliable performance in deep water is critical to the success of the field development, as repair and replacement of equipment in deep water, is cost prohibitive. In such circumstances nickel based corrosion resistant alloys (CRA’s) for wetted parts in trees and chokes etc. should become mandatory rather than optional. It is paramount to know each CRA’s operating limits such as pitting resistance, crevice corrosion and their ability to resist erosion-corrosion and also hydrogen embrittlement from cathodic protection and hydrogen sulfide. Other challenges include the selected elastomers ability to seal at both high and low temperatures in manifolds and subsea trees etc.
Hydrogen sulfide production from SRB’s has been a problem for many years in waterflooded oil formations. Some offshore operators have run into problems with sulfide stress corrosion cracking (SSCC) and microbiological induced corrosion (MIC) where seawater containing sulfate ions has been used for water injection, especially where equipment was not originally built to meet NACE MR 0175 requirements. Various techniques have been tested to control and reduce hydrogen sulfide levels such as injection of nitrate ions into injection water, with the premise that nitrate-reducing bacteria (NRB) can out-compete SRB’s and the use of large quantities of hydrogen sulfide scavenger. Other approaches besides using biocides, which are long-lasting and considered toxic to the environment, include the feasibility of utilizing infective phage panels of selected bacteria that will reduce the SRB or iron-oxidizing bacteria population and those that produce acidic metabolites.
The development of water-soluble corrosion inhibitors in the last decade has been a significant achievement in the corrosion control of flowlines as they are able to partition effectively into water and reach the pipe wall in water-wet areas. In three phase flow it has been found that water can stratify below oil even when the oil is in slug flow. Flowline and well hydraulics must also be understood to be able to select and apply inhibitors effectively. The use of pH stabilization in wet gas pipelines using sodium bicarbonate is also becoming a proven method except where high volumes of water are present. 
The services OSG can provide include:
  • Assessing corrosion rates and defining the requirements for inhibition, internal protection or the selection of corrosion resistant alloys.
  • Corrosion mechanisms - galvanic, crevice, pitting, preferential weldment corrosion, corrosion fatigue, inter / intragranular, SCC, SSC and HPIC, SOHIC, MIC.
  • Specialist materials testing for sour service (HISC, SOHIC, HE, SSCC and the full ring test), including sour service requirements for plastically strained line pipe.
  • Cathodic protection (CP) design work for flowlines and SCR's, subsea components, offshore pipelines, offshore structures and onshore pipelines and tanks and terminals. Utilization of attenuation calculations for the CP design of SCR's and insulated and non-insulated flowlines.
  • Corrosion rates in CO2 containing environments, using programs such as deWaard/Milliams, Norsok and Electronic Corrosion Engineer.
  • Materials susceptibility to H2S bearing hydrocarbon service using NACE MR 0175 and EFC 16.
  • Corrosion theory, anodic/cathodic reactions, polarization diagrams, Evans diagram, principles of cathodic protection, over potentials, galvanic series/couples.
  • Coating selection for pipelines, risers, subsea structure, topsides and field joints, e.g. coal tar, FBE, epoxies, polyolefinics, 3 layers, PU, high temperature systems, arctic coatings, insulations and new coatings technologies.
  • Coating testing requirements (laboratory and field) including cathodic disbondment, impact, high temperature, high pressure, collapse, sour service.
  • Cause and effects of corrosion.
  • Causes of failure to pipelines, risers and subsea equipment.
  • Internal and external corrosion mechanisms on pipelines, subsea structures/components, topsides components, piping.
  • Specifying and checking coatings before, during and after application.
  • Selecting, specifying and checking cathodic protection monitoring systems and site surveys.
  • Field joint coating materials selection, design and application methodologies.
  • Hydrate prevention (methanol), dehydration systems (MEG/TEG) and dew point control.